Note: Descriptions are shown in the official language in which they were submitted.
DOWNHOLE PRESSURE SENSING DEVICE
FOR OPEN-HOLE OPERATIONS
FIELD
[0001] The present
disclosure relates generally to drilling systems and
particularly to a controllable downhole barrier employed during drilling
operations. More
specifically, the present disclosure describes an
automatically triggered downhole barrier employed during drilling
operations.
BACKGROUND
[0002] Barriers
are typically employed to prevent hydrocarbon influx
to the surface. Cased-hole operations, such as well completion and well
intervention, generally employ sophisticated pressure control systems at
the wellhead and in the production tubing.
[0003] By contrast, open-hole operations typically employ less
sophisticated pressure control systems. For
example, a drilling fluid
barrier is generally employed during open-hole well construction to
prevent formation pressures from overcoming hydrostatic head pressure,
which may result in hydrocarbon influx. Conventional open-hole pressure
control systems include human operators that monitor and react to well
conditions. For
example, human operators adjust drilling fluid
characteristics or drilling fluid pressures to maintain a regulated
overbalance to prevent hydrocarbon influx. What is needed is a pressure
control system for open-hole operations that automatically monitors and
reacts to well conditions in real-time, without human operator
intervention, to prevent uncontrolled influx.
SUMMARY
[0003a] In
accordance with a general aspect, there is provided a
drilling assembly, comprising: a pressure control module positioned
CA 2952010 2018-04-09
proximate to a drill bit, the pressure control module comprising: a
pressure sensor that detects pressure conditions at the drill bit; and a
valve that automatically shuts-off fluid flow within a drillpipe based on the
pressure sensor detecting threshold pressure condition.
[0003b] In accordance with another aspect, there is provided a
method of performing open-hole drilling operations, the method
comprising: detecting pressure conditions at a drill bit provided at a
downhole end of a drillpipe; automatically shutting-off fluid flow within
the drillpipe upon detecting a threshold pressure condition; and
switching-on fluid flow within the drillpipe upon detecting an activation
condition.
[0003c] In accordance with a further aspect, there is provided a
drilling assembly, comprising: a drillpipe; a drill bit provided at a
downhole end of the drillpipe; a pressure control module positioned
proximate to the drill bit; and a processor provided at the pressure
control module, the processor communicating with a computer-readable
storage medium having instructions stored thereon that, when executed
by the processor, cause the processor to: detect pressure conditions at
the drill bit; automatically shut-off fluid flow within the drillpipe upon
detecting a threshold pressure condition; and switch-on fluid flow within
the drillpipe upon detecting an activation condition.
la
CA 2952010 2018-04-09
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] Implementations of the present technology will now be described,
by way of example only, with reference to the attached figures, wherein:
[0005] FIG. 1 is a partial cross-section view illustrating an embodiment of
a drilling rig for drilling a wellbore with the drilling system configured in
accordance with principles of the present disclosure;
[0006] FIG. 2A is a diagram illustrating the pressure control module 114
in a shut-off state according to one example;
[0007] FIG. 26 is a diagram illustrating the pressure control module 114
in a fluid-flow state according to one example;
[0008] FIG. 3 is a diagram illustrating a close-up view of a mechanism in
the pressure control module that controls fluid flow there through;
[0009] FIG. 4 is a flowchart of an example method according to the
present disclosure;
[0010] FIG. 5 is a diagram illustrating various drilling assembly designs
that include the pressure control module and supporting components
according to the present disclosure; and
[0011] FIG. 6 is a diagram illustrating various completion assembly
designs that include the pressure control module and supporting components
according to the present disclosure.
2
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
DETAILED DESCRIPTION
[0012] It
will be appreciated that for simplicity and clarity of illustration,
where appropriate, reference numerals have been repeated among the
different figures to indicate corresponding or analogous elements. In
addition, numerous specific details are set forth in order to provide a
thorough understanding of the embodiments described herein. However, it
will be understood by those of ordinary skill in the art that the embodiments
described herein can be practiced without these specific details. In other
instances, methods, procedures and, components have not been described
in detail so as not to obscure the related relevant feature being described.
Also, the description is not to be considered as limiting the scope of the
embodiments described herein. The drawings are not necessarily to scale
and the proportions of certain parts have been exaggerated to better
illustrate details and features of the present disclosure.
[0013]
Throughout this description, terms such as "upper," "upward,"
"lower," "downward," "above," "below," "downhole," "uphole," "longitudinal,"
"lateral," and the like, as used herein, are descriptive of a relationship
with,
and are used with reference to, the bottom or furthest extent of the
surrounding wellbore, even though the wellbore or portions of it may be
deviated or horizontal. Correspondingly, the transverse, axial, lateral,
longitudinal, radial, etc., orientations shall mean orientations relative to
the
orientation of the surrounding wellbore or wellbore tool in question.
Additionally, the non-limiting embodiments within this disclosure are
illustrated such that the orientation is such that the right-hand side is down
hole compared to the left-hand side.
[0014]
Several definitions that apply throughout this disclosure will now
be presented. The term "coupled" is defined as connected, whether directly
or indirectly through intervening components, and is not necessarily limited
3
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
to physical connections. The connection can be such that the objects are
permanently connected or releasably connected. The term "outside" refers
to a region that is beyond the outermost confines of a physical object. The
term "inside" indicates that at least a portion of a region is partially
contained within a boundary formed by the object. The term "substantially"
is defined to be essentially conforming to the particular dimension, shape, or
other word that substantially modifies, such that the component need not be
exact. For
example, substantially cylindrical means that the object
resembles a cylinder, but can have one or more deviations from a true
cylinder.
[0015] The
term "radially" means substantially in a direction along a
radius of the object, even if the object is not exactly circular or
cylindrical.
The term "axially" means substantially along a direction of the axis of the
object. If not specified, the term axially is such that it refers to the
longer
axis of the object.
[0016] The
term "drillpipe" means any conduit that extends downhole to
support drilling operations. The drillpipe is coupled to a drill bit provided
at
the downhole end of the drillpipe. The drillpipe may include a drill string,
coil tubing, or any other conduit that extends downhole to support drilling or
workover operations. The drill string may include drillpipe of pre-determined
lengths, such as 30 feet, 90 feet, or the like. The coil tubing may include
continuous piping of several hundred feet or greater.
[0017]
"Processor" as used herein is an electronic circuit that can make
determinations based upon inputs and is interchangeable with the term
"controller". A processor can include a microprocessor, a rnicrocontroller,
and a central processing unit, among others. While a single processor can
be used, the present disclosure can be implemented over a plurality of
4
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
processors, including local controllers provided in a tool or sensors provided
along the drillpipe.
[0018] According to one example, open-hole operations are employed
during well construction. The open-hole operations typically include forming
casing strings, such as a surface casing and intermediate casing. If a well is
determined to be viable, then well completion may include forming a
production casing for cased-hole operations.
[0019] FIG. 1 schematically illustrates an open-hole drilling operation 100
used to form a subterranean well according to one example. A wellbore 102
is illustrated drilled into the earth 104 from the ground's surface 106 using
a
drill bit 110 provided on a drillpipe 112. For illustrative purposes, the top
portion of the wellbore 102 includes the surface casing 107, which is
typically at least partially comprised of cement and which defines and
stabilizes the wellbore 102 after being drilled. The wellbore 102 also may
include intermediate casings (not shown), which may be stabilized with
cement. The cement performs several functions, including preventing
wellbore collapse, maintaining a physical separation between the Earth's
layers, providing a barrier to prevent fluid migration, enhancing safety, and
protecting the Earth's layers from any contaminants introduced during open-
hole operations, or the like.
[0020] As illustrated in FIG. 1, the drill bit 110 is located at the
bottom,
distal end of the drillpipe 112 that supports components along its length.
During the open-hole operations, the drill bit 110 and drillpipe 112 are
advanced into the earth 104 by a drilling rig 120. The drilling rig 120 may
be supported directly on land as illustrated or on an intermediate platform if
at sea.
[0021] A pressure control module 114 is illustrated on the drillpipe 112
for controlling pressure conditions near the drill bit 110. Measurement while
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
drilling (MWD)/logging while drilling (LWD) procedures are supported both
structurally and communicatively. The lower end portion of the drillpipe 112
may include a drill collar proximate the drilling bit 110. The drill bit 110
may
take the form of a roller cone bit or fixed cutter bit or any other type of
bit
known in the art. Sensor sub-units 130, 132 are shown within the cased
portion of the well and can be enabled to sense nearby characteristics and
conditions of the drillpipe, formation fluid, casing, and surrounding
formation. Data indicative of sensed conditions and characteristics is either
recorded downhole, for instance at a processor (now shown) for later
download or communicated to the surface either by wire using repeaters
134,136 up to surface wire 138, or wirelessly or otherwise. If wirelessly, the
downhole transceiver (antenna) 134 may be utilized to send data to a local
processor 140, via surface transceiver (antenna) 142. The data may be
either processed at processor 140 or further transmitted along to a remote
processor 144 via wire 146 or wirelessly via antennae 142 and 148. For
purposes of completeness, FIG. 1 illustrates coiled tubing 150 and wireline
152 deployment, which are contemplated and within the context of this
disclosure.
[0022] A drilling fluid 160 may be circulated through the drilling
components to perform functions such as preventing blow-out and
preventing collapse of the wellbore 102. According to one example, the
drilling fluid 160 may be circulated during drilling operations through the
drillpipe 112, the pressure control module 114, the drill bit 110, and the
annulus 109. According to one example, the drill bit 110 may include
nozzles that direct a flow of drilling fluid 160. After passing through the
drilling components, the drilling fluid 160 may be circulated to the surface
106, where it passes through a filter (not shown) to remove any drilling
debris, such as cuttings or the like. According to one example, the filter may
6
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
include a shale shaker or the like. The filtered drilling fluid 160 may be
collected in a tank 162 for re-circulation through the drilling components.
The drilling fluid 160 may be formulated to perform other functions,
including lubricating the drill bit 110, cooling the drill bit 110, flushing
drilling
debris, such as rock, away from the drill bit 110 and upward to the Earth's
surface 106 through the annulus 109 formed between the wellbore 102 and
the drillpipe 112, and reducing friction between the drillpipe 112 and the
wellbore 102, or the like.
[0023] An additional mode of communication is contemplated using
drilling fluid 160 pumped via conduit 164 to a downhole drilling fluid motor
165. The drilling fluid is circulated down through the drillpipe 112 and up
the
annulus 109 around the drillpipe 112. For purposes of communication,
resistance to the incoming flow of drilling fluid may be modulated downhole
to send backpressure pulses up to the surface for detection at sensor 166.
Data from sensor 166 may be sent along communication channel 167 (wired
or wirelessly) to one or more processors 140, 144 for recordation and/or
processing. A surface installation 170 may be provided to send and receive
data to and from the well. The surface installation 170 may include a local
processor 140 that may optionally communicate with one or more remote
processors 144, 145 by wire 146 or wirelessly using transceivers 142, 148.
[0024] FIG. 1 further illustrates that the wellbore 102, which extends
downhole into the Earth's layers, is subjected to hydrostatic pressure
originating from subterranean destinations or formations. The hydrostatic
pressure originating from outside the wellbore 102 is identified as formation
hydrostatic pressure. The hydrostatic pressure originating from inside the
wellbore 102 is defined as drilling fluid hydrostatic pressure. As the
drilling
depth increases, a hydrostatic pressure differential varies between the
outside formation hydrostatic pressure and the drilling fluid hydrostatic
7
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
pressure. For example, the hydrostatic pressure differential may increase as
the drilling depth increases. The hydrostatic pressure differential may force
minerals, such as oil and gas, from the formation into the wellbore 102.
Alternatively, the hydrostatic pressure differential may force drilling fluid
160
from the wellbore 102 into the formation. In either of these situations, the
effect of the hydrostatic pressure differential may disrupt drilling
operations.
[0025] According to one example, the hydrostatic pressure may be
under-balanced when the formation hydrostatic pressure is greater than the
drilling fluid hydrostatic pressure. During under-balanced conditions, any
minerals that enter the wellbore 102 may ascend under pressure through
the drillpipe 112 and the annulus 109 causing a blow-out at the surface 106.
The blow-out may damage equipment and cause injury or death to workers
at the surface 106. Additionally or alternatively, during under-balanced
conditions, the hydrostatic pressure difference may collapse or restrict the
diameter of the wellbore 102, which may cause disruptions to drilling
operations.
[0026] During over-balanced conditions, the drilling fluid 160 may exit
the wellbore 102 and leach into the formation. Loss of drilling fluid 160 is
financially and environmentally undesirable. Furthermore, the drilling fluid
160 may cause the formation to swell proximate to the wellbore 102. The
swelling may restrict the diameter of the wellbore 102, which may cause
disruptions to drilling operations.
[0027] According to one example, the hydrostatic pressure differential
may be controlled during open-hole operations by adjusting characteristics
of the drilling fluid 160, such as density or drilling fluid weight,
viscosity, or
the like. For example, the drilling fluid characteristics may be adjusted
using
additives or the like. Drilling fluid engineers and drilling fluid loggers may
constantly monitor and adjust the drilling fluid characteristics to maintain
8
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
desired hydrostatic pressure differentials during open-hole drilling
operations. The drilling fluid characteristics may be adjusted to
accommodate for drilling depth, detected properties of the exposed
formation, or the like. When
desired drilling fluid characteristics are
reached, the drilling fluid 160 may be employed to control the hydrostatic
pressure differential downhole. For example, the drilling fluid 160 may be
used to exert appropriate back pressure through the drillpipe 112. The
drilling fluid characteristics may be continuously monitored and adjusted
during the open-hole drilling operations to control the hydrostatic pressure
differential. For
example, the hydrostatic pressure differential may be
controlled to one of an over-balanced condition or an under-balanced
condition, as desired. Furthermore, the hydrostatic pressure differential
may be controlled to equalize the formation hydrostatic pressure and the
drilling fluid hydrostatic pressure.
[0028]
According to another example, managed pressure drilling ("MPD")
may be applied to control the hydrostatic pressure differential during open-
hole operations. With MPD, the open-hole drilling operations are not
disrupted to change drilling fluid characteristics. Instead, the drilling
fluid
pressure exerted within annulus 109 and within the drillpipe 112 may be
adjusted during the open-hole drilling operations without disrupting
operations. For example, the drilling fluid pressure may be adjusted during
the open-hole drilling operations to increase or decrease the drilling fluid
hydrostatic pressure. Thus, MPD eliminates delays to open-hole drilling
operations, such as delays associated with stopping open-hole drilling
operations to adjust drilling fluid characteristics.
[0029] As
described above, the hydrostatic pressure differential may be
controlled downhole by adjusting drilling fluid characteristics and/or by
applying managed pressure drilling techniques. These techniques suffer
9
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
from various drawbacks such as relying on a human operator for
implementation. The human operator is typically located at the surface 106
of the open well and is tasked with monitoring and reacting to open-hole
conditions as they occur. The activities of monitoring and reacting should
occur in substantially real-time to be effective. For example, the human
operator should detect and react to a hydrostatic pressure change
substantially immediately upon its occurrence downhole. For
various
reasons, however, detection and reaction delays may be introduced.
[0030]
Detection time delays may be introduced due to propagation
delays resulting from a physical distance between the location of the
pressure change event location and the location of the human operator.
Reaction time delays may be introduced due to varying reaction times of
human operators. Yet, other reasons for detection and reaction time delays
may be due to experience levels of the human operators and their ability to
determine a significance of a pressure change event.
[0031]
Furthermore, once the pressure change event is detected during
open-hole operations, there is a reaction time delay associated with
adjusting drilling fluid characteristics and/or adjusting the drilling fluid
pressure within the annulus 109 and/or the drillpipe 112. Any time delays
associated with detecting and reacting to the pressure change event may
result in the hydrostatic pressure differential disrupting drilling
operations.
For example, the hydrostatic pressure difference may result in a collapse or
restriction of a diameter of the wellbore 102. Additionally or alternatively,
any time delay associated with detecting and/or reacting to the pressure
change event may result in a blow-out which may damage equipment and
cause injury or death to workers located at the surface 106.
[0032] These drawbacks associated with open-hole operations are
overcome by introducing a pressure control module 114 on the drillpipe 112.
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
The pressure control module 114 may monitor well conditions in real-time
and may automatically trigger to shut-off fluid flow in the drillpipe 112. For
example, the pressure control module 114 may include components that
monitor a pressure differential proximate to the drill bit 110 in real-time
and
may automatically trigger the fluid flow in the drillpipe 112 to shut-off if
the
pressure differential reaches a predetermined amount.
Positioning the
pressure control module 114 proximate to the location of the pressure
change event provides a substantially instantaneous reaction time, which
may minimize or eliminate any time delays. Also, removing the human
operator from a monitoring role may eliminate any reaction delay time.
[0033]
According to one example, a signal may be sent via repeaters
134,136 to alert the human operator of the existence of a fluid flow shut-off
event within the drillpipe 112. Additionally, the signal may provide data that
includes corresponding to well conditions that triggered the shut-off
condition. The human operator may evaluate the data to determine causes
of the shut-off condition. If needed, drilling fluid characteristics may be
adjusted and/or the drilling fluid pressure may be adjusted within the
annulus 109 and within the drillpipe 112 to adjust the hydrostatic pressure
differential to desired conditions. Additionally, a trigger threshold value
may
be adjusted to change that shut-off trigger conditions for the pressure
control module 114. While this example is described with reference open-
hole operations, one of ordinary skill in the art will readily appreciate that
the pressure control module 114 may be applied to closed-hole operations.
[0034] The
near instantaneous detection of any pressure change events
and near instantaneous reaction by the pressure control module 114
enhances safety conditions during open-hole operations, such as drilling
operations. For example, the near instantaneous detection and reaction to a
pressure change event may increase safety by automatically cycling the
11
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
drillpipe 112 from a flow-through condition to a shut-off condition without
delays typically introduced by human intervention. In this way, the pressure
control module 114 may reduce drilling delays and may eliminate blow-back
during open-hole operations. Accordingly, the pressure control module 114
may eliminate damage to equipment located at the surface 106 and may
avoid injury or death to workers located at the surface 106.
[0035]
According to one example, the pressure control module 114 may
include a processor that communicates with a computer-readable storage
medium having instructions stored thereon that, when executed by the
processor, cause the processor to detect pressure conditions and control
fluid flow. According to one example, the processor is configured to shut-off
fluid flow upon detecting a threshold pressure condition. Upon detecting an
activation condition, the processor may be configured to switched-on the
fluid flow.
[0036] FIG.
2A illustrates the pressure control module 114 in a shut-off
state according to one example. The pressure control module 114 may
include a valve that controls fluid flow through the conduit 203. For
example, the valve may include a ball 201 having a channel 202 bored
therethrough such that when the channel 202 is aligned with the conduit
203, fluid flows through the conduit 203. The ball 201 also may include a
solid portion 204 such that when the solid portion 204 is provided to the
conduit 203, fluid flow through the conduit 203 is blocked. One of ordinary
skill in the art will readily appreciate that other mechanisms may be
employed to control fluid flow through the conduit 203. For example, the
pressure control module 114 may include a flapper valve, a butterfly valve, a
choke valve, a globe valve, a piston valve, a plug valve, a spool valve, or
the
like.
12
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
[0037] Returning to FIG. 2A, the ball 201 may be configured to rotate
about an axis 206 to flip between the closed position and an open position.
According to one example, an actuation arm 205 is provided to rotate the
ball 201 between the closed position and the open position. According to
one example, the actuation arm 205 may be controlled by a hydraulic piston
207 that is fluidly coupled to a hydraulic pump 209 via a hydraulic circuit
that includes fluid lines 210,211. A hydraulic reservoir 212 is provided to
store hydraulic fluid. One of ordinary skill in the art will readily
appreciate
that other mechanisms may be employed to rotate the ball 201 between the
closed position and the open position.
[0038] FIG. 3 illustrates a close-up view of the mechanism that controls
rotation of the ball 201 between the closed position and the open position. A
battery 217 may be provided to energize components of the pressure control
module 114. A diverter block 213 is fluidly coupled to the fluid lines 210,211
and the hydraulic reservoir 212 to divert hydraulic fluid between
corresponding fluid lines 210,211 in order to actuate the hydraulic piston
207. The hydraulic piston 207 may be configured to slide the actuation arm
205 in order to rotate the ball 201 between the closed position and the open
position. A processor 215 is communicatively coupled to the hydraulic pump
209 to control operation of the hydraulic pump 209 according to signals
received from a pressure sensor 214 that is fluidly coupled to a pressure
port 218. According to one example, the pressure sensor 214 monitors the
pressure of fluid flowing through the pressure control module 114.
According to one example, the processor 215 may communicate with the
sub-unit 132 to relay information to the surface 106.
[0039] According to one example, the pressure control module 114 may
be provided along the drillpipe 112 and may be positioned proximate to the
drill bit 110 in order to detect pressure conditions at the drill bit 110.
When
13
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
the ball 201 is oriented in the open position, the pressure sensor 214 may
be monitoring the drilling fluid hydrostatic pressure and the formation
hydrostatic pressure. Thus, the pressure sensor 214 may detect a kick or
surge in the formation hydrostatic pressure. In contrast, when the ball 201
is oriented in the closed position, the pressure sensor 214 may be isolated
from the formation hydrostatic pressure. Accordingly, the pressure sensor
214 may be monitoring only the drilling fluid hydrostatic pressure when the
ball 201 is oriented in the closed position. One of ordinary skill in the art
will
readily appreciate that the pressure control module 114 may be provided at
any position along the drillpipe 112.
[0040] With reference to FIG. 2B, the ball 201 is illustrated in the open
position. Thus, the pressure sensor 214 is monitoring the drilling fluid
hydrostatic pressure and the formation hydrostatic pressure. According to
one example, the processor 215 executes instructions that cause the
hydraulic pump 209 and diverter block 213 to supply hydraulic fluid through
the fluid line 211 to push a piston 216 in a direction toward the ball 201
when the formation hydrostatic pressure exceeds the drilling fluid
hydrostatic pressure. Alternatively, the processor 215 executes instructions
that cause the hydraulic pump 209 and diverter block 213 to supply
hydraulic fluid through the fluid line 211 to push a piston 216 in a direction
toward the ball 201 when the fluid pressure detected at the pressure sensor
214 exceeds a predetermined threshold. When the piston 216 is pushed in
the direction toward the ball 201, then the actuation arm 205 is pushed
toward the ball 201, which orients the ball 201 in the closed position. One of
ordinary skill in the art will readily appreciate that other algorithms may be
employed to orient the ball 201 in the closed position.
[0041] With reference to FIG. 2A, the ball 201 is illustrated in the closed
position. Thus, the pressure sensor 214 monitors only the drilling fluid
14
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
hydrostatic pressure. In
this example, the processor 215 may be
programmed to monitor for predetermined conditions before executing
instructions to orient the ball 201 in the open position. Thus, the flow-
through condition may be activated remotely after the pressure control
module 114 is triggered to the shut-off condition. For
example, the
predetermined conditions may include a preselected pressure for a
preselected amount of time, lapsing of a preselected amount of time, or the
like. If
the fluid pressure detected at the pressure sensor 214
correspondence to the predetermined conditions, then the processor 215
executes instructions that cause the hydraulic pump 209 and diverter block
213 to supply hydraulic fluid through the fluid line 210 to push a piston 216
in a direction away from the ball 201. When the piston 216 is pushed in the
direction away from the ball 201, then the actuation arm 205 is pushed
away from the ball 201, which orients the ball 201 in the open position. One
of ordinary skill in the art will readily appreciate that other algorithms may
be employed to orient the ball 201 in the open position.
[0042] One
of ordinary skill in the art will readily appreciate that the
pressure control module 114 may be implemented in various other ways.
Additionally, the pressure control module 114 may be modified structurally
without impacting the manner of operation. For example, the control lines
210, 211 may be embedded within walls of the pressure control module 114.
Furthermore, the pressure control module 114 may be formed in a uni-body
construction or separated into additional modules.
[0043] According to another example, two or more automatically
triggered pressure control modules 114 may be provided along the drillpipe
112. For example, the pressure control modules 114 may be deployed at
different depths along the drillpipe 112. Each
of the pressure control
modules 114 may act independently of one another. Additionally, each of
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
the pressure control modules 114 may be programmed to trigger at different
predetermined pressure threshold conditions to orient the ball 201 in the
closed position. Furthermore, each of the pressure control modules 114 may
be programmed to monitor for a different predetermined condition before
executing instructions to orient the ball 201 in the open position. In other
words, each of the pressure control modules 114 may be reset to the flow-
through condition based upon different activation parameters. For example,
the first pressure control module 114 may be subjected to a first pre-
selected pressure condition for a first pre-selected amount of time, whereas
the second pressure control module 114 may be subjected to a second pre-
selected pressure condition for a second pre-selected amount of time. One
of ordinary skill in the art will readily appreciate that only one activation
parameter may be different between the first and second pressure control
modules 114.
[0044] According to yet another example, the pressure control module
103 may be applied to closed-hole operations, such as well stimulation
liners. In closed-hole operations, the pressure control module 114 may
operate as an automatic closing float shoe after the stimulation fluid is
displaced with the completion fluid or after cement is pumped. In closed-
hole operations, the pressure control module 114 may be operated using a
combination of rate (or pressure), density, time (or duration), or the like.
[0045] FIG. 4 illustrates a flowchart of an example method 400 according
to the present disclosure. The method 400 can be implemented using the
above described components. For example, the method 400 can be
implemented by the processor 215 configured to directly or indirectly control
operation of the various components. In other implementations, other
controls of the various components are considered within the scope of this
disclosure.
16
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
[0046] The
method 400 may include detecting pressure conditions at the
drill bit 110 (block 402). The pressure conditions associated with the
drilling
fluid hydrostatic pressure and the formation hydrostatic pressure may be
monitored by the pressure sensor 214 as described above. The method 400
may further include automatically shutting-off fluid flow within the drillpipe
112 upon detecting a threshold pressure condition (block 404). The
processor 215 may execute instructions to orient the ball 201 in the closed
position as described above when the fluid pressure detected at the pressure
sensor 214 exceeds a predetermined threshold.
[0047] The
present method 400 may also include switching-on fluid flow
within the drillpipe upon detecting an activation pressure condition (block
406). When the ball 201 is provided in the closed position, the pressure
sensor 214 is monitoring only the drilling fluid hydrostatic pressure. The
processor 215 may be programmed to monitor the drilling fluid hydrostatic
pressure for predetermined conditions before executing instructions to orient
the ball 201 in the open position.
[0048] Numerous examples are provided herein to enhance
understanding of the present disclosure. A specific set of examples are
provided as follows.
[0049] FIG.
5 illustrates the pressure control module 114 and supporting
components provided along a length of the drillpipe 112 for open-hole
operations. According to one example, the drillpipe 112 may include a drill
pipe 501, HWO pipe 503, drill collars, and spiral drill collars 505, or the
like.
A supporting component provided along a length of the drillpipe 112 may
include an alternator 502 that is provided downhole and may be positioned
proximate to the pressure control module 114. According to one example,
the alternator 502 may include an axial flow design may be configured to
energize electronics in the pressure control module 114. The alternator 502
17
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
may be electrically coupled to the pressure control module 114 via an
inductive coupling or by an internal hardwire.
Another supporting
component provided along a length of the drillpipe 112 may include a float
valve 504 that is provided downhole and may be positioned proximate to the
pressure control module 114. A float valve 504 may be provided to prevent
entry of the drilling fluid 160 into the drillpipe 112 while the drillpipe 112
is
being lowered. Thus, the drillpipe 112 may float during the descent, which
may decrease a little on the derrick or mast.
[0050] FIG.
5 illustrates various drilling assemblies 510, 520, 530, 540,
550, 560, 570 that may be coupled below the pressure control module 114.
According to one example, a milling assembly 510 may be provided below
the pressure control module 114 that includes a motor 511, a mill 512, and
a drill bit 514. For example, the mill 512 may include junk mills, taper
mills,
cement mills, under-reamers, cone mills, skirted mills, burn shoes, plug
mills, window mills, round nose mills, watermelon mills, CPE mills, tri-blade
mills, and guide mills, or the like. For example, the drill bit 514 may
include
tri-cone bits, multiple tri-cone bits, rock bits, coring bits, and PDC bits.
[0051]
According to another example, a hydra blast assembly 520 may
be provided below the pressure control module 114 and may include a hydra
blast pro-rotating tool 522 or a hydra blast indexing tool 524. According to
yet another example, a hydra jet assembly 530 may be provided below the
pressure control module 114 and may include a hydra jet tool 532.
According to another example, a casing scraper assembly 540 may be
provided below the pressure control module 114 and may include a casing
scraper tool 542. According to another example, a packer assembly 550
may be provided below the pressure control module 114 and may include a
packer tool 552. According to yet another example, a fishing assembly 560
may be provided below the pressure control module 114 and may include an
18
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
up/down hydraulic jar tool 562, an up/down accelerator tool 564, and a GS
pulling tool 566 or a rope spear tool 568. According to another example, a
cleaning assembly 570 may be provided below the pressure control module
114 and may include a washing tool 572, a nitrogen jet tool 574, or other
cleaning tool 576.
[0052] FIG. 6 illustrates the pressure control module 114 and supporting
components provided along a length of the drillpipe 112 for open-hole
operations. According to one example, the drill tubing 112 may include
coiled tubing. A supporting component provided along a length of the
drillpipe 112 may include an alternator 602 that is provided downhole and
may be positioned proximate to the pressure control module 114. According
to one example, the alternator 602 may include an axial flow design may be
configured to energize electronics in the pressure control module 114. The
alternator 602 may be electrically coupled to the pressure control module
114 via an inductive coupling or by an internal hardwire. Another supporting
component provided along a length of the drillpipe 112 may include a float
valve 604 that is provided downhole and may be positioned proximate to the
pressure control module 114. A float valve 604 may be provided to prevent
entry of the drilling fluid 160 into the drillpipe 112 while the drillpipe 112
is
being lowered. Thus, the drillpipe 112 may float during the descent, which
may decrease a little on the derrick or mast. A hydraulic/mechanical
disconnect 605 also may be provided to enable detachment of tools.
[0053] FIG. 6 illustrates various drilling assemblies 610, 620, 630, 640,
650, 660, 670 that may be coupled below the pressure control module 114.
According to one example, a milling assembly 610 may be provided below
the pressure control module 114 that includes a motor 611 and a mill 612.
For example, the mill 512 may include junk mills, taper mills, cement mills,
under-reamers, cone mills, skirted mills, burn shoes, plug mills, window
19
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
mills, round nose mills, watermelon mills, CPE mills, tri-blade mills, and
guide mills, or the like.
[0054] According to another example, a hydra blast pro-rotating tool 622
may be provided below the pressure control module 114. According to
another example, a hydra blast indexing tool 632 may be provided below the
pressure control module 114. According to yet another example, a coil
sweep 640 may be provided below the pressure control module 114.
According to another example, a Pulsonix TF 650 may be provided below the
pressure control module 114. According to yet another example, a fishing
assembly 660 may be provided below the pressure control module 114 and
may include an up/down hydraulic jar tool 662, an up/down accelerator tool
664, and a GS pulling tool 666 or a rope spear tool 668. According to
another example, a cleaning assembly 670 may be provided below the
pressure control module 114 and may include a washing tool 672, a nitrogen
jet tool 674, or other cleaning tool 676.
[0055] Although not illustrated, one of ordinary skill in the art will
readily
appreciate that the pressure control module 114 and supporting components
may be provided anywhere along a length of workstring for open-hole
operations, such as stimulation operations. According to one example, the
pressure control module 114 may be coupled onto a downhole end of the
workstring, such as by threading or the like.
[0056] Although not illustrated, one of ordinary skill in the art will also
readily appreciate that the pressure control module 114 and supporting
components may be provided along a length of completion tubes during
closed-hole operations.
[0057] Numerous examples are provided herein to enhance
understanding of the present disclosure. A specific set of examples are
provided as follows. In a first example, a drilling assembly is disclosed that
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
includes a pressure control module positioned proximate to a drill bit, the
pressure control module includes a pressure sensor that detects pressure
conditions at the drill bit and a valve that automatically shuts-off fluid
flow
within a drillpipe based on the pressure sensor detecting threshold pressure
condition.
[0058] In a second example, there is disclosed herein the drilling
assembly according to the first example, further including a drillpipe having
the drill bit provided at a downhole end, the drillpipe including one of a
drill
string or coil tubing.
[0059] In a third example, there is disclosed herein the drilling
assembly according to the first or second examples, wherein the pressure
sensor detects pressure conditions associated with a drilling fluid
hydrostatic
pressure and a formation hydrostatic pressure.
[0060] In a fourth example, there is disclosed herein the drilling
assembly according to any of the preceding examples first to the third,
wherein the valve automatically shuts-off fluid flow within the drillpipe when
the formation hydrostatic pressure exceeds the drilling fluid hydrostatic
pressure.
[0061] In a fifth example, there is disclosed herein the drilling assembly
according to any of the preceding examples first to the fourth, wherein the
valve switches-on fluid flow within the drillpipe when the pressure sensor
detects an activation condition.
[0062] In a sixth example, there is disclosed herein the drilling
assembly according to any of the preceding examples first to the fifth,
wherein the activation condition includes at least one of a preselected
pressure for a preselected amount of time and lapsing of a preselected
amount of time.
21
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
[0063] In a seventh example, there is disclosed herein the drilling
assembly according to any of the preceding examples first to the sixth,
further comprising a second pressure control module positioned along the
drillpipe, the second pressure control module including a second pressure
sensor that detects pressure conditions along the drillpipe and a second
valve that automatically shuts-off fluid flow within the drillpipe when the
second pressure sensor detects second threshold pressure condition.
[0064] In an eighth example, there is disclosed herein a method of
performing open-hole drilling operations, including detecting pressure
conditions at a drill bit provided at a downhole end of a drillpipe;
automatically shutting-off fluid flow within the drillpipe upon detecting a
threshold pressure condition; and switching-on fluid flow within the drillpipe
upon detecting an activation condition.
[0065] In a ninth example, there is disclosed herein a method according
to the preceding eighth example, wherein detecting the pressure conditions
includes detecting a drilling fluid hydrostatic pressure and detecting a
formation hydrostatic pressure.
[0066] In a tenth example, there is disclosed herein a method according
to any of the preceding examples eighth to ninth, wherein automatically
shutting-off fluid flow within the drillpipe is performed when the formation
hydrostatic pressure exceeds the drilling fluid hydrostatic pressure.
[0067] In an eleventh example, there is disclosed herein a method
according to any of the preceding examples eighth to tenth, wherein the
activation condition includes at least one of a preselected pressure for a
preselected amount of time and lapsing of a preselected amount of time.
[0068] In a twelfth example, there is disclosed herein a method
according to any of the preceding examples eighth to eleventh, wherein the
22
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
preselected pressure for the preselected amount of time is actuated from a
remote location.
[0069] In a thirteenth example, there is disclosed herein a method
according to any of the preceding examples eighth to twelfth, wherein the
activation condition includes detecting a drilling fluid hydrostatic pressure.
[0070] In a fourteenth example a drilling assembly is disclosed that
includes a drillpipe; a drill bit provided at a downhole end of the drillpipe;
a
pressure control module positioned proximate to the drill bit; and a
processor provided at the pressure control module, the processor
communicating with a computer-readable storage medium having
instructions stored thereon that, when executed by the processor, cause the
processor to detect pressure conditions at the drill bit; automatically shut-
off
fluid flow within the drillpipe upon detecting a threshold pressure condition;
and switch-on fluid flow within the drillpipe upon detecting an activation
condition.
[0071] In a fifteenth example, there is disclosed herein the drilling
assembly according to the first example, wherein the drillpipe includes one
of a drill string or coil tubing.
[0072] In a sixteenth example, there is disclosed herein the drilling
assembly according to the examples fourteenth and fifteenth, wherein the
processor is further configured to detect the pressure conditions including a
drilling fluid hydrostatic pressure and a formation hydrostatic pressure.
[0073] In a seventeenth example, there is disclosed herein the drilling
assembly according to the examples fourteenth and sixteenth, further
comprising an alternator that provides electrical energy to the processor.
[0074] In an eighteenth example, there is disclosed herein the drilling
assembly according to the examples fourteenth and seventeenth, wherein
23
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
the activation condition includes at least one of a preselected pressure for a
preselected amount of time and lapse of a preselected amount of time.
[0075] In a nineteenth example, there is disclosed herein the drilling
assembly according to the examples fourteenth and eighteenth, wherein the
preselected pressure for the preselected amount of time is actuated from a
remote location.
[0076] In a twentieth example, there is disclosed herein the drilling
assembly according to the examples fourteenth and nineteenth, further
comprising a second pressure control module positioned along the drillpipe;
and a second processor provided at the second pressure control module, the
second processor communicating with a computer-readable storage medium
having instructions stored thereon that, when executed by the second
processor, cause the second processor to detect pressure conditions along
the drillpipe; automatically shut-off fluid flow within the drillpipe upon
detecting a second threshold pressure condition; and switch-on fluid flow
within the drillpipe upon detecting a second activation condition.
[0077] In a twenty-first example, there is disclosed herein the drilling
assembly according to the examples fourteenth and twentieth, wherein the
processor obtains a first signal from a pressure sensor that detects pressure
conditions at the drill bit; automatically actuates a valve to shut-off fluid
flow
within the drillpipe upon obtaining a second signal from the pressure sensor
detecting a threshold pressure condition; and actuates the valve to switch-
on fluid flow within the drillpipe upon detecting an activation condition
received from the pressure sensor or calculated by the processor.
[0078] In a twenty-second example, there is disclosed herein the
drilling assembly according to the examples fourteenth and twenty-first,
wherein the processor is further configured to obtain a signal from the
24
CA 02952010 2016-12-12
WO 2016/028320 PCT/US2014/052332
pressure sensor that detects the pressure conditions including a drilling
fluid
hydrostatic pressure and a formation hydrostatic pressure.
[0079] In a twenty-second example, there is disclosed herein the
drilling assembly according to the examples fourteenth and twenty-first,
wherein the second processor obtains a first signal from a second pressure
sensor that detects pressure conditions along the drillpipe; automatically
actuates a valve to shut-off fluid flow within the drillpipe upon obtaining a
second signal from the second pressure sensor detecting a second threshold
pressure condition; and actuates the valve to switch-on fluid flow within the
drillpipe upon detecting a second activation condition received from the
second pressure sensor or calculated by the second processor.
[0080] The embodiments shown and described above are only
examples. Many details are often found in the art and therefore are neither
shown nor described. Even though numerous characteristics and advantages
of the present technology have been set forth in the foregoing description,
together with details of the structure and function of the present disclosure,
the disclosure is illustrative only, and changes may be made in the detail,
especially in matters of shape, size and arrangement of the parts within the
principles of the present disclosure to the full extent indicated by the broad
general meaning of the terms used in the attached claims. It will therefore
be appreciated that the embodiments described above may be modified
within the scope of the appended claims.
