U.S. patent application number 11/382598 was filed with the patent office on 2007-01-25 for wellbore telemetry system and method.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to BRIAN CLARK, PABLO A. CODESAL, STEVE R. GOMEZ, REMI HUTIN, LUCIAN JOHNSTON, RANDALL P. LEBLANC, NICOLAS G. PACAULT.
Application Number | 20070017671 11/382598 |
Document ID | / |
Family ID | 36775674 |
Filed Date | 2007-01-25 |
United States Patent
Application |
20070017671 |
Kind Code |
A1 |
CLARK; BRIAN ; et
al. |
January 25, 2007 |
WELLBORE TELEMETRY SYSTEM AND METHOD
Abstract
Wellbore communication systems and methods for a wellsite having
a downhole tool deployed from a rig into a wellbore penetrating a
subterranean formation are disclosed. One example communication
system includes a first mud pulse telemetry device positioned in a
downhole tool and at least one additional non-mud pulse telemetry
device positioned in the downhole tool. The example system also
includes at least one of a pressure transducer or a pressure sensor
adapted to detect a modulated pressure provided by at least one of
the telemetry devices.
Inventors: |
CLARK; BRIAN; (SUGAR LAND,
TX) ; JOHNSTON; LUCIAN; (SUGAR LAND, TX) ;
HUTIN; REMI; (NEW ULM, TX) ; PACAULT; NICOLAS G.;
(MONTROUGE, FR) ; CODESAL; PABLO A.; (AL KHOBAR,
SA) ; GOMEZ; STEVE R.; (HOUSTON, TX) ;
LEBLANC; RANDALL P.; (KATY, TX) |
Correspondence
Address: |
SCHLUMBERGER OILFIELD SERVICES
200 GILLINGHAM LANE
MD 200-9
SUGAR LAND
TX
77478
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
SUGAR LAND
TX
|
Family ID: |
36775674 |
Appl. No.: |
11/382598 |
Filed: |
May 10, 2006 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60697073 |
Jul 5, 2005 |
|
|
|
Current U.S.
Class: |
166/248 |
Current CPC
Class: |
E21B 47/18 20130101;
E21B 47/12 20130101; E21B 47/13 20200501 |
Class at
Publication: |
166/248 |
International
Class: |
E21B 43/00 20060101
E21B043/00 |
Claims
1. A wellbore communication system for a wellsite having a downhole
tool deployed in a wellbore penetrating a subterranean formation,
the communication system comprising: a first mud pulse telemetry
device disposed in the downhole tool; at least one additional
telemetry device other than a mud pulse telemetry device disposed
in the wellbore; and at least one of a pressure transducer or a
pressure sensor to detect a modulated pressure provided by the mud
pulse telemetry device.
2. The communication system of claim 1, further comprising a
surface unit to communicate with at least one of the telemetry
devices.
3. The communication system of claim 1, further comprising at least
one formation evaluation component to perform a downhole
operation.
4. The communication system of claim 3, wherein at least one
formation evaluation component is to be operatively coupled to at
least one of the telemetry devices.
5. The communication system of claim 1, wherein at least one
additional telemetry device comprises a telemetry system.
6. The communication system of claim 5, wherein the at least one
additional telemetry system comprises an electromagnetic wellbore
telemetry system.
7. The communication system of claim 5, wherein the at least one
additional telemetry system comprises a wired drill pipe telemetry
system.
8. The communication system of claim 1, further comprising at least
one additional mud pulse telemetry device positioned in the
downhole tool.
9. A wellbore communication system for a wellsite having a downhole
tool deployed from a rig into a wellbore penetrating a subterranean
formation, the communication system comprising: a plurality of
wellbore telemetry systems, wherein at least one of the wellbore
telemetry systems comprises a wired drill pipe telemetry system;
and at least one surface unit in communication with at least one of
the plurality of wellbore telemetry systems.
10. The communication system of claim 9, wherein the plurality of
wellbore telemetry systems comprises one or more of another wired
drill pipe telemetry system, a mud pulse telemetry system, or an
electromagnetic telemetry system.
11. The communication system of claim 9, further comprising at
least one formation evaluation component to perform a downhole
operation.
12. The communication system of claim 11, wherein the at least one
formation evaluation component is to be operatively coupled to at
least one of the wellbore telemetry systems.
13. A wellbore communication system for a wellsite having a
downhole tool deployed in a wellbore penetrating a subterranean
formation, the communication system comprising: at least one
formation evaluation component to measure at least one wellbore
parameter; and a plurality of wellbore telemetry systems, wherein
at least one of the wellbore telemetry systems is to be in
communication with the at least one formation evaluation component
to receive data therefrom and to transmit the data to a surface
unit.
14. The communication system of claim 13, wherein the wellbore
telemetry systems comprise one or more of a mud pulse telemetry
system, an electromagnetic telemetry system, or a wired drill pipe
telemetry system.
15. The communication system of claim 13, wherein each formation
evaluation tool is to be operatively coupled to a respective
wellbore telemetry device.
16. A method of communicating between a surface location and a
downhole tool deployed in a wellbore penetrating a subterranean
formation, the method comprising: evaluating a subterranean
formation using at least one downhole component positioned in the
downhole tool, wherein the downhole tool comprises a plurality of
wellbore telemetry systems; and selectively transmitting data from
the at least one downhole component to a surface unit of at least
one of the wellbore telemetry systems.
17. The method of claim 16, wherein the data is transmitted
simultaneously from each downhole component.
18. The method of claim 16, wherein the data is transmitted at
different times from at least two downhole components.
19. The method of claim 16, further comprising transmitting the
data between wellbore telemetry devices.
20. The method of claim 16 further comprising analyzing data
collected from the at least one formation evaluation component.
21. The method of claim 20, wherein the data from each formation
evaluation component is compared.
22. The method of claim 16, further comprising supplying power to a
downhole tool using one of the plurality of wellbore telemetry
systems.
23. A wellbore telemetry system, comprising: a first wellbore
telemetry device coupled to a downhole tool and adapted to use a
communication medium to communicate with a surface computer; and a
second wellbore telemetry device coupled to a downhole tool and
adapted to use one of the communication medium, a wired drill pipe
communication link, or an electromagnetic communication link to
communicate with the surface computer.
24. The wellbore telemetry system of claim 23, wherein the downhole
tool comprises at least two measurement while drilling tools.
25. The wellbore telemetry system of claim 23, wherein the
communication medium comprises mud in a wellbore.
26. The wellbore telemetry system of claim 23, wherein the
communication medium comprises a mixture of mud and gas in a
wellbore.
27. The wellbore telemetry system of claim 23, wherein the
communication medium comprises a gas consisting substantially of
nitrogen, methane, or air in a wellbore.
28. The wellbore telemetry system of claim 24, wherein the first
and second wellbore telemetry devices comprise at least one of mud
pulse telemetry devices, sirens, positive pulse devices, or
negative pulse devices.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to U.S. Provisional
Application Ser. No. 60/697,073, filed on Jul. 5, 2005 and entitled
"WELLBORE TELEMETRY SYSTEM AND METHOD."
FIELD OF THE DISCLOSURE
[0002] The present disclosure relates to telemetry systems and
methods for use in wellbore operations. More particularly, the
present disclosure relates to wellbore telemetry systems and
methods for conveying signals between a surface unit and a downhole
tool.
BACKGROUND
[0003] Wellbores may be drilled to locate and produce hydrocarbons.
Typically, a wellbore is formed by advancing a downhole drilling
tool having a drill bit at one end into the ground. As the drilling
tool is advanced, drilling fluid ("mud") is pumped from a surface
mud pit through a passage or passages in the drilling tool and out
the drill bit. The mud exiting the drill bit flows back to the
surface to be returned to the mud pit and may be re-circulated
through the drilling tool. In this manner, the drilling mud cools
the drilling tool, carries cuttings and other debris away from the
drilling tool, and deposits the cuttings and other debris in the
mud pit. As is known, in addition to the cooling and cleaning
operations performed by the mud pumped into the wellbore, the mud
forms a mudcake that lines the wellbore which, among other
functions, reduces friction between the drill string and
subterranean formations.
[0004] During drilling operations (i.e., advancement of the
downhole drilling tool), communications between the downhole
drilling tool and a surface-based processing unit and/or other
surface devices may be performed using a telemetry system. In
general, such telemetry systems enable the conveyance of power,
data, commands, and/or any other signals or information between the
downhole drilling tools/bottom hole assemble (BHA) and the surface
devices. Thus, the telemetry systems enable, for example, data
related to the conditions of the wellbore and/or the downhole
drilling tool to be conveyed to the surface devices for further
processing, display, etc. and also enable the operations of the
downhole drilling tool to be controlled via commands and/or other
information sent from the surface device(s) to the downhole
drilling tool.
[0005] One known wellbore telemetry system 100 is depicted in FIG.
1. A more detailed description of such a known system is found in
U.S. Pat. No. 5,517,464, which is incorporated by reference herein
in its entirety. With reference to FIG. 1, a drilling rig 10
includes a drive mechanism 12 to provide a driving torque to a
drill string 14. The lower end of the drill string 14 extends into
a wellbore 30 and carries a drill bit 16 to drill an underground
formation 18. During drilling operations, drilling mud 20 is drawn
from a mud pit 22 on a surface 29 via one or more pumps 24 (e.g.,
reciprocating pumps). The drilling mud 20 is circulated through a
mud line 26 down through the drill string 14 and the wall of the
wellbore 30. Upon reaching the surface 29, the drilling mud 20 is
discharged through a line 32 into the mud pit 22 so that rock
and/or other well debris carried in the mud can settle to the
bottom of the mud pit 22 before the drilling mud 20 is
recirculated.
[0006] As shown in FIG. 1, a downhole measurement while drilling
(MWD) tool 34 is incorporated in the drill string 14 near the drill
bit 16 for the acquisition and transmission of downhole data or
information. The MWD tool 34 includes an electronic sensor package
36 and a mudflow wellbore telemetry device 38. The mudflow
telemetry device 38 an selectively block the passage of the mud 20
through the drill string 14 to cause pressure changes in the mud
line 26. In other words, the wellbore telemetry device 38 can be
used to modulate the pressure in the mud 20 to transmit data from
the sensor package 36 to the surface 29. Modulated changes in
pressure are detected by a pressure transducer 40 and a pump piston
sensor 42, both of which are coupled to a processor (not shown).
The processor interprets the modulated changes in pressure to
reconstruct the data collected and sent by the sensor package 36.
The modulation and demodulation of a pressure wave are described in
detail in commonly assigned U.S. Pat. No. 5,375,098, which is
incorporated by reference herein in its entirety.
[0007] In addition to the known mud pulse telemetry system 100
depicted in FIG. 1, other wellbore telemetry systems may be used to
establish communication between a downhole tool and a surface unit.
Examples of known telemetry systems include a wired drill pipe
wellbore telemetry system as described in U.S. Pat. No. 6,641,434,
an electromagnetic wellbore telemetry system as described in U.S.
Pat. No. 5,624,051, an acoustic wellbore telemetry system as
described in published PCT Patent Application No. WO21004085796,
all of which are hereby incorporated by reference herein in their
entireties. Further examples using data conveyance or communication
devices (e.g. transceivers coupled to sensors) have also been used
to convey power and/or data between a downhole tool and a surface
unit.
[0008] Despite the development and advancement of wellbore
telemetry devices in wellbore operations, there remains a need for
additional reliability and wellbore telemetry capabilities for
wellbore operations. As with other many other wellbore devices,
wellbore telemetry devices sometimes fail. Additionally, the power
provided by many known wellbore telemetry devices may be
insufficient to power desired wellbore operations. Attempts have
been made to use two different types of mud pulse telemetry devices
in a downhole tool. In particular, each of the different mud pulse
telemetry devices is typically positioned in the downhole tool and
communicatively linked to a different, respective surface unit.
Such wellbore telemetry tools have been run simultaneously and
non-simultaneously and at different frequencies. Attempts have also
been made to develop dual channel downhole wellbore telemetry for
transmitting data streams via communication channels to be
interpreted independently as described in U.S. Pat. No.
6,909,667.
[0009] Despite the above-noted advancements in wellbore telemetry
systems, there remains a need to provide wellbore telemetry systems
capable of providing added reliability, increased speed, and
increased power capabilities. As set forth in the detailed
description below, the example methods and apparatus enable
telemetry systems to operate at one or more desired frequencies and
provide increased bandwidth. Additionally, the example methods and
apparatus described below enable a plurality of different wellbore
telemetry devices to be combined with a variety of one or more
downhole components, such as formation evaluation tools, to provide
flexibility in performing wellbore operations. Still further, the
example methods and apparatus described below provide backup
wellbore telemetry capability, enable the operation of multiple
identical or substantially similar wellbore telemetry tools, enable
the generation of comparative wellbore measurements, enable the
activation of multiple wellbore telemetry tools, increase the
available bandwidth and/or data transmission rates for
communications between one or more downhole tools and one or more
surface units, and enable adaptation of the wellbore telemetry
tools to different and/or varying wellbore conditions.
SUMMARY
[0010] In accordance with one disclosed example, a wellbore
communication system for a wellsite having a downhole tool deployed
in a wellbore penetrating a subterranean formation includes a first
mud pulse telemetry device disposed in the downhole tool. The
example system may also include at least one additional telemetry
device other than a mud pulse telemetry device and disposed in the
wellbore. Additionally, the example system may include at least one
of a pressure transducer or a pressure sensor adapted to detect a
modulated pressure provided by at least one of the telemetry
devices.
[0011] In another disclosed example, a wellbore communication
system for a wellsite having a downhole tool deployed in a wellbore
penetrating a subterranean formation includes a plurality of
wellbore telemetry systems. At least one of the wellbore telemetry
systems may comprise a wired drill pipe telemetry system. The
example system may also include at least one surface unit in
communication with at least one of the plurality of wellbore
telemetry systems.
[0012] In yet another disclosed example, a wellbore communication
system for a wellsite having a downhole tool deployed in a wellbore
penetrating a subterranean formation includes at least one
formation evaluation component to measure at least one wellbore
parameter. The example system may also include a plurality of
wellbore telemetry systems. At least one of the wellbore telemetry
systems may be in communication with the at least one formation
evaluation component to receive data therefrom and to transmit the
data to a surface unit.
[0013] In still another disclosed example, a method of
communicating between a surface location and a downhole tool
deployed in a wellbore penetrating a subterranean formation
evaluates a subterranean formation using at least one downhole
component positioned in the downhole tool. The downhole tool may
comprise a plurality of wellbore telemetry systems. The example
method may also selectively transmit data from the at least one
downhole component to a surface unit via at least one of the
wellbore telemetry systems.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] FIG. 1 is a schematic view, partially in cross-section, of a
known measurement while drilling tool and wellbore telemetry device
connected to a drill string and deployed from a rig into a
wellbore.
[0015] FIG. 2 is a schematic view, partially in cross-section, of
an example telemetry system including a downhole tool having
multiple mud pulse telemetry devices.
[0016] FIG. 3 is a schematic view, partially in cross-section, of
another example telemetry system including a downhole tool having a
wired drill pipe wellbore telemetry device.
[0017] FIG. 4 is a schematic view, partially in cross-section, of
yet another example telemetry system including a downhole tool
having a mud pulse telemetry device and an electromagnetic wellbore
telemetry device.
[0018] FIG. 5 is a schematic view, partially in cross-section, of
still another example telemetry system including a downhole tool
having multiple downhole components and multiple wellbore telemetry
devices.
DETAILED DESCRIPTION
[0019] Certain examples are shown in the above-identified figures
and described in detail below. In describing these examples, like
or identical reference numbers are used to identify common or
similar elements. The figures are not necessarily to scale and
certain features and certain views of the figures may be shown
exaggerated in scale or in schematic for clarity and/or
conciseness.
[0020] Referring now to FIG. 2, a mud pulse wellbore telemetry
system 200 having multiple telemetry devices is shown. In contrast
to the known system 100 of FIG. 1, the example wellbore telemetry
system 200 includes two MWD tools 234a and 234b, two mud pulse
telemetry devices 238a and 238b, two transducers 240a and 240b, and
two sensors 242a and 242b. Additionally, the MWD tools 234a and
234b may communicate with a single surface computer or unit 202 via
the mud pulse telemetry devices 238a and 238b. As can be seen in
the example system 200 of FIG. 2, the mud pulse telemetry devices
238a and 238b are identical or substantially identical, the MWD
tools 234a and 234b are identical or substantially identical, and
the devices 238a and 238b and the tools 234a and 234b are
positioned within a single downhole tool 201 (i.e., the same
downhole tool). The surface unit or computer 202 may be implemented
using any desired combination of hardware and/or software. For
example, a personal computer platform, workstation platform, etc.
may store on a computer readable medium (e.g., a magnetic or
optical hard disk, random access memory, etc.) and execute one or
more software routines, programs, machine readable code or
instructions, etc. to perform the operations described herein.
Additionally or alternatively, the surface unit or computer 202 may
use dedicated hardware or logic such as, for example, application
specific integrated circuits, configured programmable logic
controllers, discrete logic, analog circuitry, passive electrical
components, etc. to perform the functions or operations described
herein.
[0021] Still further, while the surface unit 202 is depicted in the
example of FIG. 2 as being relatively proximate to the drilling rig
10, some part of or the entire surface unit 202 may alternatively
be located relatively remotely from the rig 10. For example, the
surface unit 202 may be operationally and/or communicatively
coupled to the wellbore telemetry system 200 via any combination of
one or more wireless or hardwired communication links (not shown).
Such communication links may include communications via a packet
switched network (e.g., the Internet), hardwired telephone lines,
cellular communication links and/or other radio frequency based
communication links, etc. using any desired communication
protocol.
[0022] Returning in detail to FIG. 2, the MWD tools 234a and 234b
may be implemented using the same device(s) used to implement the
MWD tool 34 of FIG. 1. Similarly, the mud pulse telemetry devices
238a and 238b may be implemented using the same device(s) used to
implement the mud pulse telemetry device 38 of FIG. 1. An example
of a mud pulse telemetry device that may be used or otherwise
adapted to implement the devices 38, 238a, and 238b is described in
U.S. Pat. No. 5,517,464, which has previously been incorporated by
reference.
[0023] In operation, the example wellbore telemetry system 20 of
FIG. 2 uses the mud pulse telemetry devices 238a and 238b to
generate signals (e.g., modulated pressure signals) in the mud 20
flowing in the annulus 28 of the wellbore 30. These generated
signals (e.g., modulated or varying pressure signals) may be sensed
by one or more of the pressure transducers 240a and 240b and/or the
pressure sensors 242a and 242b and analyzed by the surface unit 202
to extract or otherwise obtain data or other information relating
to the operational condition(s) of the downhole tool 201 (e.g., one
or both of the MWD Tools 234a and 234b), conditions in wellbore 30,
and/or any other desired downhole information. In this manner,
communications may be established between the downhole tool 201
and, thus, between the MWD tools 234a and 234b, and the surface
unit 202. More generally, such communications between the downhole
tool 201 and the surface unit 202 may be established using uplink
and/or downlink systems. Further, while mud pulse telemetry devices
238a and 238b are described in connection with the example
telemetry system 200 of FIG. 2, other types of wellbore telemetry
devices may be employed instead of or in addition to the mud pulse
telemetry devices 238a and 238b. For example, one or more mud
sirens, positive pulse mud flow telemetry devices, and/or negative
pulse mud flow telemetry devices may be used.
[0024] In general, the example wellbore telemetry systems described
herein may use telemetry devices arranged or positioned in various
configurations relative to the downhole tool. In the example of
FIG. 2, one or both of the telemetry devices 238a and 238b may be
operatively or communicatively coupled to the same (i.e., a single)
MWD tool (e.g., the tool 234a or the tool 234b). Alternatively,
each of the telemetry devices 238a and 238b may be operatively or
communicatively coupled to different respective tools. For example,
the telemetry device 238a may be communicatively or operatively
coupled to the MWD tool 234a and the telemetry device 238b may be
communicatively or operatively coupled to the MWD tool 234b, as
depicted in FIG. 2. As described in greater detail below, one or
both of the telemetry devices 238a and 238b may be communicatively
or operatively coupled to one or more additional downhole
components.
[0025] Turning again to the operation of the example system 200 of
FIG. 2, the mud pulse telemetry devices 238a and 238b may send
uplink signals (e.g., varying or modulated pressure signals to be
conveyed up along the annulus 28 to the surface 29) by altering the
flow of mud through the telemetry devices 238a and 238b. Such
uplink signals (e.g., varying or modulated pressure signals) are
sensed or detected by the pressure transducers 240a and 240b and/or
the pressure sensors 242a and 242b. In particular, the uplink
signals generated by the telemetry device 238a may be detected or
sensed by the transducer 240a and/or the pressure sensor 242a.
Similarly, the uplink signals generated by the telemetry device
238b may be detected or sensed by the transducer 240b and/or the
pressure sensor 242b. The pressure transducers 240a and 240b may be
implemented using devices identical or similar to that used to
implement the pressure transducer 40 of FIG. 1, and the sensors
242a and 242b may be implemented using devices identical or similar
to that used to implement the sensor 42 of FIG. 1.
[0026] FIG. 3 is a schematic view, partially in cross-section, of
another example telemetry system 30 including a downhole tool 301
having a wired drill pipe wellbore telemetry system or device 348.
In contrast to the known mud pulse telemetry system 100 depicted in
FIG. 1, the example telemetry system 300 utilizes a mud pulse
telemetry device 338 that is housed in a MWD tool 334 and includes
the wired drill pipe telemetry system 348.
[0027] As shown in FIG. 3, the MWD tool 334 and the mud pulse
telemetry device 338 may be positioned in the downhole tool 301.
The MWD tool 334 may be implemented using a device that is similar
or identical to that used to implement the MWD tool 34 of the FIG.
1 and/or the MWD tools 234a and 234b of FIG. 2. Similarly, the mud
pulse telemetry device 338 may be implemented using a device that
is similar or identical to that used to implement the mud pulse
telemetry device 38 of FIG. 1 and/or the mud pulse telemetry
devices 238a and 238b of FIG. 2. Additionally, the surface unit or
computer 302 may be implemented in a manner similar to the surface
unit or computer 202 described in connection with FIG. 2. Thus, the
surface unit 302 may be operatively or communicatively coupled to
the MWD tool 334 via the mud pulse telemetry device 338 and/or may
be operatively or communicatively coupled to the wired drill pipe
telemetry system 348 via one or more communication links (not
shown). As with the example system 200 of FIG. 2, the surface unit
or computer 302 may be proximate the drilling rig 10 or,
alternatively, some or all of the surface unit or computer 302 may
be remotely located relative to the drilling rig 10.
[0028] Turning in detail to the wired drill pipe wellbore telemetry
system 348, it can be seen in the example of FIG. 3 that the system
348 extends substantially entirely through the drill string 14. An
example of a wired drill pipe wellbore telemetry system that may be
used to implement the system 348 is described in U.S. Pat. No.
6,641,434, which has been previously incorporated by reference
herein. As depicted in FIG. 3, the wired drill pipe wellbore
telemetry system 348 includes a plurality or series of wires 352
positioned in each drill pipe 350 that forms or composes the drill
string 14. A coupler 354 is positioned at the end of each of the
drill pipes 350 so that when the pipes 350 are connected, joined,
or otherwise coupled, the drill string 14 provides a hardwired
communication link extending through the drill string 14. While the
wired drill pipe telemetry system 348 is depicted in FIG. 3 as
extending substantially entirely through the drill string 14 to the
MWD tool 334, the wired drill pipe telemetry system 348 may instead
extend only partially through the drill string 14.
[0029] During operation, either or both of the mud pulse telemetry
device 338 and the wired drill pipe system 348 may be used to
enable communications between the downhole tool 301 (e.g., the MWD
tool 334) and the surface unit 302. Depending on the particular
operational mode of the rig 10 and/or downhole or other
environmental conditions, the device 338 or the system 348 may be
best suited to convey data to the surface unit 302. Alternatively
or additionally, both the device 338 and the system 348 may be used
to convey information between the surface unit 302 and the downhole
tool 301 at the same time. In such a case, the conveyed information
may concern the same downhole parameter(s) or condition(s) or
different parameter(s) or condition(s).
[0030] FIG. 4 is a schematic view, partially in cross-section, of
yet another example telemetry system 400 including a downhole tool
401 having a mud pulse telemetry device 438 and an electromagnetic
wellbore telemetry device 448. Similar to the systems 200 and 300
depicted in FIGS. 2 and 3, respectively, the system 400 includes a
surface unit or computer 402 that can communicate with the downhole
tool 401 and/or other downhole components and analyze information
obtained therefrom. In this manner, the surface unit 402 may be
operationally or otherwise coupled to a MWD tool 434 via, for
example, the mud pulse telemetry device 438. Still further, as with
the other systems 200 and 300, the surface unit 402 may be
proximate the drilling rig 10 as shown, or some or all of the
surface unit 402 may be remotely located relative to the drilling
rig 10 and communicatively coupled via, for example, any desired
combination of wireless and hardwired communication links to the
system 400.
[0031] The mud pulse telemetry device 438 is position in the
downhole tool 401 and may be implemented using the same device or a
device similar to the device used to implement the device 38 of
FIG. 1, the device 238a and 238b of FIG. 2, and/or the device 338
of FIG. 3. Also, the MWD tool 434 is positioned in the downhole
tool 401 and may be implemented using the same device or a device
similar to the device used to implement the device(s) used to
implement the tools 234a and 234b of FIG. 2, and/or 334 of FIG.
3.
[0032] The electromagnetic wellbore telemetry system 448 includes a
downhole transceiver 454 and a surface transceiver 452. An example
of an electromagnetic wellbore telemetry system that may be used to
implement the system 448 of FIG. 4 is described in U.S. Pat. No.
5,624,051, previously incorporated by reference herein. As depicted
in the example of FIG. 4, the electromagnetic wellbore telemetry
system 448 is also provided with a gap collar 450, which is
position in the downhole tool 401 to enhance the electromagnetic
signals conveyed between the transceivers 452 and 454. An example
of a gap collar that may be used to implement the collar 450 is
described in U.S. Pat. No. 5,396,232.
[0033] While the example systems depicted in FIGS. 2-4 include
certain combinations of mud pulse telemetry, wired drill pipe
telemetry, and electromagnetic telemetry systems, other
combinations of such systems may be employed to achieve the same or
similar results. For example, a wellbore telemetry system using a
mud siren, positive and/or negative pulse telemetry devices, an
acoustic telemetry device, a tortional wave telemetry device, or
any other telemetry device(s) could be used instead of or in
addition to those depicted in FIGS. 2-4 to communicate with a
surface unit or computer. Additionally, various combinations of
communication links (e.g., wireless, hardwired, etc.) may be
employed to provide selective communications between the surface
unit and the telemetry devices to suit the needs of particular
applications.
[0034] Still further it should be understood that the telemetry
devices, or any combination thereof, used with the example systems
described herein may be positioned in various configurations about
the downhole tool. For example, the devices may be positioned
adjacent to each other or, alternatively, at some desired distance
or spacing apart, with or without components disposed therebetween.
The telemetry devices may be oriented vertically as shown in the
examples, or one or more of the devices may be inverted.
[0035] FIG. 5 is a schematic view, partially in cross-section, of
still another example telemetry system 500 including a downhole
tool 501 having multiple downhole components and multiple wellbore
telemetry devices. As depicted in the example system 500 of FIG. 5,
the downhole tool 501 includes two MWD tools 534a and 534b, two mud
pulse telemetry devices 538a and 538b, two pressure transducers
540a and 540b, and two sensors 542a and 542b.
[0036] A surface unit or computer 502, which may be similar or
identical to one or more of the example surface units 202, 302, and
402 of FIGS. 2, 3, and 4, respectively, may be communicatively
and/or operationally coupled to the telemetry devices 538a and 538b
and/or downhole components 548a and 548b. As with the other example
surface units 202, 302, and 404, the example surface unit 502 may
be proximate (e.g., onsite) or remotely situated (e.g., offsite)
relative to the rig 10 and operationally and/or otherwise coupled
to the telemetry systems, MWD tools 534a and 534b, and/or mud pulse
telemetry devices 538a and 538b via any desired communication links
(not shown). The MWD tools 534a and 534b may be implemented using
devices similar or identical to those used to implement the MWD
tools 34, 234a, 234b, 334, and/or 434. Similarly, the mud pulse
telemetry devices 538a and 538b may be implemented using devices
similar or identical to those used to implement the mud pulse
telemetry devices 38, 238a, 238b, 338, and/or 438.
[0037] As depicted in FIG. 5, the downhole tool 501 houses the MWD
tools 534a and 534b, the mud pulse telemetry devices 538a and 538b,
and downhole components 548a and 548b. In the example of FIG. 5,
the downhole components 548a and 548b are depicted as formation
evaluation tools, which may be used to test and/or sample fluid
from a surrounding formation. Examples of such formation valuation
tools that may be used to implement the tools 548a and 548b are
described in published U.S. Patent Application No. 2005/01109538,
which is incorporated by reference herein in its entirety. As
shown, the downhole components 548a and 548b include stabilizer
blades 552a and 552b with proves 554a and 554b for drawing fluid
into the downhole tool 501, and backup pistons 550a and 550b to
assist in driving the proves 554a and 554b into position against
the wall of the wellbore 30. The formation evaluation components
548a and 548b may enable various pressure testing and/or sampling
procedures to be performed. Although the example of FIG. 5 depicts
two formation evaluation components in the downhole tool 501, one
or more than two formation evaluation components may be used
instead.
[0038] In the example of FIG. 5, the wellbore telemetry devices
538a and 538b are operationally coupled to the respective downhole
components 548a and 548b. However, one or more wellbore telemetry
devices may be coupled to one or more formation evaluation
components. For example, two wellbore telemetry devices may be
coupled to the same downhole component or, alternatively, each
wellbore telemetry device may be coupled to a single, respective
downhole component. Additionally, a variety of formation evaluation
components may be coupled to one or both of the wellbore telemetry
devices 538a and 538b. As used herein, "formation evaluation
component" refers to a device for performing formation evaluation
such as, for example, sampling, detecting formation pressure while
drilling, measuring resistivity, nuclear magnetic measurements, or
any other downhole tool used to evaluate a subterranean
formation.
[0039] Multiple wellbore telemetry devices and/or systems such as
those described in connection with the example systems herein may
be used to provide downhole tools with the ability to perform
independent or integrated downhole operations. For example, one
wellbore telemetry system and/or telemetry device may be used in
conjunction with a downhole formation evaluation component to
perform various testing operations, while a second telemetry device
may be used to perform resistivity operations. Additional wellbore
telemetry systems and/or devices may be provided as desired. In
some cases it may be desirable to use certain wellbore telemetry
systems or devices in conjunction with certain downhole components
to perform certain downhole operations.
[0040] Measurements taking using the wellbore telemetry devices may
be compared and analyzed. In this manner, duplicate or redundant
measurements may be taken for calibration and/or verification
purposes. Additionally, duplicate or redundant measurements may be
taken at different positions (at the same or different times) to
determine differences in the formation at various downhole
locations. Measurements taken by different components may also be
analyzed to determine, for example, performance capabilities and/or
formation properties.
[0041] The separate or individual functionality of the wellbore
telemetry devices may also be used to supply and/or enhance power
capabilities for instruments or tools downhole/in the BHA as needed
to perform continuous or additional operations. For example,
embodiments of the systems disclosed herein may be implemented with
a power source (e.g. batteries) or power generator (e.g. mud
turbine), as known in the art, to provide the desired energy. Yet
other embodiments may be implemented for power transmission via
electromagnetic energy conveyance using the wired drill pipe
systems disclosed herein.
[0042] Multiple wellbore telemetry devices may also be used to
increase data transmission rates to the surface and/or to eliminate
the need for batteries in the downhole tool. The use of multiple
wellbore telemetry devices may also provide a backup system in a
case where one of the wellbore telemetry systems fails or is
otherwise unable to function properly. Further, in cases where two
different wellbore telemetry systems and/or devices are used,
alternative types of communications may be employed as desired or
needed to provide more effective communications between a downhole
tool and a surface unit. Still further, any desired communication
medium (e.g., gas/gas mixtures including air, methane, nitrogen,
mud, etc.) or combination of media may be used to implement the
telemetry systems described herein. For example, any combination of
wireless and/or hardwired media may be used to suit the needs of
particular applications. More specifically, wireless media may
include drilling mud, electromagnetic signals, acoustic signals,
etc., and hardwired media may include wired drill pipe and/or any
other media using electrical conductors. In some cases, especially
when running under-balanced drilling, inert gas like nitrogen,
methane or air is mixed to reduce the weight of the mud. If there
is an excessive amount of gas in the mud system, mud pulse
telemetry systems often fail to work. In some cases only
pressurized gas is used for drilling. In these cases
electromagnetic and/or wired drill pipe telemetry systems of the
invention may be used. A combination of these telemetry systems or
multiple electromagnetic or other telemetry devices can also be
used as disclosed herein.
[0043] As noted above in connection with the examples of FIGS. 2,
3, 4, and 5, the surface units 202, 302, 402, and/or 502 may be
located onsite or offsite (e.g., relative to the rig) and may be
communicatively and/or operationally coupled to one or more
respective downhole tools via communication links (not shown). The
communication links may be implemented using any desired wireless
and/or hardwired link capable of transmitting data between wellbore
telemetry devices and surface units or computers. In some examples,
the communication link may be coupled to a wellbore telemetry
device via an intermediary device such as, for example, a pressure
transducer. The communication link provides means for passing
signals such as command, data, power or other signals between the
wellbore telemetry devices and the surface computer. These signals
may be used to control the downhole tool and/or to retrieve data
collected by the downhole tool. Preferably, but not necessarily,
signals are passed in real time to provide fast and efficient data
collection, tool operation and/or response to wellbore
conditions.
[0044] One or more communication links may be provided to
operatively couple the wellbore telemetry system(s) and/or
device(s) to one or more surface unit(s). In this manner, each
wellbore telemetry device and/or system can selectively communicate
with one or more surface unit(s). Alternatively, such links may
couple the wellbore telemetry system(s) and/or device(s). The
telemetry device(s) may communicate with the surface via a wellbore
telemetry system. Various communication links may be provided so
that the wellbore telemetry devices and/or systems may communicate
with each other and/or the surface unit(s) independently,
simultaneously or substantially simultaneously, alternately (e.g.,
while one telemetry device is actively communicating, other
telemetry devices are not actively communicating), and/or during
selected (e.g., predetermined) time frames or intervals.
[0045] The signals and/or other communications conveyed via the
example wellbore telemetry systems described herein may be used or
manipulated to enable the efficient flow of data or information.
For example, the example telemetry devices and/or systems may be
selectively operated to pass data from the downhole tool to the
surface unit or computer. Such data may be passed from the
telemetry devices and/or systems at similar or different
frequencies, simultaneously or substantially simultaneously, and/or
independently. The data and/or signals may be selectively
manipulated, analyzed, or otherwise processed to generate an
optimum and/or desired data output. The data (e.g., the output
data) may be compared (e.g., to reference values, threshold values,
etc.) and/or analyzed to determine wellsite conditions, which may
be used to adjust operating conditions, locate valuable
hydrocarbons, and/or perform any other desired wellsite operations
or functions.
[0046] It will be understood from the foregoing description that
the example systems and methods described herein may be modified
from the specific embodiments provided. For example, the
communication links described herein may be wired or wireless. The
example devices described herein may be manually and/or
automatically activated or operated to perform the desired
operations. Such activation may be performed as desired and/or
based on data generated, conditions detected, and/or results from
downhole operations.
[0047] The foregoing description and example systems and methods
provided thereby are for purposes of illustration only and are not
to be construed as limiting. Thus, although certain apparatus and
methods have been described herein, the scope of coverage of this
patent is not limited thereto. To the contrary, this patent covers
all embodiments fairly falling within the scope of the appended
claims either literally or under the doctrine of equivalents.
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