Note: Descriptions are shown in the official language in which they were submitted.
APPARATUS AND METHOD FOR
ABRASIVE PERFORATING AND CLEAN-OUT
STATEMENT OF RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Serial No. 62/902,471
entitled
"Apparatus and Method for Abrasive Perforating and Clean-Out." That
application was filed
on September 19, 2019.
[0002] This application also claims the benefit of U.S. Serial No.
62/939,341 also entitled
"Apparatus and Method for Abrasive Perforating and Clean-Out." That
application was filed
on November 22, 2019.
[0003] The application is also filed as a continuation-in-part to U.S.
Serial 16/686,955 filed
November 18, 2019. That application is entitled "Multi-Cycle Wellbore Clean-
Out Tool."
[0004] The '955 application was itself filed as a continuation-in-part to
U.S. Serial No.
16/280,364. That application was filed February 20, 2019 and is also entitled
"Multi-Cycle
Wellbore Clean-Out Tool."
[0005] The '364 application claims the benefit of U.S. Serial No.
62/778,384 filed on
December 12, 2018 and U.S. Serial No. 62/677,023 filed May 27, 2018.
BACKGROUND OF THE INVENTION
[0006] This section is intended to introduce selected aspects of the art,
which may be
associated with various embodiments of the present disclosure. This discussion
is believed to
assist in providing a framework to facilitate a better understanding of
particular aspects of the
present disclosure. Accordingly, it should be understood that this section
should be read in
this light, and not necessarily as admissions of prior art.
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Field of the Invention
[0007] The present disclosure relates to the field of hydrocarbon recovery
operations.
More specifically, the invention relates to wellbore completions and
remediation operations.
Further still, the invention relates to a tool that may be connected to a
string of coiled tubing
(or other working string) and used for wellbore clean-out.
Discussion of Technology
[0008] During the course of a well operation, it is sometimes desirable to
clean out the
wellbore. For example, after a well is completed and before a string of
production tubing is
hung, the operator may wish to run a clean-out tool down the hole to circulate
out cement chips,
sand, and other debris. In addition, it is sometimes desirable to clean out a
producing well that
has become filled with sand. Such incidents may occur because the well is
producing from an
unconsolidated formation, or due to a poorly designed fracturing operation.
[0009] In either of these instances, a simple nozzle may be run into a
wellbore at the end
of a coiled tubing string. A coiled tubing connector may be used to connect
the coiled tubing
string with the nozzle. An aqueous circulating fluid is pumped down the
working string,
through the nozzle and then up the back side (or annulus) of the working
string. Preferably, a
surfactant, an acid or other chemical is injected down the coiled tubing
string following the
aqueous circulating fluid as part of the clean-out.
[0010] A separate type of tool that also involves circulating fluid down a
working string is
an abrasive perforating tool. Abrasive perforating tools utilize custom
lateral jetting ports that
allow a fluid containing abrasive particles, e.g., sand, to be pumped downhole
through the
working string at high pressures and then out of the jetting ports. The
abrasive fluid erodes
through the surrounding casing at a designated depth, then through the cement
and out into the
surrounding rock formation. This is an alternative to explosive charge
perforating and the use
of detonators and gun barrels.
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100111 Some abrasive perforating tools frequently offer a clean-out
function using reverse
circulation. In one aspect, an abrasive perforating tool may be part of a
bottom hole assembly
containing a reverse ball check valve. The BHA components include a CT
connector, a
disconnect, a stabilizer, an abrasive cutting sub having at least one jetting
nozzle, the reverse
ball check valve, and then the nozzle. A schematic view of such a device is
shown in Figure
1 of U.S. Patent No. 9,115,558.
[0012] The reverse ball check valve of the '558 patent includes a pin and a
ball. When
fluid is pumped down the coiled tubing, the reverse ball check valve is forced
closed,
preventing fluid from exiting the nozzle at the bottom of the BHA. Fluid is
then directed
through the lateral jetting ports for hydraulic perforating. Subsequently,
when sand or other
particulates are required to be cleaned out, a "reverse clean-out" procedure
is conducted.
[0013] To perform the reverse clean-out, an aqueous fluid is injected down
the back side
of the coiled tubing. The fluid is pumped downhole where it then flows back up
the BHA,
through the reverse ball check valve, through the bore of the coiled tubing
string and to the
surface. The fluid returns will include the abrasive fluid used in the
perforating process. A
somewhat schematic reverse clean-out flow for a BHA having a known reverse
ball check
valve is shown in Figure 2 of the same '558 patent.
[0014] As described in greater detail in the '558 patent, the use of
reverse flow clean-out
valves is often impractical in connection with horizontal wellbores. This is
because of the
significant likelihood of fill material gathering around the outer diameter of
the BHA during
the reverse circulation phase. In this respect, the BHA cannot take advantage
of gravity to
bring the fill material down to the nozzle as is present in a vertical well.
Depending on the size
of the wellbore, the length of the horizontal leg of the well and the cleanout
medium used, the
annular velocity (governed by gauge pressure at the surface) likely will not
be high enough to
sweep the entire fill to the end of the bottom hole assembly.
[0015] Due to this limitation, the '558 patent disclosed a novel abrasive
perforating tool
capable of being cycled during pumping operations to provide clean-out. This
allows for a
multi-cycle adjustment of tool function carried out by manipulating pumping
rates.
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[0016] The abrasive perforating tool of the '558 patent utilizes a plunger
that is moved up
and down in response to pumping rates applied at the surface. Depending on the
pumping
mode, the tool operates in either a flow-through mode where the plunger
resides above a seat,
or a perforating mode, where the plunger lands on the seat. In the flow-
through mode, working
fluids are circulated around the plunger, through the seat, and then back up
the wellbore along
the back side of the coiled tubing string. In the perforating mode, all fluids
are forced through
lateral nozzles and are directed against the surrounding casing. Beneficially,
fluids can be
pumped down the bore of the working string and through an end nozzle in the
same direction
for both abrasive perforating and for clean-out, using a cycling mechanism.
[0017] A need exists for an improved abrasive perforating tool that
operates with a similar
cycling mechanism for wellbore clean-out, but wherein a feature is provided to
ensure that
circulating fluids do not exit the tool through the lateral nozzles while the
tool is in its flow-
through mode. Stated another way, a need exists for a multi-cycle wellbore
perforating tool
that does not offer, as an option, split flow. A need further exists for a
method of cleaning out
a well, wherein a positive displacement motor is disposed below a perforating
tool, with the
motor taking advantage of a full flow of fluids moving through the seat during
a flow-through
mode.
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SUMMARY OF THE INVENTION
[0018] An abrasive perforating tool for controlling a direction of an
injected fluid within
a wellbore is first provided herein. The perforating tool is configured to
cycle between a
flow-through mode wherein all fluid is pumped under pressure through the tool
and then
circulated back up to the surface on the back side of the tool, and a
perforating mode wherein
an abrasive fluid is pumped under pressure into the tool and through lateral
jetting ports to
cut or "perforate" a surrounding casing string.
[0019] The perforating tool first includes a tubular housing. The tubular
housing defines
a series of tubular bodies tIffeadedly connected end-to-end. The tubular
housing provides an
elongated bore through which fluid may flow. The tubular housing includes one
or more
jetting ports disposed there along. The jetting ports are designed to receive
the abrasive fluid
when the tool is in a perforating mode.
[0020] The perforating tool also includes a piston. The piston defines a
short cylindrical
body that is disposed at an upstream end of the housing. The piston has an
orifice configured
to deliver fluids from a wellbore conveyance tubing to the elongated bore of
the housing. Of
interest, the piston forms a pressure shoulder as fluids are injected through
the conveyance
tubing.
[0021] The perforating tool additionally includes a tubular mandrel. The
tubular mandrel
is slidably positioned within the housing. The mandrel has a proximal end
connected to or
otherwise acted upon by the piston, and a distal end comprising a plunger. In
one
embodiment, the plunger is a separate body threadedly connected to the distal
end of the
mandrel.
[0022] As part of the tubular housing, The perforating tool may comprise a
spring
housing. The spring housing has an internal shoulder that supports a spring.
An upper end
of the spring acts against the piston, biasing the piston and connected
mandrel in the raised
position. This is a flow-through mode.
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[0023] The perforating tool further includes a seat. The seat is disposed
along the tubular
housing below the distal end of the tubular mandrel. The seat is dimensioned
to receive the
plunger when the piston and connected tubular mandrel slide from a raised
position to a
lowered position along the tubular housing. Of interest, the seat provides a
central flow-
through opening through which fluids flow when the tool is in its flow-through
mode.
[0024] Preferably, the tubular housing further includes an upper sub having
a first upper
end and a second lower end, wherein the lower end is threadedly connected to
an upper end
of the spring housing. Preferably, the tubular housing also includes a lower
sub having a
first upper end and a lower end, with the lower end being threadedly connected
to a downhole
rotary tool.
[0025] In one aspect, the wellbore clean-out tool further comprises:
an annular region formed between the mandrel and the surrounding tubular
housing;
one or more slots residing along the mandrel;
one or more flow ports also residing along the mandrel, but below the slots;
an upper seal residing along an inner diameter of the tubular housing; and
a separate lower seal also residing along the inner diameter of the tubular
housing, wherein the upper and lower seals straddle the jetting ports.
[0026] When the perforating tool is in its raised position, pumped fluid
exits the mandrel
through the flow ports, but the lower seal prevents the pumped fluid from
flowing all the way
up the annular region and to the jetting ports, thereby forcing all of the
fluid to flow around
the plunger and through the seat. Reciprocally, when the perforating tool is
in its lowered
position, abrasive fluid exits the mandrel through the slots, with the
abrasive fluid being
confined by the upper and lower seals to flow through the jetting ports.
[0027] The perforating tool is configured to cycle a position of the
mandrel and
connected plunger in response to fluid pumping rate into the wellbore.
Preferably, the tool
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is configured to cycle between two operating modes ¨ a flow-through (or a
clean-out) mode
and a perforating mode. All fluid flows through the flow-through opening in
the seat when
the mandrel and connected plunger are in the raised position, which is the
flow-through
mode. Reciprocally, all fluid flows through the jetting ports when the mandrel
and connected
plunger are in the lowered position, which is the abrasive perforating
position.
[0028] In one embodiment, a positive displacement motor is disposed below
the tubular
housing as the rotary tool. The positive displacement motor is operatively
connected to the
lower sub at its distal end. The positive displacement motor, in turn, is
connected to a milling
tool or a drill bit.
[0029] In the flow-through mode, fluid is pumped into the bore of the
tubular housing at
a first flow rate. In this mode, all of the pumped fluid flows into the
mandrel, through flow
ports located along the mandrel, around the plunger, and then through the flow-
through
opening in the seat.
[0030] In the perforating mode, the fluid is pumped into the bore of the
tubular housing
at a second higher flow rate. In this mode, all of the pumped fluid flows into
the mandrel,
through the slots located along the mandrel, and then through the jetting
ports. In this
instance, the pumped fluid is preferably mixed with sand, forming an abrasive
perforating
fluid.
[0031] In the preferred embodiment, the mandrel and connected plunger
remain in a
raised position during run-in. The plunger is maintained a sufficient distance
above the seat
to permit fluid to travel through the flow ports in the mandrel and through
the seat below.
Once the pump rate is raised to an activation rate (referred to in some
instances herein as the
"second flow rate"), the plunger is lowered onto the seat, providing for the
perforating mode.
The upper and lower seals serve to direct flow in the two modes, ensuring that
there is no
split flow.
[0032] To facilitate the cycling of injection modes, the abrasive
perforating tool may also
include a sequencing mechanism. The sequencing mechanism is responsive to a
sequence
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of pump rates applied above the piston. In one aspect, the sequencing
mechanism comprises
a cylindrical body configured to cycle the mandrel between its flow-through
mode (wherein
all fluid flows through the seat at the end of the tool) and its perforating
mode (wherein all
fluid is directed laterally through the jetting ports). In one aspect, an
intermediate position
is provided wherein the mandrel and connected plunger reside between the
raised position
and the lowered position but the mandrel remains in its flow-through mode.
100331 Preferably, the sequencing mechanism is a J-slot sequencing
mechanism. The J-
slot mechanism will cooperate with one or perhaps two pins that are disposed
along the
tubular housing as a J-slot collar. The pins are configured to ride in slots
along the J-slot
mechanism to cycle the mandrel and connected plunger between the raised
position and the
lowered position. In this instance, the pins are fixed from axial movement and
ride in the
slots of the J-slot channel of the mandrel to restrict axial movement of the
mandrel on
alternating downward strokes.
100341 A method of operating an abrasive perforating tool in a wellbore is
also provided.
The method first includes running a multi-cycle perforating tool into the
wellbore. The
perforating tool is run in on a lower end of a string of coiled tubing. The
perforating tool is
arranged in accordance with the perforating tool as described above, in any of
its
embodiments.
100351 The method additionally includes locating the perforating tool at a
selected depth
along the wellbore. In one aspect, the wellbore has been completed with a
string of
production tubing. In this instance, the perforating tool is run into the
production tubing in
order to clean out fill that may have accumulated within the production tubing
and casing.
More preferably, the perforating tool is run into production casing during
well completion,
enabling the tool to both mill out plugs or clean out wellbore debris, and
perforate casing. It
is observed that the tool is particularly suited for clean-out operations or
tool setting
operations along a horizontal section of a wellbore.
[0036] The method further includes pumping a working fluid down the coiled
tubing and
into the bore of the tubular housing. This injection is done at a first flow
rate. This injection
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causes the pumped fluid to flow through the bore of the tubular housing, out
of the mandrel
through radial flow ports and into the annular area, around the plunger, and
then through the
flow-through opening in the seat. In other words, the pumped fluid flows
entirely through
the end of the tool. This is a flow-through mode.
[0037] The method also includes further pumping the working fluid down the
coiled
tubing and into the bore of the tubular housing at a second flow rate. Here,
the second flow
rate is higher than the first flow rate. This increases a hydraulic force
acting on the pressure
shoulder of the piston, and causes the mandrel and connected plunger to slide
downward
along the tubular housing.
[0038] As the mandrel and connected plunger move down the tubular housing,
the
plunger will land on the seat, sealing flow through the flow-through opening.
In this position,
the fluid will flow down the mandrel, through slots in the mandrel and into
the annular area,
and then through the lateral jetting ports. This is a perforating mode. Of
interest, in this
position the upper and lower seals confine the fluid so that all working fluid
exits the tool
through the lateral jetting ports. In this mode, the pumped fluid will likely
include sand.
[0039] In one aspect, the perforating tool employs a sequencing mechanism
to cycle the
tool between positions. Preferably, the sequencing mechanism is a so-called J-
slot
mechanism. In one aspect, the J-slot mechanism has slots that cycle the
plunger between the
flow-through mode and the perforating mode. Specifically, the J-slot mechanism
is
configured to:
(i) maintain the perforating tool in its raised position while pumping at or
below the first pump rate, placing the perforating tool in its flow-through
mode
wherein all of the pumped fluid flows through the bottom of the tool;
(ii) maintain the perforating tool in an intermediate position while
increasing
pump rate above the first pump rate (which may meet or exceed a second pump
rate),
and wherein all of the pumped fluid continues to flow through the mandrel and
out
of the bottom of the tool;
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CA 3064105 2019-12-06
(iii) upon dropping the pump rate back down to or below the first pump rate,
allowing the spring to move the perforating tool back to its raised position,
which
again is the flow-through mode;
(iv) upon raising the pump rate to a rate that meets or exceeds the second
pump rate, move the perforating tool to its lowered position, placing the
perforating
tool in its perforating mode wherein all pumped fluid is forced through the
lateral
jetting nozzles; and
(v) repeat the cycle of steps (i) through (iv), such as at a different depth.
[0040] A second embodiment of a perforating tool is also provided herein.
The
perforating tool is again used for controlling a direction of a working fluid
within a wellbore,
with the wellbore having been lined with a string of production casing. In
this embodiment,
the perforating tool comprises:
a tubular housing providing an elongated bore through which fluids may be
injected, the tubular housing having one or more lateral jetting ports;
a piston disposed proximate an upstream end of the housing, the piston
forming a pressure shoulder and having an orifice configured to deliver the
working
fluid from a wellbore conveyance tubing into the elongated bore of the
housing;
a tubular mandrel slidably positioned within the housing, the mandrel having
a proximal end connected to or acted upon by the piston, and a distal end
forming a
plunger;
one or more flow ports; and
a seat disposed along the tubular housing and having a through-opening, the
through-opening being configured to slidably receive the plunger when the
piston and
connected mandrel slide from a raised position to a lowered position along the
tubular
housing.
[0041] In this arrangement, the perforating tool is configured to cycle a
position of the
mandrel and connected plunger in response to changes in fluid pumping rate
into the
conveyance tubing. The tool is biased to an abrasive perforating position such
that (i) all
CA 3064105 2019-12-06
working fluid flows through the flow ports in the mandrel and out of the
lateral jetting ports
in the tubular housing above the seat when the mandrel and connected plunger
are in the
raised position. In response to an increase in pump rate (ii) all working
fluid flows through
the flow ports and out of the tubular housing below the seat when the mandrel
and connected
plunger are in the lowered position.
[0042] The plunger comprises a solid body that is operatively connected to
the distal end
of the mandrel. Preferably, the perforating tool further comprises a stem
wherein an upper
end of the stem is threadedly connected to a lower end of the mandrel, and the
plunger resides
at a lower end of the stem. In this instance, the one or more flow ports
comprises two or
more flow ports radially disposed around the stem proximate to and above the
plunger.
[0043] In one aspect, the tubular housing comprises a spring housing having
an internal
shoulder. The perforating tool then further comprises a spring residing within
the spring
housing, with an upper end of the spring acting against the piston, biasing
the tool in its raised
position.
[0044] In one arrangement, the tubular housing further comprises an upper
sub having a
first upper end and a second lower end, wherein the lower end is threadedly
connected to an
upper end of the spring housing, and a lower sub having a first upper end and
a lower end,
with the lower end being threadedly connected to a downhole tool. In this way,
the
perforating tool is part of a larger bottom hole assembly, or BHA.
Brief Description of the Drawings
[0045] So that the manner in which the present inventions can be better
understood, certain
illustrations, charts and/or flow charts are appended hereto. It is to be
noted, however, that the
drawings illustrate only selected embodiments of the inventions and are
therefore not to be
considered limiting of scope, for the inventions may admit to other equally
effective
embodiments and applications.
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[0046] Figure lA is a first cross-sectional view of a perforating tool (or
"flow diverter") of
the present invention, in one embodiment. In this view, the perforating tool
is in its run-in
position. A plunger is in a raised position, allowing injected fluids to flow
through a flow-
through opening at the bottom of the tool.
[0047] Figure 1B is a second cross-sectional view of the perforating tool
of Figure 1A.
The perforating tool is again in its raised position, or flow-through mode.
Here, a flow path of
injected fluid is shown.
[0048] Figure 1C is a third cross-sectional view of the perforating tool of
Figure 1A. Here,
the perforating tool has been cycled to an intermediate position. In this
position, the plunger
has advanced partially down the tool, but all of the injected fluid continues
to flow through the
seat at the bottom of the tool.
[0049] Figure 2A is a cross-sectional view of the perforating tool of
Figure 1A. Here, the
tool has advanced to its lowered position. This is an abrasive perforating
mode, with all of the
injected fluids being diverted from the tool through lateral jetting ports.
[0050] Figure 2B is a second cross-sectional view of the perforating tool
of Figure 2A.
The perforating tool again is in its lowered position, or abrasive perforating
mode. Here, a
flow path of injected perforating fluid is shown.
[0051] Figure 3A is a perspective view of a positive displacement motor as
may be placed
below the perforating tool of Figures lA and 2A.
[0052] Figure 3B is an example of a suitable sliding sleeve shifting tool
that may be used
as part of a bottom hole assembly with the perforating tool of Figures lA and
2A.
[0053] Figure 3C is an example of a bridge plug that may be set, retrieved
or drilled out
using a bottom hole assembly that includes the perforating tool of Figures lA
and 2A.
[0054] Figure 3D is an example of an extended reach tool that may be used
as part of a
bottom hole assembly with the perforating tool of Figures 1A and 2A.
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[0055] Figure 4A is a side view of a j-slot mechanism. In this view, pins
are in a default
position along the slots.
[0056] Figure 4B is another side view of the j-slot mechanism of Figure 4A.
In this view,
the pins have advanced along the channel and are in an intermediate position.
To achieve this,
a mandrel has been pushed down along a spring housing.
[0057] Figure 4C is another side view of the j-slot mechanism of Figure 4A.
In this view,
the pins have advanced along the channel to a second slot, allowing the
mandrel to return to
its default position of Figure 4A.
[0058] Figure 4D is still another side view of the j-slot mechanism of
Figure 4A. In this
view, the pins have advanced to a new slot along the channel, allowing the
mandrel to move
into its fully lowered position. In this position, the plunger lands on the
seat per Figure 2A.
[0059] Figure 5A is side view of the mandrel of Figures lA and 2A. So
called J-slots are
visible along the outer diameter of the mandrel. These are part of a
sequencing mechanism.
[0060] Figure 5B is a cross-sectional view of the mandrel of Figure 5A. The
view of the
J-slots is retained in phantom.
[0061] Figure 6A is cross-sectional view of a J-slot collar, in one
embodiment. The J-slot
collar includes a pair of opposing pins that ride in the J-slots of Figure 5A.
The J-slot collar is
also part of the sequencing mechanism.
[0062] Figure 6B is a perspective view of the J-slot collar of Figure 6A.
[0063] Figure 7 is a cross-sectional view of the jetting port housing of
Figures 1A and 2A.
Jetting ports are visible in the body of the housing.
[0064] Figure 8A is a side view of the piston assembly of Figures lA and
2A.
[0065] Figure 8B is a cross-sectional view of the piston assembly of Figure
8A.
[0066] Figure 8C is a perspective view of the piston assembly of Figure 8A.
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[0067] Figure 9A is a side view of the plunger of Figures lA and 2A.
[0068] Figure 9B is a cross-sectional view of the plunger of Figure 9A.
[0069] Figure 9C is a perspective view of the plunger of Figure 9A.
[0070] Figure 10 is a cross-sectional view of an illustrative wellbore.
Here, the wellbore
has received the perforating tool of Figures lA and 2A.
[0071] Figure 11 is a flow chart showing operational steps for controlling
a flow of fluid
through the perforating tool, in one arrangement.
[0072] Figure 12A is a first cross-sectional view of a perforating tool (or
"flow diverter")
of the present invention, in an alternate embodiment. In this view, the
perforating tool is in its
run-in position. This is an abrasive perforating mode, with all of the
injected fluids being
diverted from the tool through lateral jetting ports.
[0073] Figure 12B is a second cross-sectional view of the perforating tool
of Figure 12A.
Here, the perforating tool has been cycled to an intermediate position. In
this position, the
plunger has advanced partially down the tool, but all of the injected fluid
continues to flow
through the lateral jetting ports.
[0074] Figure 12C is a third cross-sectional view of the perforating tool
of Figure 12A.
Here, the tool has advanced to its lowered position. This is a flow-through
mode where all of
the injected fluid flows through a seat at the bottom of the tool.
Detailed Description of Certain Embodiments
Definitions
[0075] For purposes of the present application, it will be understood that
the term
"hydrocarbon" refers to an organic compound that includes primarily, if not
exclusively, the
elements hydrogen and carbon. Examples of hydrocarbon-containing materials
include any
form of oil, natural gas, coal, and bitumen that can be used as a fuel or
upgraded into a fuel.
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[0076] As used herein, the term "hydrocarbon fluids" refers to a
hydrocarbon or mixtures
of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may
include a
hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation
conditions, at
processing conditions, or at ambient condition.
[0077] As used herein, the terms "produced fluids," "reservoir fluids" and
"production
fluids" refer to liquids and/or gases removed from a subsurface formation,
including, for
example, an organic-rich rock formation. Produced fluids may include both
hydrocarbon
fluids and non-hydrocarbon fluids. Production fluids may include, but are not
limited to, oil,
natural gas, pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal,
nitrogen, carbon
dioxide, hydrogen sulfide and water.
[0078] As used herein, the term "fluid" generally refers to gases, liquids,
and combinations
of gases and liquids, as well as to combinations of gases and fines,
combinations of liquids and
fines, and combinations of gases, liquids, and fines.
[0079] As used herein, the term "wellbore fluids" means water, hydrocarbon
fluids,
formation fluids, or any other fluids that may be within a wellbore during a
production
operation.
[0080] As used herein, the term "formation" refers to any definable
subsurface region
regardless of size. The formation may contain one or more hydrocarbon-
containing layers,
one or more non-hydrocarbon containing layers, an overburden, and/or an
underburden of any
geologic formation. A formation can refer to a single set of related geologic
strata of a specific
rock type, or to a set of geologic strata of different rock types that
contribute to or are
encountered in, for example, without limitation, (i) the creation, generation
and/or entrapment
of hydrocarbons or minerals, and (ii) the execution of processes used to
extract hydrocarbons
or minerals from the subsurface region.
[0081] As used herein, the term "wellbore" refers to a hole in the
subsurface made by
drilling or insertion of a conduit into the subsurface. The term "well," when
referring to an
opening in the formation, may be used interchangeably with the term
"wellbore."
CA 3064105 2019-12-06
[0082] As used herein, the term "subsurface" refers to geologic strata
occurring below the
earth's surface.
[0083] The terms "zone" or "zone of interest" refer to a portion of a
formation containing
hydrocarbons. Sometimes, the terms "target zone," "pay zone," or "interval"
may be used.
[0084] As used herein, the terms "working fluid" and "clean-out fluid"
refer to any fluid
that may be pumped into a wellbore in connection with a downhole flow-diverter
tool. Such
fluids may include aqueous fluids, fluids containing an abrasive material used
for perforating
casing, a hardware treating fluid, or a fluid containing a surfactant.
[0085] The terms "tubular" or "tubular member" refer to any pipe, such as a
joint of casing,
a portion of a liner, a joint of tubing, a pup joint, or coiled tubing. The
terms "production
tubing" or "tubing joints" refer to any string of pipe through which reservoir
fluids are
produced.
Description of Specific Embodiments
[0086] The present disclosure relates to hydraulic clean-out operations for
pipe. The tools
and methods disclosed herein are ideally suited for wellbore operations,
including using the
perforating tool in combination with a downhole positive displacement motor
and mill bit.
[0087] Figure 1A is a cross-sectional view of a wellbore clean-out tool 100
of the present
invention, in one embodiment. In some cases herein, the perforating tool 100
may be referred
to as a flow diverter. The perforating tool 100 is used to inject fluids into
a wellbore for clean-
out and for abrasive perforating. An illustrative wellbore is shown at 1000 in
Figure 10 and
is discussed below.
[0088] The perforating tool 100 defines a generally tubular body formed
from a series of
components. As shown, the perforating tool 100 has a first (or upstream) end
102 and a second
(or downstream) end 104. A central bore 105 is formed within the body
extending from the
first end 102 to the second end 104.
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CA 3064105 2019-12-06
[0089] As will be discussed, the perforating tool 100 is configured to
cycle or otherwise
move a position of a mandrel 155 and a connected plunger 160 within the
tubular body, in
response to fluid pumping rates into the wellbore 1000 by an operator. In this
way, a flow of
working fluid through the tool 100 may be adjusted. In the view of Figure 1A,
the perforating
tool 100 is in its run-in position wherein all of the injected fluid flows
through the tool 100
from the top (or upstream) end 102 to the bottom (or downstream) end 104 en
route to a next
downhole tool or to the bottom of the wellbore 1000 or to a plug, as the case
may be.
Specifically, the fluid will flow into the bore 105, out of the mandrel 155
through side ports
185, then through an annular area 145 around the plunger 160, and through a
seat 170.
[0090] Of interest, a lower seal 164 resides along a lower mandrel seal sub
160 and inside
of a jetting port housing 140 . This is just above the flow ports 185. A seal
164 prevents
working fluids from flowing up the annular area 145 to a level of lateral
jetting nozzles (or
jetting ports) 148 when the tool 100 is in its flow-through mode.
100911 The perforating tool 100 is comprised of a series of tubular bodies
that are
threadedly connected end-to-end. A first of these represents a top sub 110.
The top sub 110
defines a tubular body wherein a first (or upstream) end 112 comprises female
threads while a
second (or downstream) end 114 comprises male threads. The female threads are
configured
to threadedly connect to a CT connector (not shown), which in turn is
connected to a string of
coiled tubing (or other conveyance medium).
100921 The perforating tool 100 next includes a spring housing 120. The
spring housing
120 also defines a generally tubular body wherein a first end 122 comprises
female threads
while a second opposite end 124 comprises male threads. The first end 122 of
the spring
housing 120 threadedly connects to the second (or downstream) end 114 of the
top sub 110.
[0093] The perforating tool 100 also includes a spring 125. The spring 125
resides along
an inner diameter of the spring housing 120. The spring 125 is held in
compression within the
tool 100. In one aspect, the spring 125 is an Inconel spring. Alternatively,
the spring material
is 17-7 stainless steel. Of interest, a shoulder 126 resides along an inner
diameter of the spring
housing 120. The shoulder 126 serves as a face against which the spring 125
resides.
17
CA 3064105 2019-12-06
100941 Moving down the tool 100, the perforating tool 100 next includes an
upper mandrel
seal sub 130. The upper mandrel seal sub 130 also defines a generally tubular
body wherein a
first (or upstream) end 132 comprises female threads while a second opposite
(or downstream)
end 134 comprises male threads. The upstream end 132 threadedly connects to
the second (or
downstream) end 124 of the spring housing 120. Of interest, the upper mandrel
seal sub 130
encompasses a sequencing mechanism 400, discussed below.
[0095] The perforating tool 100 also comprises a jetting port housing 140.
The jetting port
housing 140 also defines a generally tubular body wherein a first (or
upstream) end 142
comprises female threads while a second (or downstream) opposite end 144 also
comprises
female threads. The jetting port housing 140 resides downstream from the upper
mandrel seal
sub 130. Specifically, the first end 142 of the jetting port housing 140
threadedly connects to
the second end 134 of the upper mandrel seal sub 130.
100961 Of importance, the jetting port housing 140 comprises one or more
jetting ports
148. Preferably, the jetting ports 148 are placed within the jetting port
housing 140 at a 900
angle, or transverse to a longitudinal axis of the tool 100. In this way, when
the tool 100 is in
its perforating mode, jetting fluid may exit the jetting port housing 140
directly at the
surrounding casing to be perforated. Preferably, a plurality of lateral
jetting ports 148 are
placed radially around the jetting port housing 140 along at least two levels.
[0097] As a next component, the perforating tool 100 includes a lower
mandrel seal sub
180. The lower seal sub 180 defines a generally tubular body that is
essentially a mirror image
of the upper mandrel seal sub 130. Seal subs 130 and 180 are the same
component, but with
sub 160 being turned upside down. An upper end 182 of the lower seal sub 180
is threadedly
connected to the lower end 144 of the jetting port housing 140.
[00981 Below the lower seal sub 180 is a bottom sub 190. The bottom sub 190
also defines
a tubular body having an upper end 192 and a lower end 194. The upper end 192
comprises
male threads that connect to a female bottom end 184 of the lower mandrel seal
sub 180.
The bottom sub 190 forms a bore 195 that is in fluid communication with and
forms a part of
the bore 105.
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CA 3064105 2019-12-06
[0099] The top sub 110, the spring housing 120, the upper mandrel seal sub
130, the jetting
port housing 140, the lower mandrel seal sub 180 and the bottom sub 190
together make up a
tubular housing for the perforating tool 100.
[0100] The perforating tool 100 additionally includes a piston assembly
150. The piston
assembly 150 defines a series of components that are configured to slide
together along the
spring housing 120 in response to fluid pressure. The piston assembly 150
includes an orifice
retainer 151, a piston body 156, a piston orifice 153 and a piston scraper
retainer 157. The
piston assembly 150 essentially serves as a pressure shoulder, moving down the
spring housing
120 in response to fluid pressure applied from the surface.
[0101] It is observed here that while it is pressure that moves the piston
assembly 150
down, it is also accurate to refer to changes in flow rate that actuate the
piston assembly 150.
This is because the piston orifice 153 is configured according to a desired
flow rate to cause
the tool 100 to change between operational modes. In this respect, the orifice
153 is sized to
generate the required differential pressure across itself to function.
External pressures do not
have an impact on the piston assembly 150; only pressure from the flow rate
through the orifice
153 changes the tool mode.
[0102] The orifice retainer 151 secures the piston assembly 150 in place
below the top sub
110. Specifically, the orifice retainer 151 abuts the lower end 114 of the top
sub 110 to prevent
the piston assembly 150 from moving further upstream. Various o-rings (not
numbered) may
be disposed around the piston body 156 and the piston orifice 153 to prevent
pressure
communication between the area above the piston assembly 150 and below the
piston assembly
150. Additional details concerning the piston assembly 150 are provided below
in connection
with Figures 8A through 8C.
[0103] As stated above, the piston assembly 150 is operatively connected to
a mandrel 155.
The mandrel 155 has an upper (or upstream) end 152 connected to (or acted upon
by) the piston
assembly 150, and a lower (or downstream) end 154. The upper end 152 of the
mandrel 155
is threadedly connected to the piston body 156. The piston assembly 150 and
connected
mandrel 155 reside within the inner diameter of the spring housing 120. Of
interest, an upper
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CA 3064105 2019-12-06
end of the spring 125 acts against the piston scraper retainer 157, biasing
the piston assembly
150 against the top sub 110.
[0104] In operation, hydraulic pressure (generated by fluid flow through
the piston orifice
153) acts on the shoulder that is the upper side of the piston assembly 150
above the piston
orifice 153. In response, the piston assembly 150 and connected mandrel 155
move down the
tubular housing 110 together. Specifically, the piston assembly 150 (and
connected mandrel
155) moves from its raised position (shown in Figure 1A), to a lowered
position (shown in
Figure 2A).
[0105] It is noted that the spring 125 resides in an annular region formed
between the
mandrel 155 and the surrounding spring housing 120. This first annular region
is pressure-
balanced via ports 159 in the mandrel 155. These ports let the fluid volume
inside the spring
housing 120 change as the piston assembly 150 moves up and down.
[0106] A second annular area 145 is reserved between the mandrel 155 and
the surrounding
jetting port housing 140. A pair of annular seals 162, 164 resides within the
annular area 145.
The seals 162, 164 may be mechanically or adhesively affixed to inner
diameters of the upper
mandrel seal sub 130 and the lower mandrel seal sub 180, respectively. Thus,
the seals 162,
164 do not slide along the bore 105 with the mandrel 155.
[0107] It is observed that the seals represent an upper seal 162 and a
lower seal 164. The
two seals 162, 164 straddle the jetting ports 148 along the jetting port
housing 140.
101081 At the lower end 154 of the mandrel 155 is a plunger 160. The
plunger 160 defines
a short body that is configured to sealingly land onto a seat 170 (described
below). An upper
end 162 of the plunger 160 is connected to the lower end 154 of the mandrel
155. In this way,
the plunger 160 moves up and down along the bore 105 of the perforating tool
100 with the
mandrel 155.
[0109] The mandrel 155 also includes one or more flow ports 185. The flow
ports 185
preferably reside immediately above the plunger 160. The flow ports 185
provide fluid
CA 3064105 2019-12-06
communication between the bore 105 of the tool 100 and the annular region 145
when the
wellbore clean-out tool 100 is in its flow-through mode.
[0110] Finally, the perforating tool 100 comprises a seat 170. The seat 170
defines a short
tubular body having a flow-through opening 175. The seat 170 is configured to
sealingly
receive the plunger 160 when the piston body 150 is moved to a lowered
position (seen in
Figure 2A). Of interest, the opening 175 is sized to provide little to no
restriction in dovvnhole
fluid flow when the plunger 160 is in the flow-through mode of Figure 1A.
[0111] In the view of Figure 1A, the piston body 150 is at is uppermost
position. This is
its default (or raised) position wherein the orifice retainer 155 is abutting
the lower end 114 of
the top sub 110. As noted, the piston body 150 is held in this default
position due to the upward
mechanical force provided by the spring 125.
101121 A piston o-ring may be disposed around the piston body 156 to
prevent pressure
communication between the area above the piston body 156 and below the piston
body 156
when fluid is passing through the orifice 153. Additionally, an orifice o-ring
may be disposed
around the orifice 153 to prevent pressure communication between the area
above the orifice
153 and below the orifice 153 when fluid is passing through the orifice 153.
[0113] In the raised position of Figure 1A, fluid is injected by an
operator into the bore
105 of the perforating tool 100 under a first pressure. The first pressure
correlates to a first
flow rate. Those of ordinary skill in the art will understand that there is a
correlation between
flow rate, tubular dimension and pressure. At the first flow rate, the
hydraulic pressure acting
on the piston assembly 150 is not great enough to cause the piston assembly
150 to compress
the spring 125.
101141 In the position of Figure 1A, the plunger 160 remains in its raised
position above
the seat. As working fluid is injected into the wellbore 1000 at the first
flow rate, fluid will
pass through the bore 105 of the tool 100, through the flow ports 185, into
the annular region
145, around the plunger 160, and then down through the flow-through opening
175 of the seat
170.
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CA 3064105 2019-12-06
[0115] Figure 1B is another cross-sectional view of the perforating tool
100 of Figure 1A.
In this view, line 50A is provided to demonstrate a path of the injected
fluids for the tool in its
flow-through mode. Fluids are shown entering the upper end 102 of the tool
100, and then
ultimately passing out of the lower end 104 according to the flow path
described immediately
above. Of interest, all pumped fluids pass through the flow ports 185, into
the annular area
145, around the plunger 160, through the opening 175 in the seat 170, and on
to any bottom
hole assembly that may reside below the tool 100. Beneficially, the lower seal
164 prevents
pumped fluids from flowing back up the annular area 145 to a level of lateral
jetting nozzles
(or jetting ports) 148 when the tool 100 is in its flow-through mode.
[0116] In operation, once the wellbore clean-out tool 100 is set at a
desired depth within
the wellbore 1000, the operator will begin pumping. During pumping, the
operator will
increase the pump rate. This will apply a greater hydraulic force to the
shoulder of the piston
assembly 150 and will start to overcome the biasing force of the spring 125
(plus any friction
created by o-rings). The piston assembly 150, the mandrel 155 and its
connected plunger 160
will then start to move down the bore 105.
[0117] The aperture size of the orifice 153 defines the activation rate.
Thus, one aspect of
using the abrasive perforating tool 100 involves the selection of the aperture
size of the orifice
153. Alternatively or in addition, the operator may select an opening size for
the flow ports
185 and the seat 170.
101181 Figure IC is still another cross-sectional view of the perforating
tool 100 of Figure
1A. Here, an increase in fluid pumping pressure from the surface is acting on
the piston body
156, causing the piston body 156 and connected mandrel 155 and plunger 160 to
advance down
the spring housing 120. Stated another way, hydraulic pressure acting on the
piston body 156
overcomes the upward biasing force of the spring 125, causing the mandrel 155
and plunger
160 to move towards the seat 170.
[0119] In Figure 1C, the perforating tool 100 is in an intermediate
position. In this
position, all of the injected fluid continues to flow through the end 104 of
the tool 100. In this
respect, fluids continue to flow through the flow ports 185, into the annular
area 145, around
22
CA 3064105 2019-12-06
the plunger 160, and through the flow-through opening 175 of the seat 170.
Lower seal 164
prevents the fluids from moving up the annular region 145 and accessing the
jetting ports 148.
10120] Figure 2A is another cross-sectional view of the multi-cycle
perforating tool 100
of Figure 1A. Here, the perforating tool 100 has further translated (that is,
has moved down
the spring housing 120) to its abrasive perforating position. This is done by
further increasing
the hydraulic force acting on the piston assembly 150. Specifically, an
increased flow rate
from the surface acts on the body 156 of the piston assembly 150.
[0121] The increased hydraulic force is achieved by increasing pump rate of
the hydraulic
fluid into the wellbore from the surface. In response to the increased
pressure (or increasing
flow rate), the piston body 156 and operatively connected mandrel 155 and
plunger 160 have
slid down to a position where the lower end 164 of the plunger 160 lands on
the seat 170.
[0122] It is observed from Figure 2A that in addition to flow ports 185,
the mandrel 155
also includes slots 165. The slots 165 reside higher up the mandrel 155, that
is, above flow
ports 185. The slots 165 also provide fluid communication between the bore 105
and the
annular region 145. In the flow-through mode of Figures 1A and 1C circulation
fluids that
flow through the slots 165 are blocked from leaving the tool 100 by the upper
seal 162.
However, in the perforating mode of Figure 2A, as the mandrel 155 has moved
down, the slots
165 have moved into a position adjacent the jetting ports 148. Thus, abrasive
perforating fluids
are injected through the slots 165 and through the jetting ports 148.
101231 Figure 2B is another cross-sectional view of the multi-cycle
abrasive perforating
tool 100 of Figure 2A. The perforating tool 100 again is in its lowered
position, or abrasive
perforating mode. In this view, line SOB is provided to demonstrate a flow
path of the
perforating fluids for the tool 100. Fluids are shown entering the upper end
102 of the tool
100, and then exiting out of the jetting ports 148. Of interest, all fluids
exit the tool 100 through
the slots 165, and are confined to exit through the jetting ports 148 by the
upper 162 and lower
164 seals.
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CA 3064105 2019-12-06
101241 It is also observed that in the perforating position of Figures 2A
and 2B, fluid
communication remains between the bore 105 and the annular region 145 through
the flow
ports 185. However, any fluids that exit the flow ports 185 or that reside in
the annular region
145 below the lower seal 164 are trapped. Fluids can exit neither the flow-
through opening
175 of the seat 170 nor the jetting ports 148. Thus, complete fluid isolation
is provided in both
the flow-through mode and the perforation mode, meaning there is no "split
flow."
[0125] As described above, the cycling of the tool 100 between its raised
position (Figure
1A) and its lowered position (Figure 2A) may be accomplished by applying
pumping pressure
against the biasing force of the spring 125. However, in a more preferred
embodiment a
mechanical sequencing mechanism is also used. The sequencing mechanism is
preferably a J-
slot mechanism as shown at 400 in Figures 4A-4D, discussed below. The
sequencing
mechanism 400 allows the operator to cycle the flow rates to move the tool 100
between
settings so that:
(i) In a first setting, the plunger 160 is in a raised position in response to
the
biasing mechanical force exerted by the spring 125 on the mandrel 155, placing
the
tool in its flow-through mode. This is the view of Figure 1A.
(ii) In a second setting, the pumping rate is increased and the J-slot
mechanism 400 advances to a next slot, allowing the plunger 160 to move down
to
an intermediate position. In the intermediate position, the tool 100 remains
in its
flow-through mode, allowing the operator to inject hydraulic fluid into the
bore 105
of the tubular housing 110 and through the seat 170 at a second rate, or at
any rate
higher than the second rate. This is the view of Figure 1C.
(iii) In the first setting again, hydraulic pumping rate is reduced to its
first
rate, or any rate below the first rate, allowing the plunger 160 to return to
its raised
position. The perforating tool 100 remains in its flow-through mode.
(iv) Finally, in a third setting, the plunger 160 is forced down into a
lowered
position in response to the injection of hydraulic fluid through the piston
assembly
150 and into the perforating tool 100 at a second rate, or at any rate higher
than the
24
CA 3064105 2019-12-06
second rate. The J-slot mechanism 400 advances to a next slot, placing the
perforating tool 100 in its abrasive perforating mode. This is the view of
Figure 2A.
[0126] Beneficially, in the second setting the operator may ramp up the
pumping pressure
and be assured that all fluids are passing through the seat. This allows the
operator to place a
bottom hole assembly at the end of the bottom sub, conducting an additional
wellbore function.
[0127] An example of such a function is the milling out of a plug or
drilling through the
bore of a section of horizontal casing that is screened out or contains
debris. In this respect,
the bottom end 194 of the sub 190 is configured to threadedly connect to a
separate tool that
may be placed in the wellbore 1000 below the perforating tool 100. For
example, a positive
displacement motor may be placed downstream from the perforating tool 100.
[0128] Figure 3A is a perspective view of a positive displacement motor
300A. This
provides an example of a rotary tool that may be connected to the bottom sub
190. It can be
seen that the motor 300A includes an elongated tubular body 310. The body 310
defines a
fluid in-take end 312 and a fluid outlet end 314. The positive displacement
motor 300A
operates with a rotor and a stator residing within the tubular body 310. In
one aspect, the
positive displacement motor 300A is used as an agitator, sending pressure
pulses across the
wellbore downhole while cleaning. In another aspect, a small drill bit (not
shown) is connected
to the outlet end 314, and is turned by the rotor of the motor 300A. The drill
bit may be used
to mill through plugs or debris.
[0129] It is understood that the positive displacement motor 300A is merely
illustrative;
other positive pressure tools may be placed downstream of the seat 170.
[0130] As noted, to enable the cycling, a sequencing mechanism such as a J-
slot
mechanism may be provided. A J-slot mechanism is a cylindrical device having a
circuitous
channel forming slots. One or more pins ride along the slots, rotating from
slot-to-slot in
response to changes in fluid pressure.
CA 3064105 2019-12-06
101311 Figure 4A is a side view of a portion of a J-slot mechanism 400. It
can be seen that
a pair of pins 482 reside in respective lower slots 484A. This is a slot
position that would
correlate with the default, or raised position of the plunger 160 as presented
in Figures 1A and
1B. In this position, the pump rate is below the activation rate. This cycle
position will allow
injected fluid to flow to the flow ports 185, sending the fluid on through the
bottom end 194
of the bottom sub 190.
[0132] Figure 4B is another side view of the J-slot mechanism 400 of Figure
4A. In this
view, the pins 482 have advanced one slot 484B. In slot 484B, the pins 482 are
in an
intermediate position. This is a slot position that would correlate to the
operator increasing
pump rate from the surface as shown in Figure 1C. In this position, the
location of the J-slot
pins 482 restricts the movement of the plunger 160 while allowing the flow-
rate to beneficially
move above the activation rate. In other words, the plunger 160 will not
advance along the
mandrel 155 even when the pump rate is well above the activation rate,
allowing operation of
the positive displacement motor 300A.
101331 Figure 4C is another side view of the J-slot mechanism 400 of Figure
4A. In this
view, the pumping rate has been dropped back below the activation rate,
causing the pins 482
to follow along the channel and to advanced one slot 484A. In this position
484A, the plunger
160 has returned to its raised position per Figure 1A.
[0134] Figure 4D is still another side view of the J-slot mechanism 400 of
Figure 4A. In
this view, the pump rate has again been increased above the activation rate,
causing the pins
482 to advance along the channel to a next slot 484D. In this position, the
plunger 160 is
seated, exposing the slots 165 to the jetting ports 148 per Figure 2A. In this
position, the
operator may inject at high rates to perforate a surrounding section of
production casing.
[0135] In operation, the pins 482 advance from slot-to-slot in response to
alternating cycles
of the piston body 150 and connected internals moving longitudinally. The pins
482 cause the
piston assembly 150 and connected internals to ratchet, or rotate, in a
circular path. Also, the
component housing the J-slot pin or pins 482 may ratchet, or rotate, in a
circular path. The J-
slot grooves (484A) are configured so that the piston body 150 and connected
internals travel
26
CA 3064105 2019-12-06
is unrestricted in the upward direction so that every time the flow rate is
brought below the
activation rate the plunger 160 is in its raised position and cannot seal
against the seat 170.
Additionally, on alternating cycles of the flow rate being brought to or above
the activation
rate, the J-slot grooves allow the piston body 150 and connected internals to
move down so the
plunger 160 seals against the seat 170.
[0136] Figure 5A is side view of the mandrel 155 of Figures 1A and 2A. So
called J-slots
410 are visible along the outer diameter of the mandrel 155. Also of interest,
flow ports 185
can be seen below the J-slots 410 while radial slots 165 can also be seen
below the J-slots 410.
101371 Figure 5B is a cross-sectional view of the mandrel 155 of Figure 5A.
In both
Figures 5A and 5B, slot 484D of the J-slots 410 is visible. Here, the J-slots
410 themselves
are shown in phantom.
[0138] It is understood that the J-slots 410 of Figures 5A and 5B are part
of the sequencing
mechanism 400. The J-slots 410 work in tandem with a J-slot collar (shown at
420 in Figure
6A).
[0139] Figure 6A is cross-sectional view of the J-slot collar 420. The J-
slot collar 420
includes a pair of opposing pins 482 that ride in the J-slots 410 of Figure
5A.
[0140] Figure 6B is a perspective view of the J-slot collar 420 of Figure
6A. Visible in
this view is one of the pins 482 extending inwardly into a bore 425.
[0141] Figure 7 is a cross-sectional view of the jetting port housing 140
of Figures 1A
and 2A. The proximal (or upstream) end 142 and the distal (or downstream) end
144 are
indicated. It is observed that the jetting port housing 140 defines a wall 141
forming a bore
146. The bore 146 extends from the proximal 142 to the distal 144 end. The
jetting ports 148
are visible in the wall 141 making up the housing 140.
[0142] Figure 8A is a side view of the piston assembly 150 of Figures 1A
and 2A.
101431 Figure 8B is a cross-sectional view of the piston assembly 150 of
Figure 8A.
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CA 3064105 2019-12-06
[0144] Figure 8C is a perspective view of the piston assembly 150 of Figure
8A. The
piston assembly 150 will be discussed with reference to Figures 8A ¨ 8C
together.
101451 The piston assembly 150 includes an orifice retainer 151, a piston
body 156, a
piston orifice 153 and a piston scraper retainer 157. The piston orifice 153
resides below the
orifice retainer 151. The piston orifice 153 comprises a shoulder, with the
shoulder being
exposed to fluid pressure above the fluid assembly 150. The piston orifice 153
includes a
central through-opening that permits working fluids to flow through the piston
assembly 150
during clean-out operations. Piston scrapers (not shown) may be disposed
around the piston
body 156 to ensure debris is not able to reach the piston body o-ring.
101461 Figure 9A is a side view of the plunger 160 of Figures 1A and 2A.
Figure 9B is
a cross-sectional view of the plunger 160. Figure 9C is a perspective view of
the plunger 160
of Figure 9A. The plunger 160 will be discussed with reference to Figures 9A,
9B and 9C
together.
101471 The plunger 160 comprises an upper end 162 and a lower end 164. The
upper end
162 is mechanically or adhesively connected to a lower end of the mandrel 155.
The lower
end 164, in turn, is dimensioned to sealingly land onto the seat 170, above
the flow-through
opening 175. The plunger 160 defines a short body 166. The body 166 may
comprise a solid
steel, plastic or elastomeric material. Preferably, an upper portion
(representing the upper end
162) of the body 166 is fabricated from plastic or steel while a lower portion
(representing the
lower end 164) represents a separate elastomeric body. A flat portion 168 is
provided on each
of opposing sides of the body 166 to facilitate threadedly connecting the
plunger 160 to the
mandrel 155.
[0148] An opening 161 is preserved internal to the body 166. The opening
161 is
dimensioned to threadedly receive a bolt 163. More specifically, the opening
161 receives a
threaded stud 167 of the bolt 163. An opening 169 for an Alan wrench is
provided in the bolt
163 for securing the stud 167 into the opening 161.
28
CA 3064105 2019-12-06
[0149] When the piston assembly 150 and connected plunger 160 are in their
lowered
position (or abrasive perforating mode), the bottom 164 of the plunger 160
lands on the seat
170. At the same time, the slots 165 in the mandrel 155 advance to a position
intermediate the
upper 162 and lower 164 seals, exposing the slots 165 to the jetting ports
148. In this position,
all of the jetting fluids flow down through the bore 105 of the tool 100,
through the slots 165,
into the annular region 145 and through the lateral jetting ports 148.
[0150] As noted above, the perforating tool 100 (with or without rotary
tool 300A or some
bottom hole assembly below) is intended to be run into a wellbore. Figure 10
is a cross-
sectional view of an illustrative wellbore 1000. The wellbore 1000 penetrates
into a subsurface
formation 1050 and is completed for producing hydrocarbon fluids. Of interest,
for purposes
of the present disclosure, the wellbore 1000 has received a multi-cycle clean-
out tool such as
the tool 100 of Figure 1A.
[0151] It can be seen that the wellbore 1000 has been completed with a
series of pipe
strings referred to as casing. First, a string of surface casing 1010 has been
cemented into the
formation 1050. The cement resides in an annular region 1015 around the casing
1010,
forming an annular sheath 1012. The surface casing 1010 has an upper end in
sealed
connection with a bottom wellhead valve 1064.
101521 Next, at least one intermediate string of casing 1020 is cemented
into the wellbore
1000. The intermediate string of casing 1020 is in sealed fluid communication
with a top
wellhead valve 1062. A cement sheath 1022 resides in an annular region 1025 of
the wellbore
1000. The combination of the casing 1010 / 1020 and the cement sheaths 1010,
1022 in the
annular regions 1015, 1025 strengthens the wellbore 1000 and facilitates the
isolation of
aquitards and formations behind the casing 1010 / 1020. It is understood that
a wellbore 1000
may, and typically will, include more than one string of intermediate casing.
[0153] Finally, a production string 1030 is provided. The production string
1030 is hung
from the intermediate casing string 1020 using a liner hanger 1031. The
production string
1030 is a liner that is not tied back to the surface 1001. In the arrangement
of Figure 10, a
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CA 3064105 2019-12-06
cement sheath 1032 is provided around the liner 1030. The cement sheath 1032
fills an annular
region 1035 between the liner 1030 and the surrounding rock matrix in the
subsurface
formation 1050.
[0154] The production liner 1030 has a lower end 1034 that extends to an
end 1054 (or
"toe") of the wellbore 1000. For this reason, the wellbore 1000 is said to be
completed as a
cased-hole well. Those of ordinary skill in the art will understand that for
production purposes,
the liner 1030 will be perforated after cementing to create fluid
communication between a bore
1045 of the liner 1030 and the surrounding rock matrix making up the
subsurface formation
1050. In one aspect, the production string 1030 is not a liner but is a casing
string that extends
back up to the surface 1001. In this instance, the cement sheath 1032 will not
be extended to
the surface 1001.
[0155] As an alternative, end 1054 of the wellbore 1000 may include joints
of sand screen
(not shown). The use of sand screens with gravel packs allows for greater
fluid communication
between the bore 1045 of the liner 1030 and the surrounding rock matrix 1050
while still
providing support for the wellbore 1000. In this instance, the wellbore 1000
would include a
slotted base pipe as part of the sand screen joints. Of course, the sand
screen joints would not
be cemented into place.
[0156] It is also noted that the bottom end 1054 of the wellbore 1000 is
completed
substantially horizontally. This is a common orientation for wells that are
completed in so-
called "tight" or "unconventional" formations. Indeed, in the United States
well over half of
all wells are now completed horizontally.
[0157] Horizontal completions not only dramatically increase exposure of
the wellbore to
the producing rock face, but also enable the operator to create fractures that
are substantially
transverse to the direction of the wellbore. Those of ordinary skill in the
art may understand
that a rock matrix will generally "part" in a direction that is perpendicular
to the direction of
least principal stress. For deeper wells, that direction is typically
substantially vertical.
CA 3064105 2019-12-06
However, the present inventions have equal utility in vertically completed
wells or in multi-
lateral deviated wells.
101581 When completed, the wellbore 1000 will include a string of
production tubing (not
shown). However, before that is done, it is desirable to clean out the
wellbore 1000.
Accordingly, the wellbore 1000 includes a perforating tool 100 as shown in
Figure 1A.
101591 It is noted that the perforating tool 100 is connected to a string
of coiled tubing
1040. The coiled tubing string 1040 serves as a working string for delivering
an aqueous fluid
under high pressures downhole. Such pressures may exceed 500 psi, or even
3,000 psi. The
perforating tool 200 is preferably extended along the horizontal leg of the
wellbore within the
subsurface formation 1055.
[0160] A lubricator 1060 or frac tree is placed over the wellbore 1000. The
lubricator 1060
is positioned at the surface 1001 to control wellbore pressures during a
completion (or other
wellbore) operation and to isolate tools such as a string of coiled tubing
1040 being moved into
and back out of the wellbore 1000.
101611 As can be seen, a unique abrasive perforating tool 100 has been
provided. The
perforating tool acts as a flow diverter that increases the efficiency of fill
removal operations.
Fluid flow can be entirely in a straight-through path of the tool to an
optional bottom hole
assembly below. In addition, the fluid flow can also be entirely diverted to
jetting ports. The
cycling of fluid flow modes is possible an unlimited number of times and does
not require
dropping a ball or reversing circulation.
101621 Using the perforating tool 100 described above, a method 1100 of
conducting a
wellbore operation is also provided. The method 1100 is presented in the flow
chart of Figure
11.
[0163] The method 1100 first includes providing a wellbore. This is
indicated at Box 1110.
The wellbore is being completed for the production of hydrocarbon fluids. Of
interest, the
wellbore has been completed with a string of casing, including a string of
production casing
along a selected subsurface formation.
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[0164] The wellbore may be completed vertically. Alternatively, the
wellbore may be a
deviated well formed from a lateral drilling operation. More preferably, the
wellbore is
completed horizontally as shown in Figure 10. However, the methods are not
limited to the
orientation of the wellbore unless expressly stated in the claims.
[0165] It is understood that for purposes of Box 1110, the term "providing"
includes but is
not limited to "forming" or "completing." The term "providing" may also mean
that a service
company accesses a wellbore that has already been drilled and completed, or
accesses a
wellbore that has been undergoing production operations for a period of time.
[0166] The method 1100 also includes running a perforating tool into the
wellbore. This
is provided in Box 1120. The perforating tool is run into the wellbore at the
lower end of a
string of coiled tubing 1040. The perforating tool may be constructed in
accordance with any
of the embodiments described above. Particularly, the perforating tool is a
multi-cycle tool
having a tubular housing that includes an elongated bore. Fluids are pumped
from the surface,
down the string of coiled tubing, and into the bore.
[0167] The perforating tool includes one or more lateral jetting ports. The
jetting ports are
spaced apart radially around the housing, and preferably constitute two levels
of ports in close
proximity to one another. The jetting ports deliver an abrasive fluid to the
casing when the
tool is in its perforating mode.
[0168] The method 1100 may additionally include tuning the various openings
along the
tool in order to provide a desired total cross-sectional area of fluid flow in
the perforating
tool. This is seen at Box 1130. For example, the step of Box 1130 may include
setting or
adjusting an aperture size of an orifice associated with the piston. This has
the effect of
varying flow rates associated with the raised and lowered positions.
[0169] In order for the perforating tool to change modes, the piston
orifice needs to be
sized small enough to ensure the required activation rate will be achievable
during the
operation. Although the perforating tool will change modes correctly, sizing
the piston
orifice too small for a planned pump-rate will cause excessive and unnecessary
pressure drop
32
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that may limit the total flow capacity of the operation in flow-through mode.
Optimally, the
piston orifice is sized appropriately to ensure the activation rate will be
achievable in both
modes throughout the operation with minimal back-pressure.
[0170] Additionally, the Box 1130 may include a step of selecting or
adjusting the cross-
sectional area of the flow ports along the mandrel, and/or a step of selecting
or adjusting a
diameter of the lateral slots associated with the mandrel and the flow-through
opening
associated with the seat. A larger cross-sectional area in the opening of the
seat enables more
working fluid to flow from the perforating tool en route to the PDM 300A.
[0171] Additionally, the Box 1130 may also include a step of adjusting a
size of the
lateral jetting ports. The ports should be small enough to provide ample flow
restriction for
effective jetting.
[0172] It is observed that while Box 1130 is shown after the step of
running the perforating
tool into the wellbore, it is understood that these adjustments of Box 1160
will be taken during
tool design and before the tool is run into the wellbore in Box 1120.
[0173] The method 1100 also includes the step of locating the perforating
tool. This is
seen at Box 1140. The perforating tool is located at a selected depth along a
tubular body
within the wellbore. Subsurface formation 1055 of Figure 10 is an example of a
location or
depth for the perforating tool, although the operator will choose specific
total depths for
perforation and clean-out. Thus, the term "depth" includes "total depth" along
a horizontal
wellbore.
[0174] The method 1100 further includes injecting a working fluid down a
coiled tubing
string. This is provided at Box 1150. The fluid is a hydraulic fluid that is
pumped into the
wellbore under pressure. The fluid is pumped down the coiled tubing and into
the bore of
the tubular housing making up the perforating tool at a first flow rate. The
first flow rate is
below an activation rate. The pumping at the first flow rate causes the pumped
fluid to flow
through the mandrel, through the radial flow ports of the mandrel, into the
annular area,
around the plunger and through the seat.
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[0175] The method 1100 also includes further injecting the working fluid
down the
coiled tubing and into the bore of the tubular housing at a second flow rate.
This is shown at
Box 1160. The second flow rate is higher than the first flow rate. In this
instance, the higher
flow rate increases a hydraulic force acting on a pressure shoulder of a
piston, causing the
mandrel and connected plunger to slide along the tubular housing such that the
plunger is
landed on the seat. The result is that the tool is moved into its perforating
mode. In this
mode, all pumped fluid flows into the bore of the tubular housing, down the
mandrel, through
the radially-disposed slots, into the annular area and through the lateral
jetting ports.
[0176] As noted above, during the perforating mode the pumped fluid will
preferably
include abrasive particles such as sand. In addition, a water-soluble polymer
may be used in
the concentration range of about 10 pounds to about 40 pounds per 1,000
gallons of liquid.
The polymer keeps the abrasive particles suspended and reduces friction
pressure loss during
flow of fluid through the tubing 1040. A concentration of abrasive particles
may be selected
depending on wellbore conditions, but normally concentrations up to about one-
half pound of
abrasive per gallon may be used. Chemicals such as KC1 and HC1 may be added to
the working
fluid to assure that the fluid is compatible with the reservoir rock.
Preferably, the fluid pumped
is filtered to minimize plugging of jetting ports 148.
[0177] To effectuate the method 1100, it is preferred that a sequencing
mechanism be
placed along the tubular housing. The sequencing mechanism may be a J-slot
mechanism.
The J-slot mechanism may be configured to cycle between three settings. Those
include:
(i) a first setting wherein a pin associated with the J-slot mechanism resides
in a first slot that places the plunger in a raised position in response to a
biasing
mechanical force exerted by a spring on the mandrel while pumping at a first
rate,
maintaining the perforating tool in a flow-through mode (shown in Figure 1A);
(ii) a second setting wherein the pin moves higher in the first slot in
response
to the injection of fluids into the wellbore at a second increased rate,
placing the
plunger into an intermediate position while allowing the tool to remain in its
flow-
through mode (shown in Figure 1C);
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(iii) the first setting again wherein the pin resides in a second slot that
returns
the plunger to its raised position in response to the upward biasing force of
the spring;
and
(iv) a third setting wherein the pin moves higher along a third slot in
response
to the injection of fluids into the wellbore at a second increased rate, and
wherein the
plunger slides from the raised position to the lowered position, placing the
perforating
tool in its abrasive perforating mode (shown in Figure 2A).
[0178] It is observed that the second increased rate is an activation rate.
The pump rate
in both the second setting and the third setting may be higher than the
activation rate.
[0179] The method 1100 may include repeating the step of Box 1150 to
provide further
clean-out. During this step, a rotary tool below the perforating tool such as
(positive
displacement motor 300A) may be activated in order to mill out a plug or other
wellbore
obstacle.
[0180] In one aspect of the method 1000, the perforating tool 100 is part
of a bottom hole
assembly that includes a downhole tool. The downhole tool is threadedly (or
otherwise
operatively) connected to the lower end of the lower sub. An upper end of the
lower sub
supports or abuts or is otherwise proximate to the seat.
[0181] In one embodiment, the downhole tool is a positive displacement
motor. The
positive displacement motor is configured to rotate a connected mill bit in
response to
hydraulic pressure received when the perforating tool is in its flow-through
mode. In this
instance, the method further comprises milling out a plug or debris located in
the wellbore
below the bottom sub using the positive displacement motor.
[0182] Milling operations may also be conducted to remove plugs that have
been placed
in the well bore. The operator may mill through wellbore obstacles using the
flow-through
mode, then switch the tool to its perforating mode to create perforations at
the desired location.
The tool can then be cycled back to the flow-through mode to resume
circulation through the
motor to circulate out the sand that was used for creating the perforations.
Changing the flow
CA 3064105 2019-12-06
path to the motor has the benefit of maintaining circulation around the entire
BHA to avoid
getting stuck, as well as enabling a higher pump rate than would be achievable
through the
perforating nozzles.
[0183] In another embodiment, the downhole tool is a sliding sleeve
shifting tool. The
setting tool is configured to shift a sliding sleeve along the wellbore in
response to hydraulic
pressure received when the perforating tool is in its flow-through mode. In
this instance, the
method further comprises shifting a sliding sleeve located in the wellbore
below the bottom
sub using the sliding sleeve shifting tool.
[0184] Figure 3B is an example of a suitable sliding sleeve shifting tool
300B that may be
used as part of a bottom hole assembly with the perforating tool 100 of
Figures 1A and 2A.
This illustrative tool 300B is a bi-directional shifting tool that is
available from Hunting Energy
Services, LLC of Houston, Texas.
[0185] In still another embodiment, the downhole tool is a bridge plug. The
bridge plug
may be either a permanently installed bridge plug or a resettable bridge plug.
In this instance,
the method further comprises setting the bridge plug in the wellbore below the
bottom sub in
response to hydraulic pressure received when the perforating tool is in its
flow-through mode.
In another instance the bridge plug may be set in response to movement of the
conveyance
tubing.
[0186] Figure 3C presents an example of a suitable bridge plug 300C. This
illustrative
tool 300C is a CrownstoneTM GTV tubing-retrievable well barrier (or
retrievable bridge plug)
that is available from Baker Hughes (a GE Company) also of Houston, Texas.
[0187] In another embodiment, the downhole too is an extended reach tool.
The extended
reach tool creates pressure pulses in the flow through the coiled tubing,
which reduces friction
between the coiled tubing and the wellbore. An operator may utilize the
extended reach tool
while in clean-out (that is, flow-through) mode to achieve deeper depths that
would otherwise
not be attainable and then switch to perforating mode to perforate the
wellbore. In perforating
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CA 3064105 2019-12-06
mode, the sand laden fluid is isolated from the extended reach tool, which
typically would be
damaged by such fluid.
[0188] Figure 3D resents an example of a suitable extended reach tool 300D.
This
illustrative tool 300D is a Toe TapperTm extended reach tool that is available
from CT Energy
Ltd. of Calgary, Alberta.
[0189] Further, variations of the tool and of methods for operating a flow
diverter tool may
fall within the spirit of the claims, below. For example, the location of the
upper 162 and lower
164 seals, and the corresponding locations of the slots 165 and the flow ports
185, may be
reconfigured such that the raised position of the perforating tool 100
correlates to the
perforating mode rather than the flow-through mode, and such that the lowered
position
correlates to the flow-through mode rather than the perforating mode.
[0190] Figures 12A through 12C demonstrate a perforating tool 1200 wherein
the tool is
biased in its abrasive perforating mode. This means that in the raised
position abrasive
perforating fluid is injected through lateral jetting nozzles, while in the
lowered position a
working fluid is entirely injected through a seat at the bottom of the
perforating tool. This
allows the fluid to serve as a working fluid for operating a positive
displacement motor 300A
or for activating a sliding sleeve 300B or for setting a bridge plug 300C in
the wellbore.
101911 Figure 12A is a first cross-sectional view of the perforating tool
(or "flow diverter")
1200. In this view, the perforating tool 1200 is in an abrasive perforating
mode. Here, all of
the injected fluids are diverted from the tool 1200 and through lateral
jetting ports 1248. Thus,
the tool 1200 is spring-biased to the abrasive perforating mode rather than to
the flow-through
mode.
[0192] The perforating tool 1200 defines a generally tubular body formed
from a series of
components. As shown, the perforating tool 1200 has a first (or upstream) end
102 and a
second (or downstream) end 104. A central bore 105 is formed within the body
extending
from the first end 102 to the second end 104.
37
CA 3064105 2019-12-06
[0193] As with clean-out tool 100 described above, the perforating tool
1200 is configured
to cycle a position of a mandrel 155 and connected plunger 160 in response to
fluid pumping
rates into the wellbore 1000 by an operator. In this way, a flow of fluid
through the tool 1200
may be adjusted. In the view of Figure 12A, the perforating tool 1200 is in
its run-in position
wherein all the injected fluid flows through the tool 1200 from the top (or
upstream) end 102,
then out through side ports 1285 and into an annular area 1245, then through
lateral jetting
ports 1248. Of interest, the lowered end of the plunger 160 has no through-
bore and is sealingly
inserted in a seat 170, preventing the injected fluids from flowing through
the bottom end 104
of the tool 1200.
101941 It is observed here that some of the tubular components in the
perforating tool 1200
correspond to components of the perforating tool 100, or at least very closely
there to.
Examples include the top sub 110, the piston assembly 150, the spring housing
120 and spring
125, the upper mandrel seal sub 130, the jetting port housing 140 with one or
more jetting ports
148, the mandrel 155 and the bottom sub 190. Accordingly, those components
need not be
described again here.
[0195] The spring housing 120, the mandrel seal sub 130 and the jetting
housing 140
together make up a tubular housing for the perforating tool 1200. Of interest,
a shoulder 146
resides along an inner diameter of the jetting port housing 140. The shoulder
146 forms a
profile above the jetting ports 148. A separate shoulder 136 resides at the
bottom end 134 of
the mandrel seal sub 130. 0-rings are placed inside the bottom end 134,
helping to keep
perforating fluid from flowing from an annular area between the mandrel 155
and the spring
housing 120 during perforating.
[0196] An annular area 145 is reserved between the mandrel 155 and the
surrounding
jetting port housing 140. The annular area 145 has an upper portion where the
spring 125
resides, and a lower portion where jetting ports 148 are placed. Appropriate o-
rings reside
around and inside the downstream end 134 of the mandrel seal sub 130 to
provide a fluid seal
between the upper and lower annular regions 145. The annular region the spring
125 resides
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in is pressure balanced via ports 159 in the mandrel 155. These ports 159 let
the fluid volume
inside the spring housing 120 change as the piston body 156 moves up and down.
101971 At the lower end 154 of the mandrel 155 is a stem 1280. The stem
1280 defines a
short tubular body having an upper (or upstream) end 1282 and an opposing
lower (or
downstream) end 1284. A bore 1265 is formed from the upper 1282 to the lower
1284 end,
allowing working fluids to flow through the side ports 1285. Preferably, two
or more equi-
radially disposed slots are provided for the side ports 1285. The upper end
1282 comprises
male threads that connect to the lower end 154 of the mandrel 155. In this
way, the stem 1280
moves up and down along the bore 105 of the perforating tool 1200 with the
mandrel 155.
101981 The lower end 1284 of the stem 1280 is connected to a plunger 160.
As noted
above, the plunger 160 is a solid body that may be fabricated from plastic,
steel or an
elastomeric material. In this instance, the plunger 160 is dimensioned to move
through a seat
170. Appropriate seals are provided along the I.D. of the seat 170 to prevent
fluids from
bypassing the plunger 160.
[0199] In the raised position of Figure 1A, fluid is injected by an
operator into the bore
105 of the perforating tool 1200 under a first pressure. The first pressure
correlates to a first
flow rate. Those of ordinary skill in the art will understand that there is a
correlation between
flow rate, tubular dimension and pressure. At the first flow rate, the
hydraulic pressure acting
on the piston assembly 150 is not great enough to cause the piston assembly
150 to compress
the spring 125.
[0200] Figure 12B is a second cross-sectional view of the perforating tool
1200 of Figure
12A. Here, the perforating tool 1200 has been cycled to an intermediate
position. Stated
another way, the perforating tool 1200 is translating (that is, sliding down
the spring housing
120) to its intermediate position. This is done by increasing the hydraulic
force acting on the
piston assembly 150. In this position, the plunger 160 has advanced partially
down the tool
1200, but all of the injected fluid continues to flow through the lateral
jetting ports 148.
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[0201] Figure 12C is a third cross-sectional view of the perforating tool
1200 of Figure
12A. Here, the tool 1200 (or the plunger 160 in the tool 1200) has advanced to
its lowered
position. This is a flow-through mode where all of the injected fluid flows
through the side
ports 1285 below the seat 170. Advancing the plunger 160 is done by further
increasing the
pump rate above an activation rate, thereby increasing the hydraulic force
acting on the
shoulder that is the piston assembly 150.
102021 The cycling of the tool 1200 between its raised position (Figure
12A), its
intermediate position (Figure 12B) and its lowered position (Figure 12C) is
preferably
accomplished by using a sequencing mechanism. The sequencing mechanism is
preferably the
J-slot mechanism as shown in Figures 4A-4D, discussed above. The sequencing
mechanism
400 allows the operator to cycle the flow rates to move the tool 1200 between
settings so that:
(i) in a first setting, the plunger 160 is in a raised position in response to
the
biasing mechanical force exerted by the spring 125 on the mandrel 155, placing
the
perforating tool in an abrasive perforating mode;
(ii) in a second setting, pumping rate is increased and the J-slot mechanism
400 advances to a next slot, allowing the plunger 160 to move down no more
than to
its intermediate position and allowing the operator to inject hydraulic fluid
(typically
the perforating fluid) into the bore 105 of the tubular housing 110 and
through the
piston orifice 153 at a second rate, or at any rate higher than the second
rate, and
keeping the perforating tool 1200 in its abrasive perforating mode;
(iii) in the first setting again, hydraulic pumping rate is reduced to its
first
rate, or any rate below the first rate, and the perforating tool 1200 remains
in its
perforating mode; and
(iv) in a third setting, the plunger 160 is forced through the seat 170 in
response to the injection of hydraulic fluid through the piston assembly 150
and into
the perforating tool 1200 at a second rate, or at any rate higher than the
second rate,
moving the J-slot mechanism 400 to a next slot and causing the plunger 160 to
slide
CA 3064105 2019-12-06
from the raised position to the lowered position, placing the perforating tool
1200 in
its flow-through mode.
[0203] Using the perforating tool 1200 of Figures 12A-12C, a method of
cleaning out a
wellbore is also provided herein. The wellbore may be the wellbore 1000 of
Figure 10, for
example. In one aspect, the method includes the steps of:
(a) placing a perforating tool in the wellbore along a string of production
casing;
(b) locating the perforating tool and connected downhole tool within the
wellbore;
(c) pumping working fluid down the wellbore and into the perforating tool
at or
above an activation rate, causing the tubular mandrel and connected plunger
to move through a seat to a lowered position such that all fluid flows through
the perforating tool (a flow-through mode);
(d) lowering the pumping rate to advance the J slot pins to the next
setting,
therefore placing the tool in its perforating mode;
(e) pumping the working fluid down the wellbore and into the perforating
tool at
a rate at or above the activation rate such that all fluid flows through
lateral
jetting ports (a perforating mode); and
(0 continuing to pump the working fluid down the wellbore and into
the
perforating tool at a rate at or above the activation rate in order to
hydraulically perforate a surrounding string of production casing.
[0204] In one aspect of the method, the perforating tool is part of a
bottom hole assembly
that includes a downhole tool. The downhole tool is threadedly (or otherwise
operatively)
connected to the lower end of the lower sub. An upper end of the lower sub
supports the seat.
[0205] In one embodiment, the downhole tool is a positive displacement
motor. The
positive displacement motor is configured to rotate a connected mill bit in
response to
hydraulic pressure received when the perforating tool is in its flow-through
mode. In this
41
CA 3064105 2019-12-06
instance, the method further comprises milling out a plug or debris located in
the wellbore
below the bottom sub using the positive displacement motor.
[0206] In another embodiment, the downhole tool is a sliding sleeve
shifting tool. The
setting tool is configured to shift a sliding sleeve along the wellbore in
response to hydraulic
pressure received when the perforating tool is in its flow-through mode. In
this instance, the
method further comprises shifting a sliding sleeve located in the wellbore
below the bottom
sub using the sliding sleeve shifting tool.
[0207] In still another embodiment, the downhole tool is a bridge plug. The
bridge plug
may be either a permanently installed bridge plug or a resettable bridge plug.
In one instance,
the method further comprises setting the bridge plug in the wellbore below the
bottom sub in
response to hydraulic pressure received when the perforating tool is in its
flow-through mode.
In another instance, the method further comprises setting the bridge plug in
the wellbore below
the bottom sub in response to movement of the conveyance tubing.
[0208] In another embodiment, the downhole too is an extended reach tool.
The extended
reach tool creates pressure pulses in the flow through the coiled tubing,
which reduces friction
between the coiled tubing and the wellbore. An operator may utilize the
extended reach tool
while in flow-through mode to achieve deeper depths that would otherwise not
be attainable
and then switch to perforating mode to perforate the wellbore. In perforating
mode, the sand
laden fluid is isolated from the extended reach tool, which typically would be
damaged by such
fluid.
[0209] It will be appreciated that the inventions are susceptible to other
modifications,
variations and changes without departing from the spirit thereof
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