Note: Descriptions are shown in the official language in which they were submitted.
"REAL-TIME SYSTEM FOR HYDRAULIC FRACTURING"
FIELD
[0001]
Embodiments herein relate to methods and apparatus used for
completion of a wellbore and, more particularly, to methods for performing
completion operations and monitoring in real-time, at surface, downhole
conditions
during completion operations.
BACKGROUND
[0002]
Apparatus and methods are known for single-trip completions of
deviated wellbores, such as horizontal wellbores. To date, unlike the drilling
industry
which commonly utilizes intelligent apparatus for drilling wellbores,
particularly
horizontal or deviated wellbores, the fracturing industry has relied largely
on
mechanically-actuated apparatus to perform a majority of the operations
required to
complete a wellbore. This is particularly the case with coiled tubing (CT)
deployed
bottom hole assemblies (BHA's), largely due to the difficulty in providing
sufficient,
reliable electrical signals and power from surface to the BHA and vice versa.
Further, fracturing operations require relatively high flow rates through the
CT, in the
order of about 1m3/min or greater. The bore restrictions necessitated by the
inclusion of electronic equipment on existing instrumentation subs, such as
those
used in drilling operations, limits flow rates therethrough to an extent that
is not
conducive for fracturing operations.
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[0003] It is known to deploy BHAs for completion operations using
jointed
tubular, wireline or cable, or coiled tubing (CT). Further, it is known to use
wireline
deployed within an interior of CT to electrically actuate conventional select-
fire
perforation charges and to transmit signals associated with casing-collar
locators
.. used in depth measurement, such as taught in US Patent 7,059,407 to Toman.
[0004] One class of prior methodology for performing fracturing
operations is
commonly referred to as "plug and pelf. Fracturing operations at multiple
zones in
a formation have used wireline-deployed electrically-actuated bridge plugs
which
are pumped into the wellbore. The known pump-down bridge plugs have a single,
fixed diameter being slightly smaller than the wellbore for deployment into
the
wellbore and require a valve at a toe of the wellbore to remove fluid used to
pump
the bridge plug into place. As wireline is comparatively weak and cannot pull
more
than about 2500 lbs at surface, and much less at depth, the wireline cannot be
reliably used to release or to pull the bridge plugs to surface. Thus,
multiple bridge
plugs must be used and left in the wellbore to be drilled out later, at
considerable
expense. After the bridge plug has been set, the casing is perforated with
perforating guns located above the bridge plug. The bridge plug and the
perforating
guns are often deployed together so that both operations, isolating and
perforating,
can be done in the same wireline run. When the perforations have been shot,
the
wireline is pulled out of the hole and the fracture fluid is pumped through
the casing.
Once the fracture is completed, the steps of setting the bridge plug and
perforating
followed by pumping the frac are repeated for sequential uphole intervals
until the
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fracturing job on the wellbore is complete. Following fracturing of all of the
zones,
the bridge plugs are drilled out.
[0005] In other embodiments, a plurality of sliding sleeve subs, each
sub
having pre-existing fracturing ports, are spaced along a casing string or a
liner of a
wellbore and located at zones of interest in the formation. The sliding
sleeves of the
sleeve subs are selectively opened to expose the pre-existing fracturing
ports,
minimizing the need to perforate the casing to access the formation
therebeyond. In
some cases, the sleeves can also be actuated back to a closed position for
isolating
portions of the formation from fluids flowing through the casing, such as when
fracturing through the ports of other sleeves, or to permit the zone of the
formation
to "heal". The sleeve subs can be opened using a variety of conventional
sleeve
opening and closing techniques, including, but not limited to, setting a
packer of a
BHA within the sleeve, expanding the packer element, and thereafter utilizing
a
tensile pull for or fluid flow in the annulus to force the first packer and
sleeve to shift
the sleeve axially therein. Other sleeve actuation techniques involve
electronically
or mechanically actuating a shifting tool incorporated in a BHA installed on
CT to
engage and axially shift the sleeve, or by actuating a rotational opening tool
to
engage and rotate the sleeve to an open position. Alternatively, differential
pressure
can be used to hydraulically open the sleeve.
[0006] In fracturing operations using sleeve subs, a shifting tool is run
in hole,
typically on CT having a BHA at a distal end that is fit with the shifting
tool. The CT
is run into the wellbore and the shifting tool is used to selectively engage
and
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actuate the sliding sleeves to establish or shut off communication between the
wellbore and the various zones in the formation. Once the shifting tool has
engaged a target sleeve, the CT is manipulated to selectively open the sleeve
and
expose the fracturing ports at said sleeve. A packer set below the fracturing
ports
directs fracturing fluid to exit the wellbore through open ports thereabove.
In
embodiments, the shifting tool can also close selected sleeves, such as to
permit
the formation to heal, or enable fracturing through opened ports in other
sleeves
therebelow. Treatment fluid can be delivered to the selected zone of the
formation
through the annulus between the casing and the CT, through the CT, or through
both at the same time. Typical sleeve-shifting BHA's comprise mechanically-
operated downhole tools having telescoping mandrels, packers and tubing,
controlled by axially delimited J-mechanisms for selecting a variety of
operating
modes of the shifting tool. While reliable, the axially reciprocating
components of
the shifting tool introduce challenges as described below.
[0007] As will be appreciated by those of skill in the art, the acquisition
of
downhole conditions before, during, and after fracturing is performed is
useful to
operators. Multi-zone fracturing is characterized by setting a packer and
introduction
of proppant-loaded treatment fluid at high pressure to a zone or stage, then
repeated release, pressure equalization, and re-location of the BHA to
subsequent
fracturing stages. Downhole conditions are determined with electronic sensors
and
the data is typically stored in memory located in tools carried by the BHA. In
conventional methods, the data pertaining to downhole conditions is stored in
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memory and reviewed at surface after the BHA is pulled out of hole. A
disadvantage
of storing sensor data to on-board memory is that the downhole conditions are
not
known until such operations are completed and the BHA has been retrieved to
surface. As such, the operator cannot adjust the operating parameters of the
BHA
and fracturing operation to respond to changes in downhole conditions as they
arise
in real-time, or near real-time.
[0008] Real-time tools have been applied in drilling operations and
the like.
Downhole parameters related to the downhole drilling environment and
parameters
are not directly ascertainable at surface. As such, the operator is typically
only
provided with surface feedback, such as torque and string weight variation to
estimate downhole performance. Absent direct downhole data, which may be
located thousands of meters distant from surface, too much or too little
string weight
can be applied at surface, resulting in downhole tool damage or ineffective
rate of
penetration. Accordingly, coiled-tubing conveyed BHAs capable of acquiring
direct,
real-time downhole data and delivering said data to surface may be used, such
as
that disclosed in published international application WO 2018/137027 to
Timberstone Tools Inc, Canada, incorporated herein in its entirety. An
electrically
enabled coiled tubing, such as coiled tubing having wireline running
therethrough or
fixed to the inner or outer walls thereof, forms a non-rotating conveyance
string and
can conduct data readings uphole during drilling. The BHA is fit with a
variety of
sensors, including those capable of measuring pressure and acceleration, for
gathering downhole parameters relating to the drilling interface. Such real-
time
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communication systems between surface and drilling BHAs are robust in part due
to
the fixed arrangement of the coiled tubing, which has no moving parts.
However,
repetitive movement of the coiled tubing and wireline can result in fatigue
connection issues. Thus, these applications are suitable for use with fixed
assemblies of components which are not subject to repeated movement, and no
relative movement therealong, such as with telescoping of a portion of the
BHA.
[0009] In hydraulic fracturing operations, the sleeve shifting tool
of a BHA is
subject to repeated, relative axial movement to set the packer and cycle the J-
mechanism, and is subject to high fluid rates of abrasive, proppant loaded
fluids
flowing therethrough and thereby in the annulus between the BHA and wellbore.
Such operating conditions are unsuitable for the implementation of real-time
instrumentation subs, such as those used for drilling operations, due to
fatigue
issues caused by the repeated relative axial movement of the shifting tool. It
is
particularly difficult to locate sensors on the BHA below the shifting tool,
as the
telescoping and/or rotational movement of portions of the shifting tool
relative to the
coiled tubing presents a significant obstacle to electrically connecting
sensors below
the shifting tool to an instrumentation sub or other electrical components
thereabove.
[0010] Additionally, present instrumentation subs for drilling have
restricted
inner bore diameters due to the space requirements for housing and sealing
circuits
and other electronic components therein. Flow is also restricted at the cable
head
assembly of the instrumentation sub, where the electrical connections in a
wireline
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cable terminate and are connected to contacts of the instrumentation sub. Such
restricted bore diameters result in relatively lower fluid flow rates
therethrough that
are not conducive to fracturing operations, which typically require flow rates
of
1m3/min or greater. In fracturing operations, it is preferable to have
unrestricted flow
capacity throughout the CT, and not be restricted at any point, such as at the
instrumentation sub of the BHA. Such flow restriction at the BHA can also
result in
severe erosion, due to the high flow rates required for fracturing operations,
and the
fact that fracturing fluid is often sand-laden and quite erosive. As clean
fluid is
typically used in drilling operations, and flow rates are lower, conventional
instrumentation subs for drilling operations are not designed to account for
the flow
and erosion considerations of fracturing operations and are therefore
unsuitable for
use in such operations
[0011] Further, conventional instrumentation subs for drilling do not
have
means for communicating with components below the BHA, such as additional
sensors. Information acquired by such sensors may be useful in fracturing
operations. For example, downhole pressure data above and below the packer of
the BHA can be used to determine whether the packer was successfully set
before
fracturing fluid is pumped into the wellbore.
[0012] There is interest in the industry to improve access to
operational data
at the downhole tool for improving reliability and effectiveness of hydraulic
fracturing.
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SUMMARY
[0013] Embodiments of a bottom hole assembly (BHA) are provided
herein
for obtaining data regarding downhole conditions and BHA operation during
fracturing operations, and transmitting said data in real-time from the BHA to
surface. Some embodiments also permit bi-directional communication between the
BHA and surface, such that instructions can be sent from surface or remotely
to the
BHA. The BHA is connected to the downhole or distal end of coiled tubing (CT)
or a
similar tubular string.
[0014] The monitoring of pressure uphole and downhole of a BHA during
fracturing operations provides data indicative of how the formation is
reacting to the
fracturing operation and may also be indicative of the integrity of the
isolation
effectiveness of the BHA and the characteristics of the formation between
adjacent
zones. Instead of calculating or estimating downhole parameters from
parameters
measurable at surface, or reviewing data at a later time as recovered from
machine-
readable memory located on the BHA, downhole data is transmitted to surface in
real-time or near real-time.
[0015] In one embodiment, real-time downhole data collection and
transmission is effected, including on mechanical BHA tools, using an
electronics
interface sub located on the conveyance string.
[0016] In some embodiments, a short-hop wireless transmission system can
be implemented to permit communication between components uphole and
downhole from the mechanical BHA tool.
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[0017] In another embodiment, real-time or near real-time downhole
data
collection and transmission is effected uphole and downhole of an
electronically-
actuated BHA tool, the uphole and downhole being axially fixed.
[0018] In embodiments, abrasive fracturing fluid is delivered through
the
annulus for minimizing erosive effects on the electronics interface sub. The
annulus
provides a large cross-sectional area suitable for the high fluid rates
required for
hydraulic fracturing. Fracturing fluid can also be communicated downhole via
the
bore of the CT. The electronics interface sub can be configured to provide an
axial
bore that permits flow rates suitable for fracturing operations, and avoid
flow bore
restrictions that would result in accelerated erosion due to fracturing fluid
flowing
therethrough. Further, when treatment fluid is delivered to the formation
through
one of the annulus and the CT, the other can act as a "dead leg". For example,
when the treatment fluid is delivered through the annulus, a minimal, constant
amount of a deadhead fluid can be delivered through the tubing string to act
as the
"dead leg" for maintaining pressure within the CT. The pressure required to
maintain
the constant fluid delivery is monitored from surface and can be used for
calculating
fracture extension pressure and formation breakdown pressure, as well as
fracture
closure pressure.
[0019] In conventional completion operations, a "dead leg" is used
not only to
prevent collapse of the CT under pressure from fluids in the annulus, but also
to
permit calculation of pressure to determine reaction of the formation to the
fracturing
operation.
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[0020] However, in embodiments where the CT is electronically enabled
coil
having a wireline running therethrough, and the bore of CT is fluidly coupled
with
the annulus, such as through ports at the BHA, flow of abrasive fluid downhole
or
uphole through the CT is discouraged due to potential erosion of the
electronic
interface sub, and the wireline itself. There is the possibility of reverse
flow into the
CT, by pressure imbalance or through operator directed purposeful reverse
circulation to clear sands from the packer area and the like.
[0021] As introduced above, mechanical fracturing tools incorporate
axially
telescoping components, such as to compress a packer, complicating electrical
connections uphole to downhole of the packer.
[0022] As discussed in Applicant's international
application
WO/2013/159237, published Oct 31, 2013, and incorporated herein in its
entirety,
electrically-enabled CT was implemented for bidirectional communication of
signals
between a BHA and surface. Power can be provided to the BHA components which
can be electrically-actuated. The disclosed BHA comprised an electrically-
actuated,
variable diameter packer located below fracturing treatment ports. The
electrically-
enabled BHA obviates the need for axially movable components and includes
electrical circuitry extending below the packer to arrays of perforating guns
therebelow.
[0023] Herein, a downhole fracturing tool is provided comprising
electrically
enabled coiled tubing, an interface sub and a mechanically-actuated BHA.
Date Recue/Date Received 2020-12-04
[0024] In a general aspect, a bottom hole assembly (BHA) adapted for
connection to coiled tubing extending from surface into a wellbore is
provided, the
coiled tubing having a tubing bore, the BHA comprising: an instrumentation sub
in
electrical communication with the surface and having a data processor, an
axial
bore in communication with the tubing bore, and an electrical conduit
permitting
electrical power and signals to pass from a first end of the instrumentation
sub to a
second end of the instrumentation sub downhole of the first end; one or more
sensors electrically connected to the instrumentation sub; and a mechanical
shifting
tool downhole of the instrumentation sub and adapted for actuating sleeve
valves
located along the wellbore; wherein the data processor is adapted to receive
data
from the one or more sensors and communicate the data to the surface; and
wherein the axial bore is sized to permit a fluid flow rate conducive to
hydraulic
fracturing operations.
[0025] In an embodiment, the one or more sensors comprise at least
one of a
3D directional sensor, a sensor adapted to determine axial movement, a sensor
adapted to determine rotational movement, an axial force sensor, an
accelerometer,
a positional sensor, a pressure sensor, a temperature sensor, or a combination
thereof.
[0026] In an embodiment, the BHA further comprises a receiver located
uphole of the shifting tool and a transmitter located downhole of the shifting
tool,
wherein the transmitter is electrically connected to one or more electrical
components located downhole of the shifting tool and the receiver is
electrically
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connected to the data processor, and wherein the transmitter is adapted to
communicate data to the receiver.
[0027] In an embodiment, the receiver is a first transceiver, and the
transmitter is a second transceiver.
[0028] In an embodiment, at least one of the one or more sensors is located
downhole of the shifting tool and electrically connected to the transmitter.
[0029] In an embodiment, at least a first pressure sensor is located
uphole of
the shifting tool and at least a second pressure sensor is located downhole of
the
shifting tool and electrically connected to the transmitter.
[0030] In an embodiment, the BHA further comprises a check valve located
in-line with the axial bore and adapted to prevent fluid from flowing uphole
therethrough.
[0031] In an embodiment, the fluid flow rate is about 1m3/min or
greater.
[0032] In an embodiment, the BHA further comprises a power source and
memory module located on the instrumentation sub and electrically connected to
the one or more sensors.
[0033] In an embodiment, the shifting tool is configured to actuate
between
various operational modes via an axial telescopic movement of a mandrel of the
shfiting tool relative to a housing of the shifting tool.
[0034] In an embodiment, the BHA further comprises a disconnect located
between the instrumentation sub and the shifting tool.
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[0035] In an embodiment, the disconnect is configured to sever an
electrical
and mechanical connection between the instrumentation sub and shifting tool in
response to an electrical signal.
[0036] In an embodiment, the disconnect is configured to sever an
electrical
and mechanical connection between the instrumentation sub and shifting tool in
response to an actuating member engaging the disconnect.
[0037] In an embodiment, the diameter of the axial bore is
substantially
uniform.
[0038] In an embodiment, the BHA further comprises a drilling tool
adapted to
be interchangeable with the shifting tool.
[0039] In a general embodiment, a method for performing fracturing
operations in a wellbore having one or more sleeve valves positioned
therealong
comprises: running a bottom hole assembly (BHA) located on a tubing string to
a
position adjacent a sleeve valve of interest of the one or more sleeve valves;
pulling
uphole on the BHA to locate the sleeve valve of interest using a mechanical
shifting
tool of the BHA; acquiring data regarding one or more parameters of the BHA
and
wellbore using one or more sensors electrically connected to an
instrumentation sub
of the BHA; confirming the successful locating of the sleeve valve of interest
using
the acquired data; actuating the sleeve valve of interest to an open position
with the
shifting tool; isolating the wellbore below the sleeve valve of interest with
a packer
of the BHA; and introducing fluid into the wellbore to fracture a zone of
interest of
the wellbore adjacent the sleeve valve of interest.
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[0040] In an embodiment, the method further comprises confirming the
successful actuation of the sleeve valve of interest to the open position
using the
acquired data, and wherein the acquired data comprises at least one of
accelerometer data and axial load data.
[0041] In an embodiment, the method further comprises confirming the
successful isolation of the wellbore below the sleeve valve of interest using
the
acquired data, and wherein the acquired data comprises at least data regarding
a
first pressure uphole of the shifting tool and data regarding a second
pressure
downhole of the shifting tool.
[0042] In an embodiment, the step of acquiring data further comprises
acquiring the second pressure using a pressure sensor downhole of the shifting
tool, receiving the data regarding the second pressure at a transmitter
downhole of
the shifting tool, and sending the data regarding the second pressure to a
receiver
uphole of the shifting tool.
[0043] In an embodiment, the acquired data comprises data regarding
pressure within an axial bore of the BHA and pressure within an annulus
defined
between the BHA and the wellbore, and the step of introducing fluid further
comprises monitoring the pressure in the axial bore and the pressure in the
annulus.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0044] Figure 1 is a representative illustration of a downhole
fracturing
operation incorporating an instrumentation sub in a bottom hole assembly for
communicating data regarding various downhole parameters to surface;
[0045] Figure 2A is a representative illustration of an embodiment of a
bottom
hole assembly having an instrumentation sub incorporated therein for acquiring
data
regarding various downhole parameters;
[0046] Figure 2B is a representative illustration of another
embodiment of a
bottom hole assembly having an instrumentation sub;
[0047] Figure 3A is a cross-sectional depiction of another embodiment of a
bottom hole assembly incorporating an instrumentation sub, according to an
embodiment of the disclosure;
[0048] Figure 3B is a cross-sectional depiction of the bottom hole
assembly
of Figure 3A in use for shifting a sleeve located along a wellbore and
fracturing a
.. zone of interest outside and adjacent to the sleeve;
[0049] Figure 4A is an elevation view of an embodiment of an
instrumentation
sub for use with a bottom hole assembly for fracturing operations; and
[0050] Figure 4B is a cross-sectional view of the instrumentation sub
of
Figure 4A.
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DETAILED DESCRIPTION
[0051] Embodiments are described herein in the context of fracturing
operations. However, as one of skill in the art will understand, systems and
methods
disclosed herein are also applicable to other completion and stimulation
operations.
[0052] The terms "uphole" and "downhole" used herein are applicable
regardless the type of wellbore; "downhole" indicating being toward a distal
end or
toe of the wellbore and "uphole" indicating being toward a proximal end or
surface
of the wellbore.
[0053] With reference to Fig. 1, embodiments described herein utilize
an
electronic instrumentation sub and electronic sensing components incorporated
into
a bottom-hole assembly (BHA) having a mechanically-actuated fracturing/sleeve
shifting tool. The BHA can be run into a wellbore on a tubing string, such as
coiled
tubing (CT), for completion of multiple zones of interest of a hydrocarbon
formation
adjacent to the wellbore. The electronic instrumentation sub can be connected
to
monitoring equipment at surface, such as via a wireline running through, fixed
to, or
embedded in coiled tubing for communicating data collected by the sensing
components regarding various wellbore parameters to surface. The CT and
wireline
can be provided on a spool connected to a motor. Moreover, a bore of the
instrumentation sub is configured to accommodate the flow requirements of
fracturing operations and be suitable for use with the flow rates and erosive
fluids
often utilized in such operations. Incorporation of the instrumentation sub
and
electronic sensing equipment in conjunction with a mechanical fracturing tool
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enables operators to be aware of downhole conditions and make adjustments to
completion operations in real-time or near real-time, thus permitting
flexibility
heretofore unavailable in conventional completion operations using
mechanically-
actuated fracturing/shifting tools alone. A pump at surface is configured to
pump
fracturing fluid, such as a sand-laden fluid, downhole via the bore of the CT
or the
annulus formed between the CT and wellbore casing.
[0054] Embodiments described herein are useful for treating or
fracturing
new wellbores that are drilled, but have not yet been completed. The wellbores
can
be cased and have ported sliding sleeve subs installed therein, the sleeve
subs
having sliding sleeves actuable between a closed position, wherein the sleeves
cover fracturing ports of the sleeve sub, and an open position, wherein the
fracturing ports are exposed to establish fluid communication between the
wellbore
and the formation. At the beginning of fracturing operations, the sleeves are
typically in the closed position, having not yet been actuated to expose the
fracturing ports. In embodiments, the sliding sleeves may also be selectively
closable to stop communication between the formation and the wellbore
therethrough. The sliding sleeves can have an inner profile adapted to be
engaged
by the fracturing tool of the BHA such that the sleeves can be shifted axially
between the open and closed positions by manipulation of the CT after being
engaged by the fracturing tool.
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General BHA Construction
[0055] In embodiments, with reference to Figs. 2A and 2B, a BHA is
shown
located at a distal end of a CT string for deployment into a wellbore for
completion
operations, such as fracturing operations. The BHA comprises an
instrumentation
sub, a mechanically actuated fracturing/sleeve shifting tool, and one or more
sensors electrically connected to the instrumentation sub and capable of
measuring
various parameters of the BHA and wellbore. The sensors can be configured to
measure parameters such as circulation pressure inside the CT, wellbore
pressure
in the annulus surrounding the CT and BHA, differential pressure across select
components (e.g. across a packer of the fracturing tool), relative axial force
on the
CT (e.g. tension and compression), BHA vibration or shock (e.g. total RMS
vibration), torque, BHA inclination, axial and/or rotational movement of the
BHA,
and 3D direction of the BHA. In the depicted embodiments, the mechanical
fracturing tool is located downhole from the instrumentation sub. In
alternative
embodiments, the fracturing tool can be located uphole from the
instrumentation
sub.
[0056] When the BHA is deployed into the wellbore, an annulus is
formed
between the CT/BHA and the wellbore casing. Fluid can be conducted from
surface
downhole through a tubing bore of the CT, or through the annulus. The BHA can
also have an axial bore for allowing the communication of fluid therethrough.
Bi-
directional electrical communication between surface and the BHA is enabled
via
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wireline. The wireline is connected at a proximal end thereof to electrical
equipment
at surface, such as a controller and a display device, and terminates at a
distal end
thereof at a cable head assembly of the instrumentation sub. As one of skill
in the
art will understand, any wireline or other electrical connection that provides
.. sufficient electrical capability to permit transmission of power and
communication of
data between the BHA and surface would be suitable for use in embodiments
described herein. In embodiments, fiber optics incorporated into the wireline
may be
used to communicate data between surface and the BHA.
[0057] In embodiments, a release sub or disconnect can be located
between
.. the instrumentation sub and the fracturing tool, such that the
instrumentation sub
can be disconnected from the fracturing tool and retrieved to surface in the
event
the fracturing tool becomes stuck in the wellbore. The disconnect can be
mechanically actuated, such as via a ball or other actuating member dropped
into
the CT from surface to engage the disconnect, or electrically connected to the
.. instrumentation sub and electrically actuated to decouple the fracturing
tool from the
components thereabove. In other embodiments, the disconnect can be configured
to separate if a predetermined tensile load is experienced.
[0058] The BHA is fluidly connected to a distal end of the CT, and
the
instrumentation sub has an axial bore having a cross-sectional flow area that
permits fluid flow rates suitable for fracturing operations while avoiding
fluid
velocities that would result in severe erosion of the axial bore due to
fracturing fluid
flowing therethrough. Additionally, the cable head assembly of the
instrumentation
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sub is configured such that it does not restrict the size of the axial bore of
the sub,
further enabling fluid flow rates required for fracturing operations, and
mitigating
erosion of components in the instrumentation sub. Such an enlarged flow area
is
advantageous over prior art instrumentation subs, which have restricted axial
bores
in order to accommodate electronic components in a bulkhead of the sub.
[0059] In embodiments, the axial bore of the instrumentation sub is
deviated
to accommodate the electronic components of the instrumentation sub. The
location
at which the axial bore deviates is particularly susceptible to erosion. To
mitigate
such erosive effects, the angle at which the axial bore is deviated can be
reduced.
[0060] At least one radially-extending fracturing port can be formed in the
housing of the BHA and be configured to selectively permit fluid communication
between the axial bore and annulus such that fracturing fluid can be delivered
to the
formation via the tubing bore and axial bore in coiled-tubing fracturing
operations. In
the embodiment depicted in Figs. 2A and 2B, the fracturing ports are located
downhole from the instrumentation sub, between the disconnect and the
fracturing
tool.
[0061] In embodiments, the instrumentation sub can have a power
storage
means, such as a battery or capacitor, and a memory module configured to store
data acquired by sensors, and be capable of operating in a memory mode in
which
data collected by the sensors is stored in the memory module for later
retrieval. In
embodiments, the instrumentation sub can operate in the memory mode while
transmitting downhole data to surface, such that a backup of the data is
stored in
Date Recue/Date Received 2020-12-04
the event real-time data transmission to surface is interrupted or otherwise
unavailable.
Fracturing Tool
[0062] In embodiments, the fracturing tool is a mechanical sleeve shifting
tool
such as that shown in Figs. 2A-3B, comprising a packer, a plurality of dogs,
and a J-
slot mechanism that enables the tool to be actuated between various operating
modes, including a running position (RIH), a sleeve locating position
(LOCATE), a
set or sleeve engaged position (SET), and a pull-out-of-hole position (POOH).
The
dogs have uphole and downhole interfaces configured to engage with the sleeve
profiles of the sleeve valves located along the wellbore casing. In the
running
position RIH and pull-out-of-hole position POOH, the plurality of dogs are in
a
radially inwardly retracted position such that the dogs do not contact or
engage the
wellbore casing or sleeves as the tool is being run-in-hole RIH or pulled-out-
of-hole
POOH. In the sleeve locating position LOCATE, the dogs are biased radially
outwards into contact with the wellbore casing and the sleeve valves, such
that the
dogs will engage the sleeve profiles of the sleeve valves as the BHA is
axially
manipulated thereby. In the sleeve engaged position SET, the dogs are locked
in
the radially outward position in engagement with the sleeve profile of a
sleeve, such
as by a cone, such that the tool can be RIH or POOH to open or close the
sleeve
valve. Further, in the SET position, the packer of the fracturing tool is
energized and
engaged with the wellbore to isolate the portion of the wellbore above the
fracturing
21
Date Recue/Date Received 2020-12-04
tool from the portion of the wellbore therebelow. In embodiments, a bypass
valve of
the fracturing tool is also closed to prevent fluid from flowing downhole of
the
fracturing tool through the axial bore of the BHA.
[0063] A best shown in Figs. 3A and 3B, the dogs can be secured to a
housing of the fractural tool while the packer and cone can be secured to a
fracturing tool mandrel. Mandrel is telescopically connected to the fracturing
tool
housing such that axial manipulation of the CT telescopically actuates the
mandrel
relative to the fracturing tool housing. A drag sub or drag block can be
connected to
the housing to provide axial resistance and facilitate the telescoping action
of the
mandrel. The various operating modes of the BHA are delimited by the J-slot
mechanism and are correlated to the axial position of the mandrel relative to
the
fracturing tool housing. For example, the dogs can be located at the distal
ends of
arms having cams formed thereon, the cams having a radially varying profile.
An
actuating ring or spider secured to, and movable with, the mandrel is
configured to
engage the cams of the arms and retract the arms and dogs radially inwardly or
permit the arms and dogs to extend radially outwardly, depending on the axial
position of the mandrel relative to the housing. Axial stroking of the mandrel
relative
to the housing cycles the J-slot mechanism and actuates the fracturing tool
through
its operating modes. As discussed above, such axial telescoping makes it
difficult to
locate sensors and other electrical components downhole of the fracturing
tool, as
providing an electrical connection between the uphole and downhole ends of the
fracturing tool is challenging due to the varying axial distance therebetween.
22
Date Recue/Date Received 2020-12-04
[0064] An example of a suitable fracturing/shifting tool for use with
the BHA is
the tool disclosed in Applicant's US patent no. 10,472,928, incorporated
herein in its
entirety. One of skill in the art would understand that other fracturing tools
may be
used depending on factors such as the type of sleeve or zone isolation
mechanism
used in the wellbore.
Short Hop System
[0065] In embodiments, with reference again to Figs. 2A and 2B, a
receiver
can be located uphole from the fracturing tool, such as inside the
instrumentation
sub or in a separate receiver sub electrically connected to the
instrumentation sub,
and a transmitter can be located downhole from the fracturing tool, such as on
a
transmitter sub. The transmitter can be connected to sensors configured to
take
measurements of various parameters downhole of the fracturing tool, such as
annular pressure, temperature, tension/compression, and torque, and wirelessly
send said measurements or other data to the receiver for subsequent
transmission
to surface in real-time or near real-time. Such a "short hop" system for
bridging
communication of data above and below the fracturing tool is desirable. For
example, sensors can be used to obtain pressure data above and below packers
or
other isolation elements of the fracturing tool in order to confirm whether
the packer
was successfully engaged against the casing to isolate the zone of interest
from the
rest of the wellbore before fracturing. In embodiments, first and second
transceivers
can be used in place of the receiver and transmitter, such that data can be
23
Date Recue/Date Received 2020-12-04
communicated bi-directionally between components uphole and downhole of the
fracturing tool.
[0066] Currently, data regarding the uphole and downhole ends of the
fracturing tool is collected by sensors and stored in memory modules onboard
the
BHA to be analyzed at surface when the BHA is retrieved. Real-time
communication
of such data to surface has been heretofore unavailable due to the difficulty
of
establishing a physical electrical connection between equipment uphole and
downhole of the mechanical fracturing tool as a result of the axially
reciprocating
and rotational functions of the tool.
[0067] The transmitter/transceiver downhole of the fracturing tool can be
powered by an on-board power source located on the BHA downhole of the
fracturing tool, such as a battery or a capacitor, such that it is unnecessary
to have
any electrical connection between the uphole and downhole ends of the
fracturing
tool.
Electrical Throughput
[0068] The instrumentation sub can have an electrical throughput to
permit
additional electrical tools to be located below the instrumentation sub.
Electrical
connection between the instrumentation sub and components therebelow can be
accomplished in a number of ways including, but not limited to, conductors
extending therebetween through the axial bore of the BHA, or conductors
extending
24
Date Recue/Date Received 2020-12-04
therebetween through an electrical race formed about a periphery of the BHA's
corn ponents.
Check Valve
[0069] In embodiments, a check valve is located in the axial bore of the
BHA
to prevent fluids from flowing from the wellbore up the CT and potentially
damaging
the wireline. The check valve can comprise a mechanical check valve or an
electrically-actuated valve, such as a solenoid valve. As best seen in Figs.
2A, 2B,
and 4B, the check valve is located in the axial bore of the BHA downhole from
the
instrumentation sub, such that fluid cannot flow uphole from the wellbore to
the
tubing bore of the CT through the instrumentation sub and potentially damage
the
components or connections therein. An issue with check valves currently
employed
in BHAs is that they have relatively restricted bore dimensions, resulting in
reduced
flow rates therethrough that may not be conducive to fracturing operations,
and
suffering damage as the erosive wellbore fluids flow therethrough. The check
valve
of the present application has a bore sized to permit fluid flow rates
suitable for
fracturing operations. For example, the check valve bore can be sized to
permit a
flow rate of at least 1m3/min therethrough.
Sensors & Controller
[0070] As discussed above, the sleeve shifting/fracturing tool of the
BHA is
used to open and close sleeves by actuating the shifting tool to engage the
sleeve
Date Recue/Date Received 2020-12-04
profile of the sleeve sub of the zone of interest and pulling the CT uphole or
running
it downhole to axially shift the sleeve. Currently, mechanical shifting tools
do not
have means to confirm whether the shifting tool has successfully engaged with
the
sleeve profile of the desired sleeve, whether the sleeve was successfully
shifted,
and whether the packer of the BHA has successfully sealed with the wellbore
casing in preparation for fracturing operations.
[0071] To provide such downhole measurement capabilities, the BHA can
be
fit with one or more sensors to measure parameters of interest during
fracturing
operations. The one or more sensors can be electrically connected to the
instrumentation sub, which is configured to receive the data measured by the
sensors and communicate it to surface in real-time or near real-time via the
wireline.
[0072] A terminal can be located at surface to receive the data
transmitted by
the instrumentation sub. The terminal can have or otherwise be connected to a
display device and be configured to display the received data on the display
device.
In embodiments, the terminal can also act as a controller capable of sending
commands to the BHA and configured to manage various fracturing operation
parameters, such as a rate of injection of fluid into the wellbore, axial or
rotational
force applied to the CT string, whether to open or close the electronic check
valve
or release the electronic disconnect, and other parameters. In embodiments, as
shown in Fig. 1, the terminal can further be configured to compile the data
into
charts or tables, or process the data into other forms for further analysis.
26
Date Recue/Date Received 2020-12-04
[0073] In embodiments, the terminal can have a wireless
communications
module to enable the data received from the instrumentation sub to be
transmitted
over a wireless network, such as the Internet, a cellular network, and the
like.
Instructions to the BHA can also be sent over the wireless network to the
terminal to
be relayed to the BHA.
[0074] In embodiments described herein, and having reference again to
Figs.
2A and 2B, the instrumentation sub of the BHA and the sensors connected
thereto
permit direct measurement of parameters such as pressure, temperature, strain,
vibration and the like, and the transmission of the acquired data to surface
in real-
time or near real-time.
[0075] One or more of the sensors can be a strain sensor configured
to
measure axial loading of the CT string and/or the BHA to assist the operator
to
understand if the CT string or BHA is under tension or compression, which can
be
useful in determining whether the fracturing tool has engaged a sleeve profile
while
in the sleeve locating position, or whether the packer of the fracturing tool
has
successfully engaged with the casing. In embodiments, the strain sensor is
located
in the instrumentation sub above the fracturing tool. As one of skill in the
art will
appreciate, the strain gauges or sensors provide data to surface to assist
with
determining the status of the fracturing tool and whether an operator can
proceed to
the next stage of the fracturing operation.
[0076] In an embodiment, one or more strain sensors can also be
located
downhole from the fracturing tool and connected to the short hop transmitter /
27
Date Recue/Date Received 2020-12-04
transceiver for measuring tension and compression below the tool and
transmitting
the measured data to surface. In such embodiments, the strain sensor(s) are
preferably located uphole from the drag sub of the BHA so as to obtain
accurate
strain measurements.
[0077] The sensors can also comprise position sensors, such as
accelerometers or MEMS sensors, which are capable of measuring and providing
data regarding the orientation of each of the sensors. The data from the
sensors are
then mathematically manipulated with respect to the orientation of the sensors
to
determine the position, orientation, and bearing of the BHA, as is understood
in the
art. The accelerometers can be placed on multiple axes to determine movement,
direction, and orientation of the BHA as well as to detect vibration and
shocks to the
BHA, for example when the dogs of the fracturing tool engaged the sleeve
profile of
a sleeve and movement of the BHA stops abruptly.
[0078] Temperature sensors can also be located on the BHA to measure
fluid
and wellbore temperatures.
[0079] Pressure sensors can also be used in the BHA at different
locations to
determine the differential pressure, for example on either side of the packer
of the
fracturing tool when it is deployed. Such differential pressure measurements
can be
used to determine whether the packer successfully has engaged the casing to
isolate the zone of interest for fracturing. Pressure sensors can also be
located
inside and outside the CT for determining pressures in the annulus and/or CT
tubing
bore, as well as the differential pressure therebetween. As will be
appreciated by
28
Date Recue/Date Received 2020-12-04
those of skill in the art, pressure P1 above the packer of the fracturing tool
is
indicative of how the formation is reacting to the fracturing operation while
pressure
P2 below the packer may be indicative of the integrity of the packer element
the
packer and the formation between adjacent zones. Further, after cessation of
pumping of the fracture fluid into the wellbore, fracture closure pressures
can also
be monitored. The ability to measure pressure may be particularly advantageous
when high rate foam fracturing is performed as measuring pressure enables
understanding of the quality of the foam at the perforations. As discussed
above,
the implementation of short-hop subs above and below the fracturing tool
permit the
use of pressure sensors above and below the fracturing tool for measuring P1
and
P2, and the transmission of data acquired therewith to surface in real-time,
while
avoiding the problems associated with electrically connecting the uphole and
down hole ends of the telescoping fracturing tool.
[0080]
Movement sensors such as accelerometers can also be provided on
the BHA for measuring axial or rotational movement thereof. Such sensors can
have a resolution sufficient to measure small axial movements, such that axial
movement of the BHA when shifting a sleeve between the open and closed
positions can be detected by the sensors to confirm successful shifting of the
sleeve.
[0081]
The inclusion of sensors capable of providing 3D survey and
inclination data is also advantageous, at it permits the BHA to be quickly
reconfigured for drilling and fracturing operations. For example, a drilling
tool can be
29
Date Recue/Date Received 2020-12-04
attached to the BHA, such as at the disconnect, and used to drill a wellbore.
The
positioning sensors on the instrumentation sub are used to provide real-time
data
regarding the drilling operation. Once drilling is complete, the BHA can be
retrieved
to surface, and the drilling tool can be removed therefrom. A fracturing tool
can then
be connected to the BHA, for example at the disconnect, and the BHA used for
fracturing operations.
[0082] Additionally, the one of more sensors can also comprise 3D
directional
sensors, which could be used in embodiments where the BHA is used to
directionally drill a wellbore.
[0083] In embodiments, sensors specific to the drilling operation can be
located on or downhole of the drilling tool, and sensors specific to the
fracturing
operation can be located on or downhole of the fracturing/shifting tool.
[0084] As one of skill in the art would understand, additional
sensors for
measuring other parameters of the BHA and wellbore can be provided on the BHA
in order to provide additional data during fracturing operations.
Use in new cased or lined wellbores
[0085] In use, as shown in Fig. 1, the BHA is connected to the distal
end of a
CT string and is run into the wellbore. The wellbore has a plurality of sleeve
subs
positioned adjacent various zones of interest of the wellbore. The
instrumentation
sub of the BHA is electrically connected to the distal end of a wireline. A
proximal or
surface end of the wireline is connected to the terminal and other equipment
at
Date Recue/Date Received 2020-12-04
surface configured to receive data from the instrumentation sub and send
instructions to the BHA and surface equipment for controlling various aspects
of the
fracturing operation. Typically, the BHA is first run to the toe of the
wellbore as
fracturing is performed at intervals or zones of interest from the toe of the
wellbore
.. toward a heel of the wellbore.
[0086] The fracturing tool of the BHA can first be set to the running
position
and run-in-hole to the toe of the wellbore. After reaching the toe, the
fracturing tool
can then be actuated to the sleeve locating position LOCATE and pulled uphole
until it reaches the first zone of interest and engages the sleeve profile of
a
corresponding sleeve valve of interest. Arrival of the BHA at the first zone
of interest
can be confirmed by data received from the various sensors of the BHA, as
described above. For example, confirmation that the fracturing tool
successfully has
engaged the sleeve profile of the sleeve sub of the first zone of interest can
be
obtained from data acquired by the strain gauges and accelerometers, which
would
respectively show increased tension along the CT string and a sudden
deceleration.
[0087] Once engagement with the sleeve profile by the fracturing tool
is
confirmed, the tool can be actuated to the sleeve engaged position SET to lock
the
dogs of the fracturing tool in engagement with the sleeve profile, and the BHA
can
be lowered downhole to shift the sleeve to the open position and expose the
fracturing ports of the sleeve sub, thereby establishing communication between
the
wellbore and the zone of interest via the fracturing ports. Data from the
movement
31
Date Recue/Date Received 2020-12-04
sensors can be used to confirm that the sleeve was indeed shifted to the open
position i.e. a sudden downhole acceleration and deceleration of the BHA.
[0088] With reference to Fig. 3B, after confirming that the sleeve
has been
opened, the packer of the fracturing tool can be set below the fracturing
ports of the
sleeve sub to isolate the portion of the wellbore above the fracturing tool
from the
portion of the wellbore therebelow, and fracturing fluid can be introduced
into the
wellbore to fracture the formation at the zone of interest. Fracturing fluid
can be
introduced into the wellbore either through the CT or the annulus, or both, to
stimulate the zone of interest. In CT frac operations, fracturing fluid flows
through
the tubing bore and out of the ports of the BHA and the fracturing ports of
the
corresponding sleeve valve to reach the zone of interest. In annular frac
operations,
fracturing fluid flows through the annulus and out of the fracturing ports of
the
corresponding sleeve valve to reach the zone of interest. The fluid is
prevented from
flowing further down the annulus by deploying the packer of the fracturing
tool
below the fracturing ports of the sleeve valve. In embodiments, a bypass valve
of
the fracturing tool is also closed to prevent fluid from flowing downhole of
the
fracturing tool through the axial bore of the BHA. The sensors of the BHA can
be
used to confirm successful isolation of the wellbore, for example by comparing
the
measurements of a first pressure sensor uphole of the fracturing tool with the
measurements of a second pressure sensor downhole of the fracturing tool.
Pressure sensors located in the tubing bore and annulus can be used during the
pumping of fluid into the wellbore to evaluate the status of the frac. For
example, an
32
Date Recue/Date Received 2020-12-04
increase in annular or tubing pressure may indicate a screenout, and a rising
differential pressure between the tubing bore and annulus may indicate a need
to
adjust fluid flow.
[0089] Once the zone of interest has been fractured, injection of
fracturing
fluid can cease. In embodiments, for annular fracturing operations, clean
fluid can
be reverse circulated, that is, injected into the CT to flow out of the flow
ports of the
BHA and back to surface through the annulus to remove debris. Such reverse
circulation can be done in the case of CT fracturing operations as well if the
check
valve is not present in the BHA, or if the check valve can be actuated to an
open
position to permit fluid to flow up the CT through the instrumentation sub. In
the
case of reverse circulation in CT fracturing operations, care must be taken to
avoid
screenout of the instrumentation sub due to sand and debris entrained in the
circulating fluid.
[0090] The BHA is then repositioned by actuating the fracturing tool
to the
pull-out-of-hole position POOH and pulling on the CT to position the BHA
adjacent
the next sleeve valve of interest, uphole from the previously completed zone.
Once
again, the mechanical fracturing tool can be actuated to the sleeve locating
position
LOC and the BHA moved axially uphole until the sleeve valve corresponding to
the
new zone of interest is located. Once again, the sensors of the BHA can be
used to
provide information with respect to whether the fracturing tool has
successfully
located a sleeve. Once successful location of the sleeve has been confirmed,
the
33
Date Recue/Date Received 2020-12-04
fracturing tool can be actuated to the sleeve engaging position SET and the
BHA
moved downhole to shift the sleeve to the open position.
[0091] In embodiments, the BHA can also be used to close sleeve
valves by
locating sleeve valves of interest in the manner described above, and using
the
BHA to shift the sleeves of said sleeve valves to the closed position. The
sensors of
the BHA can be used to confirm successful location and actuation of the sleeve
valves to the closed position, for example by detecting the sudden
acceleration and
deceleration of the BHA, or a change in axial load on the CT and BHA.
34
Date Recue/Date Received 2020-12-04
