U.S. patent application number 12/350557 was filed with the patent office on 2010-07-08 for system and method for downhole blowout prevention.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. Invention is credited to Harald Grimmer, Michael Koppe, Sven Krueger.
Application Number | 20100170673 12/350557 |
Document ID | / |
Family ID | 42310966 |
Filed Date | 2010-07-08 |
United States Patent
Application |
20100170673 |
Kind Code |
A1 |
Krueger; Sven ; et
al. |
July 8, 2010 |
SYSTEM AND METHOD FOR DOWNHOLE BLOWOUT PREVENTION
Abstract
A system for monitoring and controlling fluid flow through a
borehole in an earth formation is disclosed. The system includes: a
downhole tool configured to be movable within the borehole; and a
plurality of interchangeable modules disposed within the downhole
tool, the plurality of interchangeable modules including at least a
sensor module for detecting a property change in the borehole and a
packer module for sealing a portion of the borehole in response to
the property change. Each of the plurality of interchangeable
modules includes a connection configuration, the connection
configuration of one of the modules being removably engageable with
at least another of the modules. A method of monitoring and
controlling fluid flow through a borehole in an earth formation is
also disclosed.
Inventors: |
Krueger; Sven;
(Niedersachsen, DE) ; Grimmer; Harald;
(Lachendorf, DE) ; Koppe; Michael; (Lachendorf,
DE) |
Correspondence
Address: |
CANTOR COLBURN, LLP
20 Church Street, 22nd Floor
Hartford
CT
06103
US
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
42310966 |
Appl. No.: |
12/350557 |
Filed: |
January 8, 2009 |
Current U.S.
Class: |
166/250.15 ;
166/66 |
Current CPC
Class: |
E21B 21/10 20130101 |
Class at
Publication: |
166/250.15 ;
166/66 |
International
Class: |
E21B 47/00 20060101
E21B047/00; E21B 43/12 20060101 E21B043/12; E21B 43/00 20060101
E21B043/00; E21B 47/06 20060101 E21B047/06 |
Claims
1. A system for monitoring and controlling fluid flow through a
borehole in an earth formation, the system comprising: a downhole
tool configured to be movable within the borehole; and a plurality
of interchangeable modules disposed within the downhole tool, the
plurality of interchangeable modules including at least a sensor
module for detecting a property change in the borehole and a packer
module for sealing a portion of the borehole in response to the
property change, each of the plurality of interchangeable modules
including a connection configuration, the connection configuration
of one of the modules being removably engageable with at least
another of the modules.
2. The system of claim 1, wherein the downhole tool includes a
segmented tool body having a plurality of segments, each segment
having compatible connection mechanisms to allow each of the
plurality of interchangeable modules to be replaced.
3. The system of claim 1, wherein the connection includes a common
connection configuration, the connection configuration of one of
the modules being engageable with any other of the modules.
4. The system of claim 1, wherein the property change is detection
of an influx of fluid or loss of fluid circulation.
5. The system of claim 1, wherein the sensor module includes at
least one additional sensor for measuring selected characteristics
of at least one of the borehole and the formation
6. The system of claim 5, wherein the property change is selected
from a change in at least one of a pressure, flow rate, gas content
and fluid composition.
7. The system of claim 1, further comprising at least one
additional module selected from at least one of an upper crossover
module, a power/pulser module, a communication module, a bypass
module, a decoder module and a lower crossover module.
8. The system of claim 1, wherein the connection configurations are
selected from one of a shaft connection, a threaded connection, a
bayonet connection and a pin connection.
9. The system of claim 1, wherein the packer module includes an
actuator and a packer, the actuator configured to cause the packer
to extend radially toward a surface of the borehole.
10. The system of claim 9, wherein the actuator includes at least
one valve, and the packer is an inflatable member surrounding an
annulus, the valve being actuateable to open a circulation port and
cause drilling fluid to enter the annulus and inflate the
packer.
11. A method of monitoring and controlling fluid flow through a
borehole in an earth formation, the method comprising: disposing a
plurality of interchangeable modules within a downhole tool, the
plurality of interchangeable modules including at least a sensor
module and a packer module, each of the plurality of
interchangeable modules including a connection configuration, the
connection configuration of one of the modules being removably
engageable with at least another of the modules. detecting a change
in property in the borehole by the sensor module; and responsive to
the change in property being greater than a selected threshold,
actuating the packer sub to seal a portion of the borehole.
12. The method of claim 11, wherein detecting the change in
property includes detecting an influx of fluid or loss of fluid
circulation.
13. The method of claim 11, further comprising measuring at least
one additional selected characteristic of at least one of the
borehole and the formation.
14. The method of claim 11, wherein detecting the change in
property includes detecting a change in at least one of a pressure,
flow rate, gas content and fluid composition.
15. The method of claim 11, wherein disposing the plurality of
interchangeable modules includes connecting each of the plurality
of modules together via the common connection configuration.
16. The method of claim 11, wherein the packer module includes an
actuator and a packer, and actuating the packer module includes
causing the packer to extend radially toward a surface of the
borehole.
17. The method of claim 16, wherein the actuator includes at least
one valve, the packer is an inflatable member surrounding an
annulus, and actuating the packer module includes opening a
circulation port and causing drilling fluid to enter the annulus
and inflate the packer.
18. The method of claim 11, further comprising circulating a fluid
having a selected density in a section of the borehole to equalize
pressure in the borehole.
19. The method of claim 11, wherein the plurality of
interchangeable modules includes at least one additional module
selected from at least one of an adapter sub, a power/pulser sub, a
bypass sub, and a decoder sub.
20. The method of claim 11, wherein the connection configurations
are selected from one of a shaft connection, a threaded connection,
a bayonet and a pin connection.
Description
BACKGROUND OF THE INVENTION
[0001] Blowout prevention is a significant concern in hydrocarbon
exploration and production. Blowouts generally refer to
uncontrolled fluid or gas flow from an earth formation into a
wellbore, which could potentially flow to the surface. Despite
health, safety and environment (HSE) issues, this causes loss of
income either directly or by reduced or delayed production. Blowout
preventers are provided to seal all or a portion of the wellbore in
response to a kick, i.e., a sudden flow of formation fluid, such as
water, oil and/or gas, into the borehole. Such action prevents the
kick from evolving into a blowout at the surface. Kicks usually
refer to influxes when drilling into an over pressured zone but
include also influxes occurring when the well pressure becomes
lower than the pore pressure, which is a consequence of loss of
circulation fluid occurring when the well pressure is partially
higher than the fracture pressure or when drilling into permeable
low-pressure formations.
[0002] Various independent pressure barriers are used during
drilling operations. Such barriers include the use of heavy mud,
surface blowout preventers (BOP) and downhole BOPs. Typical blowout
prevention devices, and especially downhole BOPs, do not allow for
ease of replacement of various components or addition or
subtraction of supplemental capabilities.
BRIEF DESCRIPTION OF THE INVENTION
[0003] A system for monitoring and controlling fluid flow through a
borehole in an earth formation includes: a downhole tool configured
to be movable within the borehole; and a plurality of
interchangeable modules disposed within the downhole tool, the
plurality of interchangeable modules including at least a sensor
module for detecting a property change in the borehole and a packer
module for sealing a portion of the borehole in response to the
property change. Each of the plurality of interchangeable modules
includes a connection configuration, the connection configuration
of one of the modules being removably engageable with at least
another of the modules.
[0004] A method of monitoring and controlling fluid flow through a
borehole in an earth formation includes: disposing a plurality of
interchangeable modules within a downhole tool, the plurality of
interchangeable modules including at least a sensor module and a
packer module, each of the plurality of interchangeable modules
including a connection configuration, the connection configuration
of one of the modules being removably engageable with at least
another of the modules; detecting a change in property in the
borehole by the sensor module; and responsive to the change in
property being greater than a selected threshold, actuating the
packer sub to seal a portion of the borehole.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] The following descriptions should not be considered limiting
in any way. With reference to the accompanying drawings, like
elements are numbered alike:
[0006] FIG. 1 depicts an embodiment of a drilling and/or well
logging system including a downhole blowout prevention (BOP)
tool;
[0007] FIG. 2 depicts an exploded side view of an embodiment of a
downhole BOP tool;
[0008] FIG. 3 depicts a side view of a bypass sub of FIG. 2;
[0009] FIG. 4 depicts a side view of a packer sub of FIG. 2 in a
non-actuated position;
[0010] FIG. 5 depicts a side view of the packer sub of FIG. 2 in an
actuated position;
[0011] FIG. 6 depicts a side view of an exemplary embodiment of the
downhole tool of FIG. 2;
[0012] FIG. 7 depicts a side view of another exemplary embodiment
of the downhole tool of FIG. 2;
[0013] FIG. 8 depicts a side view of another exemplary embodiment
of the downhole tool of FIG. 2;
[0014] FIG. 9 is a block diagram of a system for preventing
blowouts in a borehole; and
[0015] FIG. 10 is a flow chart providing an exemplary method
preventing blowouts in a borehole.
DETAILED DESCRIPTION OF THE INVENTION
[0016] Referring to FIG. 1, an exemplary embodiment of a drilling
and/or well logging system 10 includes a drillstring 11 that is
shown disposed in a borehole 12 that penetrates at least one earth
formation 14. The drillstring 11 includes a drill pipe, which may
be one or more pipe sections or coiled tubing. Drilling fluid, or
drilling mud 16 may be pumped through the drillstring 11 and/or the
borehole 12. In one embodiment, a bottom hole assembly (BHA) 18 is
disposed in the system 10 at or near the downhole portion of the
drillstring 11. A modular downhole tool 20 is disposed in the BHA
18 or other location in the drillstring 11, and includes a blowout
preventer (BOP) 25 capable of sealing off a portion of the borehole
12 upon detection of an influx of fluid or loss of drilling mud
circulation. In one embodiment, the BHA 18 includes a drill bit 22
to drill through earth formations. The drill bit 22 is powered by a
surface rotary drive, a motor using pressurized fluid (e.g., mud
motor, not shown) an electrically driven motor and/or other
suitable mechanism.
[0017] As described herein, "borehole" or "wellbore" refers to a
single hole that makes up all or part of a drilled well. As
described herein, "formations" refer to the various features and
materials that may be encountered in a subsurface environment.
Accordingly, it should be considered that while the term
"formation" generally refers to geologic formations of interest,
that the term "formations," as used herein, may, in some instances,
include any geologic points or volumes of interest (such as a
survey area). In addition, it should be noted that the drillstring
may be any structure suitable for lowering a tool through a
borehole or connecting a drill to the surface, and is not limited
to the structure and configuration described herein. The
drillstring 11 may be configured as a drillstring, production
string or other borehole string. As used herein, a "string" refers
to any structure, tool or apparatus configured to be lowered within
a borehole in an earth formation.
[0018] Referring to FIG. 2, in one embodiment, the tool 20 includes
a modular downhole blowout preventer (BOP) assembly that is
configured to control influx into and/or loss of fluid from the
borehole 12. The BOP assembly is included to seal off the borehole
12 in the event of an influx of gas and/or fluid or a loss of
circulation. As described herein, "blowout" refers to uncontrolled
fluid or gas flow from an earth formation into a wellbore which
could potentially flow to the surface, and/or any fluid or gas flow
from the formation and/or the borehole into the surface
environment.
[0019] The tool 20 includes at least one of a plurality of modular
units serving various functions. In one embodiment, the tool 20
includes a plurality of modular units. Each unit is also referred
to herein as a "sub", which is an interchangeable component of the
tool 20 and is connectable to other subs to form selected
drillstring sections and/or sections of the BHA 18. Examples of
subs include but are not limited to an upper crossover sub 28 such
as a wired pipe or other adapter sub, a power/pulser sub 30, a
battery sub 31, a communication sub 32 to receive and send
commands, a packer sub 34, a bypass sub 36 (in one embodiment, the
bypass sub 36 is located above the packer sub 34 to allow
circulation, as shown in FIG. 2), a string valve sub 37, a sensor
sub 38 (e.g., for kick detection), a decoder sub 40, and a lower
crossover sub 42 connected to the string or the BHA 18. In one
embodiment, the sensor sub 38 includes one or more sensors for
detecting a kick. In one embodiment, the subs are integrated into
the BHA 18 and are configured to communicate with the surface via
suitable LWD equipment. The individual placement of the subs within
the tool 20 is exemplary, as the subs may be placed relative to one
another in any suitable configuration.
[0020] Each sub includes a connection mechanism 41, 43 configured
to allow each sub to be removed and/or replaced without disassembly
of the tool 20. In one embodiment, the connection mechanisms 41, 43
have a common configuration so that each connection mechanism 41,
43 of a respective sub is engageable with the connection mechanism
41, 43 of any other sub.
[0021] Each sub can be replaced with a sub having operating
characteristics more suited to the particular conditions
encountered. For example, the sensor sub 38 can be switched with
another sensor sub 38 having a different combination of sensors. In
one embodiment, each sub is individually designed to have selected
characteristics. For example, the weights and dimensions of each
sub is individually determined based on their individual
requirements. Housings for each sub include any selected materials
or combinations to have selected resistances to the borehole
environment, such as pressure, temperature and corrosion.
[0022] In one embodiment, the upper crossover sub 28 and the lower
crossover sub 42 include electrical conduits 44 for coupling power
and/or communication signals from an electric cable or other wire
in the drillstring 11 and/or BHA 18 to the modular assembly, i.e.,
the tool 20. The upper crossover sub 28 may also be configured to
couple other power/communication setups to the modular assembly 20,
such as wireline connections and logging-while-drilling (LWD)
connections. In one embodiment, the upper crossover sub 28 is
configured to be connected to a drillstring, wired pipe or
wireline.
[0023] In one embodiment, the power/pulser sub 30 includes a power
source 46 such as at least one battery and a suitable electronics
unit 48 to regulate voltage, current and/or frequency of power
supplied to the modular assembly 20. In one embodiment, the
power/pulser sub 30 is capable of running the tool 20 at low or
even no flow. Exemplary batteries include rechargeable batteries,
lithium batteries and nickel cadmium (Ni--Cd) batteries. In one
embodiment, the power source 46 is included that individually
powers each module. For example, the power source 46 includes one
or more batteries 46 to operate the sensor sub 38 and one or more
batteries 46 to operate the packer sub 34. Various subs are powered
by the power source 46, the wired pipe adapter 28 or any other
suitable power source.
[0024] In one embodiment, the sensor sub 38 includes at least one
sensor 50 configured to measure various properties of the borehole
12 and/or the formation 14, such as a pressure sensor. Examples of
such properties include pressure, flow rate, gas content, mud
composition and others. In one embodiment, the pressure sensor 50
is an electrically conductive member that changes resistance due to
changes in strain in response to pressure variations. In one
embodiment, a sensor electronics unit 52 is coupled to the sensor
50 and measures a current change to calculate change in resistance
and the corresponding pressure change. The sensor electronics unit
52 may include its own power source or measure current applied by
the power/pulser sub 30. In one embodiment, the sensor electronics
unit 52 includes an amplifier to amplify the signal generated
therein. The sensor sub 38, in addition to pressure sensors, may
include any number or type of additional sensors to detect various
conditions in and/or characteristics of the borehole, the
circulating fluid and/or the formation.
[0025] The decoder sub 40, in one embodiment, includes a decoder
electronics unit 54, such as a microprocessor, to receive input
from the sensor sub 34 and actuate the packer sub 34 when a
sufficient change in a property is detected. The decoder
electronics unit 54 is configured to recognize when a change in a
property occurs beyond a selected threshold, and in response
actuate the packer sub 34 to seal off a portion of the borehole 12.
In one embodiment, the decoder electronics unit 54 is configured to
be in a sleeping mode when the tool 20 is out of hole, and to power
up when the tool 20 is exposed to pressure to preserve power and
protect the tool 20 from premature actuation during transport and
storage.
[0026] Referring to FIG. 3, the bypass sub 36 includes a bypass
assembly having a valve 56 and bypass electronics unit 58 for
controlling the valve 56 to allow mud to flow from the interior of
the drillstring 11 to an exterior of the drillstring 11 and into
the borehole 12. In one embodiment, the valve 56 is a poppet valve
cooperating with a bypass annulus 60 or other conduit to engage in
fluid communication with an interior conduit 62 of the drillstring
11. In the closed position shown in FIG. 3, the poppet valve seals
56 off the annulus 60 to prevent fluid flow between the interior
conduit 62 and an exterior of the drillstring 11. In the open
position, the poppet valve 56 is moved to allow fluid flow through
the annulus. In one embodiment, the bypass electronics unit 58
includes various sensors and/or motors for sensing a condition in
which bypass is needed and/or to actuate the valve 56. In one
embodiment, the bypass sub includes a string valve 57, which may be
connected to suitable control electronics 59, for controlling fluid
flow through the drillstring 11. The string valve may be a poppet
valve or any other suitable valve configuration. In one embodiment,
the bypass assembly and the drillstring valve 57 are housed in
separate modules that can be individually removed and attached to
the tool 20. In one embodiment, the string valve 57 is located
below the valve 56 to allow bypass circulation in the event that
the string valve 57 is actuated to close the string.
[0027] Referring to FIGS. 4 and 5, the packer sub 34 includes a
string valve 63, a packer element 64 and an actuator assembly 66
including a packer valve 67 such as a poppet valve. Although the
string valve 63 and the valve 67 are shown as poppet valves, either
may take any suitable configuration. The actuator assembly 66
includes electronics and/or pressure sensors for controlling
actuation of the valve 67 and/or the element 64. The actuator
assembly 66, in one embodiment, is disposed in communication with
the decoder sub 40, for example, which in turn activates the
actuator assembly 66 to cause the packer 64 to inflate or otherwise
extend radially toward the sides of the borehole 12 to seal off a
section of the borehole 12. FIG. 4 shows the actuator assembly 66
in a non-actuated or drilling position, and FIG. 5 shows the
actuator in an actuated position. When the packer sub 34 is in the
actuated mode, both the drillstring 11 and a fluid conduit 68
within the packer sub 38 housing is sealed off. The drilling fluid
or mud 16 is now circulated through a circulation port 70 just
above the annular seal formed by the poppet valve 67 and directed
to an annulus 72 through one or more bores 74 to inflate the packer
element 64. In one embodiment, the valve 63 is located below the
valve 67 to allow for bypass circulation, and may also be located
below the packer element 64.
[0028] In one embodiment, the system includes four independently
operating valves. For example, the valves are incorporated into the
bypass sub 36 and/or the packer sub 34 and are configured with the
bypass valve 56 located above the packer valve 67. In one
embodiment, the packer valve 67 is configured as independently
operating inflation and deflation valves. The string valve 63,
which may be located in the separate string valve sub 37 and/or the
bypass sub 36, is located below the bypass valve 56 and the packer
valve(s) 67. Such a configuration allows for increased flexibility
to perform various functions such as measuring the bottom hole
pressure development inside the drill pipe, i.e., the shut-in drill
pipe pressure (SIDPP), releasing a kick through the drill pipe
instead of the annulus, and bullheading the formation. This
configuration is also useful in performing drill stem testing.
[0029] In one embodiment, the actuator assembly 66 includes one or
more of an electric motor, a translational mechanism such as a
roller screw, the valve 67, and the circulation port 70. In one
embodiment, the electric motor is started by the decoder sub 40
when the detected pressure change is beyond a selected threshold.
In one embodiment, motor current is continuously controlled by the
decoder electronics 54 during actuation. The motor current
increases at the end position of the poppet stroke, and is switched
off by the decoder electronics 54 at a predetermined value. In one
embodiment, if any unforeseen motor loads should occur during
actuation, the decoder electronics 54 are configured to control the
current to prevent damage to the packer sub 34.
[0030] The circulation port 70 extends from an exterior of the
packer sub 34 to the interior conduit 68 through which mud or other
fluid or gas is introduced. In the actuated mode, the poppet valve
67 seals the drillstring 11 and opens the circulation port 70 to
allow fluid to enter the annulus 72 and inflate the packer element
64. In one embodiment, the packer is automatically deflated by
internal stresses in the packer element when the circulation port
70 is closed and the tool 20 is in the drilling mode.
[0031] In one embodiment, one or more of the components of the
actuator assembly 66, such as the electronics unit, motor, roller
screw and the poppet valve 67 each form their own modular
sub-assembly. In another embodiment, the actuator assembly 66 and
the packer element 64 are each disposed within their own modular
sub.
[0032] Although the embodiment shown in FIG. 2 includes subs 28,
30, 32, 34, 36, 38, 40 and 42, the tool 20 is not limited to the
exemplary number and types of subs or modules described herein. Any
number or type of modules may be included to provide selected
functionality for blowout prevention and other uses. In one
embodiment, the tool 20 includes all of the subs 28, 30, 32, 34,
36, 38, 40 and 42 described herein in the order shown. However, any
number of subs may be added or omitted, or the order of the subs
changed. Tool modifications may also introduce additional functions
such as multi-operational circulation ports, drillstring chokes and
test plugs for traditional BOPs.
[0033] Each modular unit is interchangeable and includes the
standardized connection interface 41, 43 to allow for each sub to
be interchangeable with any other sub. In one embodiment, the
connection interface 41, 43 is standardized among all of the subs
to allow for each sub to be interchangeable with any other sub.
Such interchangeability allows for the BHA 18 and/or tool 20 to be
easily adjusted to account for different operation needs. In one
embodiment, all electric wires for communication to other modules
are located in the center of each module for simple connection and
disconnection. In one embodiment, one or more of the subs are
encased in a protective housing, for example a resilient or
rubberized casing to protect the sub from shocks and
vibrations.
[0034] Examples of connections 41, 43 include shaft connections,
threaded connections, bayonet and pin connections. In one
embodiment, shown in FIG. 2, each sub has a male connection 41 and
a female connection 43, which may be tapered or straight. In one
embodiment, each connection 41, 43 includes an electrical and/or
signal connection to couple power and communication signals between
subs.
[0035] Referring again to FIG. 2, sensors 50, in other embodiments,
include sensors that are used to measure properties of the
formation 14, to measure properties of the borehole 12 and/or to
assess the stresses on and operation of the tool 20. Examples of
such sensors 50 include pressure sensors, current sensors,
vibration sensors, temperature sensors flow rate sensors, gas
content and/or mud composition sensors and others.
[0036] Referring again to FIG. 1, in one embodiment, the tool 20 is
equipped with transmission equipment to communicate ultimately to a
surface processing unit 26. Such transmission equipment allows the
tool 20 to send critical data to the surface, stop or otherwise
control pipe rotation, stop or otherwise control axial movement,
control fluid flow, receive and decode commands sent downhole to
activate the tool, and perform other functions. Such transmission
equipment may take any desired form, and different transmission
media and connections may be used. Examples of connections include
wired pipe, fiber optic, wireless connections, mud pulse telemetry
and any other suitable communication utilized in
logging-while-drilling (LWD) equipment.
[0037] In one embodiment, the surface processing unit 26 and/or the
tool 20 include components as necessary to provide for storing
and/or processing data collected from the tool 20. Exemplary
components include, without limitation, at least one processor,
storage, memory, input devices, output devices and the like. The
surface processing unit 26 optionally is configured to control the
tool 20.
[0038] FIGS. 6-8 illustrate various examples of the tool 20.
Referring to FIG. 6, in a first example, the tool 20 includes a
wired pipe adapter sub 76 in a modular connection with a BOP sub
78, that includes a battery sub. Referring to FIG. 7, in a second
example, the tool 20 includes a bi-directional power and
communications module 80 in a modular connection with the BOP sub
78. Referring to FIG. 8, in a third example, the tool 20 includes a
low flow pulser/decoder sub 82 in a modular connection with the BOP
sub 78.
[0039] Referring to FIG. 9, there is provided a system 80 for
preventing blowouts, or other device used in conjunction with the
BHA 18 and/or the drillstring 11. The system 80 may be incorporated
in a computer or other processing unit capable of receiving data
from the tool 20. The processing unit may be included with the tool
20 or included as part of the surface processing unit 26.
[0040] In one embodiment, the system 80 includes a computer 81
coupled to the tool 20. Exemplary components include, without
limitation, at least one processor, storage, memory, input devices,
output devices and the like. As these components are known to those
skilled in the art, these are not depicted in any detail herein.
The computer 81 may be disposed in at least one of the surface
processing unit 24 and the tool 20.
[0041] Generally, some of the teachings herein are reduced to an
algorithm that is stored on machine-readable media. The algorithm
is implemented by the computer 81 and provides operators with
desired output.
[0042] FIG. 10 illustrates a method for preventing blowouts in a
borehole. The method includes one or more of stages 101-104
described herein. The method may be performed continuously or
intermittently as desired. The method is described herein in
conjunction with the tool 20 and optionally the decoder sub 40,
although the method may be performed in conjunction with any number
and configuration of processors, sensors and tools. The method may
be performed by one or more processors or other devices capable of
receiving and processing measurement data, such as the
microprocessor and/or the computer 81. In one embodiment, the
method includes the execution of all of stages 101-104 in the order
described. However, certain stages 101-104 may be omitted, stages
may be added, or the order of the stages changed.
[0043] In the first stage 101, subs are selected and the modular
assembly 20 is assembled by connecting each sub in operable
communication via the connections 41, 43. In one embodiment, the
selection of subs and the position within the assembly depend on
the assessment of the blow out risk and the property chosen to
trigger an adequate reaction.
[0044] In the second stage 102, a change in a property, such as
pressure, that is greater than a selected threshold is detected.
Information regarding the property change may be sent to the
surface for decision. Such decisions include reacting
conventionally without use of the downhole BOP, and/or stopping
string movement and activating the downhole BOP, and/or running an
automatic process at the surface and/or downhole. Transmitting the
information to surface may be done with wired pipe, conventional
mud pulse telemetry or other suitable means. In one embodiment, a
pressure code is generated in the pulser sub in response to the
change in pressure.
[0045] In the third stage 103, a code depending on the selected
action is transmitted inside the drillstring 11 (via pulse, wired
pipe, etc.) to the packer sub 34 and/or the decoder sub 40, and the
packer sub 34 is actuated to cause the packer element 64 to seal
off a portion of the borehole 12. When the packer sub 34 is
actuated, both the drillstring 11 and the borehole 12 are sealed
off. Actuation moves the poppet valves 63 and 67, e.g., after the
electronic unit in the actuator assembly 66 has accepted the code.
The drillstring 11 is closed and the circulation port 70 is opened
to seal off the lower part of the borehole 12.
[0046] In the fourth stage 104, the section of the borehole 12
above the packer sub 34 is circulated with mud 16 of sufficient
density to equalize pressure in the borehole 12 to regain control
of the borehole pressure and stabilize the borehole 12. After the
borehole 12 is stabilized, the packer sub 34 is reset back to
normal drilling mode, e.g., by sending a new pressure code.
[0047] The systems and methods described herein provide various
advantages over prior art techniques. The embodiments described
herein offer greatly increased system flexibility, which allows the
tool to be easily adjusting to coincide with changing operational
needs. Examples of such embodiments are described above.
[0048] In support of the teachings herein, various analyses and/or
analytical components may be used, including digital and/or analog
systems. The system may have components such as a processor,
storage media, memory, input, output, communications link (wired,
wireless, pulsed mud, optical or other), user interfaces, software
programs, signal processors (digital or analog) and other such
components (such as resistors, capacitors, inductors and others) to
provide for operation and analyses of the apparatus and methods
disclosed herein in any of several manners well-appreciated in the
art. It is considered that these teachings may be, but need not be,
implemented in conjunction with a set of computer executable
instructions stored on a computer readable medium, including memory
(ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, hard drives),
or any other type that when executed causes a computer to implement
the method of the present invention. These instructions may provide
for equipment operation, control, data collection and analysis and
other functions deemed relevant by a system designer, owner, user
or other such personnel, in addition to the functions described in
this disclosure.
[0049] Further, various other components may be included and called
upon for providing aspects of the teachings herein. For example, a
sample line, sample storage, sample chamber, sample exhaust, pump,
piston, power supply (e.g., at least one of a generator, a remote
supply and a battery), vacuum supply, pressure supply,
refrigeration (i.e., cooling) unit or supply, heating component,
motive force (such as a translational force, propulsional force or
a rotational force), magnet, electromagnet, sensor, electrode,
transmitter, receiver, transceiver, controller, optical unit,
electrical unit or electromechanical unit may be included in
support of the various aspects discussed herein or in support of
other functions beyond this disclosure.
[0050] One skilled in the art will recognize that the various
components or technologies may provide certain necessary or
beneficial functionality or features. Accordingly, these functions
and features as may be needed in support of the appended claims and
variations thereof, are recognized as being inherently included as
a part of the teachings herein and a part of the invention
disclosed.
[0051] While the invention has been described with reference to
exemplary embodiments, it will be understood by those skilled in
the art that various changes may be made and equivalents may be
substituted for elements thereof without departing from the scope
of the invention. In addition, many modifications will be
appreciated by those skilled in the art to adapt a particular
instrument, situation or material to the teachings of the invention
without departing from the essential scope thereof Therefore, it is
intended that the invention not be limited to the particular
embodiment disclosed as the best mode contemplated for carrying out
this invention, but that the invention will include all embodiments
falling within the scope of the appended claims.
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