Note: Descriptions are shown in the official language in which they were submitted.
MODIFIED DOWNHOLE ISOLATION TOOL HAVING
A SEATING MEANS AND PORTED SLIDING SLEEVE
FIELD OF THE INVENTION
The invention relates to a downhole tool and more specifically to an improved
downhole tool having a seating means and a modified ported sliding sleeve and
seal sub.
BACKGROUND OF THE INVENTION AND DESCRIPTION OF THE PRIOR ART
Normally, when a downhole pump is to be removed for servicing or replacement,
the well must be "killed" (i.e. prevent the well from flowing). The downhole
tool of the
present invention allows for direct sealing attachment to a downhole assembly
in order
for the well to be temporarily sealed downhole to allow the removal of a
downhole pump
for servicing or replacement without the need to remove the downhole assembly
(e.g. a
gas separator).
Specifically, when extracting hydrocarbons from production wells drilled into
hydrocarbon formations, it is a safety and regulatory requirement that
pressurized fluids
and/or gases coming from the drilled well (e.g. sour gases), be isolated from
surface to
thereby prevent their escape to atmosphere at the surface of the well.
Accordingly, downhole pump assemblies typically possess seal rings, which
when the pump is installed in the operative position, typically engage
circumferential seals
within the casing or tubing in which the downhole pump assembly was placed and
positioned, thereby preventing pressurized fluids and/or gases from flowing to
surface
except through the pump and thereby through the production tubing.
However, any raising of the downhole pump for the purposes of repair or
replacement, as taught in the prior art, necessarily disengages the sealing
rings, thereby
releasing the downhole pressurized fluids and/or gases to surface.
To avoid this undesirable situation and to avoid communication with surface
when
a downhole pump assembly is being replaced, the prior art teaches that a well
be
effectively "killed" prior to pump removal, typically by pumping viscous
fluids downhole to
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temporarily seal the well prior to blowout preventer installation and the pump
being
removed.
The process of "killing" a well each time to service downhole components is
costly
and time-consuming. Additionally, in some instances, the "killing" process may
be too
effective where it becomes difficult, and sometimes impossible, to later
"restore" the well
by removing the viscous fluids. Therefore, a well that is temporarily killed
may
unintentionally be permanently killed or unable to be brought back on-stream
as
effectively as before.
In heavy oil formations, where the produced oil contains large amounts of
abrasive sand, wear on the pumps is extensive. This results in the necessity
to frequently
replace the pumps. As described above, replacing the pumps results in the
undesirable
need in the prior art to "kill" the well so that pressurized fluids and/or
gases deep in the
formation are not otherwise allowed to flow directly to surface.
Applicant's commonly- assigned US Patent No. 8,893,776 disclosed a pump
assembly for removing hydrocarbons from downhole wells without the need to
"kill" the
well. The apparatus disclosed therein involved a ported sleeve whereby in an
operative
first position, fluid is drawn from the well through a first port means in the
sidewall of the
sleeve, through the hollow interior of the sleeve, and out of the sleeve into
the production
tubing through a second port means near the upper end. In a closed second
position,
the ported sleeve shifts upwardly to position the first port means between two
sets of seal
means within a seal sub that surrounds the ported sleeve, thus sealing off the
flow of fluid
upwards in the well by preventing access to the lower (first) sidewall port
means.
In an alternative design, Applicant's commonly-assigned US Patent
No. 8,889,316 disclosed a downhole isolation tool having a ported sliding
sleeve that is
slidably positioned within a seal sub that has a port means. In an operative
first position,
the sliding sleeve is positioned within a bore of the seal sub such that an
aperture means
in the sidewall of the sleeve is aligned with the port means on the seal sub,
allowing fluids
to pass from an exterior surface of the seal sub into an elongate cavity
within the sleeve.
The fluids pass through a hollow internal cavity in the sleeve and out into
the production
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tubing through a second aperture means near the upper end. In a closed second
position,
the sliding sleeve is moved upwards such that a seal member within the sliding
sleeve is
aligned with the port means on the seal sub, blocking fluids from the
surrounding exterior
from entering the sleeve.
These downhole tools provide significant benefits in downhole drilling
operations
for reasons described above in avoiding the need to "kill" the well prior to
pump removal.
The isolation tools are particularly well suited for sealing the flow of oil
and gas through
production tubing and permitting removal of a pump for repair or replacement.
In oil and gas reservoirs, petroleum oil is frequently found in intimate
association
with natural gas and water. Natural gas may, for instance, be in the form of
free gas
bubbles entrained in the oil and/or in the form of dissolved gas in the oil.
Thus, well fluids
commonly comprise both liquids and gas. In wells where artificial lift
(pumping) is
necessary, the presence of a gas-liquid mixture can materially affect the
efficiency of the
pumping operations. For example, gas presence in the pumping zone can cause
problems such as gas lock, gas pound and gas interference.
Specifically, the presence of gas can reduce pump efficiency because, when gas
enters the pump with oil, gas causes many pump problems. It may pocket around
the
pump or accumulate inside the pump and "gas lock" the valves. "Gas pound" can
occur
when the gas breaks out of solution and occupies a part of the pump intake
chamber.
The pump plunger will compress the gas during the down stroke and then contact
the
fluid. The presence of gas provides some amount of cushion, but the pump can
still
experience a sudden shock upon striking the fluid, causing "gas pound"
followed by "fluid
pound". This phenomenon can cause significant damage to the pump assembly and
rod
string, such as rod buckling, rods rubbing against the tubing causing leaks
and, in severe
conditions, the splitting of the barrel and/or cages. Attacking downhole gas
can reduce
pump failures and maximize pump efficiency.
Specialized production equipment is commonly used in oil wells to mitigate
damage. In wells where bubbles of gas are present, it is known in the art to
use a gas
separator (a.k.a. degasser, gas anchor or gas break assembly) to continuously
separate
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the gas from the liquids before the liquid enters the inlet of the pump ¨ the
liquids being
directed to the suction inlet of the pump and the gas being directed to the
casing annulus.
Therefore, the gas separator is typically fluidly coupled to the suction inlet
of the rod pump,
and is therefore located immediately below the rod pump. The efficiency of the
separation
of liquid and gas by the gas separator is an important aspect of gas separator
design,
and no gas separator is totally effective in this separation process. Thus,
pump repair or
replacement is still often required.
Moreover, gas separators frequently become plugged themselves and require
that the entire gas separator assembly, or components thereof, be removed from
the well
for cleaning. This is particularly the case in wells drilled in heavy oil
formations, where
.. the produced oil contains large amounts of abrasive sand. It is not
uncommon for sand
to plug the inlet slots of the dip tube of a gas separator assembly, thereby
necessitating
removal and cleaning or replacement of the gas separator. Similar to the
removal of a
pump for repair or replacement, replacing the gas separator results in the
undesirable
need to "kill" the well so that pressurized fluids and/or gases deep in the
formation are not
otherwise allowed to flow directly to surface.
In wells equipped with such equipment (e.g. a gas separator) a real need
exists
for a specialized apparatus and method that is directly compatible with the
downhole
assemblies and which allows for removing worn or defective pumps without the
need to
first "kill" the well, and/or is able to avoid the undesirable release of
pressurized fluids
and/or gases from within the formation to surface via the open well. A need
also exists
for a downhole tool that permits the cleaning of a downhole assembly, e.g. a
gas
separator, without the need to remove the assembly and "kill" the well.
SUMMARY OF THE INVENTION
In order to provide certain advantages over the prior art, it is an object of
the
present invention to provide a downhole isolation tool which is capable of
direct seating
and sealing engagement to a downhole assembly, such as a gas separator, and
which
avoids having to otherwise "kill" the well when a downhole pump is desired to
be detached
from the downhole assembly and removed from the well for repair or replacement
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It is a further object of the present invention that the isolation tool be
configured
with a fluid flow path sufficient for functioning of the downhole assembly in
an operative
position, but which fluid flow path can be altered in a manner that avoids
downhole
pressures in a hydrocarbon formation from being exposed to surface when
desired.
It is a further object of the present invention to allow for fluid in a
downhole
assembly, such as a gas separator, to be "shut in" within the assembly itself
(i.e. not
upwardly in production tubing), without breaking wellhead containment when a
downhole
pump is desired to be removed from the well for repair or replacement.
It is a further object of the invention to provide a downhole isolation tool
capable
of being positioned immediately adjacent, and in seated and sealed engagement
with, a
downhole assembly, such as a gas separator, whereby the tool is capable of
acting as a
fluid flow "stop-gate" between the downhole assembly and other equipment, such
as a
pump. For instance, in certain situations it may be desirous to prevent flow-
through
between a gas separator and a pump, even when the pump is not being removed
for
repair or replacement. This might involve a situation where it is desirous to
avoid gas
lock and/or gas pound when the gas separator is not capable handling the level
of gas
interference, but high pressure has built up in the well.
It is a further object of the invention to provide a downhole isolation tool
to save
rig time in respect of wells containing specialized downhole equipment, such
as a gas
separator, by eliminating time which would otherwise be required to "kill" the
well prior to
removal of a downhole pump, and to otherwise restore the rig to operation when
the
downhole pump assembly is reinserted and the well is desired to then be
restored and
brought back "on-line".
It is a further object of the invention to provide a downhole isolation tool
that can
be utilized in association with a downhole pump to permit cleaning of a
plugged gas
separator. In such mode of operation, by optimal configuration of the flow
path through
the downhole tool and by its seating and sealing engagement directly to a gas
separator,
the pump could be unseated and a reverse flush can be used to "flush" the gas
separator
(e.g. flush sands and other accumulation out of the gas separator and back
into the well).
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The seated and sealed engagement of the downhole tool directly with the gas
separator
would allow increased pressure to build up in the gas separator, while
preventing
exposure to the production tubing to the increased pressures. For instance,
sealed
engagement to the gas separator prevents pressure escaping into the production
tubing.
Also, after reverse flush, the downhole tool could be immediately adjusted to
a closed
configuration to hold the increased pressure within the gas separator for an
extended
period to effectively clear the plug. This operation would advantageously
avoid the prior
art need to remove the gas separator, or components thereof, for cleaning when
the gas
separator becomes plugged (e.g. with sand).
It is yet a still-further object of the present invention to provide a
downhole
isolation tool which allows unseating of a rod insert pump or other pump
regardless of
downhole pressures or temperatures at a downhole assembly, such as a gas
separator.
It is yet a still-further object of the present invention to provide a
downhole
isolation tool which, by direct seating and sealing engagement to a gas
separator, permits
a pump to be positioned higher in the well and away from the gas separator.
Typically,
in wells utilizing gas separators, reciprocating rod pumps are positioned
immediately
adjacent the gas separator to maintain unregulated downhole reservoir
pressures low in
the well during pumping. This results in the use of lengthy reciprocating rods
to extend
from the top of the well to the pump position. In wells with higher deviations
in gas-liquid
mixtures, this can be problematic for rod wear, e.g. long rods are more
susceptible to
damage and breaking. Advantageously, by utilizing a downhole tool of the
present
invention, unregulated downhole reservoir pressures can be handled by the
downhole
tool, thus allowing a pump to be positioned higher in the well and spaced away
from the
gas separator where deviations in gas-liquid are more pronounced. This should
advantageously reduce rod wear.
It is yet a still-further object of the present invention to provide a
downhole tool
that can be used in combination with Applicant's downhole tools disclosed in
US Patent
Nos. 8,893,776 and 8,889,316. For instance, it is a safety and regulatory
requirement
that wells with exceedingly high pressures have at least two barriers in place
to prevent
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pressurized fluids and/or gases from escaping into the atmosphere at the
surface of a
well. Commonly, a wireline plug may be used in such instances. However, the
downhole
tool of the present invention can advantageously be used in combination with a
downhole
tool of US Patent Nos. 8,893,776 and/or 8,889,316 to reversibly and
controllably seal a
wellbore at two distinct locations. The downhole tool of the present invention
may be
positioned low in the well attached to a downhole assembly to seal the well at
that
location, and a separate downhole tool could be used higher up in the
production tubing
of the well using Applicant's tools disclosed in US Patent Nos. 8,893,776 and
8,889,316.
Accordingly, in one broad aspect of the present invention, the invention
relates
to a downhole isolation tool adapted for insertion in a wellbore, which when a
component
thereof is positioned in a first position allows fluids within said wellbore
to be drawn
through said tool, and when said component is positioned in a second position
prevents
said fluids from passing therethrough and up the wellbore, comprising:
(A) an elongate sliding sleeve having an upper and lower end and an elongate
cavity therewithin separated into an upper cavity and a lower cavity by a seal
member
that prevents fluid communication between said upper and lower cavity, further
having:
(i) a releasable latch means at said upper end thereof, constructed and
arranged for releasibly coupling to a lower end of a pump apparatus;
(ii) an opening at said lower end to allow fluid communication between said
wellbore and said lower cavity;
(iii) a first aperture means, situated proximate said upper end, in fluid
communication with said upper cavity;
(iv) a second aperture means, situated above said seal member and
longitudinally separated from said first aperture means, likewise in fluid
communication with said upper cavity; and
(v) a third aperture means, situated below said seal member and in fluid
communication with said lower cavity;
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(B) an elongate seal sub, having an upper and lower end and a bore
therethrough
for slidably receiving therewithin said sliding sleeve and allowing slidable
movement
thereof from said first position to said second position, further having:
(i) a bypass channel, situated along said bore at a bore surface distal to
said upper and lower ends of said seal sub, and bounded by the sidewall of the
seal sub, thereby preventing fluid communication exterior to the seal sub from
the
bypass channel; and
(ii) a seating means capable of sealingly engaging said seal sub to an
assembly in the wellbore;
wherein said component is said sliding sleeve, and when said sliding sleeve is
in
said first position it is positioned within said bore so that said second and
third aperture
means, and said seal member, are aligned with said bypass channel in said seal
sub to
allow communication of fluids from said lower cavity to said upper cavity of
said sliding
sleeve via said bypass channel; and
when said sliding sleeve is in said second position, said first aperture means
and
said seal member are positioned towards said upper end of said seal sub, above
said
bypass channel, to thereby prevent communication of fluids from said lower
cavity to said
upper cavity of said sliding sleeve.
In a further refinement of the above embodiment, in said second position said
seal
member aligns with and engages a circumferential seal means in said bore of
said seal
sub, situated above said bypass channel.
In a further refinement of the above embodiments, said bypass channel is a
circumferential channel in the surface of the bore.
In a still further refinement of the above embodiments, said seating means is
situated on an exterior surface at said lower end of said seal sub. In a
further refinement,
said seating means is capable of sealingly engaging a circumferential seal
situated on a
seating surface of said assembly.
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In a still further refinement of the above embodiments, said assembly in said
wellbore is a gas separator assembly.
In a still further refinement of the above embodiments, said tool is adapted
to be
releasibly coupleable to a lower end of a pump apparatus when said sliding
sleeve is in
said first position, and when said sliding sleeve is in said second position
is adapted to
.. be decoupled from said lower end of said pump apparatus.
In a still further refinement of the above embodiments, movement limiting
means,
such as a stop means, may be provided to prevent further upward movement of
said
sliding sleeve within said bore upon said sliding sleeve being repositioned
from said first
position to said second position.
In a still further refinement of the above embodiments, said downhole tool is
further
provided with releasibly-engageable detent means, engageable when said sliding
sleeve
is in said second position to prevent or resist downward slidable movement of
said sliding
sleeve, and adapted to become disengaged upon said pump apparatus being
lowered
onto said downhole tool and said releaseable latch means, and said sliding
sleeve being
forced downwardly by said pump apparatus.
In a still further refinement of the above embodiments, said downhole tool is
further
provided with releasibly-engageable detent means engageable when said sliding
sleeve
is in said first position to prevent or resist further downward slidable
movement of said
sliding sleeve.
In a second broad aspect, the present invention relates to a method for
preventing
at least one of downhole fluids and gases in a hydrocarbon formation from
reaching
surface upon removal of a pump apparatus from a wellbore, using a downhole
tool
comprising an elongate sliding sleeve and an elongate seal sub, comprising the
steps of:
(a) providing an elongate sliding sleeve having an elongate cavity
therewithin
separated into an upper cavity and a lower cavity by a seal member that
prevents
fluid communication between the upper and lower cavity, said upper cavity
having
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a first and second aperture therein and said lower cavity having a third
aperture
therein;
(b) providing an elongate seal sub having a bore therethrough and a bypass
channel situated along said bore;
(c) slidably inserting said elongate sliding sleeve within said bore of
said seal
sub to a first position where said second and third apertures, and said seal
member, are aligned with said bypass channel situated within said bore of said
seal sub to allow communication of fluids from said lower cavity to said upper
cavity
of said sliding sleeve by bypassing the seal member via said bypass channel;
(d) either before or after step (c), releasably coupling, via releasable
latch
means on an upper end of said sliding sleeve, said downhole tool to a lower
end
of a pump apparatus;
(e) inserting said downhole tool and pump apparatus downhole into a
wellbore;
(f) sealingly engaging said downhole tool and pump apparatus to an assembly
in said wellbore via a seating means situated on said seal sub;
(g) operating said pump apparatus;
(h) raising said pump apparatus and causing said sliding sleeve to be
slidably
re-located upwardly in said bore from said first position to a second position
where
said first aperture means and said seal member are positioned above said
bypass
channel in said bore of said seal sub, to thereby prevent communication of
fluids
from said lower cavity to said upper cavity of said sliding sleeve;
(i) pulling said pump apparatus upward so as to releasibly dis-engage latch
means on said sliding sleeve from said lower end of said pump apparatus; and
(j) removing said pump apparatus from said wellbore.
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In a further refinement of the above method, step (h) comprises slidably
relocating
said sliding sleeve upwards ,until said seal member aligns with and engages a
circumferential seal means in said bore of said seal sub.
In a further refinement, said method further comprises further utilizing stop
means
on said downhole tool to prevent further upward movement of said sliding
sleeve past
said second position.
In a further refinement, said method further comprises after step (j), the
steps of:
(k) lowering said pump assembly within said wellbore so as to cause said pump
apparatus
to push downwardly on said sliding sleeve; and (I) causing said sliding sleeve
to move
from said second position back to said first position.
In an third broad aspect, the present invention relates to a downhole
isolation tool
for insertion in a wellbore, which when configured to a first position allows
fluids within a
hydrocarbon formation to be drawn through said tool, and when configured to a
second
position prevents said fluids from passing therethrough and up the wellbore,
comprising:
(A) an elongate sliding sleeve having an upper and lower end and an elongate
cavity therewithin separated into an upper cavity and a lower cavity by a seal
member
that prevents fluid communication between said upper and lower cavity, further
having:
(i) a releasable latch means at said upper end thereof, constructed and
arranged for releasibly coupling pump apparatus;
(ii) an opening at said lower end to allow fluid communication between said
wellbore and said lower cavity;
(iii) a first aperture means, situated proximate said upper = end, in fluid
communication with said upper cavity;
(iv) a second aperture means, situated above said seal member and
longitudinally separated from said first aperture means, likewise in fluid
communication with said upper cavity;
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(v) a third aperture means, situated below said seal member and in fluid
communication with said lower cavity; and
(B) an elongate cylindrical seal sub, having an upper and lower end and, along
a
longitudinal axis of said seal sub, a bore therethrough for slidably receiving
therewithin
said sliding sleeve and allowing slidable movement thereof from said first
position to said
second position, further having:
(i) a bypass channel, situated along said bore at a bore surface distal to
said upper and lower ends of said seal sub, and bounded by the sidewall of the
seal sub, thereby preventing fluid communication exterior to the seal sub from
the
bypass channel; and
(ii) a seating means capable of sealingly engaging said seal sub to an
assembly in the wellbore;
wherein when said downhole tool is configured in said first position, said
sliding
sleeve is positioned within said bore so that said second and third aperture
means, and
said seal member, are aligned with said bypass channel in said seal sub to
allow
communication of fluids from said lower cavity to said upper cavity of said
sliding sleeve
via said bypass channel; and
wherein when said sliding sleeve is slidably moved upwardly so as to thereby
be
configured in said second position, said first aperture and said seal member
are
positioned above said bypass channel to thereby prevent communication of
fluids from
said lower cavity to said upper cavity of said sliding sleeve.
In a refinement of the above embodiment, in said second position said seal
member aligns with and engages a circumferential seal means in said bore of
said seal
sub, situated above said bypass channel.
In a further refinement of the above embodiments, said bypass channel is a
circumferential channel in the surface of the bore.
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In a further refinement of the above embodiments, said seating means is
capable
of sealingly engaging a circumferential seal situated on a seating surface of
said
assembly.
In a still yet further refinement of the above embodiments, said assembly in
said
wellbore is a gas separator assembly.
BRIEF DESCRIPTION OF THE DRAWINGS
Further advantages and permutations and combinations of the invention will now
appear from the above and from the following detailed description of the
various particular
embodiments of the invention taken together with the accompanying drawings,
each of
which are intended to be non-limiting, in which:
FIG. 1A is a cross-sectional view of a prior art downhole tubing assembly in
"top
hold down" configuration and having a seating surface;
FIG. 1B is a cross-sectional view of the prior art downhole tubing assembly of
Fig. 1A, with the downhole pump assembly partially removed;
FIG. 1C is a cross-sectional view of the downhole tubing assembly of the prior
art, with the pump and seating surface thereof removed from the well;
FIG. 2A is a cross-sectional view of an alternative prior art downhole tubing
assembly in "bottom hold down" configuration and;
FIG. 2B is a cross-sectional view of the prior art downhole tubing assembly of
Fig. 2A, with such prior art downhole assembly partially removed from the
well;
FIG. 2C is a cross-sectional view of the downhole tubing assembly of the prior
art
shown in Fig.s 2A-2B, with the pump removed for servicing or replacement;
FIG. 3A is a cross-sectional view of a prior art downhole ported sleeve, where
the sleeve is positioned in a first position allowing flow of hydrocarbons
into a first port
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.. means and out of a second port means so as to enable flow uphole to a pump
apparatus
or the like;
FIG. 3B is a cross-sectional view of the downhole ported sleeve shown in Fig.
3A,
where the sleeve is repositioned to a second position wherein the first port
means is
located in the seal sub and positioned between lower seal means and upper seal
means,
.. thereby preventing flow of hydrocarbons uphole;
FIG. 4 is a perspective view of the downhole ported sleeve only, which is
shown
in Fig.s 3A and 3B;
FIG. 5A is a cross-sectional view through another prior art downhole isolation
tool, where the sliding sleeve is positioned in a first position allowing flow
of hydrocarbons
into a second aperture, via a port in a seal sub, and out of a first aperture
therein so as to
enable flow uphole to a pump apparatus or the like;
FIG. 5B is a cross-sectional view of the downhole isolation tool shown in Fig.
5A,
where the sliding sleeve is repositioned to a second position wherein a seal
member
occupies the port in the seal sub and blocks the second aperture, thereby
preventing flow
of hydrocarbons uphole;
FIG. 6 is a perspective view of the sliding sleeve shown in Fig.s 5A and 5B;
FIG. 7A is a cross-sectional view through an embodiment of a downhole
isolation
tool of the present invention, where the sliding sleeve is positioned in a
first position
allowing hydrocarbons in a lower cavity to flow through second and third
aperture means,
via alignment with a bypass channel, thereby bypassing a seal member to access
an
upper cavity so as to enable flow uphole to a pump apparatus or the like;
FIG. 7B is a cross-sectional view of the downhole isolation tool of the
present
invention shown in Fig. 7A, where the sliding sleeve is repositioned to a
second position
wherein the second aperture and seal member are positioned above the bypass
channel,
blocking access to the upper cavity from the lower cavity, thereby preventing
flow of
hydrocarbons uphole;
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FIG. 8 is a perspective view of the sliding sleeve of the present invention
shown
in Fig.s 7A and 7B;
FIG. 9A is a cross-sectional view of a prior art gas separator;
FIG. 9B is a cross-sectional view of a prior art gas separator showing the
flow of
hydrocarbons through the separator;
FIG.10A is a side elevation cross-sectional view of a prior art gas separator
and
pump apparatus, affixed and installed downhole in an operative configuration.
FIG. 10B is a side elevation cross-sectional view of a prior art gas separator
and
pump apparatus, affixed and being removed from the well for repair,
replacement or
servicing (e.g. cleaning).
FIG. Ills a side elevation cross-sectional view of the downhole isolation tool
of
Fig.s 7A and 7B, affixed to a lower portion of a pump apparatus, and installed
downhole
in a well bore seated and sealingly engaged to a gas separator, when sliding
sleeve
thereof is in the first position;
FIG. 12 is a side elevation cross-sectional view of the downhole isolation
tool of
Fig.s 7A and 7B, affixed to a lower portion of a pump apparatus, and installed
downhole
in a well bore seated and sealingly engaged to a gas separator, when sliding
sleeve
thereof is in the second position;
FIG. 13 is a side elevation cross-sectional view of the downhole isolation
tool of
Fig.s 7A and 7B, installed downhole in a well bore seated and sealingly
engaged to a
gas separator, when sliding sleeve thereof is in the second position and the
pump
apparatus is pulled uphole, it becomes detached from the isolation tool,
leaving the
isolation tool downhole seated and sealingly engaged to the gas separator,
preventing
hydrocarbons from being in communication uphole.
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DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
Referring to Fig. 1A, a downhole pump apparatus 1 of the prior art in a "top
hold
down" configuration is shown. The pump apparatus 1 is installed in a downhole
operative
(pumping) position in well casing 2 of a production well 12. The pump
apparatus 1 is
situated within production tubing 30 and comprises a pump assembly 4 having a
pump 6
and a pump intake 8. The pump intake 8 may comprise a plurality of openings
arranged
around the circumference of the pump assembly 4 and/or comprise a single
opening at
the bottom of the pump assembly 4.
A production fluid (e.g. oil 3) being produced from the bottom 10 of well 12
enters
pump intake 8 and is pumped upwardly within pump assembly 4 by pump 6 so as to
be
forced out exit aperture 85 within a top portion of pump assembly 4 and
directly into
production tubing 30 and thereby forced upwardly to surface.
In the downhole operative pumping position shown, pump assembly 4 is situated
proximate the bottom 10 of well 12. A seating surface 18 on hold-down member
16
sealingly engages a circumferential seal 22 on seating nipple 20 situated
within
production tubing 30. This arrangement prevents the unregulated flow of
pressurized
fluids and/or gases otherwise than through the pump 6 and production tubing
30.
The configuration shown in Fig. 1A is commonly referred to in the art as a
"top
hold down" configuration, wherein the pump assembly 4 is situated below
seating nipple
20 and thus the exterior of pump 6 is disadvantageously exposed to unregulated
.. downhole reservoir pressures during pumping.
Pump 6 forming part of pump assembly 4 may comprise a rod pump and a rod
string encased within polish rod 14 which reciprocates up and down and is
provided to
power pump 6. Alternatively, pump 6 may comprise electric submersible pumps or
progressive cavity pumps, or any type of pump which may require removal for
servicing
and/or replacement.
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Referring to Fig. 1B, pump assembly 4 is being removed from the well 12 for
the
servicing or replacement of pump 6. Disadvantageously, as the pump assembly 4
is being
raised from well 12, seating surface 18 on hold-down member 16 is raised and
thereby
removed from, and no longer sealingly engages, circumferential seal 22 on
seating nipple
20. In such circumstances, downhole pressurized fluids and/or gases within the
hydrocarbon formation may then flow uphole in an unregulated manner (as
indicated by
arrows) since the pressurized fluids and/or gases are no longer required to
flow in a
regulated manner through pump 6.
Referring to Fig. 1C, the pump assembly 4, including seating surface 18, has
been completely removed from well 12, and downhole pressurized fluids and/or
gases
within the hydrocarbon formation are given free flow uphole in an unregulated
manner
(indicated by arrows). The downhole pressurized fluids and/or gasses will then
be directly
exposed to surface, via production tubing 30, unless the well has been
previously "killed".
As seen in Fig.s 1A-1C, due to the "top hold down" configuration of pump
assembly 4, the thin exterior of pump 6 is exposed to downhole reservoir
pressures, which
in high pressure reservoirs, can lead to pump 6 damage.
The present invention is adapted for use in association with any type of
downhole
pump 6 used in applications shown similar to that shown in Fig.s 1A-1C for
pumping well
bore fluids, e.g. where a "top hold down" configuration is used.
Particularly, the present downhole isolation tool is adapted for uses such as
that
shown in Fig.s 1A-1C where a downhole pump 6 is required and in which the
downhole
pump 6 has to be removed from the well 12 for purposes of servicing or
replacement.
More particularly, the present downhole isolation tool is adapted for uses in
which
a pump assembly 4 is in a "top hold down" configuration and is positioned
above another
downhole assembly, such as a gas separator, and in which it is advantageous to
seat
and sealingly engage the downhole isolation tool of the present invention to
the downhole
assembly so that the downhole pump 6 can be removed from the well 12 for
purposes of
servicing or replacement.
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Referring to Fig. 2A, a modified pump apparatus 1, also used in the prior art,
is
shown in a "bottom hold down" configuration. In such a configuration, the
downhole pump
assembly 4 is positioned above seating surface 18 on hold-down member 16,
thereby
preventing, due to the sealing engagement of seating surface 18 with
circumferential seal
22 on seating nipple 20, pressurized liquids and/or gases from within the
reservoir from
bypassing the downhole pump 6 and thereby flowing to surface in an unregulated
manner
via production tubing 30. Since the pump assembly 4 is positioned above
seating surface
18 on hold-down member 16, the pump 6 is positioned above the hold-down
assembly
so as not to be directly exposed to downhole reservoir pressure. Such a
"bottom hold
down" configuration is typically used in applications where there are concerns
of
excessive reservoir pressures which could possibly collapse the thin outer
barrel of
downhole pump 6. Such configurations may alternatively or additionally be used
in
applications where the downhole pump 6 is to be seated and sealingly engaged
to
another downhole assembly, such as a gas separator. For instance, seating
surface 18
on hold-down member 16 may be sealingly coupled to a circumferential seal 22
on seating
a seating surface situated within the downhole assembly.
Referring to Fig. 2B, pump assembly 4 is being removed from the well 12 for
servicing or replacement. Disadvantageously with regard to this configuration,
as was the
case with the prior art apparatus shown in Fig.s 1A-1C, as the pump assembly 4
is being
raised from well 12, seating surface 18 on hold-down member 16 is raised from,
and
therefore no longer sealingly engages, circumferential seal 22 on seating
nipple 20. The
loss of sealing engagement of seating surface 18 with circumferential seal 22
on seating
nipple 20 permits downhole pressurized fluids and/or gases to flow uphole in
an
unregulated manner (indicated by arrows).
Referring to Fig. 2C, the pump assembly 4, including seating surface 18, has
been completely removed from the production well 12, and downhole fluids
and/or gases
within the hydrocarbon formation are given free flow uphole in an unregulated
manner
(indicated by arrows). The downhole pressurized fluids and/or gases will then
be directly
exposed to surface, via production tubing 30, unless the well has been
previously "killed".
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Applicant's commonly assigned US Patent Nos. 8,893,776 and 8,889,316,
disclose downhole isolation tools that are suitable in many applications to
permit a well
12 to be temporarily sealed downhole to allow the removal of a downhole pump 6
for
servicing or replacement. While these downhole tools provide significant
advantages
over the prior art apparatuses and methods of Fig.s 1A-1C and Fig.s 2A-2C,
limitations
exist in that the downhole tools do not adequately address situations in which
it would be
beneficial to have the downhole isolation tool directly seat and sealingly
engage a
specialized downhole assembly, such as a gas separator. Particularly, these
downhole
isolation tools do not provide sliding sleeve and seal sub configurations to
readily permit
such specialized applications, including appropriate seating means and fluid
flow paths
through the sliding sleeve and seal sub. These features are advantageously
disclosed
herein as aspects of the novel downhole isolation tool of the present
invention.
Referring to Fig.s 3A, 3B and 4, an embodiment of the downhole tool 100 of US
Patent No. 8,893,776 is shown. Downhole tool 100 comprises a hollow ported
sleeve 80
that is closed on both ends. In a well-producing first position, wellbore
fluids enter ported
sleeve 80 through first port means 81 in the sidewall of the ported sleeve 80
positioned
below lower seal means 26 on the seal sub 24. In this first position, wellbore
fluids exit
ported sleeve 80 through second port means 83, likewise situated in the
sidewall of the
ported sleeve 80. In a closed second position, ported sleeve 80 is positioned
in seal sub
24 in a manner by which first port means 81 is positioned between lower and
upper seal
means (26 and 28) on seal sub 24, thereby preventing access of wellbore fluids
to the
internal hollow cavity of ported sleeve 80. Since ported sleeve 80 is hollow
over its entire
length, it is essential to its operation that the bottom end of the ported
sleeve 80 is closed
to the hollow interior. If it were otherwise, ported sleeve 80 would not
function to prevent
fluids from upward movement to the surface.
Referring to Fig.s 5A, 5B and 6, an embodiment of the downhole tool 200 of US
Patent No. 8,899,316 is shown. Similar to downhole tool 100, downhole tool 200
comprises a sliding sleeve 202 with a pair of apertures, namely a first
aperture 212
situated proximate upper end 204 and a second aperture 214 situated
approximately
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mid-length of sliding sleeve 202. In contrast to downhole tool 100, seal sub
230 of
downhole tool 200 comprises a port means in the form of aperture 250, which
aperture
250 extends from exterior surface 252 of seal sub 230 through to and is in
fluid
communication with bore 232. Thus, fluid enters downhole tool 200 through an
aperture
in the side of the seal sub 230.
In a well-producing first position, wellbore fluids enter sliding sleeve 202
by
second aperture means 214 being aligned with port means 250 on the seal sub
230, to
allow communication of fluids surrounding the exterior of seal sub 230 into
the elongate
cavity 210 of sliding sleeve 202. In this first position, wellbore fluids exit
sliding sleeve
202 through first aperture means 212, likewise situated in the sidewall of the
sliding sleeve
202. In a closed second position, a seal member 220 within sliding sleeve 202
becomes
aligned with port means 250, blocking and thereby preventing communication of
fluids
with the elongate cavity 210 of sliding sleeve 202. Since fluid access to
sliding sleeve
202 is through port means 250 in the seal sub 230, it is essential to the
operation of
downhole tool 200 that the seal member 220 align with and block the port means
250 in
the seal sub 230. If it were otherwise, sliding sleeve 202 would not function
to prevent
fluids from upward movement to the surface.
Fig.s 7A & 7B and Fig. 8 show a novel downhole isolation tool 300 of the
present
invention, particularly for use in a well/wellbore 12 wherein seating and
sealing
engagement of the downhole isolation tool 300 to a downhole assembly (e.g. a
gas
separator) is desired. The wellbore 12 may further possess a well casing 2, a
rod string
encased within a polish rod 14, a pump apparatus 4 which has inlet apertures
322 for a
pump 6, and a gas separator 400 (see Fig.s 9 and 11-13).
Fig.s 11-13 show an embodiment of the downhole isolation tool 300 of the
present invention and its manner of being deployed downhole in a wellbore 12,
wherein
the downhole isolation tool 300 is seated and sealingly engaged directly to a
gas
separator 400 to allow passage of fluids therethrough (Fig. 11), and
alternatively its
manner of being deployed so as to seal the wellbore 12 (Fig. 12) and thereby
allow the
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pump apparatus 4 and rod string/polish rod 14 to be withdrawn from the
wellbore 12 (as
shown in Fig. 13).
Specifically, Fig.s 7A-7B show a downhole tool 300 of the present invention in
cross-sectional view. Downhole tool 300 is provided with an elongate sliding
sleeve 302
with an upper end 304 and lower end 306, and an elongate hollow cavity 310
therein
separated into an upper cavity 311 and a lower cavity 313 by a seal member
320. Sliding
sleeve 302 is adapted to be slidably positioned in an elongate seal sub 330
having a bore
332, bypass channel 350 and seating means 380.
Downhole tool 300 further comprises releasable latch means 60 at the upper end
304 of the sliding sleeve 302.
Fig. 7A shows such downhole tool 300 in a position (first position) within the
seal
sub 330 allowing upward movement of fluids such as oil through an opening 318
in the
lower cavity 313 of the sliding sleeve 302, through a third aperture means 316
into a
bypass channel 350 of the seal sub 330, and into the upper cavity 311 of the
sliding sleeve
302 through a second aperture means 314 of the sliding sleeve 302, which
fluids may
thereafter be drawn and pass out of the sliding sleeve 302 through a first
aperture means
312 and into pump apparatus 4 via inlet apertures 322 in a distal end of pump
apparatus
4 (see Fig. 11).
Fig. 7B shows such downhole tool 300 slidably repositioned within the seal sub
330 to a position (second position) preventing upward movement of fluids such
as oil
through downhole tool 300, which advantageously allows for sealing the well 12
after the
rod string/polish rod 14 and associated pump apparatus 4 are withdrawn from
the well
12. (see Fig. 13). In this closed configuration, downhole tool 300 has
repositioned
upwardly such that seal member 316 and second aperture means 314 of the
sliding
sleeve 302 are in a position above the bypass channel 350 of the seal sub 330,
preventing
movement of fluids into the upper cavity 311 of the sliding sleeve 302.
Sliding sleeve 302 of downhole tool 300, as best shown in Fig. 8, is provided
with
three separate sets of aperture means, namely a first aperture means 312
situated
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proximate upper end 304 of tool 300 and in fluid communication with upper
cavity 311,
second aperture means 314 situated just above seal member 320 and
longitudinally
separated from first aperture means 312 within upper cavity 311, likewise in
fluid
communication with upper cavity 311, and third aperture means 316 situated
just below
seal member 320, in fluid communication with lower cavity 313 but not with
upper cavity
311. Sliding sleeve 302 is further provided with an opening 318 in the bottom
of lower
cavity 313 at lower end 306 of the sliding sleeve 302, which is in fluid
communication with
the third aperture means 316. Preferably, opening 318 is an open end of the
lower cavity
313.
The first, second and third aperture means (312, 314 and 316) each comprise at
least one aperture in the sliding sleeve 302 sidewall. Preferably, each of the
first, second
and third aperture means (312, 314 and 316) comprise at least two apertures in
the sliding
sleeve 302 sidewall. More preferably, each of the first, second and third
aperture means
(312, 314 and 316) comprise a plurality of apertures in the sliding sleeve 302
sidewall. In
an embodiment, the first, second and third aperture means (312, 314 and 316)
may
independently comprise any combination of the above, with each aperture means
comprising the same of a different number of apertures than the other(s). The
apertures
may be machined into the sliding sleeve 302 sidewall. The size, shape and
arrangement
of the apertures can be varied, and would be in the knowledge of a person
skilled in the
art, in order to maximize the flow of production fluid through the apertures.
For example,
the apertures may have a uniform shape and size and be positioned equidistant
from
each other in the sliding sleeve 302. Alternatively, the shape and size of
each aperture
may be different and the distance between each aperture may vary.
As further seen from Fig.s 7A and 7B, downhole isolation tool 300 is further
provided with an elongate seal sub 330, preferably of cylindrical shape,
having a bore
332 therethrough for slidably receiving therewithin sliding sleeve 302. A
bypass channel
350 is provided along bore 332, situated at a bore surface distal to the upper
end 340 and
lower end 360 of the seal sub 330. By distal to the upper and lower ends (340
and 360)
of the seal sub 330, it is meant that the bypass channel 350 does not extend
all the way
along the wall of bore 332 to where the bore 332 ends at the upper end 340 and
lower
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end 360 of the seal sub 330. The bypass channel 350 is bounded on its opposite
side
from bore 332 by the sidewall 352 of the seal sub 330, thereby preventing
fluid
communication exterior to the seal sub 330 from the bypass channel 350.
Exterior
surface 252 of seal sub 330 is not in fluid communication with bore 332.
In an embodiment, bypass channel 350 is a circumferential channel in the
surface
of bore 332. The channel of bypass channel 350 may span any longitudinal
length of
bore 332 of the seal sub 330, so long as it does not extend to the end of the
bore as
described above and the channel is wide enough to permit alignment, and fluid
communication therewith, of both the second and third aperture means (314 and
316) of
the sliding sleeve 302 at the same time (i.e. when sliding sleeve 302 is in
the first position
as described above). Further, when sliding sleeve 302 is in the second
position as
described above, seal member 320 of the sliding sleeve 302 should be able to
align with
a portion of bore 332 that is above the bypass channel 350. Likewise, in a
preferred
embodiment, first aperture means 314 is also aligned with bore 332 of seal sub
330 when
the sliding sleeve 302 is in the second position.
Bore 332 permits slidable movement of sliding sleeve 302 therewithin, from a
first
position shown in Fig. 7A to a second position shown in Fig. 7B, as described
herein. A
circumferential seal, such as an "0" ring seal 390, may be provided within
bore 332 of
seal sub 230 at a position above bypass channel 350, in order to assist in
sealingly
blocking passage of fluid beyond lower cavity 313 when the sliding sleeve 302
is in the
second position.
As further seen from Fig.s 7A and 7B, seal sub 330 comprises a seating means
380. Preferably, seating means 380 is situated at the lower end 360 on an
exterior
surface of the seal sub 330 so as to advantageously be positioned for seating
and sealing
engagement of the downhole tool 300 with another downhole assembly, such as a
gas
separator 400 as shown in Fig.s 9 and 11-13. In an embodiment, the seating
means 380
of the seal sub 330 is screw threads capable securely fastening to
corresponding screw
threads 402 within the upper end of the downhole assembly, such as a gas
separator
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400. In an embodiment, seating means 380 of the seal sub 330 sealingly engages
a
circumferential seal 404 situated on seating surface 402.
When pumping from a hydrocarbon production well containing gas and liquid it
is
known to be desirable to separate the gas from the liquid in order for the
pump to operate
effectively. For a reciprocating rod pump, one of the most common forms of
separation
is the modified poor boy gas separator. The function of the separator is to
remove as
much gas as possible from the gas-oil stream coming from the reservoir.
Avoiding the
entrance of gas is a key factor in order to keep the downhole pump size and
running
speed within reasonable limits.
A representative diagram of a prior art gas separator 400 is shown in Fig. 9A.
Typically, there are two major components of gas separators used wells
operating with a
reciprocating rod pump, the mud anchor 430 run on the bottom of the tubing
string and
the dip tube 420 run below the bottom of the pump (see Fig. 10A). In operation
(see
Fig. 9B), gas-liquid mixture is pulled in through the tubing intake ports 410
on the pump
upstroke. During the plunger upstroke, the free gas escapes from the liquid if
the gas
upward slip velocity is greater than the liquid downhole velocity. On the
plunger
downstroke, gas slips upward through the stationary liquid. Liquid (e.g. oil)
with reduced
gas content then enters the separator inlet slots 440 and is pumped to the
surface.
Recently, with significant inroads having been made into oil extraction,
reservoirs
have departed from their pristine initial conditions. Produced gas rates have
increased
and oil producers now regard downhole gas separation as a key technology for
successful
operations. However, gas separators are not 100% effective in separating the
gas and
there are limitations on how much gas can be handled by a downhole gas
separator. If
more gas is produced than can be handled by the separator, the gas will not
separate
completely and the downhole pump then must handle the excess gas. This can
lead to
significant problems in respect of e.g. pump volume efficiency, wasted energy
and
increased operating costs. Moreover, if excessive gas enters the pump and
there is
insufficient compression ratio to pump all the fluids, "gas-lock" can occur.
When this
happens, operating costs increase dramatically because there is no oil
production from
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the well and the pump typically has to be replaced or removed for servicing.
It is also
commonplace for gas separators themselves to become plugged with sand and
other
sediment, particularly in wells in heavy oil formations. Thus, increased
operating costs
and production down-time can also result from having to remove and clean or
replace the
gas separator or components thereof.
Referring to Fig.s 10A and 10B, a downhole pump assembly 4 and gas separator
400 of the prior art are shown. In Fig. 10A, the pump assembly 4 and gas
separator 400
are in an operative configuration, with the pump 6 attached to the dip tube
420 situated
within the gas separator 400. When servicing (e.g. cleaning) of the gas
separator dip
tube 420 is required, it is disadvantageously necessary to unseat and lift
both the pump
assembly 4 and dip tube out 420 and the well 2 (see Fig. 10B). This is a time
consuming
and costly process. Moreover, removal of the pump inevitably results in the
undesirable
need to "kill" the well.
Advantageously, the downhole isolation tool 300 of the present invention is
configured so as to be directly compatible with specialized downhole
assemblies, such
as a gas separator 400. The seating means 380 on the seal sub 330 allows for
the
downhole tool 300 to be positioned immediately adjacent, and in seated and
sealed
engagement with the gas separator 400. Likewise, the fluid flow configuration
through
the downhole tool 300 is designed to be suitable for such applications, with
an opening
318 at the bottom and an upper and lower cavity (311 and 313) to which fluid
communication is governed by the arrangement of second and third aperture
means (314
and 316) with a bypass channel 350. In such novel design, downhole tool 300 is
capable
of acting as a fluid flow "stop-gate" between the downhole assembly (e.g. gas
separator)
and other equipment, such as a pump.
Referring to Fig.s 11-13, the method of operation of the downhole tool 300 of
the
present invention is described in relation to the downhole assembly being a
gas separator
400. By operation of the downhole tool 300 of the present invention, there is
provided a
method for preventing at least one of downhole fluids and gases in a
hydrocarbon
formation from reaching surface upon removal of a pump assembly 4 from a
wellbore 12.
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The method comprises steps of: (a) providing a sliding sleeve 302 of the
present invention
as described herein, (b) providing a seal sub 330 of the present invention as
described
herein, (c) slidably inserting sliding sleeve 302 within bore 332 of seal sub
330 to a first
position where second and third apertures (314 and 316) and seal member 320 of
sliding
sleeve 302 are aligned with bypass channel 350 situated within bore 332 of the
seal sub
330 to allow communication of fluids from lower cavity 313 to upper cavity 311
of sliding
sleeve 302 by bypassing seal member 320 via bypass channel 350, (d) either
before or
after step (c), releasably coupling, via releasable latch means 50 (e.g.
bulbous spherical
knob 60) on upper end 304 of sliding sleeve 302, downhole tool 300 to a lower
end 45 of
a pump assembly 4, (e) inserting downhole tool 300 and pump assembly 4
downhole
into wellbore 12, (f) sealingly engaging downhole tool 300 and pump assembly 4
to gas
separator 400 in wellbore 12 via seating means 380 situated on seal sub 330,
(g)
operating pump assembly 4, (h) raising pump assembly 4 and causing sliding
sleeve 302
to be slidably re-located upwardly in bore 332 from the first position to a
second position
where first aperture means 312 and seal member 320 are positioned above the
bypass
channel 350 in bore 332 of seal sub 330, to thereby prevent communication of
fluids from
lower cavity 313 to upper cavity 311 of said sliding sleeve 302, (i) pulling
pump assembly
4 upward so as to releasibly dis-engage latch means 60 on sliding sleeve 302
from the
lower end 45 of the pump assembly 4, and removing pump assembly 4 from the
wellbore
12.
Referring to the above described method, in the downhole operative position,
sliding sleeve 302 is positioned in relation to seal sub 330 so that in a
producing position,
second and third aperture means (314 and 316) are aligned and in fluid
communication
with bypass channel 350 in bore 332 of seal sub 330.
When pump 6 is activated, a production fluid (e.g. oil 3) is drawn from the
well 12
through opening 318 at lower end 306 of sliding sleeve 302 and into lower
cavity 313,
through third aperture means 316 into bypass channel 350, through second
aperture
means 314 into upper cavity 311, and out of sliding sleeve 302 through first
aperture
means 312. The production fluid then enters production tubing 30 into the pump
6 through
inlet apertures 322, and through pump 6 and out exit aperture 85 to surface.
The sealing
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engagement between downhole tool 300 and gas separator 400 by seating means
380
on seal sub 330 prevents downhole pressurized fluids and/or gases from
reaching surface
in an unregulated manner. The fluid flow path through downhole tool 300 also
ensures
that downhole pressurized fluids and/or gases do not reach the surface in an
unregulated
manner.
The lower end 45 of pump assembly 4 comprises a releasable latch member 50,
which is adapted for releasably coupling and de-coupling sliding sleeve 302
from lower
end 45 of pump assembly 4. Latch member 50 may comprise and operate similar to
various "on/off" tools used in the industry, wherein in one particular
"on/off" tool
configuration is a protruding nub, which is releasibly insertable into a
helical slot milled
into an exterior surface of the latch member 50 which forms part of a "J"
slot. By lowering
latch member 50 onto a component to which it is desired to become releasibly
coupled
(in this case sliding sleeve 302), much like the rotary motion imparted to a
child's toy top
when a downward motion is imparted, engagement of a protruding lug with a
milled helical
groove which is part of a milled "j" slot on respectively latch member 50 and
coupled
component (sliding sleeve 302), when downward force is applied, causes
relative rotation
of each component relative to the other and thus movement of the lug within
the "j" slot
portion of the milled "j" slot to thereby couple latch member 50 to coupled
component
(sliding sleeve 302). To release latch member 50 from releasable securement to
sliding
sleeve 302 after the pump assembly 4 and sliding sleeve 302 have been raised
so that
the second aperture means 314 and seal member 320 are positioned above the
bypass
channel 350 in bore 332 of seal sub 330, a well operator momentarily reverses
the
direction of movement of the pump assembly 4 from up to down, thereby again
forcing
latch member 50 downwardly against the then-immobile sliding sleeve 302, and
this time
due to the action of lug within helical grooves a reverse direction of
rotation of the latch
member 50 relative to the sliding sleeve 302 is imparted, thereby removing the
lug from
within the "J" slot and permitting disengagement of the sliding sleeve 302
from latch
member 50, to thereby decouple latch member 50 from sliding sleeve 302.
In a preferred embodiment, however, latch member 50 of the present invention
comprises a plurality of resiliently flexible, hooked "fingers" 52, adapted to
releasibly
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encircle and grasp a protruding bulbous spherical knob 60 (shown in Fig.s 11-
13) on the
sliding sleeve 302 which extends upwardly therefrom. Each finger 52 may
comprise a
hook edge 55 to strengthen the connection between the latch member 50 and
protruding
bulbous knob 60, which in a preferred embodiment may be frusto-conical in
shape as
shown in Figs. 12-13, but other geometrical shapes, such as being
hemispherical in
shape provided a lip edge is provided to engage hook edge 55, would also be
satisfactory.
Referring to Fig. 12, when pump 6 is desired to be serviced or replaced, pump
assembly 4 is raised from the operative/producing position shown in Fig. 11 to
a closed
position wherein advantageously the second aperture means 314 and seal member
320
on sliding sleeve 302 are positioned upwardly within seal sub 330 above bypass
channel
350, thereby preventing the flow of production fluid from the lower cavity 313
to the upper
cavity 311 of the sliding sleeve 302. Due to the sealing engagement between
seal
member 320 in bore 332 above the bypass channel 350, pressurized fluids and/or
gases
are prevented from traveling uphole in an unregulated manner. Preferably, in
this closed
position, seal member 320 aligns with and engages circumferential seal means
390 in the
bore 332 of seal sub 330, situated above said bypass channel.
During the raising of pump assembly 4, latch member 50 (already physically
coupled to sliding sleeve 302 as shown in Fig. 12) is also raised upwardly
within
production tubing 30. In an embodiment, a movement-limiting means or stop
means may
be provided on sliding sleeve 302. In a preferred embodiment, the stop means
comprises
a protruding lip 392 on sliding sleeve 302 which comes into abutting
engagement with a
lower extremity of the seal sub 330 when the sliding sleeve 302 is moved into
the second
position, and serves to operate as a movement-limiting means, as best shown in
Fig. 7B,
to prevent further upward movement of sliding sleeve 302 past the second
position.
Due to operation of protruding lip 392 preventing further upward movement of
sliding sleeve 302, further upward movement of pump assembly 4 serves to allow
latch
means 50 to decouple from bulbous head 60 on sliding sleeve 302, as shown in
Fig. 13.
In such manner pump assembly 4 may then be drawn upward and removed from well
12
to allow servicing of pump assembly 4, while at the same time hydrocarbons in
well 12
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are prevented from communication with surface by seating means 380 on seal sub
330
sealingly engaging gas separator 400 and sliding sleeve 302 being in the
second position,
as shown in Fig. 13.
In an alternative or additional embodiment (see Fig. 7A, 7B), releasibly-
engageable detent means, such as a biased protrusion 388 on said sliding
sleeve 302,
may be provided to resiliently engage a corresponding orifice 389 within seal
sub 330
when the sliding sleeve 302 is in the second position, may further be provided
as shown
in Fig. 7A & 7B, to resist upward or downward movement of the sliding sleeve
302 when
such sliding sleeve 302 is in the second position. In an embodiment, such
detent means
serves to resist upward movement of sliding sleeve 302 past the second
position. In an
embodiment, such detent means serves to resist sliding sleeve 302 from moving
downwardly to the first position and thereby allowing passage of oil or fluids
through the
downhole tool 300 and possibly uphole to surface. In an embodiment, the detent
means
may be resilient collet fingers 84, similar to those shown in Fig. 6, to
accomplish the
released engagement.
Referring to Fig. 13, pump assembly 4 is being raised to the surface and
removed
from production tubing 30 so that pump 6 can be serviced or replaced. The
positioning of
sliding sleeve 302, including seating means 380 on seal sub 330 sealingly
engaging gas
separator 400 and the second aperture means 314 and seal member 320 positioned
above bypass channel 350 in bore 332 of the seal sub 330, prevents the passage
of
downhole pressurized fluid and/or gases from flowing to surface.
Advantageously, when a new or re-serviced pump 6 and pump assembly 4 is
desired to be re-inserted downhole, the latch member 50 at the lower end of
pump
assembly 4 may be lowered in production tubing 30 and lowered onto bulbous
spherical
knob 60 on sliding sleeve 302, in a reversal of the procedure shown in Figs.
11-13.
While typically the frictional engagement between the sliding sleeve 302 and
the
bore 332 of seal sub 330 will assist in allowing the latch member 50 to be
re-coupled to ported sleeve 80, a "stop" bar may be provided, positioned
within gas
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separator 400 or other downhole assembly to which downhole tool 302 is seated
and
sealingly attached.
In a further refinement (see Fig. 7A, 7B), releasibly-engageable detent means
such as a biased protrusion 387 on said sliding sleeve 302, may be provided to
resiliently
engage a corresponding orifice 389 within seal sub 330 when the sliding sleeve
302 is in
the first position, to resist such sleeve 302 from moving downwardly from the
first position
and thereby prevent passage of oil or fluids through the downhole tool and
possibly
uphole to surface when such may be desired.
Referring back to Fig.s 10A and 10B, in an embodiment downhole tool 300 of
the present invention advantageously avoids the need to remove the dip tube
420 of gas
separator 400 when cleaning is required. As shown in Fig.s 11-13, downhole
tool 300
seats and sealingly engages the gas separator 400 upwardly of the dip tube
420. By this
sealing engagement, if dip tube 420 becomes plugged (e.g. with sand) it is
possible to
unseat pump 6 and flush dip tube 420 of the gas separator 400 without its
removal. The
sealing engagement of the downhole tool 300 with the gas separator 400
prevents the
pressure build-up in the gas separator 400 from escaping to the production
tubing 30.
Also, after reverse flush, sliding sleeve 302 in downhole tool 300 could be
moved
upwardly in seal sub 330 to the second closed position to further seal the
increased
pressure within gas separator 400. Thus, with downhole tool 300 is not
necessary to
unseat and lift the pump 6 and dip tube 420 out of the well (as in prior art
Fig. 10B) in
order to clean out a plugged dip tube 420 of the gas separator 400. This saves
both costs
and time in oil production operations.
Likewise, with the aim of saving costs and reducing oil production down-time,
in
an embodiment downhole tool 300 of the present invention permits pump assembly
4 to
be positioned higher in the well and further away from gas separator 400 than
in the prior
art. Typically, in wells utilizing gas separators, the pump assembly 4 is
positioned
immediately adjacent the gas separator to maintain unregulated downhole
reservoir
pressures low in the well during pumping (i.e. not in the production tubing).
This
necessitates a lengthy rod string/polish rod 14 to extend from the top of the
well to the
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pump 6. The longer the rod string/polish rod 14, the more prone it is to
damage and
excessive wear that will decrease its lifespan and necessitate removal for
repair or
replacement. The downhole tool 300 of the present invention, by seating and
sealingly
engaging a downhole assembly, such as a gas separator 400, allows the pump
assembly
4 to be seated higher in the well because downhole tool 300 is capable of
preventing
downhole pressures from traveling upwards in the well. This should greatly
reduce rod
wear given that a shorter rod string/polish rod 14 can be used.
In an additional or alternative embodiment, downhole tool 300 of the present
invention can be used in a wellbore 12 in combination with Applicant's
downhole tools
disclosed in US Patent Nos. 8,893,776 and 8,889,316. As discussed above, it is
a safety
and regulatory requirement that wells with exceedingly high pressures have at
least two
barriers in place to prevent pressurized fluids and/or gases from escaping
into the
atmosphere at the surface of a well. To meet this requirement, an embodiment
of the
present invention is that downhole tool 300 be used in combination with a
downhole tool
of US Patent Nos. 8,893,776 and/or 8,889,316 to reversibly and controllably
seal a
wellbore 12 at two distinct locations. Downhole tool 300 of the present
invention would
be positioned low in the well in seating and sealing engagement with a
downhole
assembly, such as a gas separator 400. In combination with this placement of
downhole
tool 300, a downhole tool of US Patent Nos. 8,893,776 and 8,889,316 would be
positioned
higher up in the wellbore 12 in fluid connection with the production tubing
30. This novel
configuration would provide two barriers to downhole pressurized fluids and/or
gases from
escaping into the atmosphere at the surface of the well. Moreover, the
barriers could
independently be configured in their open or closed configurations to regulate
the flow of
fluids and gas up the wellbore 12. In an embodiment, more than two downhole
tools may
be used, including at least one downhole tool 300 of the present invention.
For example,
in an embodiment, downhole tool 300 is used in combination with two, three,
four, five or
more other downhole tools positioned upwardly within the well.
The foregoing description of the disclosed embodiments is provided to enable
any person skilled in the art to make or use the present invention. The scope
of the claims
should not be limited by the preferred embodiments set forth in the examples,
but should
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be given the broadest interpretation consistent with the description as a
whole. Thus, the
present invention is not intended to be limited to the embodiments shown
herein, but is
to be accorded the full scope consistent with the claims, wherein reference to
an element
in the singular, such as by use of the article "a" or "an" is not intended to
mean "one and
only one" unless specifically so stated, but rather "one or more". In
addition, where
reference to "fluid" is made, such term is considered meaning all liquids and
gases having
fluid properties, as well as semi-solids such as tar-like substances.
For a complete definition of the invention and its intended scope, reference
is to
be made to the summary of the invention and the appended claims read together
with
and considered with the disclosure and drawings herein.
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