Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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DOWNHOLE INJECTION TOOL AND METHOD FOR INJECTING A FLUID IN
AN ANNULUS SURROUNDING A DOWNHOLE TUBULAR
FIELD OF THE INVENTION
In a first aspect, the present invention relates to a downhole injection tool
for
downhole injecting a treatment fluid in a space surrounding a downhole tubular
installed in
a borehole in the Earth. In another aspect, the invention relates to method
for injecting a
treatment fluid in an annulus surrounding a downhole tubular installed within
a borehole in
the Earth.
BACKGROUND TO THE INVENTION
In the operation of oil/gas wells or other cased boreholes in the Earth, it
can often
become necessary or beneficial to punch one or more holes through, or
otherwise
perforate, the casing which lines the well bore, or a production tubing within
the casing.
Downhole tools have been proposed to perforate the casing, and to subsequently
inject
sealing material into the space between the Earth formation around the bore
hole and the
casing through the perforation or perforations formed therein. US Patent
2,381,929, for
example discloses a system in which punches are forced outwardly, and radially
against the
casing, by a pressurized fluid. The application of pressure is continued until
the punches
are forced through the casing. Each punch is accompanied by a fluid passage
through
which a sealing material can be injected from the system into the annular
space around the
casing.
The system of US Patent 2,381,929 further comprises one or more reservoirs for
holding a sealing material, or ingredients of sealing material still to be
mixed. The
reservoir(s) each contain a piston, which can push the contents of the
reservoir through the
fluid passages into the annular space. Each of the fluid passages is in fluid
communication
with each reservoir, so that the contents from each reservoir is be conveyed
to each of the
fluid passages with the aim to inject the sealing material into the annular
space at multiple
locations simultaneously.
It has been suggested that the sealing material having been injected with the
system
of US Patent 2,381,929 is not always evenly distributed around the full
circumference of
the annular space. This may lead to leak paths or weak spots along the
longitudinal
direction withtin the annulus.
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SUMMARY OF THE INVENTION
In accordance with the invention there is provided a downhole injection tool
for
injecting a treatment fluid in a space surrounding a downhole tubular
installed in a
borehole in the Earth, comprising:
- an elongate tool housing extending around a central longitudinal tool axis;
- at least two stings, each of the stings comprising a fluid channel to
establish fluid
communication from within the tool housing to an exterior of the tool housing
through the
fluid channel, wherein each said sting is movable in a radially outward
direction, away
from the central longitudinal tool axis, from a retracted position to an
extended position
whereby each sting extends to outside the elongate tool housing; and
- at least two treatment fluid cannisters, for holding the treatment fluid
that is to be
injected, wherein a first cannister of the at least two treatment fluid
cannisters is fluidly
connected with the exterior of the tool housing via a first sting of the at
least two stings,
but not via a second sting of the at least two stings, and wherein a second
cannister of the
at least two treatment fluid cannisters is fluidly connected with the exterior
of the tool
housing via the second sting, but not via the first sting.
In a further aspect of the invention, there is proviced a method of injecting
a
treatment fluid in an annulus surrounding a downhole tubular arranged within a
borehole in
the Earth, said method comprising:
- providing a downhole injection tool as defined above;
- lowering the downhole injection tool into the borehole through the
downhole
tubular to a selected depth;
- at the selected depth, extending the first sting and the second sting
through a wall of
the downhole tubular, to establish fluid communication between downhole
injection tool
and the annulus surrounding the downhole tubular;
- injecting the treatment fluid from the downhole injection tool from the
at least two
treatment fluid cannisters through the first sting into the annulus
surrounding the downhole
tubular and through the second sting into the annulus; and
- retrieving the downhole injection tool from the downhole tubular.
These and other features, embodiments and advantages of the method, and of
suitable expansion devices, are described in the accompanying claims, abstract
and the
following detailed description of non-limiting embodiments depicted in the
accompanying
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drawings, in which description reference numerals are used which refer to
corresponding
reference numerals that are depicted in the drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
The drawing figures depict one or more implementations in accord with the
present
teachings, by way of example only, not by way of limitation. In the figures,
like reference
numerals refer to the same or similar elements.
Fig. 1 is schematic cross sectional view along line B-B indicated in Fig. 2,
of a
section of a downhole injection tool for perforating and injecting;
Fig. 2 is a plan view along a longitudinal direction from above on the tool of
Fig. 1;
Fig. 3 is a detailed cross sectional view of the stings of the tool of Fig. 1;
Fig. 4 is a plan view along line C-C indicated in Fig. 1;
Fig. 5 is a detailed cross sectional view of the tool along line D-D as
indicated in
Fig. 2;
Fig. 6 is a detailed cross sectional view of the cannisters that can connected
to the
tool of Fig. 1; and
Fig. 7 is an example hydraulic circuit.
Similar reference numerals in different figures denote the same or similar
objects.
Objects and other features depicted in the figures and/or described in this
specification,
abstract and/or claims may be combined in different ways by a person skilled
in the art.
Unless otherwise indicated, the term longitudinal is used herein to express
the direction
parallel to the central longitudinal tool axis, and the term transverse is
used to express any
direction normal (perpendicular) to the central longitudinal tool axis.
DETAILED DESCRIPTION OF THE INVENTION
Disclosed is a downhole injection tool for injecting a treatment fluid in a
space
surrounding a downhole tubular installed in a borehole in the Earth. The tool
may be run
longitudinally in a bore of the downhole tubular. At least two stings are
provided with the
tool, each provided with a fluid channel. Each sting can protrude through a
wall of the
downhole tubular, and thereby establish a fluid communication channel between
the
downhole injection tool within the tubular and the space surrounding the
tubular. At least
two treatment fluid cannisters are provided in the downhole injection tool,
for holding the
treatment fluid that is to be injected. A first cannister of the at least two
treatment fluid
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cannisters is fluidly connected with the exterior of the tool housing via a
first sting of the at
least two stings, but not via a second sting of the at least two stings. A
second cannister of
the at least two treatment fluid cannisters is fluidly connected with the
exterior of the tool
housing via the second sting, but not via the first sting.
By providing a dedicated cannister (or dedicated set of cannisters) for each
of the
stings, it is achieved that the treatment fluid is injected through each sting
in predetermined
quantities, preferably in mutually equal quantities. The invention is based on
an insight that
in case of multiple stings being fed by a shared cannister, an imbalance may
cause the
treatment fluid to pass preferentially through one of the stings, thereby
filling the space
surrounding the tubular less homogenously. The imbalance may be caused, for
example,
by one of the stings experiencing a higher flow resistance than the other. The
present
invention is believed to facilitate a more controllable and homogenous
distribution of the
treatment fluid around the tool or the tubular.
In use, the downhole injection tool may be lowered into a borehole through the
bore of the downhole tubular, to a selected depth. At the selected depth, the
tool may be
kept stationary, while extending the stings through a wall of the downhole
tubular, to
establish fluid communication between downhole injection tool and the annulus
surrounding the downhole tubular. The treatment fluid is then injected, from
the at least
two treatment fluid cannisters through both stings into the annulus
surrounding the
downhole tubular. At least part of the stings may be subsequently retracted,
and the
downhole tool may then be retrieved from the downhole tubular.
Typical downhole tubulars include wellbore tubulars, such as, for example,
casing,
liner, or production tubing.
The invention can be applied with any type of downhole injection tool which
has
multiple injection stings. As one example, Figure 1 shows a cross sectional
view of a
section of a downhole injection tool that can be used. In this example, the
downhole
injection tool is a perforating and injection tool, wherein the functionality
of injecting is
advantageously combined with the functionality of perforating.
Notwithstanding,
combining perforating and injection functionality in one tool is not a
requirement of the
invention. The cross section is taken along line B-B as indicated in Fig. 2.
For reason of
clarity, some of the parts that are not essential to the present invention
have been omitted
or simplified.
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The tool can be of modular design, having several sections (or: modules) which
can
be assembled in a string using connectors. Shown in Fig. 1 are an expander
section 30 and
a piston section 50. The piston section 50 is connected to the expander
section 30 at
connector 52. The expander section 30 comprises a base 37, to which, in turn,
an elongate
tool housing 3 is connected at connector 32. The tool housing 3 is extending
around a
central longitudinal tool axis 2. The tool can be run downhole in a downhole
tubular, such
as a wellbore tubular. Connectors, such as for example screw connectors 34 in
the base 37,
may be provided to attach an optional external centralizer, such as a
(flexible) spring blade
(not shown).
The expander section 30 comprises two stings, first sting 7 and second sting
7', both
positioned in one transverse plane, but at mutually opposing azimuths. More
than two
stings may be provided, preferably in said one transverse plane and/or
preferably equally
distributed around the circumference of the tool, to facilitate equal
distribution of the
treatment fluid in all directions. Each sting 7,7' is movable in a radially
outward direction
18,18', away from the central longitudinal tool axis 2, from a retracted
position (as shown)
to an extended position (not shown), whereby each sting 7,7 partly extends to
outside the
elongate tool housing 3. Windows, for example window13, may suitably be
provided in
the elongate tool housing 13 to allow passage of each sting.
A hydraulic drive mechanism is provided to drive each sting 7,7' from its
respective
retracted position to extended position. The hydraulic drive mechanisms may
comprise a
press device for each of the stings 7,71. Each press device may comprise a
wedge segment
33,33' respectively acting the sting 7,7' to force each sting 7,7' in the
radially outward
direction 18, 18' from the tool housing 3. The movement of the first sting 7
is driven by
movement of the first wedge segment 33 in longitudinal direction with respect
to elongate
housing 3 and the first sting 7, whereas the movement of the second sting 7'
is driven by
movement of the second wedge segment 33' in said longitudinal direction with
respect to
elongate housing 3 and the second sting 7'.
The radially outward directions 18,18' are in essence transverse to the
longitudinal
axis 2. Each sting 7,7' is rigidly mounted on a distal end of a bending arm
35,35'. At a
proximal end thereof, each bending arm 35,35' is fixed longitudinally
stationary relative to
the elongate tool housing 3. In the embodiment as shown, each bending arm
35,35' is
monolithic to the base 37. This can be made by machining. Each sting 7,7', is
movable in
unison with the distal end of its own respective bending arm 35,35', each in a
longitudinal-
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radial plane from the central longitudinal tool axis 2. As a result, each
sting 7,7' can move
in said radial outward direction 18,18', essentially without experiencing any
friction in the
transverse direction. Each bending arm 35,35' effectively acts as a spring
blade, which is
elastically loaded as the press device forces the sting 7,7' in the radially
outward direction
.. 18,18'.
Thus, the expander section 30 of the present example employs multiple sting-
arm
combinations, each with their own press device. For example, in the embodiment
of Fig. 1,
the already mentioned sting 7 and bending arm 35 together form a first sting-
arm
combination, whereby the tool further comprises a second sting-arm combination
.. comprising a second sting 7' and a second bending arm 35'. The second sting
comprises,
wherein said second sting is movable in a second radially outward direction
18' opposite to
the first radially outward direction 18 and also away from the central
longitudinal tool axis
2. The first sting-arm combination and second sting-arm combination are
arranged side-
by-side whereby the first sting and the second sting are positioned in one
transverse plane,
but at mutually differing azimuths around the central longitudinal tool axis
2.
Both press devices act on both sting-arm combinations simultaneously, to force
the
first sting and second sting in mutually differing radially outward directions
from the tool
housing, transversely to the longitudinal axis.
Each press device includes its own wedge segment. Two such wedge segments are
shown in Fig. 1: the first wedge segment 33 and a second wedge segment 33'.
The first
wedge segment 33 and second wedge segment 33' are slidingly abutted against
each other
in a longitudinal-radial abutment plane 38, whereby the first wedge segment 33
is in
sliding contact with the first sting-arm combination (7,35) and whereby the
second
segment 33' is in sliding contact with the second sting-arm combination
(7',35'). When
.. being forced into relative movement, in longitudinal direction, with
respect to the first
sting 7 and second sting 7', the first wedge segment 33 and the second wedge
segment 33'
are also free to slidingly move, relative to each other, in the longitudinal
direction.
An inlay 36, consisting of sheet or platelet of a wear resistant contact
material, may
be provided in a recess in one of the wedge segments at the abutment plane 38.
The inlay
36 may be best visible in the detailed cross sectional view of Fig. 3. The
inlay may be
made of a material having a high degree of wear resistance and/or a low
coefficient of
friction. Other beneficial properties for this material include one or more of
a high
mechanical strength, stiffness, and hardness. Furthermore, it may have high
temperature
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resistance and a good creep resistance at high temperatures. Examples of
preferred
materials include PEEK (a polyetheretherketone material), preferably bearing
grade (BG)
PEEK, which may be reinfoced with carbon fiber.
The bending arms 35,35' are flexible, such that upon movement of the
respective
wedge segments 33,33' the bending arms 35,35' flex or pivot outward, such that
each sting
7,7' is movable in unison with the distal ends of the bending arms in a
longitudinal-radial
plane from the longitudinal tool axis 2. The bending arms 35,35' may flex
fully elastically,
or the flexing may be assisted by a pivot. Elastic bending has the advantage
that the
bending arms will automatically retract when the wedge segments 33,33' are
returned to
their starting positions.
With the tool ran concentrically inside a downhole tubular installed in a
borehole in
the Earth, the stings will first engage with the inside of the wall of the
tubular and after
continued forcing the wedge segments the stings will ultimately, one after the
other,
perforate the wall of the tubular and protrude through the tubular into the
annular space
.. surrounding the tubular.
As can also be seen in Fig. 3, in this particular example, a major part of the
sting 7 is
cylindrical and extends along a longitudinal sting axis 8. The longitudinal
sting axis 8 is in
essence perpendicular to the central longitudinal tool axis 2, and extending
radially
outward therefrom in the transverse plane 28. The sting 7 may comprise an end
cap 41,
which might be slightly tapered at the radially outward facing surface. The
end cap 41 may
comprise an orifice, a nozzle, and/or house a non-return valve. The sting 7 is
held in place
by a sting foot 49, which may, for example, be bolted to the distal end of the
bending arm
35.
Figure 4 shows a side view of the tool from the direction indicated by C-C in
Fig. 1.
Both the end cap 41 of the sting 7, and the sting foot 49 can be seen through
window 13 in
tool housing 3. The window 13 is preferably sufficiently large to receive the
sting foot 49
when the sting is in the extended position. Bolts 40 may be employed to mount
the sting 7
to the bending arm.
The wedge segments 33,33' each engage with a hydraulic piston, which may be
housed within the piston section 50. The hydraulic piston can be actuated by a
hydraulic
fluid that is displaced by a pump, to impart the relative movement of the
wedge segments,
in longitudinal direction, with respect to each of the stings 7,7'.
Advantageously, each of
the wedge segments 33,33' engages with a plurality of hydraulic pistons.
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Focussing now on Fig. 5, there is illustrated a cross-section of the piston
section 50
shown in Fig. 1 but along the line D-D as indicated in Fig. 2. The cross-
section view also
shows part of the base 37. The piston section 50 comprises a piston housing 57
provided
with one or more piston bores 56a,56b. Piston rods 53a and 53b traverse the
base 37, and
both piston rods engage with the wedge segment 33. Hydraulic pistons 54a and
54b are
respectively formed at the other ends of the piston rods 53a and 53b. The
hydraulic pistons
54a,54b are slidingly arranged in the piston bores 56a,56b. The piston bores
are sealed off
by piston plugs 51a and 51b sealed in place with 0-rings or the like. The
pistons 54a and
54b, are actuated by a hydraulic fluid which can be introduced in the piston
bores between
the piston plugs 51a, 51b and the hydraulic pistons 54a, 54b. The hydraulic
fluid is
displaced by a pump. The wedge segments can be retracted by hydraulically
actuating
pistons 54a and 54b to move towards the piston plugs (51a,51b), by pumping
hydraulic
fluid in the piston rod annuli (58a,58b) that exist between the piston rods
(53a,53b) and the
piston bore walls. Valves to direct the hydraulic fluid flow may be provided
in a separate
tool section (not shown). The hydraulic pump may also be provided in a
separate tool
section (not shown).
When two wedge segments 33 and 33' have to be actuated, the above described
hydraulic pistons 54a,54b together act as a first piston engaging with the
first wedge
segment 33, while similar hydraulic pistons together form a second piston
engaging with
the second wedge segment 33'. The hydraulic fluid, which is displaced by the
hydraulic
pump, can be distributed over all available piston bores. Referring now, to
Fig. 2, it can be
geometrically understood that the total combined area available for the two
piston bores
56a and 56b for the "first piston" (i.e. two times two piston bores, for two
wedge segments
of the tool) is larger than the area available for a single circular piston
bore per wedge
segment would be (i.e. two times one single piston bore). This allows for more
available
force on the stings. Moreover, each being held by two piston rods instead of
one, the
wedge segments will be more rigid and stable against force components in the
direction
perpendicular to the cross section cut plane of Fig. 1. On the other hand,
some relative
flexibility is provided on the wedge segments to react to net force components
in one of the
radially outward directions 18,18'. Under normal conditions, the forces in the
radially
outward directions 18,18' counter each other, but when one of the stings 7,7'
starts to
advance into the wall of a wellbore tubular then temporarily a net force may
present itself.
By providing wedge segments 33,33' that slide relatively to each other,
instead of a solid
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single wedge, strains that would be caused by the resulting net force can be
more easily
accommodated.
Also visible in Fig. 2 are screw holes 24 to facilitate positioning of another
tool
section (e.g. a hydraulic section with a pump and/or valves), and three
hydraulic fluid
connectors 25, which can be used to convey pressurized hydraulic fluid from a
reservoir,
using a pump and/or valve segment of the tool (not shown), to the piston
bore(s) and to
convey a return stream from the piston rod annulus or annuli back to a return
reservoir, or
vice versa. A third hydraulic fluid connector 25 is optional, and may be used
to convey
pressurized hydraulic fluid from the reservoir to one or more treatment fluid
cannisters, as
will be further elaborated on below. The hydraulic fluid connectors 25 engage
with
hydraulic fluid channels (e.g. bores) provided within the piston housing.
Referring, again, to Fig. 3, each of the stings 7,7' (but illustrated only for
sting 7)
comprise an injection tube 43 comprising a fluid channel 47, to establish
fluid
communication from within the tool housing 3 to an exterior of the tool
housing through
the fluid channel 47. The fluid channel 47 within the injection tube 43 may
suitably
connect to a discharge nozzle 45 via check valve (suitably a biased ball
valve, not shown),
which may be provided, for example, within the end cap 41. The fluid channel
can be
connected to a treatment fluid cannister via flexible line (not shown) that
can be plugged
into a socket 31. Such socket 31 may suitably comprise a compression fitting
in which a
ferrule 21 is compressed around an end of the flexible line as a nut 22 is
tightened. The
injection tube 43 may be held in place by the sting foot 49, which may, for
example, be
bolted to the distal end of the bending arm 35. An 0-ring seal 44 may be
provided to avoid
leakage of treatment fluid which is passed from the socket 31 into the fluid
channel 47.
This is only one example of how the sting can be mounted onto the bending arm,
and
alternative constructions to rigidly mount the sting to the bending arm are
assumed to be in
reach of the skilled person based on the present teaching. A frangible zone 46
may
comprise reinforcement rings 48 stacked around the injection tube 43, in
mutual abutment
with each other. The sting of Fig. 3 is modelled after the sting shown
disclosed in
W02020/229440A1, and modified to fit in the tool as described herein.
Cannisters 60,60' are provided for storing the treatment fluid. The cannisters
may be
in selective fluid communication with a hydraulic pump, via a selectable valve
which
selectively isolates the cannisters from the pump or opens the cannisters to
the pump. The
hydraulic fluid may push the treatment fluid from the cannisters to the stings
7,7', by
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displacing and replacing the treatment fluid inside the cannisters. A piston
separator may
be provided within each cannister to separate the treatment fluid from the
hydraulic fluid
and to avoid contamination of the treatment fluid by the hydraulic fluid. The
pump may be
the same pump as the one utilized for actuating the press device, as the
pump's duty for
actuating the press device will not be necessary when the sting is in its
extended position.
Figure 6 shows a cross section of how such cannisters may be implemented on
the
tool of Fig. 1, which has two stings. A first cannister 60 comprises a
treatment fluid first
reservoir 61, a hydraulic fluid first reservoir 62, a first piston separator
63, a first cannister
head 66, and a first cannister base 67. A second cannister 60' comprises a
treatment fluid
second reservoir 61', a hydraulic fluid second reservoir 62', a second
separator piston 63',
a second cannister head 66', and a second cannister base 67'. The first piston
separator 63
is slidable in longitudinal direction over a first central hydraulic fluid
tube 65 and the
second piston separator 63' is slidable in the longitudinal direction over a
second central
hydraulic fluid tube 65'.
The first cannister base 67 is provided with a hydraulic fluid connector 72
for supply
of pressurized hydraulic fluid from the pump, and with a treatment fluid first
connector 71
and a treatment fluid second connector 71'. The latter two may respectively be
fluidly
connected to sockets 31 and 31' via treatment fluid connection lines (not
shown). These
treatment fluid connection lines are suitably flexible, to allow for the
transition of the
stings 7,7' from their respective retracted position to extended position.
The treatment fluid first connector 71 communicates via a bore 73 through the
first
cannister base 67 to the treatment fluid first reservoir 61. Inside the first
central hydraulic
fluid tube 65, an inner tube 75 extends from the treatment fluid second
connector 71' to
connector 76 provided in the second cannister base 67'. This communicates via
a bore 77
through the second cannister base 67' to the treatment fluid second reservoir
61'. The
hydraulic fluid connector 72 communicates via bore 74 and the first central
hydraulic fluid
tube 65 to a hydraulic fluid first annulus 82 in the first cannister head 66
which extends
between the first central hydraulic fluid tube 65 and the first cannister head
66. From there,
the hydraulic fluid can pass via the hydraulic fluid first annulus 82 into the
hydraulic fluid
first reservoir 62. The bore 74 is suitably sealed off, for example by means
of 0-ring 85,
from the treatment fluid first reservoir 61 to avoid contamination of the
treatment fluid
inside the treatment fluid first reservoir 61 with the hydraulic fluid passing
through bore
74.
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The hydraulic fluid first reservoir 62 is fluidly connected to the hydraulic
fluid
second reservoir 62' as follows. Via bore 78 though the first cannister head
66 and liner 79
a hydraulic fluid connection is established to bore 84 in the second cannister
base 67' and
the second central hydraulic fluid tube 65'. Bore 84 is suitably sealed off
from the
treatment fluid second reservoir 61', for example with 0-ring 87 or other type
of seal.
From the second central hydraulic fluid tube 65', the hydraulic fluid can
enter into the
hydraulic fluid second reservoir 62' via annulus 82' extending between the
second central
hydraulic fluid tube 65' and the second cannister head 66'.
Both the first cannister 60 and the second cannister 60' are in selective
fluid
.. communication with the hydraulic fluid pump. During use, a selectable valve
selectively
isolates both the first cannister 60 and second cannister 60' from the pump or
opens both
the first cannister 60 and the second cannister 60' to the pump. When
selectively opened
to the pump, both the hydraulic fluid first reservoir 62 and the hydraulic
fluid second
reservoir 62' fill with the hydraulic fluid when the cannister is opened to
the pump. The
first cannister 60 is in fluid communication with the first sting 7 with a
first treatment fluid
connection line (not shown) extending between the treatment fluid first
connector 71 and
socket 31. The second cannister 60' is in fluid communication with the second
sting 7'
with a second treatment fluid connection line (not shown) extending between
the treatment
fluid second connector 71' and socket 31'. The second treatment fluid
connection line
.. bypasses the first treatment fluid connection line and the first sting 7,
and the first
treatment fluid connection line bypasses the second treatment fluid connection
line and the
second sting 7'.
An advantage of providing a dedicated cannister (or dedicated set of
cannisters) for
each of the stings, it is achieved that the treatment fluid is injected
through each sting in
predetermined quantities, preferably in mutually equal quantities. If multiple
stings would
be fed by a shared cannister, imbalances may cause the treatment fluid to pass
preferentially through one of the stings, thereby filling the annulus
surrounding the
downhole tubular less homogenously. Imbalances may be caused, for example, by
one of
the stings experiencing a higher flow resistance than the other. By feeding
each sting from
a different cannister, it is believed a more controllable and homogenous
distribution of the
treatment fluid around the tubular can be feasible.
The treatment fluid may for example be a two-component resin, the components
of
which being mixed during the injection of the treatment fluid. In this case,
multiple
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cannisters may be provided for each of the stings. Alternatively, a resin may
be employed
which hardens in contact with a wellbore fluid, such as water. Examples are
described in
International publication No. W02021/170588A1. In such cases, a single
cannister per
string could suffice.
Fig. 7 shows one non-limiting example of how the hydraulic circuit can be
designed.
The associated pump and valves may be packaged in a separate tool section. The
hydraulic
fluid is provided in a pressure-compensated reservoir 90 where the pressure is
kept equal to
the pressure outside of the elongate tool housing 3. Pump 91 is provided to
displace the
hydraulic fluid. In this example, the pump 91 is a unidirectional pump. The
outlet of pump
91 is split to two three-way valves 92,93 and a selectable valve 94. Two other
connections
of the three-way valves 92,93 are respectively connected directly to the
pressure-
compensated reservoir 90 (bypassing the pump 91), and the third connectors of
the three-
way valves are in connection with respectively connectors 95 and 96. These may
be joined
with two of the hydraulic fluid connectors 25. For example, connector 95 may
be joined
with the hydraulic fluid connector 25 which is in fluid communication with
piston bores
56a,56b, while connector 96 is joined with the hydraulic fluid connector 25
which is in
fluid communication with the piston rod annuli 58a,58b, as shown in Fig. 5
(and similar
other piston bores and piston rod annuli of other press devices provided in
the tool). The
outlet of the selectable valve 94 may be in communication with connector 96,
which in
turn may be connected to the third of the hydraulic fluid connectors 25, and
from there to a
hydraulic fluid first and second reservoirs 62,62' to actuate the treatment
fluid cannisters in
so far as provided in the tool.
The valves may be controlled electrically. To activate the press device(s),
three-way
valve 92 is selected to open pump 91 to connector 95 and block the connection
to the
pressure-compensated reservoir 90. At the same time, three-way valve 93 is in
opposite
position, blocking the connection with the pump 91 but opening the connection
to the
pressure-compensated reservoir 90. This allows circulation of the hydraulic
fluid from the
pressure-compensated reservoir 90 to the piston bores 56a,56b and from the
piston rod
annuli 58a,58b back into the pressure-compensated reservoir 90. When the
piston rods
53a,53b are in their end positions, the selectable valve 94 may be opened to
open the
cannister(s) to the pressure of the pump 91 and thereby start the injection of
the treatment
fluid. The stings may be restored to their retracted positions by reversing
the positions of
both three-way valves 92 and 93 whereby allowing circulation of the hydraulic
fluid from
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WO 2023/083945 PCT/EP2022/081438
the pressure-compensated reservoir 90 to the piston rod annuli 58a,58b and
from the piston
bores 56a,56b back into the pressure-compensated reservoir 90.
Many variations are possible for the hydraulic circuitry. For example, three-
way
valves 92 and 93 may be mechanically interlinked so that they mechanically
switch in
unison. Other variants may include use of a bi-directional pump.
The downhole tool may be used as follows. First, the downhole tool as
described
above is lowered into the borehole, through the downhole tubular, to a
selected depth.
Then, at the selected depth, the press device acting on the sting is
activated. Thereby the
sting is forced in the radially outward direction from the tool housing,
through a wall of the
downhole tubular, whereby in certain embodiments the wall of said downhole
tubular is
perforated. Subsequently, the downhole tool may be retrieved from the downhole
tubular
by pulling the downhole tool in upward direction through to borehole towards
surface.
Prior to retrieving the tool, the treatment fluid may be injected from the
downhole tool
through the sting into an annulus surrounding the downhole tubular.
At least part of the sting may be retracted prior to retrieving. This can be
done by
reversing the relative movement of the press device, in longitudinal
direction, with respect
to the sting. A distal end of the sting, for instance the end cap 41, may stay
behind in the
wall of the downhole tubular after retrieving the downhole tool. This practice
has been
proposed in e.g. W02020/229440A1.
The present disclosure is not limited to the embodiments as described above
and the
appended claims. Many modifications are conceivable, and features of
respective
embodiments may be combined. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified, combined and/or
practiced in
different but equivalent manners apparent to those skilled in the art having
the benefit of
the teachings herein.
In particular, the concept disclosed herein of providing dedicated treatment
fluid
cannisters for each sting can be applied to other types of injection stings
and expansion
mechanisms, including perforating tools as disclosed in e.g.: US Patent
2,381,929,
W02020/229440A1, a Kinley perforator tool (US Patent 3,199,287); drilling
tools
(W02018/115053A1), and more. Furthermore, the downhole tubular may already
have
been perforated prior to running the downhole injection tool, such as is the
case in above-
mentioned W02018/115053A1 wherein the drilling device may be pulled to surface
after
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WO 2023/083945 PCT/EP2022/081438
which a sealant injection device is positioned at the depth where the sealant
injection
channels had been drilled.
Furthermore, no limitations are intended to the details of construction or
design
herein shown, other than as described in the claims below. It is therefore
evident that the
particular illustrative embodiments disclosed above may be altered, combined
and/or
modified and all such variations are considered within the scope of the
present invention as
defined in the accompanying claims.
14
