Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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CA 2899863 2017-03-03
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DOWNHOLE SYSTEM INCLUDING VARIABLE PROFILE SECTION
FIELD OF INVENTION
The present invention relates to the transport of a fluid, such as cement,
through a downhole tool or assembly.
BACKGROUND TO INVENTION
In the oil and gas exploration and production industry, well boreholes are
drilled from surface in order to access subsurface hydrocarbon-bearing
formations.
A tubular string, such as a completion string, may be run into the borehole
and the
annulus between the outside of the string filled with a fluid, such as cement.
Cementing operations may be required at various instances during the life
cycle of a
well, for example to assist in securing and supporting the string in the
borehole
during its initial completion, to prevent uncontrolled migration of fluid in
the annulus,
to provide isolation of one or more formation zone during production, and/or
during
remedial or workover operations.
Completion strings beneficially provide the ability to perform a number of
different operations in the borehole, the various completion string tools
utilising a
variety of activation mechanisms and systems.
However, since many completion string tools extend into or require access to
an axial throughbore or flow passage of the string, these tools and associated
equipment represent an obstruction to the passage of cement. As such, the
ability to
direct cement to the desired location may be impaired or prevented.
Moreover, there is a significant drive to improve the effectiveness and
reliability of tools which are deployed and operated in a downhole
environment, for
example to ensure that the tools operate at maximum efficiency, have minimum
risk
of failure or imprecise operation, can be flexible according to operator
requirements,
and minimise any necessary remedial action, associated time delays and costs.
Thus, it is important also that substantially all of the cement is directed
through the
string, such that the subsequent efficient operation of the tools and downhole
equipment is not impaired.
SUMMARY OF INVENTION
Aspects of the present invention relate to apparatus and methods for use in
transporting a fluid, such as cement, through a downhole tool or assembly. In
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particular, but not exclusively, embodiments of the invention relate to
methods and
apparatus for transporting cement through a downhole tool used in the
treatment, for
example fracturing, of a subterranean formation.
According to a first aspect of the present invention there is provided a
downhole cementing apparatus deployable through a downhole tool with a volume
of
cement, comprising:
a body; and
a sealing arrangement mounted on the body and configured to define a
varying point of sealing contact axially along the sealing arrangement with an
inner
surface of a downhole tool as the cementing apparatus is deployed through said
tool.
Providing a varying point of sealing contact axially along the sealing
arrangement may permit a seal to be provided at all times during passage of
the
apparatus through the downhole tool.
The sealing arrangement may comprise a unitary seal member or structure,
wherein said seal member or structure defines a plurality of seal regions of
features
configured to establish sealing contact with an inner surface of a downhole
tool.
The sealing arrangement may comprise at least one seal member for
sealingly engaging the inner surface of the downhole tool. At least one seal
member
may be operable to swab or wipe the inside of the downhole tool during
deployment
through said tool. The seal members may be spaced so that at least one seal
member may provide sealing contact with the inner surface of the downhole tool
during deployment through said tool.
The sealing arrangement may comprise a plurality of seal members arranged
along the body. The seal members may be spaced so that the seal member
employed to provide the sealing contact varies as the apparatus is deployed
through
the downhole tool. For example, the seal members may be spaced so that where
one seal member is adjacent to the portion of the downhole tool which may
otherwise
result in fluid bypass, at least one other of the seal members is positioned
adjacent to
a portion of the downhole tool which permits a sealing contact to be provided
between the apparatus and the downhole tool, thus ensuring that a sealing
contact is
provided at all times during passage of the apparatus through the downhole
tool.
When used in a cementing operation, for example, ensuring that a sealing
contact is
provided/ maintained may ensure that the cement is efficiently driven through
the
downhole tool and so eliminate or at least mitigate the possibility that
cement will set
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in the tool and so impair the cementing operation and/or subsequent operation
of
downhole tools and equipment.
The sealing contact may be formed by a continuous circumferential seal
between the seal member and the downhole tool. In use, the apparatus may be
configured so that the sealing contact isolates a downstream portion of the
downhole
tool from an upstream portion of the downhole tool.
The apparatus may isolate fluid located downstream of the sealing contact
from the upstream portion of the downhole tool.
In particular embodiments, the downstream fluid may comprise cement to be
urged through the downhole tool. Additionally or alternatively, the downstream
fluid
may comprise a driving fluid, such as glycol, water, drilling mud or other
suitable
driving fluid. Additionally or alternatively, the downstream fluid may
comprise an
inhibitor such as sugar grease or the like. Beneficially, providing sugar
grease may
prevent or inhibit adherence of cement to the downhole tool or other downhole
equipment. Thus, an apparatus according to the present invention may be
disposed
behind a column of fluid and operable to drive the fluid through the downhole
tool.
Any suitable means for deploying the apparatus through the downhole tool
may be used. For example, the apparatus may be deployed or urged through the
downhole tool by a fluid. In particular embodiments, the apparatus may be
deployed
or urged through the downhole tool by a fluid pressure, for example a fluid
pressure
acting across the sealing contact. The apparatus may be configured for
deployment
through the downhole tool by an upstream fluid. The upstream fluid may
comprise a
driving fluid, such as glycol, water, drilling mud or other suitable driving
fluid.
Additionally or alternatively, the upstream fluid may comprise an inhibitor
such as
sugar grease or the like. Alternatively or additionally, the upstream fluid
may
comprise cement or the like. Thus, in some instances an apparatus according
to
the present invention may be disposed ahead of a column of fluid, the
apparatus
being deployed by said fluid.
The apparatus may alternatively or additionally comprise or be coupled to
mechanical means for deploying the apparatus through the downhole tool. For
example, the apparatus may be coupled to a work string or the like for urging
the
apparatus through the downhole tool.
The apparatus, and more particularly at least one of the seal members, may
be configured to swab or wipe the inside of the downhole tool. For example,
the
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apparatus may be configured to remove any cement deposits from the downhole
tool
as the apparatus is deployed therethrough.
The seal members may be of any suitable form or construction.
The radial extent of the seal members may be configured such that at a first
axial location in the downhole tool one of the seal members cooperates with
the
downhole tool to provide a sealing contact and at a second axial location
within the
downhole tool said seal member permits passage of fluid and at least one other
of
the seal members cooperates with the downhole tool to provide a sealing
contact.
The radial extent of the seal member may be configured such that at a first
axial location in the downhole tool a first seal member cooperates with the
downhole
tool to provide a sealing contact, and at a second axial location within the
downhole
tool the first seal member may not provide sealing contact and a second seal
member cooperates with the downhole tool to provide a sealing contact.
In some embodiments, two or more of the seal members may extend radially
to the same diameter. In particular embodiments, one or more of the seal
members
may extend to a different radial extent than at least one other of the seal
members.
The radial extent of each seal member may be selected according to the
downhole
tool.
In particular embodiments, one or more of the seal members may be
configured to define a cup shape. One or more of the seal members may be
configured to define a disc shape.
In particular embodiments, the apparatus may comprise five seal members,
although it will be recognised that the apparatus may alternatively comprise
two seal
members, three seal members, four seal members or more than five seal members.
The seal members may be disposed on a mandrel. Any suitable means for
disposing the seal members on the mandrel may be provided. One or more of the
seal members may be integrally formed with the mandrel. One or more of the
seal
members may be secured to the mandrel. One or more of the seal members may be
configured to slip over the mandrel. One or more of the seal member may be
moulded onto the mandrel. One or more of the seal members may engage the
mandrel by an interference fit, may be shrink fitted onto the mandrel.
The mandrel may comprise a unitary component. The mandrel may comprise
at least one module.
Alternatively, and in particular embodiments, the mandrel may comprise a
plurality of modules. In particular embodiments, a module may be associated
with
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each of the seal members. For example, each of the seal members may be mounted
or otherwise provided on its own module. Alternatively, a module may be
associated
with a plurality of the seal members. At least one module may support at least
one
seal member. In embodiments where the apparatus comprises seal members of
5 different
type or form, for example but not exclusively of different shape or radial
extent, a module may be associated with each seal member type. The modules
and/or the seal members of each type may comprise an identifier. Providing an
identifier may facilitate ready identification of each module and/or seal
members or of
at least one module or seal member, for assembly or inventory purposes for
example.
The apparatus may comprise one or more spacer configured to provide the
axial spacing between the seal members. The spacer may comprise a module of
the
mandrel.
A connection arrangement may be provided for coupling the mandrel to
adjacent components and/or for coupling modules of the mandrel together. The
connection arrangement may be provided for coupling at least two modules of
the
mandrel together. The mandrel may comprise at least one spacer for providing
an
axial spacing between at least two seal members.
The connection arrangement may comprise a female connector.
The connection arrangement may comprise a male connector. In particular
embodiments, each module may comprise a male connector and a female connector.
The connection arrangement may comprise a threaded connection, push fit
connector or the like.
The downhole tool may be of any suitable form or construction.
The downhole tool may for example comprise a tool for use in treating a
subterranean formation. The downhole tool may comprise a tool for use is
hydraulic
fracturing. Hydraulic fracturing, commonly known as "fracking", may involve
the
injection of fluid into the formation to propagate fractures in the formation
rock and
increase flow of hydrocarbons into the borehole for extraction. In use, one or
more
fracturing tools may be run into the borehole and located adjacent to the
formation.
Fluid may then be directed through ports in a sidewall of the fracturing tool
and
injected into the formation. In some instances, a number of fracturing tools
may be
located at different axially spaced positions in a tubular string and
configured to
facilitate fracturing of multiple and/or selected formations.
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The downhole tool may comprise a tool housing defining a central bore and
including a fluid port. The fluid port may be configured to permit fluid
communication
between the central bore and a location external to the housing. The fluid
port may
extend in any suitable direction. The fluid port may extend generally
perpendicularly
relative to the central bore. In some embodiments the fluid port may extend
generally obliquely relative to the central bore. The fluid port may extend in
varying
directions, for example portions of the fluid port may extend at least one of
perpendicularly, parallel and obliquely relative to the central bore.
A valve member, such as a valve sleeve may be mounted within the housing.
The valve member may be rioveable, for example axially moveable, from a closed
position in which the fluid port is blocked to an open position in which the
fluid port is
opened. The fluid port may be opened to provide fluid communication between
the
central bore of the tool and an external downhole location, such as an
annulus, a
surrounding formation or the like. The fluid port may be arranged to
accommodate
one or both of outflow and inflow.
The downhole tool may comprise a catching apparatus, such as provided in
accordance with any other aspect. The catching apparatus may be mounted within
the housing, for example on a downhole side of the valve member.
The downhole tool may comprise an indexing mechanism mounted within the
housing. The indexing mechanism may be located on an uphole side of the valve
member. The indexing mechanism may be arranged to be moved axially along the
housing towards an actuation site. Upon reaching the actuation site the
indexing
mechanism may initiate actuation, for example movement, of at least one of the
valve
member and the catching apparatus.
The downhole tool may define a downhole fracturing tool.
The downhole tool may comprise a tool as disclosed in WO 2011/117601
and/or WO 2011/117602.
In use, the apparatus may be configured for deployment through an axial flow
passage or throughbore of the downhole tool.
The axial flow passag? of the downhole tool may comprise or define a varying
profile. The axial flow passage may comprise a first portion of a first
diameter and a
second portion of a second, larger, diameter. The second portion may comprise
a
recess. In particular embodiments, the profile may comprise an indexing
profile.
Providing an apparatus according to embodiments of the present invention
may permit a sealing contact to be provided and maintained in an axial flow
passage
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having such a varying profile, since the seal members may be spaced so that
where
one seal member is adjacent to the profile portion which may otherwise result
in fluid
bypass, at least one other of the seal members is positioned adjacent to a
portion of
the downhole tool which permits a sealing contact to be provided between the
apparatus and the downhole tool, thus ensuring that a sealing contact is
provided at
all times during passage of the apparatus through the downhole tool.
Alternatively or additionally, a restriction may be provided in the downhole
tool
and the apparatus may be configured for deployment through the restriction.
The
restriction may comprise part of the downhole tool disposed in or extendable
into the
axial flow passage. Alternatively, or additionally, the restriction may
comprise a tool
disposed within the axial flow passage. The restriction may define a flow
passage
other than the axial flow passage which may, for example, define a leak path.
In
particular embodiments, the restriction may comprise a sleeve, such as a
collet
sleeve.
Providing an apparatus according to embodiments of the present invention
may permit a sealing contact to be provided and maintained in an axial flow
passage
having such a restriction, since the seal members may be spaced so that where
one
seal member is adjacent to the profile portion which may otherwise result in
fluid
bypass, at least one other of the seal members is positioned adjacent to a
portion of
the downhole tool which permits a sealing contact to be provided between the
apparatus and the downhole tool, thus ensuring that a sealing contact is
provided at
all times during passage of the apparatus through the downhole tool.
An inhibitor may be provided to prevent or mitigate adherence/ setting of the
fluid, such as cement, to the apparatus and/or the downhole tool. The
inhibitor may
comprise sugar grease or the like. Sugar grease has been found to be
particularly
effective in preventing adherence of cement to downhole tools and equipment.
The
inhibitor may be disposed on the downhole tool. The inhibitor may be disposed
on
the apparatus. The inhibitor may be provided in the form of a coating.
The downhole tool may be coupled to or form part of a tubular string, such as
a completion string.
A single downhole tool may be provided. In particular embodiments, a
plurality of downhole tools may be provided. In embodiments where the downhole
tool comprises a tool for treating, for example fracturing, a subterranean
formation
may comprise up to 30 downhole tools, for example up to 150 downhole tools.
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A single apparatus may be provided. In particular embodiments, a plurality of
downhole tools may be provided. In embodiments where a plurality of the
downhole
tools are provided, one apparatus may be provided for each downhole tool.
According to a second aspect of the present invention there is provided a
method comprising:
providing a body;
mounting a sealing arrangement on the body;
configuring the sealing arrangement such that where the cementing
apparatus is deployed through a downhole tool the sealing arrangement defines
a
varying point of sealing contact axially along the sealing arrangement with an
inner
surface of a downhole tool.
The sealing arrangement may comprise a plurality of axially spaced seal
members. At a first axial location within the downhole tool, one of the seal
members
is located to cooperate with the downhole tool to provide a sealing contact.
At a
second axial location within the downhole tool said seal member permits
passage of
fluid and at least one other of the seal members cooperates with the downhole
tool to
provide a sealing contact.
The method may comprise urging a fluid, such as cement or the like, through
the downhole tool. The method may comprise or form part of a cementing
operation
in a borehole, such as a well borehole.
The method may comprise treating, for example fracturing, a subterranean
formation.
According to third aspect of the present invention there is provided a
downhole method comprising:
deploying an apparatus through a downhole tool, wherein the
apparatus comprises a sealing arrangement;
establishing a point of sealing contact between the sealing arrangement and
an inner surface of the downhole tool; and
varying the point of sealing contact axially along the sealing arrangement
during deployment through the downhole tool.
The method may comprise providing the varying point of sealing contact
between a plurality of axially spaced seal members within the sealing
arrangement.
At a first axial location within the downhole tool, a first seal member may
cooperate with the downhole tool to provide a first point of sealing contact.
At a
second axial location within the downhole tool the first point of sealing
contact may
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be removed, and a second seal member may cooperate with the downhole tool to
provide a second point of sealing contact.
The method may comprise pumping the apparatus through the downhole tool.
The method may comprise passing a volume of cement through the downhole
tool on one axial side of the apparatus.
The method may comprise:
deploying first and second apparatuses through the downhole tool, wherein
each apparatus may include a respective sealing arrangement;
deploying a volume of cement intermediate the first and second apparatuses;
establishing a point of sealing contact between the respective sealing
arrangements and an inner surface of the downhole tool; and
varying the respective points of sealing contact axially along the respective
sealing arrangements during deployment through the downhole tool.
The method may comprise or form part of a downhole cementing operation.
The method may comprise treating a subterranean formation via the
downhole tool.
The downhole tool may comprise a tool for use in fracturing a subterranean
formation.
According to a fourth aspect of the present invention there is provided:
a downhole tool; and
an apparatus for deployment through the downhole tool, the apparatus
comprising a plurality of axially spaced seal members, wherein the axial
spacing of
the seal members is configured such that at a first axial location in the
downhole tool
one of the seal members cooperates with the downhole tool to provide a sealing
contact and at a second axial location within the downhole tool said seal
member
permits passage of fluid and at least one other of the seal members cooperates
with
the downhole tool to provide a sealing contact.
According to a fifth aspect of the present invention there is provided an
apparatus for deployment through a downhole tool, the apparatus comprising a
plurality of axially spaced seal members, wherein the axial spacing of the
seal
members is configured such that at a first axial location in the downhole tool
one of
the seal members cooperates with the downhole tool to provide a sealing
contact and
at a second axial location within the downhole tool said seal member permits
passage of fluid and at least one other of the seal members cooperates with
the
downhole tool to provide a sealing contact.
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According to a sixth aspect of the present invention there is provided a
downhole system, comprising:
a downhole tool; and
an apparatus for deployment through the downhole tool, wherein the
5 apparatus comprises a sealing arrangement configured to define a varying
point of
sealing contact axially along the sealing arrangement with an inner surface of
the
downhole tool during deployment through said tool.
The apparatus may comprise a plurality of axially spaced seal members,
wherein the axial spacing of the seal members may be configured such that at a
first
10 axial location in the downhole tool one of the seal members cooperates
with the
downhole tool to provide a sealing contact and at a second axial location
within the
downhole tool said seal member permits passage of fluid and at least one other
of
the seal members cooperates with the downhole tool to provide a sealing
contact.
The downhole tool may comprise a tool for use in treating a subterranean
formation, a tool for use in hydraulic fracturing, a tool housing defining a
central bore
and including a fluid port, a valve sleeve, a catching apparatus and/or an
indexing
mechanism, or the like.
According to a seventh aspect of the present invention there is provided a
method comprising deploying an apparatus having a plurality of axially spaced
seal
members through a downhole tool, wherein at a first axial location within the
downhole tool one of the seal members is located to cooperate with the
downhole
tool to provide a sealing contact and at a second axial location within the
downhole
tool said seal member permits passage of fluid and at least one other of the
seal
members cooperates with the downhole tool to provide a sealing contact.
An eighth aspect of the present invention relates to use of an inhibitor to
prevent adherence of cement to downhole equipment.
The downhole equipment may comprise an apparatus according to any
previous aspect.
The downhole equipment may comprise a downhole tool according to any
previous aspect.
The inhibitor may comprise sugar grease.
According to a ninth aspect of the present invention there is provided a
method for inhibiting adherence of cement to a downhole tool of a string,
comprising
coating a surface of the tool with sugar grease.
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The method may comprise directing a volume of sugar grease through the
string. The downhole tool may comprise a tool for use in treating a
subterranean
formation, a tool for use in hydraulic fracturing, a tool housing defining a
central bore
and including a fluid port, a valve sleeve, a catching apparatus, and/or an
indexing
mechanism, or the like.
The method may comprise directing a volume of cement through the
downhole tool. The method may comprise using a downhole apparatus comprising a
body and a sealing arrangement mounted on the body to direct sugar grease
through
the downhole tool.
According to a tenth aspect of the present invention there is provided a
downhole cementing method, comprising:
directing a volume of cement through a string comprising a fracturing tool;
and
directing the cement into an annulus surrounding at least a portion of the
string.
The method may comprise performing a fracturing operation after the cement
has been directed into the annulus.
The method may comprise deploying an apparatus according to any other
aspect through the string with the volume of cement.
The method may comprise disposing a first apparatus on a downhole side of
the volume of cement.
The method may comprise disposing a second apparatus on an uphole side
of the cement.
The method may comprise coating surfaces of the fracturing tool with an
inhibitor configured to inhibit adherence of cement to the surface.
The inhibitor may comprise sugar grease.
An eleventh aspect of the present invention relates to a downhole apparatus
deployable through a downhole tool. The apparatus may be deployable with a
volume of a fluid. The apparatus may comprise a body. The apparatus may
comprise a sealing arrangement mounted on the body. The sealing arrangement
may be configured to define a sealing contact with an inner surface of a
downhole
tool. The sealing arrangement may be configured to provide a varying point of
sealing contact along a length of the sealing arrangement as the apparatus is
deployed through said tool.
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It should be understood that the features defined above in accordance with
any aspect of the present invention or below in relation to any specific
embodiment of
the invention may be utilised, either alone or in combination with any other
defined
feature, in any other aspect or embodiment of the invention.
BRIEF DESCRIPTION OF DRAWINGS
Figure 1 a longitudinal sectional view of a downhole cementing
apparatus
according to an embodiment of the present invention;
Figure 2 a longitudinal sectional view of the downhole cementing apparatus
shown in Figure 1, shown disposed within a downhole tool;
Figure 3 an enlarged view of a first, uphole, end region of the
downhole tool,
showing the cementing apparatus at a first axial location;
Figure 4 an enlarged view of a second, downhole, end region of the
downhole
tool;
Figure 5 a cross sectional view of the apparatus and downhole tool
along
section A-A shown in Figure 4;
Figure 6 a diagrammatic view of a wellbore system, in which
embodiments of
the present invention may be utilised;
Figure 7 a diagrammatic view of the wellbore system of Figure 6, shown
during
a cementing operation;
Figure 8 a diagrammatic view of the wellbore system of Figures 7 and
8, shown
after a cementing operation has been completed;
Figure 9 a diagrammatic view of the wellbore system of Figures 7, 8
and 9,
shown during a fracturing operation.
DETAILED DESCRIPTION OF DRAWINGS
Referring first to Figures 1 and 2, there is shown a downhole cementing
apparatus, in the form of a cement dart 10, according to an embodiment of the
present invention. In use, the dart 10 may be employed during a downhole
cementing operation, the dart 10 being deployable through a downhole tool 12
(Figure 2) with a volume of cement 14 and configured to provide a varying
point of
sealing contact 16 between the dart 10 and the downhole tool 12 which permits
the
cement 14 to be driven through the downhole tool 12.
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As shown in Figure 1, the dart 10 comprises a body in the form of a mandrel
18 and a sealing arrangement 20 for providing the sealing contact 16. In the
illustrated embodiment, the sealing arrangement 20 comprises a plurality of
axially
spaced seal members 22a, 22b, 22c, 22d, 22e and, in use, the dart 10 is
configured
so that as the dart 10 is deployed though the downhole tool 12 the point of
sealing
contact 16 between the dart 10 and the tool 12 varies axially along the
sealing
arrangement 20, thus ensuring that a sealing contact between the dart 10 and
the
tool 12 is maintained at all times during passage of the dart 10 through the
tool 12.
The mandrel 18 comprises a number of separate modules 24a, 24b, 24c,
24d, 24e, 24f and 24g. In the illustrated embodiment, the modules 24a, 24b,
24c,
24d and 24e comprise seal member modules, each having a seal member 22a, 22b,
22c, 22d, 22e disposed or formed thereon while the modules 24f and 24g
comprise
spacer modules. Each of the modules 24a to 24g has a male connector 26a, 26b,
26c, 26d, 26e, 26f and a corresponding female connector 28a, 28b, 28c, 28d,
28e,
28f and 28g for coupling the modules 24a, 24b, 24c, 24d, 24e, 24f and 24g
together
and which permits the dart 10 to be constructed with the spacing required to
provide
the required sealing contact 16.
The axial spacing of the seal members 22a, 22b, 22c, 22d, 22e is configured
so that the point of sealing contact 16 between the dart 10 and the axial flow
passage
14 of the tool 12 is maintained by at least one of the seal members 22a, 22b,
22c,
22d, 22e at all times during passage of the dart 10 through the downhole tool
12.
Providing and maintaining the seal 16 ensures that the cement 14 is driven
through
the downhole tool 12, even where one or more of the seal members 22a, 22b,
22c,
22d, 22e is disposed at an axial location in the downhole tool 12 which may
permit
fluid passage around the respective seal member 22a, 22b, 22c, 22d, 22e.
In the illustrated embodiment, each seal member 22a to 22e comprises a
cup-shaped seal element 30a, 30b, 30c, 30d, 30e moulded or otherwise disposed
on
its respective mandrel portion 24a to 24e. The seal elements 30a to 30e each
define
a cup angle Oa, eh, Oc, ed, Oe with respect to the mandrel 18 and define a
maximum
diameter Da, Db, Dc, Dd, De at their distal ends 32a, 32h, 32c, 32d, 32e. The
cup
angles Oa, Ob, Oc, Od, Oe and the diameters Da, Db, Dc, Dd, De may be
configured
so that the point of sealing contact 16 between the dart 10 and the axial flow
passage
14 of the tool 12 is maintained by at least one of the seal members 22a, 22b,
22c,
22d, 22e at all times during passage of the dart 10 through the downhole tool
12.
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Referring now in particular to Figures 2 to 4, the downhole tool 12 comprises
a housing 34 which defines a central bore 36 and extends between an uphole
connector 38 and a downhole connector 40. The connectors 38, 40 facilitate
connection of the tool 12 to an uphole string component S1 and a downhole
string
component S2 (shown schematically in Figure 1).
Fluid ports 42 are provided radially through a wall of the housing 34 and,
when opened, the ports 42 facilitate outflow of a fluid from the central bore
36 of the
housing 34. A valve member in the form of a sleeve 44 is moveable axially
along the
housing 34 from a closed position in which the sleeve 44 blocks or closes the
ports
42, to an open position. Movement of the sleeve 44 towards its open position
is
achieved by an associated actuator portion 46.
A catching sleeve 48 is located downhole of the valve sleeve 44 and is
moveable from a free configuration in which an object, such as a ball (not
shown)
may freely pass, to a catching configuration in which an object, such as a
ball, may
be caught. In use, the catching sleeve 48 may function to catch an object and
establish diversion of any fluid from the central bore 36 outwardly through
the fluid
ports 42 when open. Further, the catching sleeve 48 is operated to move to its
catching configuration by movement of the valve sleeve 44 towards its open
configuration.
The actuator portion 46 of the tool 12 defines an indexing profile 50 provided
on the inner surface of the housing 34.
The indexing profile 50 includes a plurality of axially spaced annular
recesses
52a, 52b, 52c, 52d, 52e, 52f, 52g, 52h formed in the inner surface of the
housing 34.
An indexing sleeve 54 is mounted within the housing 34 and is configured to
cooperate with the indexing profile 50 to be driven in a number of discrete
linear
movement steps through the housing 34 by passage of a corresponding number of
actuation objects, such as balls. The indexing sleeve 54 is driven in discrete
movement steps until reaching an actuation site within the tool 12, where the
indexing sleeve 54 engages and moves the valve sleeve 44 in a downhole
direction
to open the ports 42.
In the illustrated embodiment, the indexing sleeve 50 includes a tubular wall
structure 56 which defines a central bore 58 corresponding with the central
bore 36
of the housing 34. The central bore 58 is sized to permit an actuation object,
such as
a ball, to pass therethrough.
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The indexing sleeve 54 also includes first and second circumferential arrays
of engagement members 60, 62 which are arranged such that the array of first
engagement members 60 are axially spaced apart from the array of second
engagement members 62. The engagement members are arranged within slots 64,
5 66 formed through the wall structure 56. In use, the arrays of engagement
members
60, 62 cooperate with the indexing profile 50 of the housing 34 to be
sequentially
engaged by a passing object, such as a ball, to drive the indexing sleeve 54
one
discrete linear movement step. More specifically, the first and second arrays
of
engagement members 60, 62 are arranged to be moved radially within their
10 associated slots 64, 66 such that each array of engagement members 60,
62 is
moved in an alternating or out of phase manner relative to the other array of
engagement members 60, 62 by cooperation with the indexing profile 50 during
movement of the indexing sleeve 54 through the housing 34. Such alternating
radial
movement alternately moves the first and second arrays of engagement members
15 60, 62 radially inwardly and into the central bore of the indexing
sleeve 54, to thus be
sequentially engaged by a passing actuation object. In this way, a passing
object
may engage the engagement members 62,64 of one of the first and second arrays
to
move the indexing sleeve 54 a portion of a discrete movement step, and then
subsequently engage the engagement members 62, 64 of the other one of the
first
and second arrays to complete the discrete movement step of the indexing
sleeve
54.
The engagement members 62, 64 are mounted on the distal end of
respective collet fingers 68 which are secured at their proximal ends to the
tubular
wall structure 56. The collet fingers 68 are resiliently deformable to
facilitate radial
movement of the engagement members 62, 64 by cooperation with the indexing
profile 50.
In the illustrated embodiment the collet fingers 68 are unstressed when the
engagement members 62, 64 are positioned radially outwardly and thus removed
from the central bore. As such, the collet fingers 68 must be positively
deformed by
appropriate cooperation between the engagement members 62, 64 and the indexing
profile 50 to move the engagement members 62, 64 radially inwardly into the
central
bore to permit engagement by an actuation object, such as a ball. In such an
arrangement, the collet fingers 66 may function to bias the engagement members
62,
64 in a direction to be moved radially outwardly from the central bore. Each
slot of
the indexing sleeve 54 accommodates two respective engagement members 62, 64.
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Further, the slots are defined between respective elongate ribs. Each rib
includes a
spline feature or key which are received in corresponding longitudinally
extending
slots or key-ways (not shown) formed in the housing 34. Engagement between the
keys and the longitudinal slots or key-ways may function to rotationally lock
the
indexing sleeve 54 relative to the housing 34, while still permitting movement
of the
indexing sleeve 54 linearly through the housing 34. Such an arrangement may
facilitate milling of the indexing sleeve 54, if ever required.
It will be recognised that the downhole tool 12 may thus include a profile,
such as the indexing profile 50, or a restriction through which a dart must
pass, such
as the catching sleeve 48 or indexing sleeve 50, but which may prevent the
creation
of a continuous circumferential seal. In the case of a restriction, for
example, fluid
leakage may be permitted around the restriction and so prevent the creation of
a
continuous circumferential seal.
Alternatively or additionally, the form of the
restriction, which may for example comprise a collet sleeve or the sleeve, may
prevent the creation of a continuous circumferential seal.
In embodiments of the present invention, however, the dart 10 is configured
to provide a varying point of sealing contact 16 axially along the sealing
arrangement
which permits a sealing contact 16 to be provided at all times during passage
of
the dart 10 through the downhole tool 12.
20 Deployment
of the dart 10 through the downhole tool 12 will now be
described.
In Figure 3, the dart 10 is shown located within the axial flow passage 14 of
the downhole tool 12 at a first axial location. At this first location, the
sealing contact
16 is provided by the first seal member 22a which is disposed adjacent to and
seals
against the valve sleeve 44 of the downhole tool 12.
However, as the dart 10 progresses in the direction of arrow 90, seal member
22a will become aligned with ports 92 defined in the valve sleeve (which are
used,
eventually, to become aligned with ports 42). Accordingly, seal member 22a
will
loose its sealing function. However, at this point sealing member 22b will
become
aligned with cylindrical surface 94 on the tool 12, and as such will now
establish
sealing contact.
As the dart 10 continues to progress, the particular seal member providing a
sealing function may vary, and as such permitting at least one sealing contact
to be
achieved at all times during passage of the dart 10 through the downhole tool
12.
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It should be understood that the embodiments described herein are merely
exemplary and that various modifications may be made thereto without departing
from the scope of the invention.
For example, it will be recognised that a wellbore system may comprise a
plurality of darts 10 and downhole tools 12 of the same or different
configuration and
a dart 10 may be provided behind a column of cement 14 and used to drive
cement
14 through the downhole tool 12 or may be located ahead of a column of cement
and
used, for example, to deploy an inhibitor in the downhole tool 12 prior to the
cementing operation.
Referring now to Figures 6 to 9, there is shown a wellbore system 100
including a drilled borehole 102 which extends from surface 104 and intercepts
a
subterranean reservoir or formation 106. In the illustrated embodiment, the
borehole
102 may comprise a deviated, high angle or horizontal section 108.
The formation 106 may contain hydrocarbons to be produced to surface 104
via the system 100. Alternatively, or additionally, the subterranean formation
106
may define a target for receiving a treatment medium or fluid injected from
surface
104 via the system 100, for example for increasing formation pressure to
improve
production of hydrocarbons from the formation 106 or a neighbouring formation,
for
sequestration purposes, or the like.
A tubular string 110 extends through the borehole 102, the string 1110
comprising a plurality of fracturing tools 112 distributed along its length at
a desired
interval spacing. One of more of the tools 112 may, for example, comprise a
tool
such as the tool 12 described above.
Figure 6 shows the wellbore system 100 after location of a tubular string 110
at a required depth.
A number of operations may be required during the life cycle of the wellbore
system 100 which require the ability to direct a fluid into and/or from the
formation
106. For example, a cementing operation may be carried out in order to assist
in
securing and supporting at least part of the string 110 in the borehole 102,
to prevent
uncontrolled migration of fluid in annulus 114 between the string 110 and the
borehole 102 and/or in the isolation of particular formation zones prior to
perform a
fracturing or stimulation operation.
Referring to Figure 7, the cementing operation may involve directing a volume
of cement 116 through the string 110 which is then directed into the annulus
114 and
circulated back towards surface to fill the annulus 114 or an annulus section.
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In order to control the cementing process, a first cement apparatus may
disposed ahead of the cement 116 and engage a landing collar (not shown) while
a
second cement apparatus is disposed behind the column of cement 116. The first
cement apparatus may comprise a dart 118, similar to or identical to the dart
10
described above. The second cement apparatus may also or alternatively
comprise a
dart 120, similar to or identical to the dart 10 described above. Increased
pressure
may then be used to rupture or open a fluid passage so that the cement 116 may
be
driven into the annulus 114. In use, the second dart 120 may also act to clean
any
cement 116 as it is driven through the string 110 which may otherwise form an
obstruction. The cemented borehole is shown in Figure 8.
Alternatively or additionally, the formation 106 may require stimulation or
treatment to provide improved production or injection rates to be achieved or
restored. Stimulation techniques include hydraulic fracturing which involves
injecting
a fracturing fluid into the formation at high pressure and/or flow rates to
create
mechanical fractures within the geology. These fractures may increase the
effective
near-wellbore permeability and fluid connectivity between the formation and
wellbore.
The fracturing fluid may carry proppant material, which functions to prop open
the
fractures when the hydraulic fracturing pressure has been removed. Matrix
stimulation provides a similar effect as hydraulic fracturing. This typically
involves
injecting a chemical such as an acid, for example hydrochloric acid, into the
formation to chemically create fractures or wormholes in the geology. Such
matrix
stimulation may have application in particular geology types, such as in
carbonate
reservoirs.
As shown in Figure 9, each of the tools 112 includes a plurality of
circumferentially arranged ports 122, which are initially closed. Further,
each tool
112 includes or is associated with a downhole actuator (not shown) which is
operable
to actuate the tool 112 to open the associated ports 122 to allow injection of
a
treating fluid, such as a fracturing fluid or acid, from the string 110 into
the
surrounding formation 106 to create fractures 124. Each tool 112 is operated
by
actuation objects, such as balls, which are delivered through the string 110
from
surface 104.
The tools 112 are capable of being actuated in a desired sequence, thus
allowing the formation 106 to be treated along the length of the borehole 102
in
stages. Such ability to actuate the tools 112 sequentially may be achieved via
the
associated downhole actuator. In the illustrated embodiment, the tools 112 are
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arranged to be actuated in an uphole sequence or direction. This is shown in
Figure
9 in which the lowermost illustrated tool 112 has previously been actuated,
with an
adjacent tool 112 on the uphole side shown in an actuated state with
fracturing fluid
from the opened ports 122 being directed into the formation 106 in the
direction of
arrows 126. Once appropriate fracturing has been achieved via tool 112, the
next
uphole tool 112 may then be actuated.
