Note: Descriptions are shown in the official language in which they were submitted.
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
DOWNHOLE TOOL HAVING AN AXIAL PASSAGE AND A LATERAL FLUID PASSAGE
BEING OPENED / CLOSED
FIELD
This invention relates to a downhole tool and method. More particularly, but
not
exclusively, embodiments of this invention relate to a downhole tool
operatively
associated with a downhole pump for use in artificial lift applications.
BACKGROUND
During extraction of natural resources from subterranean reservoirs, which may
include
hydrocarbon fluids and/or water and/or gas, there often exists a pressure
differential
between the reservoir and the earth's surface (known as hydrostatic head)
which must
be overcome in order to produce the fluid resources to surface. In the
hydrocarbon
production industry, this process is commonly known as "artificial lift".
Artificial lift can be achieved by using a variety of means including the use
of pumps
such as a progressive cavity pump (PCP). PCP's are positive displacement pumps
and
as such there is physical contact between their constituent pressure inducing
components. A typical PCP comprises a helical steel rotor and a rubber stator
having
an internal eccentric helical profile closely matching that of the rotor. The
stator is
typically encapsulated in steel tubing that forms a lower portion of a tubing
string that
runs from the reservoir to the surface. The rotor is typically connected to
the bottom of
a rod string that also runs to surface. The rotor and rod string have a
smaller outside
diameter than the inside diameter of the aforementioned tubing string. The
rotor and
rod string are run in from surface through the bore of the tubing string and
positioned
such that the rotor is located within the stator. This arrangement results in
a series of
cavities along the length of the PCP. The rod string is connected to a
suitable rotary
drive at surface which powers rotation of the rod string and rotor assembly
within the
stator when the PCP is in use. The use of rod guides or centralisers along the
length of
the rod string is typical to maintain the rod string in a relatively central
position within
the tubing string. This rotation causes fluid in the cavities to move upward
into the
tubing string resulting in a gradual increase in pressure between the PCP
inlet and
1
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
discharge. This positive displacement of fluid overcomes the hydrostatic head
and
provides the necessary lift to produce the reservoir fluids to surface.
PCP's may be used to produce water or hydrocarbon fluids to surface that may
be light
and thin or heavy and highly viscous, and often these applications produce
large
quantities of sand and other solids along with the produced fluids. PCP run-
life is
largely dependent on the amount of solids produced through the pump.
Often, sand and other solids produced through a PCP will suspend, entrained in
the
fluid column above the PCP, within the tubing string. If operation of the PCP
is
stopped, which may occur for a variety of reasons including planned
maintenance or
unplanned power cuts, these solids can settle on top of the PCP, forming a
sand plug on
top of the pump. With applications that produce excessive amounts of sand /
solids, the
solids may also enter the upper stages (cavities) of the pump. If a sand plug
has formed,
then when the PCP is restarted it initially runs dry as pressure gradually
increases to the
point at which the sand plug is dislodged. Due to the intimate contact between
the rotor
and the stator, this period of dry running can seriously damage the rubber
stator
effectively destroying the pump.
Historically, this has been avoided by retracting the rotor from the stator to
dislodge the sand plug and allow it to fall through the stator back into the
reservoir.
However, such a "work-over" operation requires specialist equipment and is
extremely
costly and time consuming. When operation of the pump is stopped , the large
volume
of fluid inside the tubing string will tend to drop or "u-tube" back down
towards the
static fluid level in the reservoir to equalise pressure in the system. With
conventional
PCP completions this "u-tubing" fluid column acts on the rotor with a very
high
pressure. This pressure will force the rotor / rod string to rotate inside the
stator in the
opposite direction to the PCP's normal operational mode, a condition known as
"back-
spin". This is not desirable as it can damage the rod string or surface drive
equipment
and can take significant time to subside.
Furthermore, if sand or other solids have entered the upper stages of the PCP,
in
addition to refracting the rotor from the stator to clear any sand plug, there
will be a
2
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
requirement to pump fluids through the stator as the rotor is retracted to
flush out these
solids. These procedures are commonly known as "back-flush" or "flush-by"
operations. In order for these operations to be completed not only must the
rotor be
easily retractable, but also the integrity of the tubing string must be
maintained from
surface all the way to the stator. All aspects of these operations tend be
costly and time
consuming.
SUMMARY
Aspects of the present invention relate to a downhole tool and method and more
particularly, but not exclusively, to a downhole tool operatively associated
with a
downhole pump and method for use in artificial lift operations.
According to a first aspect, there is provided a downhole tool comprising:
a body having an axial flow passage therethrough, the downhole tool configured
to
permit selective fluid communication through the axial flow passage; and
a lateral flow passage disposed through the body,
wherein the downhole tool is operable between a first, closed, configuration
in which
fluid communication through the lateral flow passage is prevented and a
second, open,
configuration in which fluid communication through the lateral flow passage is
permitted, the downhole tool being configured to normally define the first,
closed,
configuration.
The downhole tool may comprise a valve arrangement configured to permit
selective
fluid communication through the axial flow passage. When the downhole tool
defines
the second, open, configuration permitting fluid communication through the
lateral
flow passage, the downhole tool may prevent fluid communication through the
axial
flow passage. Beneficially, such an arrangement permits fluid to be diverted
through
the lateral flow passage but prevent back-flow of fluid through the axial flow
passage.
The downhole tool may comprise a sleeve member. The sleeve member may be
operatively associated with the lateral flow passage. The downhole tool may be
3
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
configured so that in the first, closed, configuration, the sleeve member
prevents fluid
communication through the lateral flow passage. The downhole tool may be
configured
so that in the second, open, configuration the sleeve member permits fluid
communication through the lateral flow passage.
The downhole tool may be operable to move from the first, closed,
configuration to the
second, open, configuration in response to an activation event.
In use, the downhole tool may be run into a borehole, such as an oil and/or
gas
production well borehole, as part of a tubing string, the downhole tool being
configured
so that the valve arrangement permits selective axial passage of fluid through
the
downhole tool while lateral passage of fluid is prevented, the downhole tool
being
operable to move from the first, closed, configuration to the second, open,
configuration
in response to the activation event to divert fluid through the lateral flow
passage.
The activation event may take a number of different forms.
The activation event may comprise a force acting on the sleeve member.
The activation event may comprise a fluid pressure force acting on the sleeve
member.
The fluid pressure force may comprise a differential pressure force acting on
the sleeve
member, for example between fluid uphole of the sleeve member and fluid
downhole
of the sleeve member. In particular embodiments, the activation event may
comprise a
fluid pressure force acting on the sleeve member as a result of shut down of a
downhole
pump with which the downhole tool is operatively associated.
In use, the downhole tool may be operatively associated with a downhole pump
and the
valve arrangement of the downhole tool may be configured to permit fluid
passage from
the downhole pump towards surface or other uphole location via the axial flow
passage
while preventing back-flow. During such operations, the downhole tool is
configured
with the lateral flow passage in the closed configuration, maintaining
integrity of the
downhole tool and the associated tubing string. In the event pump operation
ceases,
the downhole tool may be operable to move to the second, open, configuration
to divert
fluid uphole of the valve arrangement through the lateral flow passage.
4
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
Embodiments of the present invention provide a number of benefits over
conventional
equipment and techniques.
For example, in situations where solids have settled and/or a sand plug has
formed
above the downhole pump, when the downhole pump is re-started it initially
runs dry ¨
since pressure gradually increases to the point at which the sand plug can be
dislodged.
However, due to the intimate contact between the pump's rotor and the stator,
this initial
period of dry operation can result in significant damage to the pump, and
associated
equipment.
In embodiments of the present invention, however, the ability to selectively
divert fluid
through the lateral flow passage facilitates increased run-life of an
associated downhole
pump by obviating damage that may otherwise occur from settlement of solids
and/or
the formation of a sand plug on top of the downhole pump when pump operation
ceases
or is insufficient to lift such solid material to surface.
Embodiments of the present invention further obviate the need to perform work-
over
operations, thereby providing significant cost and time saving benefits for an
operator
compared to conventional techniques and technology.
For example, when seeking to dislodge a sand plug, the conventional technique
is to
perform a work-over operation whereby the pump's rotor is retracted from the
stator,
allowing the sand and other solids to fall through the pump's stator back into
the
reservoir. In addition to retracting the rotor from the stator to clear the
solids/sand plug,
there is a requirement to flush out the solids through the stator as the rotor
is retracted,
known as a "back-flush" or "flush-by" operation. Such work-over operations
require
the rotor to be easily retractable, but also that the integrity of the tubing
string is
maintained from surface all the way to the stator.
In embodiments of the present invention, the ability to maintain tubing string
integrity
during normal operation and selectively divert fluid through the lateral flow
passage
obviates the requirement to perform such work-over operations.
5
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
Embodiments of the present invention may alternatively or additionally provide
a
number of other benefits.
For example, when operation of the downhole pump is stopped to perform a work-
over
operation, the large volume of fluid inside the tubing string will tend to
drop or "u-tube"
back down towards the static fluid level in the reservoir to equalise
pressure. With
conventional downhole pump equipment, this "u-tubing" fluid column acts on the
pump's rotor with a very high pressure, and forces the rotor to rotate inside
the stator
in the opposite direction to the pump's normal operational mode, a condition
known as
"back-spin". This is not desirable as it can damage the rod string or surface
drive
equipment and can take significant time to subside.
In embodiments of the present invention, however, this high pressure acts on
the sleeve
member to transition the downhole tool from the first configuration to the
second, open,
configuration; diverting the fluid into the annulus. A downhole tool according
to
embodiments of the present invention may thus facilitate increased pump run-
life by
obviating or mitigating back-spin of the pump, while supporting and
simplifying back-
flush operations, if required.
Still further, embodiments of the present invention may permit fluid to be
diverted back
to the formation via the annulus, facilitating increased pump run-life by
mitigating the
effects of over production and pump-off in which well fluids cannot permeate
through
the reservoir formation quickly enough to replace fluids that have been
produced to
surface and which results in the pump running dry, with consequential
significant
damage to the pump and associated equipment.
Moreover, embodiments of the present invention may support and simplify well
treatment operations to optimise or stimulate production, since the annulus
may
accessed via the lateral flow passage.
The activation event may alternatively or additionally comprise a fluid
pressure force
resulting from fluid directed through the axial flow passage from surface or
other
uphole location. This fluid may, for example but not exclusively, comprise a
well
treatment fluid or the like. Embodiments of the present invention thus support
chemical
6
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
treatment or injection operations without the need to perform work-over
operations,
such as retracting the pump's rotor from the stator described above.
As described above, the downhole tool may be configured to normally define the
first,
closed, configuration in which the sleeve member prevents fluid communication
through the lateral flow passage. In use, the downhole tool may be configured
to
automatically revert to its normal condition, that is, the first, closed,
configuration after
the fluid has been diverted through the lateral flow passage. This normal
condition of
the downhole tool may be achieved in a number of different ways. In some
embodiments, the downhole tool may be biased towards the first, closed,
configuration
by a biasing member operatively associated with the sleeve member. In use, the
biasing
member may be operable to act on the sleeve member to urge the sleeve member
axially
towards a position blocking the lateral flow passage (i.e., its normal
condition/position)
until the sleeve member is acted on by a force sufficient to overcome the
force exerted
by the biasing member (i.e., the activation event). The biasing member may
comprise
a spring element, such as a coil spring, an elastomeric element, a polymeric
element or
other element configured to bias the sleeve member.
Alternatively, or additionally, the downhole tool may be biased towards the
first, closed,
configuration, by fluid pressure. For example, the sleeve member may be
configured
so that an uphole-directed area of the sleeve member exposed to/communicating
with
an uphole fluid pressure ¨ and which results in a force urging the sleeve
member
towards the open configuration - is smaller than a downhole-directed area of
the sleeve
member exposed to/communicating with a downhole fluid pressure. Beneficially,
the
difference in areas biases or further biases the sleeve member towards closing
the lateral
flow passage under equal or substantially equal pressure conditions.
As described above, the sleeve member is operatively associated with the
lateral flow
passage.
The sleeve member may be generally tubular in construction.
In some embodiments, the sleeve member may comprise one or more lateral flow
passage, such as a lateral flow port. In such embodiments, the downhole tool
may be
7
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
configured to define the second, open, configuration by aligning the lateral
flow passage
of the sleeve member with the lateral flow passage of the downhole tool. In
particular
embodiments, the sleeve member may comprise a solid member i.e., not having a
lateral
flow passage.
The sleeve member may comprise a unitary construction.
In particular embodiments, the sleeve member may comprise a plurality of
components
coupled together. For example, the sleeve member may comprise an upper sleeve
member portion and a lower sleeve member portion. The upper sleeve member
portion
and the lower sleeve member portion may be coupled together by at least one of
a
mechanical coupling arrangement, such as threaded connection, a quick
connector, a
weld connection, an adhesive bond or other suitable coupling arrangement. The
upper
sleeve member portion and the lower sleeve member portion may be constructed
from
the same material or may be constructed from different materials.
The sleeve member may be configured for location within the body. In
embodiments
comprising the biasing member, the sleeve member may be coupled at its
downhole
end to the biasing member.
The downhole tool may comprise a stop, such as a no-go, which limits the
stroke of the
sleeve member in an uphole direction.
In use, the sleeve member is operatively associated with the lateral flow
passage and
normally adopts a position blocking the lateral flow passage until acted upon
by the
activation event, following which the sleeve member moves axially to permit
fluid to
be diverted via the lateral flow passage.
The lateral flow passage may comprise at least one lateral port. In use, the
lateral port
permits fluid communication between the axial flow passage and the annulus
between
the outside of the downhole tool and the borehole.
The lateral flow passage may comprise a single lateral port. In particular
embodiments,
the lateral flow passage may comprise a plurality of lateral ports. Where the
lateral
8
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
flow passage comprises a plurality of lateral ports, two or more of the
lateral ports may
be arranged circumferentially. Alternatively, or additionally, two or more of
the lateral
ports may be arranged axially.
The at least one lateral flow port may be of any suitable form. The at least
one lateral
flow port may be circular or oval in shape. In particular embodiments, the at
least one
lateral flow port may be rectangular or substantially rectangular in shape.
The valve arrangement may comprise a valve seat. The valve seat may be formed
on,
or coupled to, a tubular member which forms part of, or which is coupled to,
the body.
The tubular member may define a lateral flow passage. In use, the lateral flow
passage
of the tubular member may provide fluid communication between the axial flow
passage of the downhole tool and the sleeve member, in particular the downhole-
directed area of the sleeve member. The downhole tool may comprise one or more
fluid
gallery providing communication between the axial flow passage and the sleeve
member. As described above, the difference in areas of the sleeve member
biases or
further biases the sleeve member towards closing the lateral flow passage
under equal
or substantially equal pressure conditions, the fluid gallery facilitating
communication
of fluid to the downhole-directed area of the sleeve member so that both the
downhole-
directed area and the uphole-directed area of the sleeve member see the same
or
substantially the same pressure.
The lateral flow passage of the tubular member may comprise at least one
lateral port.
In use, the lateral port of the tubular member permits fluid communication
between the
axial flow passage and the flow gallery. The lateral flow passage of the
tubular member
may comprise a single lateral port. In particular embodiments, the lateral
flow passage
of the tubular member may comprise a plurality of lateral ports. Where the
lateral flow
passage of the tubular member comprises a plurality of lateral ports, two or
more of the
lateral ports may be arranged circumferentially. Alternatively, or
additionally, two or
more of the lateral ports may be arranged axially.
The valve seat may be configured to minimise or reduce erosion. For example,
the
valve seat may comprise, or provide mounting for, a hard faced material. The
hard
9
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
faced material may comprise tungsten carbide. Alternatively, or additionally,
a profile
of the valve seat may minimise or reduce friction.
At least one of the body and the valve seat may be configured to promote high
fluid
velocity around the valve seat in use. Beneficially, this further assists in
preventing or
at least mitigating the accretion of solids, such as sand in the downhole
tool.
The valve seat may be configured to receive a valve member, sealing engagement
between the valve member and the valve seat preventing fluid communication
through
the axial flow passage.
In use, the valve seat is operatively associated with the valve member, the
valve seat
configured to co-operate with the valve member to permit selective axial fluid
communication through the downhole tool. During artificial lift or other
pumping
operations, fluid may act on the valve member to unseat the valve member from
the
valve seat and permit axial fluid communication through the downhole tool. In
the
event pumping operations cease or where there is insufficient pressure to
unseat the
valve member, the valve member will engage the valve seat and prevent reverse
flow
through the downhole tool.
The downhole tool may comprise or may be operatively associated with the valve
member.
In some embodiments, the valve member may be coupled to the downhole tool. In
particular embodiments, however, the valve member may be disposed on or
coupled to
the downhole pump. The valve member may be disposed on, or form part of, a
rotor of
the downhole pump and in particular embodiments the valve member may be
disposed
on a rod string of the downhole pump.
The valve member may be axially moveable relative to the downhole pump. For
example, the valve member may be axially and/or rotatably moveably coupled to
the
downhole pump. In use, the valve member may be axially moveable relative to
the
downhole pump, in particular axially moveable relative to the rod string, in
response to
fluid flow output from the downhole pump.
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
In particular embodiments, the valve member may comprise a floating valve
member.
The valve member may be freely moveable relative to the body of the downhole
tool.
The valve member may be freely axially moveable relative to the body of the
downhole
tool. The valve member may be freely rotatably moveable relative to the body
of the
downhole tool. A valve member according to embodiments of the present
invention
has a number of benefits. For example, since the valve member is freely
moveable and
does not require any latching or unlatching mechanism to operate, the valve
arrangement can move between closed and open configuration repeatedly and/or
without the requirement to perform a work-over operation to latch/unlatch the
valve
member.
The valve member may take a number of different forms.
The valve member may comprise a body portion configured to engage the valve
seat.
The valve member body portion may be tubular in construction.
The valve member may comprise a centraliser portion. The centraliser portion
may be
formed on, or coupled to, the body portion of the valve member. The
centraliser portion
may be configured to engage the tubular member of the downhole tool.
In particular embodiments, the valve member may comprise a first valve member
body
portion and a second valve member body portion. The first valve member body
portion
and the second valve member body portion may be configured for coupling
together.
The first valve member body portion and the second valve member body portion
may
be configured for coupling by at least one of a mechanical coupling
arrangement, such
as threaded connection, a quick connector, a weld connection, an adhesive bond
or other
suitable coupling arrangement. In use, the first valve member body portion may
define
an upper body portion of the valve member. The first body portion may be
configured
to engage the valve seat. In use, the second valve member body portion may
define a
lower body portion of the valve member. The second valve member body portion
may
comprise, or in particular embodiments may provide mounting for, the
centraliser
portion of the valve member. Beneficially, the valve member may act as a
centraliser
or guide for the rod string.
11
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
At least one ofthe valve member body portion and the valve member centraliser
portion
may comprise a channel to facilitate passage of fluid.
The body may comprise a unitary component.
Alternatively, the body may comprise a plurality of body portions.
The body may comprise a first body portion. The first body portion may define
an
upper housing of the downhole tool. The first body portion may be tubular. The
lateral
flow passage may be formed in the first body portion.
The body may comprise a second body portion. The second body portion may
define a
lower housing of the downhole tool.
The downhole tool may comprise, or may be configured to couple to, a top sub.
The
top sub may comprise a third body portion of the body.
The downhole tool may comprise, or may be configured to couple to, a bottom
sub.
The bottom sub may comprise a fourth body portion of the body.
The top sub, upper housing portion, flow tube and bottom sub may together form
the
axial flow passage of the downhole tool.
As described above, the downhole tool may be operatively associated with a
downhole
pump.
The downhole pump may take a number of different forms. In particular
embodiments,
the downhole pump may comprise a positive displacement pump, such as a
progressive
cavity pump (PCP) or the like. The downhole tool may form part of a downhole
pump
assembly comprising a downhole pump. The downhole tool may be configured to be
coupled to the downhole pump. In particular embodiments, the downhole tool may
be
configured to be coupled to a stator housing of the downhole pump.
The downhole tool may comprise a connection arrangement for coupling the
downhole
tool to a tubular string. The connection arrangement may comprise a connector
for
coupling the downhole tool to an uphole component of the tubular string. In
some
12
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
embodiments, the connector for coupling the tool to an uphole component of the
tubular
string may be integral to the body. In particular embodiments, the connector
for
coupling the tool to an uphole component of the tubular string may comprise a
separate
component, in particular but not exclusively a top sub or the like.
The connection arrangement may comprise a connector for coupling the tool to a
downhole component of the tubular string. In some embodiments, the connector
for
coupling the tool to a downhole component of the tubular string may be
integral to the
second member. In particular embodiments, the connector for coupling the tool
to a
downhole component of the tubular string may comprise a separate component, in
particular but not exclusively a bottom sub or the like.
At least one of the uphole connector and the downhole connector may comprise a
threaded connector or the like. At least one of the uphole connector and the
downhole
connector may comprise a threaded box connector. At least one of the uphole
connector
and the downhole connector may comprise a threaded pin connector.
The axial flow passage may comprise a throughbore of the downhole tool.
According to a second aspect, there is provided a method comprising:
providing a downhole tool comprising: a body having an axial flow passage
therethrough, the downhole tool configured to permit selective fluid
communication
through the axial flow passage; and a lateral flow passage disposed through
the body;
and
operating the downhole tool between a first, closed, configuration in which
the
downhole tool prevents fluid communication through the lateral flow passage
and a
second, open, configuration in which the downhole tool permits fluid
communication
through the lateral flow passage.
The downhole tool may comprise a valve arrangement configured to permit
selective
fluid communication through the axial flow passage. When the downhole tool
defines
the second, open, configuration permitting fluid communication through the
lateral
13
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
flow passage, the downhole tool may prevent fluid communication through the
axial
flow passage. Beneficially, such an arrangement permits fluid to be diverted
through
the lateral flow passage but prevent back-flow of fluid through the axial flow
passage.
The downhole tool may comprise a sleeve member. The sleeve member may be
operatively associated with the lateral flow passage. The downhole tool may be
configured so that in the first, closed, configuration, the sleeve member
prevents fluid
communication through the lateral flow passage. The downhole tool may be
configured
so that in the second, open, configuration the sleeve member permits fluid
communication through the lateral flow passage.
The method may comprise running the downhole tool into a borehole as part of a
downhole tubing string.
The valve arrangement of the downhole tool may comprise, or may be operatively
associated with, a valve member and the method may comprise running the valve
member into the borehole. In some embodiments, the valve member may be run
into
the borehole with the downhole tool. In some embodiments, the valve member may
be
run into the borehole separately from the downhole tool. For example, the
valve
member may be run into the borehole on a rotor or rod string of a downhole
pump to
which the downhole tool is coupled or operatively associated.
The method may comprise directing a treatment fluid from surface or other
location
upho le of the downhole tool.
According to a third aspect, there is provided a downhole tool comprising:
a body having an axial flow passage therethrough, the downhole tool configured
to
permit selective fluid communication through the axial flow passage; and
a lateral flow passage disposed through the body,
wherein the downhole tool is operable between a first, closed, configuration
in which
the downhole tool prevents fluid communication through the lateral flow
passage and
a second, open, configuration in which the downhole tool permits fluid
communication
14
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
through the lateral flow passage, and wherein the downhole tool comprises or
is
operatively associated with a valve member freely axially moveable relative to
the
body.
The downhole tool may comprise a valve arrangement configured to permit
selective
fluid communication through the axial flow passage. When the downhole tool
defines
the second, open, configuration permitting fluid communication through the
lateral
flow passage, the downhole tool may prevent fluid communication through the
axial
flow passage. Beneficially, such an arrangement permits fluid to be diverted
through
the lateral flow passage but prevent back-flow of fluid through the axial flow
passage.
The downhole tool may comprise a sleeve member. The sleeve member may be
operatively associated with the lateral flow passage. The downhole tool may be
configured so that in the first, closed, configuration, the sleeve member
prevents fluid
communication through the lateral flow passage. The downhole tool may be
configured
so that in the second, open, configuration the sleeve member permits fluid
communication through the lateral flow passage.
According to a fourth aspect, there is provided a method comprising:
providing a downhole tool comprising: a body having an axial flow passage
therethrough, the downhole tool configured to permit selective fluid
communication
through the axial flow passage; and a lateral flow passage disposed through
the body;
and
operating the downhole tool between a first, closed, configuration in which
the
downhole tool prevents fluid communication through the lateral flow passage
and a
second, open, configuration in which the downhole tool permits fluid
communication
through the lateral flow passage, wherein the downhole tool comprises or is
operatively
associated with a valve member freely axially moveable relative to the body.
The downhole tool may comprise a valve arrangement configured to permit
selective
fluid communication through the axial flow passage. When the downhole tool
defines
the second, open, configuration permitting fluid communication through the
lateral
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
flow passage, the downhole tool may prevent fluid communication through the
axial
flow passage. Beneficially, such an arrangement permits fluid to be diverted
through
the lateral flow passage but prevent back-flow of fluid through the axial flow
passage.
The downhole tool may comprise a sleeve member. The sleeve member may be
operatively associated with the lateral flow passage. The downhole tool may be
configured so that in the first, closed, configuration, the sleeve member
prevents fluid
communication through the lateral flow passage. The downhole tool may be
configured
so that in the second, open, configuration the sleeve member permits fluid
communication through the lateral flow passage.
It should be understood that the features defined above in relation to any
aspect,
embodiment or arrangement or described below in relation to any specific
embodiment
or arrangement 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 THE DRAWINGS
These and other aspects of the present invention will now be described, by way
of
example only, with reference to the accompanying drawings, in which:
Figure 1 shows a downhole tool according to an embodiment of the present
invention,
the downhole tool forming part of a downhole pump assembly;
Figure 2 shows a side view of the downhole tool shown in Figure 1;
Figure 3 is a longitudinal cut away view of the downhole tool shown in Figure
2;
Figure 4 is an enlarged view of an uphole section of the downhole tool shown
in Figure
3;
Figure 5 is an enlarged view of the downhole section of the downhole tool
shown in
Figure 3;
Figure 6 is a longitudinal section view of the downhole tool;
16
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
Figure 7 is a perspective view of a valve member for use with the downhole
tool shown
in Figures 1 to 6;
Figure 8 is a side view of the valve member shown in Figure 7;
Figure 9 is a section view of the valve member shown in Figures 7 and 8;
Figure 10 is a longitudinal cut away view of the downhole tool, in a first
configuration
and with the axial flow passage closed;
Figure 11 is an enlarged view of part of the downhole tool shown in Figure 10,
in the
first configuration and with the axial flow passage closed;
Figure 12 is a longitudinal cut away view of the downhole tool, in the first
configuration
and with the axial flow passage open;
Figure 13 is an enlarged view of part of the downhole tool shown in Figure 12,
in the
first configuration and with the axial flow passage open;
Figure 14 is a longitudinal cut away view of the downhole tool, in a second
configuration; and
Figure 15 is an enlarged view of part of the downhole tool shown in Figure 13,
in the
second configuration.
DETAILED DESCRIPTION
Referring first to Figure 1 of the accompanying drawings, there is shown a
diagrammatic view of a downhole tool 10 according to the present invention. In
use,
the downhole tool 10 is run into a borehole, such as an oil and/or gas
production well
borehole B, as part of a tubing string S, the downhole tool 10 being
configured to permit
selective axial passage of fluid through the downhole tool 10 while lateral
passage of
fluid is prevented, the downhole tool 10 being operable to move from a first,
closed,
configuration to a second, open, configuration in response to an activation
event to
divert fluid through the lateral flow passage into an annulus A between the
downhole
tool 10 and the borehole B.
17
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
As shown in Figure 1, the downhole tool 10 is operatively associated with a
downhole
pump P, in the illustrated embodiment a progressive cavity pump having a pump
stator
PS and a pump rotor PR, and as will be described further below, the downhole
tool 10
is configured to permit fluid passage from the downhole pump P towards surface
or
other uphole location via the axial flow passage while preventing back-flow
and
preventing lateral flow. In the event pump operation ceases, the downhole tool
10 is
operable to move from the first, closed configuration to the second, open,
configuration
to divert fluid uphole of the downhole tool 10 to the annulus A.
Reference is now made to Figures 2 to 6 of the accompanying drawings. Figures
2 and
3 show side and longitudinal cut away views, respectively, of the downhole
tool 10
shown in Figure 1, while Figures 4 and 5 show enlarged views of uphole and
downhole
sections of the downhole tool 10. Figure 6 shows a longitudinal section view
of the
downhole tool 10 in isolation for ease of reference.
The downhole tool 10 has a body 12 having a throughbore 14 which forms an
axial
flow passage of the downhole tool 10 and a plurality of circumferentially
arranged
lateral ports 16 which form a lateral flow passage of the downhole tool 10.
The
downhole tool 10 further comprises a valve seat 18 and a sleeve member 20.
In use, the downhole tool 10 is run into a well borehole B as part of a
downhole tubing
string S, the valve seat 18 co-operating with a valve member 22 (as will be
described
further below) to provide selective fluid communication through the
throughbore 14 of
the downhole tool 10 and the sleeve member 20 being operable to provide
selective
fluid communication through the ports 16 between the throughbore 14 and the
annulus
A between the downhole tool 10 and the borehole B.
In the illustrated embodiment, the downhole tool 10 comprises a top sub 24, a
body 26
comprising an upper housing portion 28 and a bottom housing portion 30, and a
bottom
sub 32.
Figure 4 of the accompanying drawings shows an enlarged view of an upper
portion of
the downhole tool 10. As shown in Figure 4, the top sub 24 is generally
tubular in
construction and forms the uphole end of the downhole tool 10 in use (left end
as shown
18
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
in Figure 4). The top sub 24 defines a threaded box connector 34 at its upper
end for
coupling the downhole tool 10 to an adjacent uphole tool, tubing section or
component
S1 of the string S. It will be understood that while in the illustrated
embodiment the
top sub 24 defines threaded box connector 34, the top sub 24 may alternatively
define
a threaded pin connector or any other suitable connector. A lower end portion
36 of the
top sub 24 is recessed and is configured to engage an upper end portion 38 of
the upper
housing portion 28 via a thread connection 40, the top sub 24 and the upper
housing
portion 28 being secured via a number of circumferentially arranged set screws
42. A
groove 44 is also formed in the outer surface of lower end portion 36 and a
seal element
in the form of o-ring seal 46 is disposed in the groove 44.
The upper housing portion 28 is also generally tubular in construction, the
upper end
portion 38 of the upper housing portion 28 being disposed on the lower end
portion 36
of the top sub 24 while a lower end portion 46 of the upper housing portion 28
is
recessed and is configured to engage an upper end portion 48 of the lower
housing
portion 30 via a thread connection 50, the upper housing portion 28 and the
lower
housing portion 30 being secured via a number of circumferentially arranged
set screws
52. A groove 54 is also formed in the outer surface of lower end portion 46 of
the upper
housing portion 26 and a seal element in the form of o-ring seal 56 is
disposed in the
groove 54.
Figure 5 of the accompanying drawings shows an enlarged view of a lower
portion of
the downhole tool 10. As shown in Figure 5, the lower housing portion 30 is
also
generally tubular in construction, a lower end portion 58 of the lower housing
portion
is disposed on a recessed upper end portion 60 of the bottom sub 32 and is
configured
to engage the upper end portion 58 of the bottom sub 32 via a thread
connection 62, the
25 lower housing portion 30 and the bottom sub 32 secured via a number of
circumferentially arranged set screws 64.
The bottom sub 32 is generally tubular in construction and forms the downhole
end of
the downhole tool 10 in use (right end as shown in Figures 2 to 6). The bottom
sub 32
defines a threaded pin connector 66 at its lower end for coupling the downhole
tool 10
30 to an adjacent downhole tool, tubing section or component S2 of the
string S. It will be
19
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
understood that while in the illustrated embodiment the bottom sub 32 defines
threaded
pin connector 66, the bottom sub 32 may alternatively define a threaded box
connector
or any other suitable connector. A groove 68 is also formed in the outer
surface of the
upper end portion 60 of the bottom sub 32 and a seal element in the form of o-
ring seal
70 is disposed in the groove 68.
As shown in Figure 5 and 6 and referring again also to Figure 3 of the
accompanying
drawings, it can be seen that an inner surface of the bottom sub 32 is
recessed and
provides mounting for a tubular member in the form of flow tube 72, the flow
tube 72
coupled to the bottom sub 32 via a thread connection 73. As shownõ the flow
tube 72
extends in an uphole direction (to the left as shown in Figure 3) and the
upper end of
the flow tube 72 forms or provides mounting for the valve seat 18. A plurality
of
circumferential flow ports 74 ¨ which form a lateral flow passage of the flow
tube 72 -
provide fluid communication between the throughbore 14 and a flow gallery 75
which
communicates the fluid to the sleeve member 20.
The sleeve member 20 is disposed between the outside of the flow tube 72 and
the
inside of the body 26. In the illustrated embodiment, the sleeve member 20
comprises
an upper sleeve member portion 76 and a lower sleeve member portion 78 coupled
together via a thread connection 80, although it will be understood that the
sleeve
member 20 may alternatively comprise a unitary construction. Grooves 82 are
disposed
in an inner surface of the sleeve member 20 and bushes ¨ in the illustrated
embodiment
in the form of PTFE bushes 84 - are disposed in the grooves 82. It will be
understood
that seal elements, such as o-ring seals, may alternatively or additionally be
provided
between the sleeve member 20 and the flow tube 72. In use, the bushes 84
provide
sealing and sliding engagement between the sleeve member 20 and the flow tube
72.
A groove 86 is also provided in an outer surface of the sleeve member 20 and a
seal
element in the form of an o-ring seal 88 is disposed in the groove 86. In use,
the seal
88 provides sealing between the sleeve member 20 and the body 26. It will be
understood that bushes, such as PTFE bushes, may alternatively or additionally
be
provided between the outer surface of the sleeve member 20 and the body 26.
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
A spring element 90 which forms a biasing member of the downhole tool 10 is
also
provided, the spring element 90 ¨ in the illustrated embodiment a coil spring
¨ is
secured at its lower end to the bottom sub 32 and at its upper end to the
sleeve member
20. In use, the spring element 90 biases the sleeve member 20 to the position
shown in
Figure 2, in which the lateral flow ports 16 are closed.
Referring now also to Figures 7, 8 and 9 of the accompanying drawings, the
valve
member 22 takes the form of a floating shuttle valve member 22 having a valve
member
top sub 92 which forms a body portion of the valve member 22 and a valve
member
bottom sub 94 which provides mounting for a centraliser portion 96 of the
valve
member 22 in use. The valve member top sub 92 and the valve member bottom sub
94
are coupled together via a threaded connection 98.
The valve member top sub 92 is generally tubular in construction and in the
illustrated
embodiment has an integral hard-faced valve surface 100 with a profile
configured to
match the valve seat 18 provided on the flow tube 72. A collar 102 is located
around
the top sub 90 and retained by a retention cap 104 that is connected to the
top sub 92
via a threaded connection 106, the collar 102 being free to rotate. Two
tubular rod
bushes (rod guides) 108 are provided, the bushes 108 retained by the base and
the
retention cap 104.
The valve member bottom sub 94 is also generally tubular in construction, and
as
described above provides mounting for the centraliser portion 96 having blades
110 for
engaging the inside of the flow tube 72.
In use, the valve member 22 is disposed on a rod string 112, which in the
illustrated
embodiment comprises a polished rod assembly comprises a short length of API
polished rod connected to sucker rod couplings 114 (shown in Figure 3) top and
bottom
via threaded connections (not shown).
As will be described further below, the valve member 22 and the rod string 112
are
deployed and positioned above the rotor PR of the downhole pump P. The valve
member 22 is free to move rotationally and axially along the polished rod (as
far as the
adjacent couplings) of the rod string 112, the rod string 112 sized so that
once the rod
21
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
string 112 has been run to depth and the rotor PR is located within the stator
PS of the
downhole pump P, the valve member 22 and rod string 112 are located within the
body
24 of the downhole tool 10.
Operation of the downhole tool 10 will now be described with reference to all
of the
accompanying drawings and in particular to Figures 10 to 15.
As shown in Figures 10 and 11, the downhole tool 10 is run into the borehole B
with
the tubing string S. As discussed above, during run in and under
static/equalised
pressure conditions, the lateral ports 16 that allow communication between the
throughbore 14 and the annulus A remain closed, maintaining integrity of the
string S.
This allows the operator to run a conventional tubing string in place of the
valve
member 22 and rod string 112 and produce the well should this be required.
When the pump P is switched on, the flow pressure will act on the valve member
22,
moving the valve member 22 uphole from the position shown in Figures 10 and 11
to
the position shown in Figures 12 and 13, to permit passage of well fluids up
the tubing
string S. It will be recognised, however, that the lateral ports 16 remain
closed.
If the pump P is switched off, the flow pressure will equalise allowing the
valve member
22 to move downhole from the position shown in Figures 12 and 13 back to the
position
shown in Figures 10 and 11. The valve member 22 will re-seat, shutting off any
back
flow through the pump P.
It will be recognised that the valve member 22 does not require any latching
mechanism, and so the above process may be repeated as often as required.
With the pump P non-operative, the differential head in the tubing string S
causes the
fluid in the upper string to 'u-tube', the resulting pressure acting on the
sleeve member
20 which will move downward, opening the lateral ports 16 and diverting the 'u-
tubing'
fluid into the annulus A, along with any entrained solids where they can be
transported
back to the reservoir (not shown). Beneficially, this prevents any solids from
building
up on top of the pump P and also prevents backspin from occurring.
22
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
Once the differential head in the tubing string S has equalised with the
static well
pressure or has dropped below a pre-defined level, the sleeve member 20 will
move
upward automatically, closing off the lateral ports 16 and re-instating
integrity of the
tubing string S. As described above, the bottom sealing area of the sleeve
member is
larger than the top sealing area, thus given a static pressure across the
sleeve member
20, the sleeve member 20 is biased in the "annular ports closed" position due
to static
pressure, as well as being mechanically biased by the coil spring.
In situations where the well is at risk of being over-produced, as soon as
fluid inflow at
the pump P ceases, the resulting pressure differential in the tubing string S
will act to
close off backflow through the pump P and open the lateral ports 16. The fluid
column
is again diverted into annulus A and back down to the reservoir preventing the
pump P
from running dry and mitigating pump-off conditions. Again, once pressure has
equalised, the lateral ports 16 automatically close, re-establishing integrity
of the tubing
string S.
Should a back-flush requirement arise, the operator will stop the pump P and
then
retract the pump rotor PR from the pump stator PS. As the pump rotor PR is
retracted
through the valve member 22, the valve member 22 engages and is lifted from
the valve
seat 18 by a rod string coupling (not shown) and the back-flush operation can
commence.
On completion of the back-flush operation, as the pump rotor PR is run back to
depth,
the valve member 22 will re-seat separating the pump rotor PR / pump stator PS
from
the upper portion of tubing string S. Pump operation can then recommence as
normal.
Should a chemical injection requirement arise, the operator simply pumps the
injected
chemicals down the tubing string S without retracting the pump rotor PR. The
pumped
fluids act on the downhole tool 10, axially moving the sleeve member 20 to
open the
lateral ports 16, to permit the injection fluids to be pumped in to the
annulus A and
down into the reservoir. Once pumping is complete the lateral ports 16
automatically
close reinstating integrity of the tubing string S.
23
CA 03004149 2018-05-03
WO 2017/077003
PCT/EP2016/076609
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.
This written description uses examples to disclose the invention, including
the preferred
embodiments, and also to enable any person skilled in the art to practice the
invention,
including making and using any devices or systems and performing any
incorporated
methods. The patentable scope of the invention is defined by the claims, and
may
include other examples that occur to those skilled in the art. Such other
examples are
intended to be within the scope of the claims if they have structural elements
that do
not differ from the literal language of the claims, or if they include
equivalent structural
elements with insubstantial differences from the literal languages of the
claims.
Aspects from the various embodiments described, as well as other known
equivalents
for each such aspects, can be mixed and matched by one of ordinary skill in
the art to
construct additional embodiments and techniques in accordance with principles
of this
application.
24
