U.S. patent application number 14/434734 was filed with the patent office on 2015-10-15 for telemetry for wireless electro-acoustical transmission of data along a wellbore.
The applicant listed for this patent is EXXON-MOBIL UPSTREAM RESEARCH COMPANY. Invention is credited to Scott W. Clawson, Max Deffenbaugh, Mark M. Disko, Timothy I. Morrow, Katie M. Walker, Henry Alan Wolf.
Application Number | 20150292319 14/434734 |
Document ID | / |
Family ID | 50979174 |
Filed Date | 2015-10-15 |
United States Patent
Application |
20150292319 |
Kind Code |
A1 |
Disko; Mark M. ; et
al. |
October 15, 2015 |
Telemetry for Wireless Electro-Acoustical Transmission of Data
Along a Wellbore
Abstract
A system for downhole telemetry is provided herein. The system
employs a series of communications nodes spaced along a tubular
body either above or below ground, such as in a wellbore. The nodes
allow for wireless communication between one or more sensors
residing at the level of a subsurface formation or along a
pipeline, and a receiver at the surface. The communications nodes
employ electro-acoustic transducers that provide for node-to-node
communication along the tubular body at high data transmission
rates. A method of transmitting data in a wellbore is also provided
herein. The method uses a plurality of data transmission nodes
situated along a tubular body and a specially configured network to
accomplish a wireless transmission of data along the wellbore using
acoustic energy.
Inventors: |
Disko; Mark M.; (Glen
Gardner, NJ) ; Morrow; Timothy I.; (Humble, TX)
; Deffenbaugh; Max; (Fulshear, TX) ; Walker; Katie
M.; (Milford, NJ) ; Clawson; Scott W.;
(Califon, NJ) ; Wolf; Henry Alan; (Morris Plains,
NJ) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
EXXON-MOBIL UPSTREAM RESEARCH COMPANY |
Houston, |
TX |
US |
|
|
Family ID: |
50979174 |
Appl. No.: |
14/434734 |
Filed: |
December 18, 2013 |
PCT Filed: |
December 18, 2013 |
PCT NO: |
PCT/US2013/076269 |
371 Date: |
April 9, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61739414 |
Dec 19, 2012 |
|
|
|
Current U.S.
Class: |
367/82 |
Current CPC
Class: |
E21B 47/16 20130101;
E21B 47/14 20130101 |
International
Class: |
E21B 47/16 20060101
E21B047/16 |
Claims
1. An electro-acoustic system for wireless telemetry along a
tubular body, comprising: a tubular body fabricated from steel; at
least one sensor disposed along the tubular body; a sensor
communications node placed along the tubular body and connected to
a wall of the tubular body, the sensor communications node being in
electrical communication with the at least one sensor and
configured to receive signals from the at least one sensor, the
signals representing a parameter associated with a subsurface
location along the tubular body; a topside communications node
placed proximate a surface; a plurality of intermediate
communications nodes spaced along the tubular body and attached to
an outer wall of the tubular body, the intermediate communications
nodes configured to transmit acoustic waves from the sensor
communications node to the topside communications node in
node-to-node arrangement; and a receiver at the surface configured
to receive signals from the topside communications node; wherein
each of the intermediate communications nodes comprises: a sealed
housing; an independent power source residing within the housing;
and an electro-acoustic transducer and associated transceiver also
residing within the housing designed to receive and re-transmit the
acoustic waves, thereby providing communications telemetry; and
wherein the acoustic waves represent asynchronous packets of
information comprising a plurality of separate tones, with at least
some of the acoustic waves being indicative of the parameter.
2. The electro-acoustic system of claim 1, wherein: the surface is
an earth surface; and the tubular body is a pipe residing below
ground.
3. The electro-acoustic system of claim 1, wherein: the surface is
a water surface; and the tubular body is a pipe residing below the
water surface.
4. The electro-acoustic system of claim 1, wherein: the tubular
body is comprised of pipe joints disposed in a wellbore, with the
wellbore penetrating into a subsurface formation; and the at least
one sensor and the sensor communications node are disposed along
the wellbore proximate a depth of the subsurface formation.
5. The electro-acoustic system of claim 4, wherein the parameter
comprises temperature, pressure, fluid flow, strain, or geological
information related to a rock matrix of the subsurface
formation.
6. The electro-acoustic system of claim 4, wherein the at least one
sensor comprises (i) a pressure sensor, (ii) a temperature sensor,
(iii) an induction log, (iv) a gamma ray log, (v) a formation
density sensor, (vi) a sonic velocity sensor, (vii) a vibration
sensor, (viii) a resistivity sensor, (ix) a flow meter, (x) a
microphone, (xi) a geophone, (xii) a chemical sensor, or (xiii) a
set of position sensors.
7. The electro-acoustic system of claim 4, wherein: the tubular
body is a casing string; at least some of the intermediate
communications nodes are surrounded by a cement sheath; and each of
the intermediate communications nodes is attached to an outer
surface of pipe joints making up the casing string.
8. The electro-acoustic system of claim 1, wherein (i) each of the
plurality of separate tones has a different frequency, (ii) no two
consecutive tones have the same frequency, or (iii) both.
9. The electro-acoustic system of claim 1, wherein: adjacent
intermediate communications nodes represent pairs of nodes; a
receiving node in the pair of nodes is configured to detect
amplitude and/or reverberation time for each tone received in a
packet from a transmitting node in the pair of nodes, and then
return the packet to the transmitting node; and the transmitting
node is configured to adjust its transmitting energy or its
frequency band so that a weakest tone in the packet as returned by
the receiving node will be received at a weakest signal amplitude
for which communication remains robust.
10. The electro-acoustic system of claim 9, wherein the
transmitting node is further configured to: reduce a waiting time
between tones to a smallest time required for the reverberation to
substantially subside; instruct the receiving node that it has made
any changes in the transmitting energy, the waiting time, or the
frequency band.
11. The method of claim 9, wherein: the transmitting node is
further configured to instruct other intermediate communications
nodes of the changes in the transmitting energy, changes in the
frequency band, or changes in the waiting time.
12. The electro-acoustic system of claim 9, wherein: each
intermediate communications node is configured to selectively
operate in either an awake state wherein the node is able to send
and receive signals, or in a sleep state wherein the node is able
to collect data but makes no transmissions; and during the sleep
state, each intermediate communications node is programmed to have
a periodically awake mode where it listens for a wakeup packet to
return the node to its awake state.
13. The electro-acoustic system of claim 1, wherein the at least
one sensor: (i) resides in the housing of a sensor communications
node, or (ii) resides external to the sensor communications
node.
14. The electro-acoustic system of claim 1, wherein the acoustic
waves provide data that is modulated by (i) a multiple frequency
shift keying method, (ii) a frequency shift keying method, (iii) a
multi-frequency signaling method, (iv) a phase shift keying method,
(v) a pulse position modulation method, or (vi) an on-off keying
method.
15. The electro-acoustic system of claim 1, wherein the
intermediate communications nodes are spaced apart according to the
length of the joints of pipe.
16. The electro-acoustic system of claim 1, wherein the
intermediate communications nodes are spaced at about 10 to about
100 foot intervals.
17. The electro-acoustic system of claim 1, wherein: the
communications nodes transmit data representing the asynchronous
packets of information at a rate exceeding about 50 bps; and a
frequency band for the acoustic wave transmission is about 25 KHz
wide.
18. The electro-acoustic system of claim 1, wherein: the
transceivers listen for tones that are selected to be within a
frequency band of about 25 kHz centered around about 100 kHz; and
the signals are detectable at least two nodes away from a
transmitting node.
19. The electro-acoustic system of claim 1, wherein: each
intermediate communications node listens for the acoustic waves for
a longer time than the time for which the acoustic waves were
generated by a previous intermediate communications node; and the
acoustic waves provide data that is modulated by a multiple
frequency shift keying method where each tone is selected from a
logical alphabet of at least 8 tones.
20. A method of transmitting data in a wellbore, comprising:
providing a sensor along the wellbore at a depth of a subsurface
formation; running joints of pipe into the wellbore, the joints of
pipe being connected by threaded couplings; attaching a series of
communications nodes to the joints of pipe according to a
pre-designated spacing, wherein adjacent communications nodes are
configured to communicate by acoustic waves transmitted through the
joints of pipe; providing a receiver at a surface; and sending
signals from the sensor to the receiver via the series of
communications nodes, with the signals being indicative of a
subsurface condition; wherein each of the communications nodes
comprises: a sealed housing; an electro-acoustic transducer and
associated transceiver residing within the housing configured to
send and receive the acoustic waves between nodes as part of the
signals; and an independent power source also residing within the
housing for providing power to the transceiver; and wherein the
acoustic waves represent asynchronous packets of information
comprising a plurality of separate tones, with at least some of the
acoustic waves being indicative of the parameter.
21. The method of claim 20, wherein (i) each of the plurality of
separate tones has a different frequency, (ii) no two consecutive
tones have the same frequency, or (iii) both.
22. The method of claim 20, wherein: adjacent intermediate
communications nodes represent pairs of nodes; a receiving node in
the pair of nodes is configured to detect amplitude and/or
reverberation time for each tone received in a packet from a
transmitting node in the pair of nodes, and then return the packet
to the transmitting node; and the transmitting node is configured
to adjust its transmitting energy, its frequency band, or both, so
that a weakest tone in the packet as returned by the receiving node
will be received at a weakest signal amplitude for which
communication remains robust.
23. The method of claim 22, wherein the transmitting node is
further configured to: reduce a waiting time between tones to a
smallest time required for the reverberation to substantially
subside; and instruct the receiving node that it has made any
changes in the transmitting energy, the frequency band or the
waiting time.
24. The method of claim 23, wherein the transmitting node is
further configured to instruct other intermediate communications
nodes of the changes in the transmitting energy or the frequency
band or the waiting time.
25. The method of claim 22, wherein: each intermediate
communications node is configured to selectively operate in either
an awake state wherein the node is able to send and receive
signals, or in a sleep state wherein the node is able to collect
data but make no transmission; and during the sleep state, each
intermediate communications node is programmed to have a
periodically awake mode where it listens for a wakeup packet to
return the node to its awake state.
26. The method of claim 20, wherein the joints of pipe form a
string of casing.
27. The method of claim 20, wherein the sensor is (i) a pressure
sensor, (ii) a temperature sensor, (iii) an induction log, (iv) a
gamma ray log, (v) a formation density sensor, (vi) a sonic
velocity sensor, (vii) a vibration sensor, (viii) a resistivity
sensor, (ix) a flow meter, (x) a microphone, (xi) a geophone, (xii)
a chemical sensor, or (xiii) a set of position sensors.
28. The method of claim 20, wherein each of the communications
nodes further comprises at least one clamp for radially attaching
the communications node onto an outer surface of a joint of
pipe.
29. The method of claim 28, wherein the at least one clamp
comprises: a first arcuate section; a second arcuate section; a
hinge for pivotally connecting the first and second arcuate
sections; and a fastening mechanism for securing the first and
second arcuate sections around an outer surface of the tubular
body.
30. The method of claim 20, wherein: the electro-acoustic
transceivers receive acoustic waves at a frequency, and re-transmit
the acoustic waves at the same frequency; and the electro-acoustic
transceivers listen for the acoustic waves for a longer time than
the time for which the acoustic waves were generated by a previous
communications node.
31. The method of claim 20, wherein the sensor resides in the
housing of a sensor communications node, with the housing being
fabricated from steel.
32. A method of transmitting data in a wellbore, comprising:
running a tubular body into the wellbore, the wellbore penetrating
into a subsurface formation and the tubular body being comprised of
pipe joints; placing at least one sensor along the wellbore at a
depth of the subsurface formation; attaching a sensor
communications node to a wall of the tubular body proximate the
depth of the subsurface formation, the sensor communications node
being in communication with the at least one sensor and configured
to receive signals from the at least one sensor, the signals
representing a subsurface condition; providing a topside
communications node proximate a surface of the wellbore; and
attaching a plurality of intermediate communications nodes to a
wall of the tubular body in spaced-apart relation, the intermediate
communications nodes configured to transmit acoustic waves from the
sensor communications node to the topside communications node in
node-to-node arrangement; wherein each of the intermediate
communications nodes comprises: a sealed housing; an independent
power source residing within the housing; an electro-acoustic
transducer and associated transceiver also residing within the
housing designed to receive the acoustic waves as asynchronous
packets of information and re-transmit them after reverberation of
the acoustic waves has substantially attenuated, with at least some
of the acoustic waves correlating to the signals generated by the
sensor and representing a subsurface condition; and at least one
clamp for radially attaching the communications node onto an outer
surface of the tubular body.
33. The method of claim 32, wherein: the intermediate
communications nodes transmit the acoustic waves at a rate
exceeding about 50 bps; and (i) each of the plurality of separate
tones has a different frequency, (ii) no two consecutive tones have
the same frequency, or (iii) both.
34. The method of claim 32, wherein: the tubular body forms a
string of casing; adjacent intermediate communications nodes
represent pairs of nodes; a receiving node in the pair of nodes is
configured to detect amplitude and reverberation time for each tone
received in a packet from a transmitting node in the pair of nodes,
and then return the packet to the transmitting node; and the
transmitting node is configured to adjust its transmitting energy
or its frequency band so that a weakest tone in the packet as
returned by the receiving node will be received at a weakest signal
amplitude for which communication remains robust.
35. The method of claim 33, wherein the transmitting node is
further configured to: reduce a waiting time between tones to a
smallest time required for the reverberation to substantially
subside; instruct the receiving node that it has made any changes
in the transmitting energy, the frequency band or the waiting time;
and instruct other intermediate communications nodes of the changes
in the transmitting energy, the frequency band or the waiting
time.
36. The method of claim 35, further comprising: receiving signals
from the topside communications node at a receiver; and analyzing
the signals.
37. The method of claim 33, wherein the step of attaching a
plurality of intermediate communications nodes to the tubular body
comprises clamping the intermediate communications nodes to an
outer surface of the tubular body.
38. The method of claim 33, further comprising: sending a signal
from the surface to discharge a battery in a selected intermediate
communications node.
39. The method of claim 38, wherein the signal is sent in response
to a reading from a sensor based on a subsurface parameter.
40. An electro-acoustic system for wireless telemetry along a
pipeline, comprising: a tubular body fabricated from steel; at
least one sensor disposed along the tubular body; a sensor
communications node placed along the tubular body and connected to
a wall of the tubular body, the sensor communications node being in
electrical communication with the at least one sensor and
configured to receive signals from the at least one sensor, the
signals representing a parameter associated with a location along
the tubular body; a proximal communications node placed at a
beginning location along the tubular body; a plurality of
intermediate communications nodes spaced along the tubular body and
attached to an outer wall of the tubular body, the intermediate
communications nodes configured to transmit acoustic waves from the
sensor communications node to the proximal communications node in
node-to-node arrangement; and a receiver configured to receive
signals from the proximal communications node; wherein each of the
intermediate communications nodes comprises: a sealed housing; an
independent power source residing within the housing; and an
electro-acoustic transducer and associated transceiver also
residing within the housing designed to receive and re-transmit the
acoustic waves, thereby providing communications telemetry; and
wherein the acoustic waves represent packets of information
comprising a plurality of separate tones, with at least some of the
acoustic waves being indicative of the parameter.
41. The electro-acoustic telemetry system of claim 40, wherein (i)
each of the plurality of separate tones has a different frequency,
(ii) no two consecutive tones have the same frequency, or (iii)
both.
42. The electro-acoustic telemetry system of claim 41, wherein the
at least one sensor comprises (i) a pressure sensor, (ii) a
temperature sensor, (iii) a sonic velocity sensor, (iv) a vibration
sensor, (v) a flow meter; (vi) an electrical impedance sensor,
(vii) a resistivity sensor; or (viii) a chemical sensor.
43. The electro-acoustic telemetry system of claim 41, wherein each
of the intermediate communications nodes further comprises at least
one clamp for radially attaching the communications node onto an
outer surface of the tubular body.
44. The electro-acoustic telemetry system of claim 41, wherein:
adjacent intermediate communications nodes represent pairs of
nodes; a receiving node in the pair of nodes is configured to
detect amplitude and reverberation time for each tone received in a
packet from a transmitting node in the pair of nodes, and then
return the packet to the transmitting node; and the transmitting
node is configured to adjust its transmitting energy or its
frequency band so that a weakest tone in the packet as returned by
the receiving node will be received at a weakest signal amplitude
for which communication remains robust.
45. The electro-acoustic telemetry system of claim 44, wherein the
transmitting node is further configured to: reduce a waiting time
between tones to a smallest time required for the reverberation to
substantially subside; instruct the receiving node that it has made
any changes in the transmitting energy, the frequency band or the
waiting time; and instruct other intermediate communications nodes
of the changes in the transmitting energy, the frequency band or
the waiting time.
46. The electro-acoustic telemetry system of claim 41, wherein:
each intermediate communications node is configured to selectively
operate in either an awake state wherein the node is able to send
and receive signals, or in a sleep state wherein the node is able
to collect data but make no transmissions.
47. A method for modulating acoustic waves using a multi-frequency
shift keying (MFSK) process, comprising: generating a first set of
tones from a first electro-acoustic transceiver, each tone being
associated with a defined frequency, and each tone being associated
with a logical alphabet value; reviewing the first set of tones to
determine if two consecutive tones have the same logical alphabet
value; if two consecutive tones do have the same logical alphabet
value, modifying the first set of tones to provide that no two same
tones are sent consecutively, thereby generating a modified first
set of tones; transmitting the modified first set of tones from the
first electro-acoustic transceiver; receiving the modified first
set of tones from the first electro-acoustic transceiver at a
second electro-acoustic transceiver as a message packet; reviewing
the modified first set of tones; and deconstructing the modified
first set of tones back to its original first set of tones.
48. The method of claim 47, wherein: the modifying step comprises
determining whether a tone in the first set of tones is equal to or
greater than an immediately preceding tone in the first set of
tones and, if a tone in the first set of tones is equal to or
greater than an immediately preceding tone in the first set of
tones, increasing the logical alphabet value by a defined alphabet
value; and the deconstruction step comprises determining whether a
tone in the modified first set of tones is greater than an
immediately preceding tone in the modified first set of tones and,
if a tone in the modified first set of tones is equal to or greater
than an immediately preceding tone in the modified first set of
tones, decreasing the logical alphabet value by the defined
alphabet value.
49. The method of claim 48, wherein the defined alphabet value is a
next higher frequency.
50. The method of claim 47, wherein: the modifying step comprises
determining whether a tone in the first set of tones is equal to or
less than an immediately preceding tone in the first set of tones
and, if a tone in the first set of tones is equal to or less than
an immediately preceding tone in the first set of tones, decreasing
the logical alphabet value by a defined alphabet value; and the
deconstruction step comprises determining whether a tone in the
modified first set of tones is equal to or less than an immediately
preceding tone in the modified first set of tones and, if a tone in
the modified first set of tones is equal to or less than an
immediately preceding tone in the modified first set of tones,
increasing the logical alphabet value by the defined alphabet
value.
51. The method of claim 50, wherein the defined alphabet value is a
next lower frequency.
52. The method of claim 47, wherein each of the first and the
second electro-acoustic transceivers resides either in a wellbore
or along a pipeline as part of a telemetry system.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Ser. No.
61/739,414, filed Dec. 19, 2012, the entire contents of which are
hereby incorporated by reference herein. This application is
further related to co-pending U.S. Ser. Nos. 61/739,679,
61/739,677, 61/739,678, and 61/739,681, each filed on Dec. 19,
2012, the entire contents of each of which are also hereby
incorporated by reference herein.
BACKGROUND OF THE INVENTION
[0002] This section is intended to introduce various aspects of the
art, which may be associated with exemplary embodiments of the
present disclosure. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present disclosure. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
FIELD OF THE INVENTION
[0003] The present invention relates to the field of data
transmission along a tubular body, such as a steel pipe. More
specifically, the invention relates to the transmission of data
along a pipe within a wellbore or along a pipeline at the surface
or in a body of water. The present invention further relates to a
wireless transmission system for transmitting data up a drill
string during a drilling operation or along the casing during
drilling or production operations. The present invention further
relates to the use of acoustic telemetry signals along a wellbore
to optimize communication protocol for speed, for power
conservation and for low error rates.
GENERAL DISCUSSION OF TECHNOLOGY
[0004] It is desirable to transmit data along a pipeline without
the need for wires or radio frequency (electromagnetic)
communications devices. Examples abound where the installation of
wires is either technically difficult or economically impractical.
The use of radio transmission may also be impractical or
unavailable in cases where radio-activated blasting is occurring,
or where the attenuation of radio waves near the tubular body is
significant.
[0005] Likewise, it is desirable to collect and transmit data along
a tubular body in a wellbore, such as during a drilling process. In
the drilling of oil and gas wells, a wellbore is formed using a
drill bit that is urged downwardly at a lower end of a drill
string. The drill bit is rotated while force is applied through the
drill string and against the rock face of the formation being
drilled. During this process, the operator may seek to acquire real
time data related to temperature, pressure, rate of rock
penetration, inclination, azimuth, fluid composition, and local
geology. In order to obtain such information, special downhole
assemblies have been developed. These assemblies are generally
referred to as Logging While Drilling (LWD) or Measurement While
Drilling (MWD) assemblies, or generically as bottom hole
assemblies.
[0006] LWD and MWD assemblies are typically placed proximate the
drill bit at the bottom of the drill string. Bottom hole assemblies
having LWD or MWD capabilities are able to store or transmit
information about subsurface conditions for review by drilling or
production operators at the surface. LWD and MWD techniques
generally seek to reduce the need for tripping the drill string and
running wireline logs to obtain downhole data.
[0007] A variety of technologies have been proposed or developed
for downhole communications using LWD or MWD. In one form, MWD and
LWD information is simply stored in a microprocessor having memory.
The microprocessor is retrieved and the information is downloaded
later when the drill string is pulled, such as when a drill bit is
changed out or a new bottom hole assembly is installed.
[0008] Several real time data telemetry systems have also been
offered. One involves the use of a physical cable such as an
electrical conductor or a fiber optic cable that is secured to the
tubular body. The cable may be secured to either the inner or the
outer diameter of the pipe. The cable provides a hard wire
connection that allows for real-time transmission of data and the
immediate evaluation of subsurface conditions. Further, these
cables allow for high data transmission rates and the delivery of
electrical power directly to downhole sensors.
[0009] It can be readily perceived that the placement of a physical
cable along a string of drill pipe during drilling is problematic.
In this respect, the cable will become quickly tangled and will
break if secured along a rotating drill string. This problem is
lessened when a downhole mud motor is used that allows for a
generally non-rotating drill pipe. However, even in this instance
the harsh downhole environment and the considerable force of the
pipe as it scrapes across the surrounding borehole can impair the
cable.
[0010] It has been proposed to place a physical cable along the
outside of a casing string during well completion. However, this
can be difficult as the placement of wires along a pipe string
requires that thousands of feet of cable be carefully unspooled and
fed during pipe connection and run-in. Further, the use of hard
wires in a well completion requires the installation of a
specially-designed well head that includes through-openings for the
wires. In addition, if the wire runs outside of a casing string,
this creates a potential weak spot in the cement sheath that may
contribute to a loss of pressure isolation between subsurface
intervals. It is generally not feasible to pass wires through a
casing mandrel for subsea applications. In sum, passing cable in
the annulus adds significant cost, both for equipment and for rig
time, to well completions.
[0011] Mud pulse telemetry, or mud pressure pulse transmission, is
commonly used during drilling to obtain data from sensors at or
near the drill bit. Mud pulse telemetry employs variations in
pressure in the drilling mud to transmit signals from the bottom
hole assembly to the surface. The variations in pressure may be
sensed and analyzed by a computer at the surface.
[0012] A downside to mud pulse telemetry is that it transmits data
to the surface at relatively slow rates, typically at rates of less
than 20 bits per second (bps). This rate decreases as the length of
the wellbore increases, even down to 10 or fewer bps. Slow data
transmission rates can be costly to the drilling process. For
example, the time it takes to downlink instructions and uplink
survey data (such as azimuth and inclination), during which the
drill string is normally held stationary, can be two to seven
minutes. Since many survey stations are typically required, this
downlink/uplink time can be very expensive, especially on deepwater
rigs where daily operational rates can exceed $2 million.
Similarly, the time it takes to downlink instructions and uplink
data associated with many other tasks such as setting parameters in
a rotary steerable directional drilling tool or obtaining a
pressure reading from a pore-pressure-while-drilling tool can be
very costly.
[0013] The use of acoustic telemetry has also been suggested.
Acoustic telemetry employs an acoustic signal generated at or near
the bottom hole assembly or bottom of a pipe string. The signal is
transmitted through the wellbore pipe, meaning that the pipe
becomes the carrier medium for sound waves. Transmitted sound waves
are detected by a receiver and converted to electrical signals for
analysis.
[0014] U.S. Pat. No. 5,924,499 entitled "Acoustic Data Link and
Formation Property Sensor for Downhole MWD System" teaches the use
of acoustic signals for "short hopping" a component along a drill
string. Signals are transmitted from the drill bit or from a
near-bit sub and across the mud motors. This may be done by sending
separate acoustic signals simultaneously--one that is sent through
the drill string, a second that is sent through the drilling mud,
and optionally, a third that is sent through the formation. These
signals are then processed to extract readable signals.
[0015] U.S. Pat. No. 6,912,177, entitled "Transmission of Data in
Boreholes," addresses the use of an acoustic transmitter that is
part of a downhole tool. Here, the transmitter is provided adjacent
a downhole obstruction such as a shut-in valve along a drill stem
so that an electrical signal may be sent across the drill stem.
U.S. Pat. No. 6,899,178, entitled "Method and System for Wireless
Communications for Downhole Applications," describes the use of a
"wireless tool transceiver" that utilizes acoustic signaling. Here,
an acoustic transceiver is in a dedicated tubular body that is
integral with a gauge and/or sensor. This is described as part of a
well completion.
[0016] Faster data transmission rates with some level of clarity
have been accomplished using electromagnetic (EM) telemetry. EM
telemetry employs electromagnetic waves, or alternating current
magnetic fields, to "jump" across pipe joints. In practice, a
specially-milled drill pipe is provided that has a conductor wire
machined along an inner diameter. The conductor wire transmits
signals to an induction coil at the end of the pipe. The induction
coil, in turn, then transmits an EM signal to another induction
coil, which sends that signal through the conductor wire in the
next pipe. Thus, each threaded connection provides a pair of
specially milled pipe ends for EM communication.
[0017] National Oilwell Varco.RTM. of Houston, Tex. offers a drill
pipe network, referred to as IntelliServ.RTM., that uses EM
telemetry. The IntelliServ.RTM. system employs drill pipe having
integral wires that can transmit LWD/MWD data to the surface at
speeds of up to 1 Mbps. This creates a communications system from
the drill string itself. The IntelliServ.RTM. communications system
uses an induction coil built into both the threaded box and pin
ends of the drill pipe joints so that data may be transmitted
across each connection. Examples of IntelliServ.RTM. patents are
U.S. Pat. No. 7,277,026 entitled "Downhole Component With Multiple
Transmission Elements," and U.S. Pat. No. 6,670,880 entitled
"Downhole Data Transmission System."
[0018] It is observed that the induction coils in an EM telemetry
system must be precisely located in the box and pin ends of the
joints of the drill string to ensure reliable data transfer. For a
long (e.g., 20,000 foot) well, there can be more than 600 tool
joints. This represents over 600 pipe sections to be threadedly
connected. Further, each threaded connection is preferably tested
at the drilling platform to ensure proper functioning.
[0019] National Oilwell Varco.RTM. promotes its IntelliServ.RTM.
system as providing the oil and gas industry's "only high-speed,
high-volume, high-definition, bi-directional broadband data
transmission system that enables downhole conditions to be
measured, evaluated, monitored and actuated in real time." However,
the IntelliServ.RTM. system generally requires the use of booster
assemblies along the drill string. These can be three to six foot
sub joints having a diameter greater than the drill pipe placed in
the drill string. The booster assemblies, referred to sometimes as
"signal repeaters," are located along the drill pipe about every
1,500 feet. The need for repeaters coupled with the need for
specially-milled pipe can make the IntelliServ.RTM. system a very
expensive option.
[0020] Recently, the use of radiofrequency signals has been
suggested. This is offered in U.S. Pat. No. 8,242,928 entitled
"Reliable Downhole Data Transmission System." This patent suggests
the use of electrodes placed in the pin and box ends of pipe
joints. The electrodes are tuned to receive RF signals that are
transmitted along the pipe joints having a conductor material
placed there along, with the conductor material being protected by
a special insulative coating.
[0021] While high data transmission rates can be accomplished using
RF signals in a downhole environment, the transmission range is
typically limited to a few meters. This, in turn, requires the use
of numerous repeaters.
[0022] Accordingly, a need exists for a high speed wireless
transmission system in a wellbore that does not require the
machining of induction coils with precise grooves placed into pipe
ends or the need for electrodes in the pipe ends or couplings.
Further, a need exists for such a wireless transmission system that
does not require the precise alignment of induction coils or the
placement of RF electrodes between pipe joints.
SUMMARY OF THE INVENTION
[0023] A system for downhole telemetry is provided herein. The
system employs a series of autonomous communications nodes spaced
along a wellbore. The nodes allow for wireless communication
between one or more sensors residing at the level of a subsurface
formation, and a receiver at the surface.
[0024] The system first includes a tubular body disposed in the
wellbore. Where the wellbore is being formed, the tubular body is a
drill string, with the wellbore progressively penetrating into a
subsurface formation. The subsurface formation preferably
represents a rock matrix having hydrocarbon fluids available for
production in commercially acceptable volumes. Thus, the wellbore
is to be completed as a production well, or "producer."
Alternatively, the wellbore is to be completed as an injection well
or a formation monitoring well.
[0025] In another aspect, the wellbore has already been completed.
The tubular body is then a casing string or, alternatively, a
production string such as tubing.
[0026] The system also includes at least one sensor. As noted, the
sensor is disposed along the wellbore at a depth of the subsurface
formation. The sensor may be, for example, a temperature sensor, a
pressure sensor, a microphone, a geophone, a vibration sensor, a
resistivity sensor, a fluid flow measurement device, a chemical
composition or pH sensor, a formation density sensor, a fluid
identification sensor, or a strain gauge. Where the wellbore is
being drilled, the sensor may alternatively be a set of position
sensors indicating, inclination, azimuth, and orientation.
[0027] The system further has one or more a sensor communications
nodes. The sensor communications nodes are placed along the
wellbore, such as along a drill string or along a casing string. At
least one of the sensor communications nodes is connected to the
tubular body at the depth of the subsurface formation. The sensor
communications node along the subsurface formation is in electrical
communication with a sensor. Preferably, the sensor resides within
a housing of the sensor communications node.
[0028] The sensor communications node is configured to receive
signals from the at least one sensor. The signals represent a
subsurface condition such as temperature, pressure, or logging
information. The sensor communications node preferably includes a
sealed housing for holding the electronics.
[0029] The system also comprises a topside communications node. The
topside communications node is placed proximate the surface, such
as on the wellhead or other near-surface equipment in acoustic
communication with downhole tubular bodies. In one aspect, the
topside communications node is connected to the wellhead. The
surface may be an earth surface. Alternatively, in a subsea
context, the surface may be an offshore drilling or production
platform.
[0030] The system further includes a plurality of intermediate
communications nodes. The intermediate communications nodes are
attached to the tubular body in spaced-apart relation. In one
aspect, the intermediate communications nodes are spaced at about
10 to about 100 foot (.about.3 meter to .about.30 meter) intervals.
The intermediate communications nodes are configured to relay
messages between from the sensor communications node and the
topside communications node. In one embodiment, the sensor
communications node is fully housed with the intermediate
communications node.
[0031] Each of the intermediate communications nodes has an
independent power source. The power source may be, for example,
batteries or a fuel cell. In addition, each of the intermediate
communications nodes has an electro-acoustic transducer and
associated transceiver that is used to establish telemetry. The
transceiver is designed to receive and transmit acoustic waves at a
frequency range enabling (i) node-to-node acoustic transmission and
(ii) a modulation scheme permitting the transfer of
information.
[0032] The acoustic waves represent the readings taken and data
generated by the sensor. In this way, data about subsurface
conditions are transmitted wirelessly from node-to-node up to the
surface. The acoustic waves represent asynchronous packets of
information comprising a plurality of tones. Each tone may have a
non-prescribed amplitude, a non-prescribed reverberation time, or
both. In one aspect, the communications nodes transmit data as
mechanical waves at a rate exceeding about 50 bps. In a preferred
embodiment, multiple frequency shift keying (MFSK) is the
modulation scheme enabling the transmission of information.
[0033] A method of transmitting data in a wellbore is also provided
herein. The method uses a plurality of data transmission nodes
situated along a tubular body to accomplish a wireless transmission
of data along the wellbore. The wellbore penetrates into a
subsurface formation, allowing for the communication of a wellbore
condition at the level of the subsurface formation up to the
surface.
[0034] The method first includes running a tubular body into the
wellbore. The tubular body is formed by connecting a series of pipe
joints end-to-end.
[0035] The method also includes placing at least one sensor along
the wellbore at a depth of the subsurface formation. The sensor may
be a pressure sensor, a temperature sensor, a set of position
sensors, a vibration sensor, a formation density sensor, a strain
gauge, a sonic velocity sensor, a resistivity sensor, or other
chemical or physical sensor.
[0036] The method further includes attaching a sensor
communications node to the tubular body. The sensor communications
node is then placed at the depth of the subsurface formation. The
sensor communications node is in electrical (or, optionally,
optical) communication with the at least one sensor. This
communication may be by means of a short wired connection. In one
aspect, the sensor resides in the housing of a sensor
communications node.
[0037] The sensor communications node is configured to receive
signals from the at least one sensor. The signals represent a
subsurface condition as detected by the sensor. In one embodiment,
the sensor is the same electro-acoustic transducer that enables the
telemetry communication. In this way, amplitude and amplitude
attenuation values may be analyzed.
[0038] The method also provides for attaching a topside
communications node to the tubular body or other structure, such as
the well head or the blow out preventer (BOP), that is connected to
the tubular body. The topside communications node is attached to
the tubular body proximate the surface.
[0039] The method further comprises attaching a plurality of
intermediate communications nodes to the tubular body. The
intermediate communications nodes reside in spaced-apart relation
along the tubular body between the sensor communications node and
the topside communications node. The intermediate communications
nodes are configured to relay sensor data via acoustic waves from
the sensor communications node to the topside node. The
intermediate communications nodes are configured as described above
to send asynchronous packets of information. Preferably, a sliding
alphabet algorithm is employed for signal processing as a method of
reducing adverse impact of reverberation during transmission and
reception of messages. In one aspect, the algorithm eliminates the
occurrence of two of the same tones sent consecutively (given a set
of defined tones associated with defined frequencies) during a MFSK
communication.
[0040] In a preferred embodiment, the attaching steps comprise
clamping the various communications nodes, that is, at least the
sensor communications nodes and the intermediate communications
nodes, to the tubular body. These communications nodes are welded
or otherwise pre-attached to one or more clamps, which are then
secured around the tubular body during run-in.
[0041] In one aspect, the method further includes receiving a
signal from the topside communications node at a receiver. The
receiver is located at or just above the surface. The receiver
preferably receives electrical or optical signals from the topside
communications node. In one embodiment, the electrical or optical
signals are conveyed in a conduit suitable for operation in an
electrically classified area, that is, via a so-called "Class I,
Division 1" conduit (as defined by NFPA 497 and API 500).
Alternatively, data can be transferred from the topside
communications node to a receiver via an electromagnetic (RF)
wireless connection. The electrical signals may then be processed
and analyzed at the surface.
[0042] As acoustic telemetery signals are sent between the
transceivers downhole and a processor at the surface, the acoustic
signals may change due to one or more subsurface condition changes.
Such changes may include changes in the flexural wave velocity of
the pipe, depending on the speed of sound (e.g. in steel, versus
mud, versus air), and one or more mechanisms that will attenuate
the acoustic telemetry signal as the propagation distance
increases. Detection of these changes can be helpful to the
operation of the electro-acoustic network as such changes can
affect the delay time between individual acoustic "tones" in the
packets as well as the optimal frequency band and reverberation
times for transmission.
[0043] The operating protocol for the acoustic telemetry network
can be adjusted after the network has been deployed. In order to
implement changes to network communications, a "bi-lingual" command
may be sent. This command enables pairs of nodes to temporarily
respond and transmit with both the original operating protocol and
the adjusted protocol.
[0044] The changing nature of electro-acoustic waves sent and
received by pairs of communication nodes can be used to infer
depth-dependent properties. These may include defects in metallic
tubing, defects in the coupling between lengths of tubing, and
changes in fluid, solid or mixed media along a tubular joint (e.g.,
water, oil, gas, flowing particles).
BRIEF DESCRIPTION OF THE DRAWINGS
[0045] So that the present inventions can be better understood,
certain drawings, charts, graphs and/or flow charts are appended
hereto. It is to be noted, however, that the drawings illustrate
only selected embodiments of the inventions and are therefore not
to be considered limiting of scope, for the inventions may admit to
other equally effective embodiments and applications.
[0046] FIG. 1 is a side, cross-sectional view of an illustrative
wellbore. The wellbore is being formed using a derrick, a drill
string and a bottom hole assembly. A series of communications nodes
is placed along the drill string as part of a telemetry system.
[0047] FIG. 2 is a cross-sectional view of a wellbore having been
completed. The illustrative wellbore has been completed as a cased
hole completion. A series of communications nodes is placed along a
tubing string as part of a telemetry system.
[0048] FIG. 3 is a perspective view of an illustrative pipe joint.
A communications node (such as a sensor communications node or an
intermediate communications node) of the present invention, in one
embodiment, is shown exploded away from the pipe joint.
[0049] FIG. 4A is a perspective view of a communications node as
may be used in the wireless data transmission system of the present
invention, in an alternate embodiment.
[0050] FIG. 4B is a cross-sectional view of the communications node
of FIG. 4A. The view is taken along the longitudinal axis of the
node. Here, a sensor is provided within the communications
node.
[0051] FIG. 4C is another cross-sectional view of the
communications node of FIG. 4A. The view is again taken along the
longitudinal axis of the node. Here, a sensor resides along the
wellbore external to the communications node.
[0052] FIGS. 5A and 5B are perspective views of a shoe as may be
used on opposing ends of the communications node of FIG. 4A, in one
embodiment. In FIG. 5A, the leading edge, or front, of the shoe is
seen. In FIG. 5B, the back of the shoe is seen.
[0053] FIG. 6 is a perspective view of a communications node system
of the present invention, in one embodiment. The communications
node system utilizes a pair of clamps for connecting a
communications node onto a tubular body.
[0054] FIG. 7 is a flowchart demonstrating steps of a method for
transmitting data in a wellbore in accordance with the present
inventions, in one embodiment.
[0055] FIG. 8 provides an example of an asynchronous network
message packet as may be used for the acoustic signals in the
present invention, in one embodiment.
[0056] FIG. 9 is an example of a transition of a communications
node from a sleep state to a wake state using a series of wait
stubs and a wakeup packet.
[0057] FIG. 10 shows an example of a sliding alphabet algorithm as
may be used for processing acoustic signals in the present
invention, in one embodiment. The algorithm is designed to
eliminate the occurrence of two of the same tones sent
consecutively (given a set of defined tones associated with defined
frequencies) during a MFSK communication.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
Definitions
[0058] As used herein, the term "hydrocarbon" refers to an organic
compound that includes primarily, if not exclusively, the elements
hydrogen and carbon. Examples of hydrocarbons include any form of
natural gas, oil, coal, and bitumen that can be used as a fuel or
upgraded into a fuel.
[0059] As used herein, the term "hydrocarbon fluids" refers to a
hydrocarbon or mixtures of hydrocarbons that are gases or liquids.
For example, hydrocarbon fluids may include a hydrocarbon or
mixtures of hydrocarbons that are gases or liquids at formation
conditions, at processing conditions, or at ambient conditions
(20.degree. C. and 1 atm pressure). Hydrocarbon fluids may include,
for example, oil, natural gas, gas condensates, coal bed methane,
shale oil, shale gas, and other hydrocarbons that are in a gaseous
or liquid state.
[0060] As used herein, the term "subsurface" refers to regions
below the earth's surface.
[0061] As used herein, the term "sensor" includes any electrical
sensing device or gauge. The sensor may be capable of monitoring or
detecting pressure, temperature, fluid flow, vibration,
resistivity, or other formation data.
[0062] As used herein, the term "formation" refers to any definable
subsurface region. The formation may contain one or more
hydrocarbon-containing layers, one or more non-hydrocarbon
containing layers, an overburden, and/or an underburden of any
geologic formation.
[0063] The terms "zone" or "zone of interest" refer to a portion of
a formation containing hydrocarbons. The term "hydrocarbon-bearing
formation" may alternatively be used.
[0064] As used herein, the term "wellbore" refers to a hole in the
subsurface made by drilling or insertion of a conduit into the
subsurface. A wellbore may have a substantially circular cross
section, or other cross-sectional shape. As used herein, the term
"well," when referring to an opening in the formation, may be used
interchangeably with the term "wellbore."
[0065] The terms "tubular member" or "tubular body" refer to any
pipe, such as a joint of casing, a portion of a liner, a drill
string, a production tubing, an injection tubing, a pup joint, a
buried pipeline, underwater piping, or above-ground pipeline. The
tubular body may also be a downhole tubular device such as a joint
of sand screen having a base pipe with pre-drilled holes, a slotted
liner, or an inflow control device.
Description of Selected Specific Embodiments
[0066] The invention described herein in connection with certain
specific embodiments. However, to the extent that the following
detailed description is specific to a particular embodiment or a
particular use, such is intended to be illustrative only and is not
to be construed as limiting the scope of the inventions.
[0067] FIG. 1 is a side, cross-sectional view of an illustrative
well site 100. The well site 100 includes a derrick 120 at an earth
surface 101, and a wellbore 150 extending from the earth surface
101 into an earth subsurface 155. The wellbore 150 is being formed
using the derrick 120, a drill string 160 below the derrick 120,
and a bottom hole assembly 170 at a lower end of the drill string
160.
[0068] Referring first to the derrick 120, the derrick 120 includes
a frame structure 121 that extends up from the earth surface 101
and which supports drilling equipment. The derrick 120 also
includes a traveling block 122, a crown block 123 and a swivel 124.
A so-called kelly 125 is attached to the swivel 124. The kelly 125
has a longitudinally extending bore (not shown) in fluid
communication with a kelly hose 126. The kelly hose 126, also known
as a mud hose, is a flexible, steel-reinforced, high-pressure hose
that delivers drilling fluid through the bore of the kelly 125 and
down into the drill string 160.
[0069] The kelly 125 includes a drive section 127. The drive
section 127 is non-circular in cross-section and conforms to an
opening 128 longitudinally extending through a kelly drive bushing
129. The kelly drive bushing 129 is part of a rotary table. The
rotary table is a mechanically driven device that provides
clockwise (as viewed from above) rotational force to the kelly 125
and connected drill string 160 to facilitate the process of
drilling a borehole 105. Both linear and rotational movement may
thus be imparted from the kelly 125 to the drill string 160.
[0070] A platform 102 is provided for the derrick 120. The platform
102 extends above the earth surface 101. The platform 102 generally
supports rig hands along with various components of drilling
equipment such as a pumps, motors, gauges, a dope bucket, pipe
lifting equipment and control equipment. The platform 102 also
supports the rotary table.
[0071] It is understood that the platform 102 shown in FIG. 1 is
somewhat schematic. It is also understood that the platform 102 is
merely illustrative and that many designs for drilling rigs, both
for onshore and for offshore operations, exist. The claims provided
herein are not limited by the configuration and features of the
drilling rig unless expressly stated in the claims.
[0072] Placed below the platform 102 and the kelly drive section
127 but above the earth surface 101 is a blow-out preventer, or BOP
130. The BOP 130 is a large, specialized valve or set of valves
used to control pressures during the drilling of oil and gas wells.
Specifically, blowout preventers control the fluctuating pressures
emanating from subterranean formations during a drilling process.
The BOP 130 may include upper 132 and lower 134 rams used to
isolate flow on the back side of the drill string 160. Blowout
preventers 130 also prevent the pipe joints making up the drill
string 160 and the drilling fluid from being blown out of the
wellbore 150 when a blowout threatens.
[0073] As shown in FIG. 1, the wellbore 150 is being formed down
into the subsurface formation 155. In addition, the wellbore 150 is
being shown as a deviated wellbore. Of course, this is merely
illustrative as the wellbore 150 may be a vertical well or even a
horizontal well, as shown later in FIG. 2.
[0074] In drilling the wellbore 150, a first string of casing 110
is placed down from the surface 101. This is known as surface
casing 110 or, in some instances (particularly offshore), conductor
pipe. The surface casing 110 is secured within the formation 155 by
a cement sheath. The cement sheath resides within an annular region
115 between the surface casing 110 and the surrounding formation
155.
[0075] During the process of drilling and completing the wellbore
150, additional strings of casing (not shown) will be provided.
These may include intermediate casing strings and a final
production casing string. For the final production casing, a liner
may be employed, that is, a string of casing that is not tied back
to the surface 101.
[0076] As noted, the wellbore 150 is formed by using a bottom hole
assembly 170. The bottom-hole assembly 170 allows the operator to
control or "steer" the direction or orientation of the wellbore 150
as it is formed. In this instance, the bottom hole assembly 170 is
known as a rotary steerable drilling system, or RSS.
[0077] The bottom hole assembly 170 will include a drill bit 172.
The drill bit 172 may be turned by rotating the drill string 160
from the platform 102. Alternatively, the drill bit 172 may be
turned by using so-called mud motors 174. The mud motors 174 are
mechanically coupled to and turn the nearby drill bit 172. The mud
motors 174 are used with stabilizers or bent subs 176 to impart an
angular deviation to the drill bit 172. This, in turn, deviates the
well from its previous path in the desired azimuth and
inclination.
[0078] There are several advantages to directional drilling. These
primarily include the ability to complete a wellbore along a
substantially horizontal axis of a subsurface formation, thereby
exposing a substantially greater formation face. These also include
the ability to penetrate into subsurface formations that are not
located directly below the wellhead. This is particularly
beneficial where an oil reservoir is located under an urban area or
under a large body of water. Another benefit of directional
drilling is the ability to group multiple wellheads on a single
platform, such as for offshore drilling. Finally, directional
drilling enables multiple laterals and/or sidetracks to be drilled
from a single wellbore in order to maximize reservoir exposure and
recovery of hydrocarbons.
[0079] The illustrative well site 100 also includes a sensor 178.
Here, the sensor 178 is part of the bottom hole assembly 170. The
sensor 178 may be, for example, a set of position sensors that is
part of the electronics for a RSS. Alternatively or in addition,
the sensor 178 may be a temperature sensor, a pressure sensor, or
other sensor for detecting a downhole condition during drilling.
Alternatively still, the sensor may be an induction log or gamma
ray log or other log that detects fluid and/or geology
downhole.
[0080] The sensor 178 is part of a MWD or a LWD assembly. It is
observed that the sensor 178 is located above the mud motors 174.
This is a common practice for MWD assemblies. This allows the
electronic components of the sensor 178 to be spaced apart from the
high vibration and centrifugal forces acting on the bit 172.
[0081] Where the sensor 178 is a set of position sensors, the
sensors may include three inclinometer sensors and three
environmental acceleration sensors. Ideally, a temperature sensor
and a wear sensor will also be placed in the drill bit 172. These
signals are input into a multiplexer and transmitted.
[0082] It is desirable to send signals about the downhole condition
back to an operator at the surface 101. To do this, a telemetry
system is used. As discussed above, various telemetry systems are
known in the industry. However, the well site 100 of FIG. 1
presents a telemetry system that utilizes a series of novel
communications nodes 180 placed along the drill string 160. These
nodes 180 allow for the high speed transmission of wireless signals
based on the in situ generation of acoustic waves.
[0083] The nodes first include a topside communications node 182.
The topside communications node 182 is placed closest to the
surface 101. The topside node 182 is configured to receive and/or
transmit acoustic signals. The topside communications node can is
preferably above grade and on the wellhead.
[0084] The nodes may also include a sensor communications node 184.
The sensor communications node is placed closest to the sensor 178.
The sensor communications node 184 is configured to communicate
with the downhole sensor 178, and then send a wireless signal using
an acoustic wave.
[0085] Finally, the nodes include a plurality of intermediate
communications nodes 180. Each of the intermediate communications
nodes 180 resides between the sensor node 182 and the topside node
184. The intermediate communications nodes 180 are configured to
receive and then relay acoustic signals along the length of the
wellbore 150. Preferably, the intermediate communications nodes 180
utilize two-way electro-acoustic transducers to both receive and
relay mechanical waves. In one embodiment, the sensor
communications node is fully housed with the intermediate
communications node.
[0086] In FIG. 1, the nodes 180 are shown schematically. However,
FIG. 3 offers an enlarged perspective view of an illustrative pipe
joint 300, along with an illustrative intermediate communications
node 350. The illustrative communications node 350 is shown
exploded away from the pipe joint 300.
[0087] In FIG. 3, the pipe joint 300 is intended to represent a
joint of drill pipe. However, the pipe joint 300 may be any other
tubular body such as a joint of tubing or a portion of pipeline.
The pipe joint 300 has an elongated wall 310 defining an internal
bore 315. The bore 315 transmits drilling fluids such as an oil
based mud, or OBM, during a drilling operation. The pipe joint 300
has a box end 322 having internal threads, and a pin end 324 having
external threads.
[0088] As noted, an illustrative intermediate communications node
350 is shown exploded away from the pipe joint 300. The
communications node 350 is designed to attach to the wall 310 of
the pipe joint 300 at a selected location. In one aspect, selected
pipe joints 300 will each have an intermediate communications node
350 between the box end 322 and the pin end 324. In one
arrangement, the communications node 350 is placed immediately
adjacent the box end 322 or, alternatively, immediately adjacent
the pin end 324 of every joint of pipe. In another arrangement, the
communications node 350 is placed at a selected location along
every second or every third pipe joint 300 in a drill string 160.
In other aspects, more or less than one intermediate communications
node may be placed per joint 300.
[0089] The intermediate communications node 350 shown in FIG. 3 is
designed to be pre-welded onto the wall 310 of the pipe joint 300.
However, it is preferred that the communications node 350 be
configured to be selectively attachable to/detachable from a pipe
joint 300 by mechanical means at a well site. This may be done, for
example, through the use of clamps. Such a clamping system is shown
at 600 in FIG. 6, described more fully below. Alternatively, an
epoxy or other suitable acoustic couplant may be used for chemical
bonding. In any instance, the communications node 350 is an
independent wireless communications device that is designed to be
attached to an external surface of a well pipe, a coupling or a
liner.
[0090] There are several benefits to the use of an
externally-placed communications node that uses acoustic waves. For
example, such a node will not interfere with the flow of fluids
within the internal bore 315 of the pipe joint 300. Further,
installation and mechanical attachment can be readily assessed or
adjusted, as necessary. Because the acoustic signals are carried
principally by the wall 310 of the pipe joint 300 itself, the MFSK
data content is largely unaffected by the fluids in the pipe joint
300.
[0091] In FIG. 3, the intermediate communications node 350 includes
an elongated body 351. The body 351 supports one or more batteries,
shown schematically at 352. The body 351 also supports an
electro-acoustic transducer, shown schematically at 354. In a
preferred embodiment, the electro-acoustic transducer 354 may be a
two-way transceiver that can both receive and transmit acoustic
signals. The communications node 350 is intended to represent the
communications nodes 180 of FIG. 1, in one embodiment. The two-way
electro-acoustic transducer 354 in each node 180 allows acoustic
signals to be sent from node-to-node, either up the wellbore 150 or
down the wellbore 150.
[0092] Returning to FIG. 1, in operation, the sensor communications
node 184 is in electrical communication with the sensor 178. This
may be by means of a short wire, or by means of wireless
communication such as infrared or radio-frequency communication.
The sensor communications node 184 is configured to receive signals
from the sensor 178, wherein the signals represent a subsurface
condition such as position, temperature, pressure, resistivity, or
other formation data. Preferably, the sensor is contained in the
same housing as the sensor communications node 184. Indeed, the
sensor may be the same electro-acoustic transducer that enables the
telemetry communication.
[0093] The sensor communications node 184 transmits signals from
the sensor 178 as acoustic waves. The acoustic waves are preferably
at a frequency of between about 50 kHz and 500 kHz. The signals are
received by an intermediate communications node 180 that is closest
to the sensor communications node 184. That intermediate
communications node 180, in turn, will relay the signal on to a
next-closest node 180 so that acoustic waves indicative of the
downhole condition are sent from node-to-node. A last intermediate
communications node 180 transmits the signals acoustically to the
topside communications node 182.
[0094] Communication may be between adjacent nodes, or it may
occasionally skip a node depending on node spacing or communication
range. Preferably, communication is routed around any nodes that
are broken. Preferably, the number of nodes which transmit a
communication packet is fewer than the total number of nodes
between the sensor node and the topside node in order to conserve
battery power and extend the operational life of the network.
[0095] The well site 100 of FIG. 1 also shows a receiver 190. The
receiver 190 comprises a processor 192 that receives signals sent
from the topside communications node 182. The signals may be
received through a wire (not shown) such as a co-axial cable, a
fiber optic cable, a USB cable, or other electrical or optical
communications wire. Alternatively, the receiver 190 may receive
signals from the topside communications node 182 wirelessly through
a modem, a transceiver or other wireless communications link. The
receiver 190 preferably receives electrical signals via a so-called
Class I, Division 1 conduit, that is, a housing for wiring that is
considered acceptably safe in an explosive environment. In some
applications, radio, infrared or microwave signals may be
utilized.
[0096] In any event, the processor 192 may be incorporated into a
computer having a screen. The computer may have a separate keyboard
194, as is typical for a desk-top computer, or an integral keyboard
as is typical for a laptop or a personal digital assistant. In one
aspect, the processor 192 is part of a multi-purpose "smart phone"
having specific "apps" and wireless connectivity.
[0097] It is noted that data may be sent along the nodes not only
from the sensor 178 up to the receiver 190, but also from the
receiver 190 down to the sensor 178. This transmission may be of
benefit in the event that the operator wishes to make a change in
the way the sensor 178 is functioning. This is also of benefit when
the sensor 178 is actually another type of device, such as an
inflow control device that opens, closes or otherwise actuates in
response to a signal from the surface 101.
[0098] FIG. 1 demonstrates the use of a wireless data telemetry
system in connection with a drilling operation. However, the
wireless downhole telemetry system may also be used for a completed
well.
[0099] FIG. 2 is a cross-sectional view of an illustrative well
site 200. The well site 200 includes a wellbore 250 that penetrates
into a subsurface formation 255. The wellbore 250 has been
completed as a cased-hole completion for producing hydrocarbon
fluids. The well site 200 also includes a well head 260. The well
head 260 is positioned at an earth surface 201 to control and
direct the flow of formation fluids from the subsurface formation
255 to the surface 201.
[0100] Referring first to the well head 260, the well head 260 may
be any arrangement of pipes or valves that receive reservoir fluids
at the top of the well. In the arrangement of FIG. 2, the well head
260 is a so-called Christmas tree. A Christmas tree is typically
used when the subsurface formation 255 has enough in situ pressure
to drive production fluids from the formation 255, up the wellbore
250, and to the surface 201. The illustrative well head 260
includes a top valve 262 and a bottom valve 264. In some contexts,
these valves are referred to as "master fracture valves." Other
valves may also be used.
[0101] It is understood that rather than using a Christmas tree,
the well head 260 may alternatively include a motor (or prime
mover) at the surface 201 that drives a pump. The pump, in turn,
reciprocates a set of sucker rods and a connected positive
displacement pump (not shown) downhole. The pump may be, for
example, a rocking beam unit or a hydraulic piston pumping unit.
Alternatively still, the well head 260 may be configured to support
a string of production tubing having a downhole electric
submersible pump, a gas lift valve, or other means of artificial
lift (not shown). The present inventions are not limited by the
configuration of operating equipment at the surface unless
expressly noted in the claims.
[0102] Referring next to the wellbore 250, the wellbore 250 has
been completed with a series of pipe strings, referred to as
casing. First, a string of surface casing 210 has been cemented
into the formation. Cement is shown in an annular bore between the
bore wall 215 of the wellbore 250 and the casing 210. The surface
casing 210 has an upper end in sealed connection with the lower
master valve 264.
[0103] Next, at least one intermediate string of casing 220 is
cemented into the wellbore 250. The intermediate string of casing
220 is in sealed fluid communication with the upper master valve
262. Cement is again shown in a bore 215 of the wellbore 250. The
combination of the casing strings 210, 220 and the cement sheath in
the bore 215 strengthens the wellbore 250 and facilitates the
isolation of formations behind the casing 210, 220.
[0104] It is understood that a wellbore 250 may, and typically
will, include more than one string of intermediate casing. Some of
the intermediate casing strings may be only partially cemented into
place, depending on regulatory requirements and the presence of
migratory fluids in any adjacent strata.
[0105] Finally, a production liner 230 is provided. The production
liner 230 is hung from the intermediate casing string 230 using a
liner hanger 232. A portion of the production liner 230 may
optionally be cemented in place. The liner is a string of casing
that is not tied back to the surface 201.
[0106] The production liner 230 has a lower end 234 that extends
substantially to an end 254 of the wellbore 250. For this reason,
the wellbore 250 is said to be completed as a cased-hole well.
Those of ordinary skill in the art will understand that for
production purposes, the liner 230 may be perforated or may include
sections of slotted liner to create fluid communication between a
bore 235 of the liner 230 and the surrounding rock matrix making up
the subsurface formation 255.
[0107] As an alternative, portions of the liner 230 may include
joints of sand screen (not shown). The use of sand screens with
gravel packs allows for greater fluid communication between the
bore 235 of the liner 230 and the surrounding rock matrix while
still providing support for the wellbore 250. The present
inventions are not limited by the nature of the completion unless
expressly so stated in the claims.
[0108] The wellbore 250 also includes a string of production tubing
240. The production tubing 240 extends from the well head 260 down
to the subsurface formation 255. In the arrangement of FIG. 2, the
production tubing 240 terminates proximate an upper end of the
subsurface formation 255. A production packer 242 is provided at a
lower end of the production tubing 240 to seal off an annular
region 245 between the tubing 240 and the surrounding production
liner 230. However, the production tubing 240 may extend closer to
the end 234 of the liner 230.
[0109] It is also noted that the bottom end 234 of the production
liner 230 is completed substantially horizontally within the
subsurface formation 255. This is a common orientation for wells
that are completed in so-called "tight" or "unconventional"
formations. However, the present inventions have equal utility in
vertically completed wells or in multi-lateral deviated wells.
Further, the communications nodes 280 themselves may be used in
other tubular constructions such as above-ground, under-ground, or
below water pipelines.
[0110] The illustrative well site 200 also includes one or more
sensors 290. Here, the sensors 290 are placed at the depth of the
subsurface formation 255. The sensors 290 may be, for example,
pressure sensors, flow meters, electrical impedance sensors,
resistivity sensors, chemical sensors, pH sensors, or temperature
sensors. A pressure sensor may be, for example, a sapphire gauge or
a quartz gauge. Sapphire gauges are preferred as they are
considered more rugged for the high-temperature downhole
environment. Alternatively, the sensors may be microphones for
detecting ambient noise, or geophones (such as a tri-axial
geophone) for detecting the presence of micro-seismic activity.
Alternatively still, the sensors may be fluid flow measurement
devices such as a spinners, or fluid composition sensors.
[0111] It is desirable to send signals about the downhole condition
back to a receiver at the surface 201. As with the well site 100 of
FIG. 1, the well site 200 of FIG. 2 includes a telemetry system
that utilizes a series of novel communications nodes. Here, the
communications nodes are placed along the outer diameter of the
string of production tubing 240. These nodes allow for the high
speed transmission of wireless signals based on the in situ
generation of acoustic waves.
[0112] The nodes first include a topside communications node 282.
The topside communications node 282 is placed closest to the
surface 201. The topside node 282 is configured to receive and/or
transmit signals. The topside communications node 282 should be
placed on the wellhead or next to the surface along the uppermost
joint of casing 210.
[0113] The nodes also include a sensor communications node 284. The
sensor communications node 284 is placed closest to the sensors
290. The sensor communications node 284 is configured to
communicate with the downhole sensor 290, and then send a wireless
signal using acoustic waves.
[0114] Finally, the nodes include a plurality of intermediate
communications nodes 280. Each of the intermediate communications
nodes 280 resides between the sensor communications node 284 and
the topside communications node 282. The intermediate
communications nodes 280 are configured to receive and then relay
acoustic signals along the length of the tubing string 240.
Preferably, the intermediate nodes 280 utilize two-way
electro-acoustic transducers to receive and relay mechanical waves.
The intermediate communications nodes 280 preferably reside along
an outer diameter of the casing strings 210, 220, 230.
[0115] In operation, the sensor communications node 284 is in
electrical communication with the (one or more) sensors 290. This
may be by means of a short wire, or by means of wireless
communication such as infrared or radio waves. The sensor
communications node 284 is configured to receive signals from the
sensors 290, wherein the signals represent a subsurface condition
such as temperature or pressure. Alternatively, sensor 290 may be
contained in the housing of communications node 284.
[0116] The sensor communications node 284 transmits signals from
the sensors 290 as acoustic waves. The acoustic waves are
preferably at a frequency band of about 50 to 100 kHz. The signals
are received by an intermediate communications node 280. That
intermediate communications node 280, in turn, will relay the
signal on to another intermediate communications node so that
acoustic waves indicative of the downhole condition are sent from
node-to-node. A last intermediate communications node 280 transmits
the signals to the topside node 282.
[0117] The well site 200 of FIG. 2 shows a receiver 270. The
receiver 270 comprises a processor 272 that receives signals sent
from the topside communications node 284. The receiver 270 may
include a screen and a keyboard 274 (either as a keypad or as part
of a touch screen). The receiver 270 may also be an embedded
controller with neither screen nor keyboard which communicates with
a remote computer via cellular modem or telephone lines.
[0118] The signals may be received by the processor 272 through a
wire (not shown) such as a co-axial cable, a fiber optic cable, a
USB cable, or other electrical or optical communications wire.
Alternatively, the receiver 270 may receive the final signals from
the topside node 282 wirelessly through a modem or transceiver. The
receiver 270 preferably receives electrical signals via a so-called
Class I, Division 1 conduit, that is, a wiring conduit that is
considered acceptably safe in an explosive environment.
[0119] FIGS. 1 and 2 present illustrative wellbores 150, 250 having
a downhole telemetry system that uses a series of acoustic
transducers. In each of FIGS. 1 and 2, the top of the drawing page
is intended to be toward the surface and the bottom of the drawing
page toward the well bottom. While wells commonly are completed in
substantially vertical orientation, it is understood that wells may
also be inclined and even horizontally completed. When the
descriptive terms "up" and "down" or "upper" and "lower" or similar
terms are used in reference to a drawing, they are intended to
indicate relative location on the drawing page, and not necessarily
orientation in the ground, as the present inventions have utility
no matter how the wellbore is orientated.
[0120] In each of FIGS. 1 and 2, the communications nodes 180, 280
are specially designed to withstand the same corrosive and
environmental conditions (i.e., high temperature, high pressure) of
a wellbore 150 or 250 as the casing strings, drill string, or
production tubing. To do so, it is preferred that the
communications nodes 180, 280 include sealed steel housings for
holding the electronics.
[0121] FIG. 4A is a perspective view of a communications node 400
as may be used in the wireless data transmission systems of FIG. 1
or FIG. 2 (or other wellbore), in one embodiment. The
communications node 400 may be an intermediate communications node
that is designed to provide two-way communication using a
transceiver within a novel downhole housing assembly. FIG. 4B is a
cross-sectional view of the communications node 400 of FIG. 4A. The
view is taken along the longitudinal axis of the node 400. The
communications node 400 will be discussed with reference to FIGS.
4A and 4B, together.
[0122] The communications node 400 first includes a housing 410.
The housing 410 is designed to be attached to an outer wall of a
joint of wellbore pipe, such as the pipe joint 300 of FIG. 3. Where
the wellbore pipe is a carbon steel pipe joint such as drill pipe,
casing or liner, the housing is preferably fabricated from carbon
steel. This metallurgical match avoids galvanic corrosion at the
coupling.
[0123] The housing 410 is dimensioned to be strong enough to
protect internal electronics. In one aspect, the housing 410 has an
outer wall 412 that is about 0.2 inches (0.51 cm) in thickness. A
bore 405 is formed within the wall 412. The bore 405 houses the
electronics, shown in FIG. 4B as a battery 430 and a power supply
wire 435. An example of a battery suitable for the anticipated
environment is one or more lithium primary cells.
[0124] The electronics of FIG. 4B also include a transceiver 440
and a circuit board 445. The circuit board 445 will preferably
include a micro-processor or electronics module that processes
acoustic signals. An electro-acoustic transducer 442 is provided to
convert acoustical energy to electrical energy (or vice-versa) and
is coupled with outer wall 412 on the side attached to the tubular
body. The transducer 442 is in electrical communication with at
least one sensor 432.
[0125] It is noted that in FIG. 4B, the sensor 432 resides within
the housing 410 of the communications node 400. However, as noted,
the sensor 432 may reside external to the communications node 400,
such as above or below the node 400 along the wellbore. In FIG. 4C,
a dashed line is provided showing an extended connection between
the sensor 432 and the electro-acoustic transducer 442.
[0126] The transceiver 440 will receive an acoustic telemetry
signal. In one preferred embodiment, the acoustic telemetry data
transfer is accomplished using multiple frequency shift keying
(MFSK). Any extraneous noise in the signal is moderated by using
well-known conventional analog and/or digital signal processing
methods. This noise removal and signal enhancement may involve
conveying the acoustic signal through a signal conditioning circuit
using, for example, a bandpass filter.
[0127] The transceiver will also produce acoustic telemetry
signals. In one preferred embodiment, an electrical signal is
delivered to an electromechanical transducer, such as through a
driver circuit. In a preferred embodiment, the transducer is the
same electro-acoustic transducer that originally received the MFSK
data. The signal generated by the electro-acoustic transducer then
passes through the housing 410 to the tubular body (such as
production tubing 240), and propagates along the tubular body to
other communication nodes. The re-transmitted signal represents the
same sensor data originally transmitted by sensor communications
node 284. In one aspect, the acoustic signal is generated and
received by a magnetostrictive transducer comprising a coil wrapped
around a core as the transceiver. In another aspect, the acoustic
signal is generated and received by a piezo-electric ceramic
transducer. In either case, the electrically encoded data are
transformed into a sonic wave that is carried through the wall of
the tubular body in the wellbore.
[0128] The communications node 400 optionally has a protective
outer layer 425. The protective outer layer 425 resides external to
the wall 412 and provides an additional thin layer of protection
for the electronics. The communications node 400 is also preferably
fluid sealed with the housing 410 to protect the internal
electronics. Additional protection for the internal electronics is
available using an optional potting material.
[0129] The communications node 400 also optionally includes a shoe
500. More specifically, the node 400 includes a pair of shoes 500
disposed at opposing ends of the wall 412. Each of the shoes 500
provides a beveled face that helps prevent the node 400 from
hanging up on an external tubular body or the surrounding earth
formation, as the case may be, during run-in or pull-out. The shoes
500 may have a protective outer layer 422 and an optional
cushioning material 424 (shown in FIG. 4A) under the outer layer
422.
[0130] FIGS. 5A and 5B are perspective views of an illustrative
shoe 500 as may be used on an end of the communications node 400 of
FIG. 4A, in one embodiment. In FIG. 5A, the leading edge or front
of the shoe 500 is seen, while in FIG. 5B the back of the shoe 500
is seen.
[0131] The shoe 500 first includes a body 510. The body 510
includes a flat under-surface 512 that butts up against opposing
ends of the wall 412 of the intermediate communications node
400.
[0132] Extending from the under-surface 512 is a stem 520. The
illustrative stem 520 is circular in profile. The stem 520 is
dimensioned to be received within opposing recesses 414 of the wall
412 of the node 400.
[0133] Extending in an opposing direction from the body 510 is a
beveled surface 530. As noted, the beveled surface 530 is designed
to prevent the communications node 400 from hanging up on an object
during run-in into a wellbore.
[0134] Behind the beveled surface 530 is a flat (or slightly
curved) surface 535. The flat surface 535 is configured to extend
along the drill string 160 (or other tubular body) when the
communications node 400 is attached along the tubular body. In one
aspect, the shoe 500 includes an optional shoulder 515. The
shoulder 515 creates a clearance between the flat surface 535 and
the tubular body opposite the stem 520.
[0135] The shoes 500 are preferably attached to the body 410 of the
node 400 by welding. Welding preferably takes place before the
nodes are delivered to the well site to avoid the presence of
sparks. In another arrangement, the shoes 500 are applied through a
glue, or by using a threaded connection with gaskets.
[0136] In one arrangement, the communications nodes 400 with the
shoes 500 are welded onto an inner or outer surface of the tubular
body, such as wall 310 of the pipe joint 300. More specifically,
the body 410 of the respective communications nodes 400 are welded
onto the wall of the tubular body. In some cases, it may not be
feasible or desirable to pre-weld the communications nodes 400 onto
pipe joints before delivery to a well site. Therefore, it is
desirable to utilize a clamping system that allows a drilling or
service company to mechanically connect/disconnect the
communications nodes 400 along a tubular body as the tubular body
is being run into a wellbore.
[0137] FIG. 6 is a perspective view of a communications node system
600 of the present invention, in one embodiment. The communications
node system 600 utilizes a pair of clamps 610 for mechanically
connecting an intermediate communications node 400 onto a tubular
body 630.
[0138] The system 600 first includes at least one clamp 610. In the
arrangement of FIG. 6, a pair of clamps 610 is used. Each clamp 610
abuts the shoulder 515 of a respective shoe 500. Further, each
clamp 610 receives the base 535 of a shoe 500. In this arrangement,
the base 535 of each shoe 500 is welded onto an outer surface of
the clamp 610. In this way, the clamps 610 and the communications
node 400 become an integral tool.
[0139] The illustrative clamps 610 of FIG. 6 include two arcuate
sections 612, 614. The two sections 612, 614 pivot relative to one
another by means of a hinge. Hinges are shown in phantom at 615. In
this way, the clamps 610 may be selectively opened and closed.
[0140] Each clamp 610 also includes a fastening mechanism 620. The
fastening mechanisms 620 may be any means used for mechanically
securing a ring onto a tubular body, such as a hook or a threaded
connector. In the arrangement of FIG. 6, the fastening mechanism is
a threaded bolt 625. The bolt 625 is received through a pair of
rings 622, 624. The first ring 622 resides at an end of the first
section 612 of the clamp 610, while the second ring 624 resides at
an end of the second section 614 of the clamp 610. The threaded
bolt 625 may be tightened by using, for example, one or more
washers (not shown) and threaded nuts 627.
[0141] In operation, a clamp 610 is placed onto the tubular body
630 by pivoting the first 612 and second 614 arcuate sections of
the clamp 610 into an open position. The first 612 and second 614
sections are then closed around the tubular body 630, and the bolt
625 is run through the first 622 and second 624 receiving rings.
The bolt 625 is then turned relative to the nut 627 in order to
tighten the clamp 610 and connected communications node 400 onto
the outer surface of the tubular body 630. Where two clamps 610 are
used, this process is repeated.
[0142] The tubular body 630 may be, for example, a drill string
such as the illustrative drill string 160 of FIG. 1. Alternatively,
the tubular body 630 may be a string of production tubing such as
the tubing 240 of FIG. 2. In any instance, the tubular body 630 is
ideally fabricated from a steel material having a thickness which
contributes to broadening a mechanical response of the
electro-acoustic transducer in the intermediate communications node
400, where the mechanical resonance is at a frequency contained
within the frequency band used for telemetry.
[0143] In one aspect, the communications node 400 is about 12 to 20
inches (0.30 to 0.51 meters) in length as it resides along the
tubular body 630. Specifically, the housing 410 of the
communications node may be 8 to 16 inches (0.20 to 0.41 meters) in
length, and each opposing shoe 500 may be 2 to 5 inches (0.05 to
0.13 meters) in length. Further, the communications node 400 may be
about 1 inch in width and 1 inch in height. The housing 410 of the
communications node 400 may have a concave profile that generally
matches the radius of the tubular body 630.
[0144] A method for transmitting data in a wellbore is also
provided herein. The method preferably employs the communications
node 400 and the clamping system 600 of FIG. 6.
[0145] FIG. 7 provides a flow chart for a method 700 of
transmitting data in a wellbore. The method 700 uses a plurality of
communications nodes situated along a tubular body to accomplish a
wireless transmission of data along the wellbore. The wellbore
penetrates into a subsurface formation, allowing for the
communication of a wellbore condition at the level of the
subsurface formation up to the surface.
[0146] The method 700 first includes running a tubular body into
the wellbore. This is shown at Box 710. The tubular body is formed
by connecting a series of pipe joints end-to-end. The pipe joints
are fabricated from a steel material that is suitable for
conducting an acoustical signal.
[0147] The method 700 also includes placing at least one sensor
along the wellbore at a depth of the subsurface formation. This is
provided at Box 720. Here, the sensor may be a pressure sensor, a
temperature sensor, an inclinometer, a logging tool, a resistivity
sensor, a vibration sensor, a fluid density sensor, a fluid
identification sensor, a fluid flow measurement device (such as a
so-called "spinner") or other sensor. The sensor may reside, for
example, along a string of drill pipe as part of a rotary steerable
drilling system. Alternatively, the sensor may reside along a
string of casing within a wellbore. Alternatively still, the sensor
may reside along a string of production tubing or a joint of sand
screen.
[0148] The method 700 further includes attaching a sensor
communications node to the tubular body. This is seen at Box 730.
The sensor communications node may be placed either inside or
outside of a tubular body. The sensor communications node is then
placed at the depth of the subsurface formation. The sensor
communications node is in communication with the at least one
sensor. This is preferably a short wired connection or a connection
through a circuit board. The sensor communications node is
configured to receive signals from the at least one sensor. The
signals represent a subsurface condition such as temperature,
pressure, pipe strain, fluid flow or fluid composition, or
geology.
[0149] Preferably, the at least one sensor resides within the
housing for the sensor communications node. The sensor
communications node may alternatively be configured to use the
electro-acoustic transducer as a sensor.
[0150] The method 700 also provides for attaching a topside
communications node to the tubular body. This is indicated at Box
740. The topside communications node is attached to the tubular
body proximate the surface. In one aspect, the topside
communications node is connected to the well head, which for
purposes of the present disclosure may be considered part of the
tubular body.
[0151] The method 700 further comprises attaching a plurality of
intermediate communications nodes to the tubular body. This is
shown at Box 750. The intermediate communications nodes reside in
spaced-apart relation along the tubular body between the sensor
communications node and the topside communications node. The
intermediate communications nodes are configured to receive and
transmit acoustic waves from the sensor communications node to the
topside node. Each acoustic signal represents a packet of data
comprised of a collection of separate tones.
[0152] In one aspect, piezo wafers or other piezoelectric elements
are used to receive and transmit acoustic signals. In another
aspect, multiple stacks of piezoelectric crystals or
magnetostrictive devices are used. Signals are created by applying
electrical signals of an appropriate frequency across one or more
piezoelectric crystals, causing them to vibrate at a rate
corresponding to the frequency of the desired acoustic signal. In
another aspect, the transducers are rotated within the housing
relative to the external tubular to generate acoustic waves that
propagate along the tubular with minimum loss of amplitude or
around the tubular with maximum sensitivity to parameters of
interest of the cement sheath.
[0153] In the method 700, each of the intermediate communications
nodes has an independent power source. The independent power source
may be, for example, batteries or a fuel cell. In addition, each of
the intermediate communications nodes has a transducer. The
transducer is preferably an electro-acoustic transducer with an
associated transceiver that is designed to receive the acoustic
waves and produce acoustic waves.
[0154] In one aspect, the data transmitted between the nodes is
represented by acoustic waves according to a multiple frequency
shift keying (MFSK) modulation method. Although MFSK is well-suited
for this application, its use as an example is not intended to be
limiting. It is known that various alternative forms of digital
data modulation are available, for example, frequency shift keying
(FSK), multi-frequency signaling (MF), phase shift keying (PSK),
pulse position modulation (PPM), and on-off keying (OOK). In one
embodiment, every 4 bits of data are represented by selecting one
out of sixteen possible tones for broadcast.
[0155] Acoustic telemetry along tubulars is characterized by
multi-path or reverberation which persists for a period of
milliseconds. As a result, a transmitted tone of a few milliseconds
duration determines the dominant received frequency for a time
period of additional milliseconds. Preferably, the communication
nodes determine the transmitted frequency by receiving or
"listening to" the acoustic waves for a time period corresponding
to the reverberation time, which is typically much longer than the
transmission time. The tone duration should be long enough that the
frequency spectrum of the tone burst has negligible energy at the
frequencies of neighboring tones, and the listening time must be
long enough for the multipath to become substantially reduced in
amplitude. In one embodiment, the tone duration is 2 ms, then the
transmitter remains silent for 48 milliseconds before sending the
next tone. The receiver, however, listens for 2+48=50 ms to
determine each transmitted frequency, utilizing the long
reverberation time to make the frequency determination more
certain. Beneficially, the energy required to transmit data is
reduced by transmitting for a short period of time and exploiting
the multi-path to extend the listening time during which the
transmitted frequency may be detected.
[0156] In one embodiment, an MFSK modulation is employed where each
tone is selected from an alphabet of 16 tones, so that it
represents 4 bits of information. With a listening time of 50 ms,
for example, the data rate is 80 bits per second.
[0157] The tones are selected to be within a frequency band where
the signal is detectable above ambient and electronic noise at
least two nodes away from the transmitter node so that if one node
fails, it can be bypassed by transmitting data directly between its
nearest neighbors above and below. In one example, the tones can be
approximately evenly spaced in frequency but the tones may be
spaced within a frequency band from about 50 kHz to about 500 kHz.
More preferably, the tones are spaced within a frequency band
approximately 20 kHz wide centered around 100 kHz. The tones are
preferably contiguous.
[0158] In one aspect, the tubular body is a drill string. In this
instance, each of the intermediate communications nodes is
preferably placed along an outer diameter of pipe joints making up
the drill string. In another aspect, the tubular body is a casing
string. In this instance, each of the intermediate communications
nodes is placed along an outer surface of pipe joints making up the
casing string. In yet another embodiment, the tubular body is a
production string such as tubing. In this instance, each of the
intermediate communications nodes may be placed along an outer
diameter of pipe joints making up the production string.
[0159] In one aspect, the method 700 further includes transmitting
a signal from the topside communications node to a receiver. This
is shown at Box 760. The topside communications node also comprises
an independent power source, meaning that it does not also supply
power to any other intermediate or sensor communications node. The
independent power source may be either internal to or external to
the topside communications node. Further, the topside
communications node has an electro-acoustic transducer designed to
receive the acoustic waves from one or more of the plurality of
intermediate communications nodes, and transmit acoustic waves to
the receiver as a new signal. Further, the topside node includes a
magnetically activated reed switch or other means to silence radio
transmissions from the node without opening the Class 1 Div 1
housing.
[0160] The communication signal between the topside communications
node and the receiver may be either a wired electrical signal or a
wireless radio transmission. Alternatively, the signal may be an
optical signal. In any instance, the signal represents a subsurface
condition as transmitted by the sensor in the subsurface formation.
The signals are received by the receiver, which has data
acquisition capabilities. The receiver may employ either volatile
or non-volatile memory. The data may then be analyzed at the
surface.
[0161] As can be seen, a novel downhole telemetry system is
provided, as well as a novel method for the wireless transmission
of information using a plurality of data transmission nodes. The
re-transmission process that takes place along the nodes not only
provides a mechanism to remove signal noise, but also increases the
signal amplitude. In the system, the repertoire of frequencies used
by the nodes for communication, the amplitude of each frequency,
the time duration for which each frequency is transmitted, and the
time between signals may be optimized to find a balance between
data transmission rate and energy used in data transmission.
[0162] In one embodiment, the tubular body is made up of joints of
pipe that form a casing string. Some of the joints of pipe and the
connected communications nodes may be surrounded by a cement
sheath. Acoustic signals may be sent as a collection of tones, or
message packets, through the casing string during drilling or
during later production operations. The acoustic signals may also
be used to interrogate cement properties such as density and
porosity.
[0163] In one aspect, each communications node 280 will listen for
one or more tones of a specific frequency that, individually or
collectively, indicate the start of a message packet. This enables
an asynchronous network communication.
[0164] FIG. 8 presents an example of a message packet 800. In this
example, the message packet first consists of one or more start
tones 805 The start tone(s) 805 is followed by one or more tones
810 identifying a next node to receive the message packet 800. The
next tone 810 is followed by one or more tones 815 identifying the
final node to receive the message packet 800.
[0165] One or more additional tones 820 are provided in FIG. 8 that
follow the final tone 815. The tones 820 indicate the length of the
data to be included in the message packet 800. The data length
tones 820 are then followed by a corresponding number of data tones
825. These tones 825 represent the data portion of the message
packet 800. The data portion (tones 825) of the message packet 800
typically contains a command 827 followed by one or more associated
related parameters 829.
[0166] The message packet 800 finally includes one or more tones
830 used by the receiving node to validate a correct receipt of the
message packet 800. This may be done via a checksum calculation, a
cyclic redundancy check (CRC), or some other means of error
detection.
[0167] In operation, a communications node creates and transmits a
message packet 800 with the start tone 805. The next node tones 810
identified in the packet 800 receives the message packet 800,
replaces the next node tone 810 in the message packet 800 with the
identifier for a communications node typically closer to the final
node identified in the message packet 800 by final tone 815. The
communications node then transmits the changed message packet. This
process continues until the communications node receiving the
message packet 800 is the final node as identified in the message
packet 800. The final node typically acts on the message packet 800
and transmits a reply in the form of a new message packet
identifying a different final node.
[0168] After sending a message packet 800, the transmitting node
preferably listens for the receiving node to transmit the new
message packet. The new message packet typically represents a
modified version of the original message packet, or a reply to the
original message packet. Note that the new message packet is not
necessarily addressed to the node that originated the message. If
the transmitting node does not hear the receiving node transmit a
new message packet, it resends the original message packet to the
receiving node. This protocol facilitates detection of a lost
message packet (a message packet transmitted but not received) and
increases the likelihood of successful transmission of a message
packet to a receiving node.
[0169] In order to change communication specifications such as
tonal frequencies, tone transmission duration, waiting time between
tones, and tonal amplitude, a "bi-lingual" command may be sent.
This command enables pairs of nodes to temporarily transmit and
receive using both the original communication protocol and an
adjusted communication protocol. If only a subset of nodes is to be
changed, this bi-lingual capability must be maintained at each
interface. This procedure requires the simultaneous use of two sets
of communication specifications.
[0170] In one aspect, each communications node will alternate
between being awake (an awake state) and being asleep (a sleep
state). In the awake state, a node is able to communicate; in the
sleep state, the node is unable to transmit, although it is able to
collect data. In the sleep state, the node is periodically able to
receive a wakeup packet causing it to return to the awake state. In
the sleep state, the node is also periodically able to receive a
wait stub, causing it to listen for an additional amount of time
for another wait stub or for a wakeup packet. The purpose of
placing the node into sleep state is to place the electronics in a
state of low power consumption. This multi-state capability, in
turn, extends battery life.
[0171] In one embodiment, each communications node will operate in
one of two states of operation: In the first state, called the
sleep state, the node will sleep for a first period of time
(typically a few minutes) and then wake up for a second period of
time (typically a few seconds) to listen for incoming wait stubs or
wakeup packets. If no wait stubs or wakeup packet is received, the
node will return to its sleep state. This cycle will be repeated
during the sleep state. In the second state, called the awake
state, the node is always awake. A node will change state if it
receives a message packet (while awake) instructing it to change
state.
[0172] Preferentially, the communication protocol defines a wait
stub which is short in duration compared to typical message packets
that may be sent. FIG. 9 is an example of a sleep-to-wake
transition using wait stubs 905 and a wakeup packet 910. In FIG. 9,
two nodes are shown as being in acoustic communication. The two
nodes represent a servicing node 935 and a target node 940. The
target node 940 is initially in a sleep state 915 until being
awoken into its awake state 930.
[0173] It can be seen that the servicing node 935 has transmitted a
series of wake stubs 905 to the target node 940. The wait stubs 905
cause the target node 940, which is periodically awake 920 while in
its sleep state 915, to remain awake temporarily for an additional
period of time 925 (typically 15 seconds). During the temporarily
awake times 925, additional wait stubs 905 may be received, causing
the target node 940 to stay awake for still additional periods of
time 925. A wakeup packet 910 may then be sent from the servicing
node 935, instructing the target node 940 to switch to its awake
state 930. In this state, the target node 940 will remain
awake.
[0174] It is noted that the use of the wait stubs 905 to produce
additional wake times 925 wherein a full length wakeup packet 910
may be received enables the periodic awake time while in sleep
state 920 to be shorter. This, in turn, reduces the power
consumption as compared to a protocol where the periodic awake time
920 in sleep state is long enough to receive a full wakeup packet
910. The servicing node 935 may transmit wait stubs 905 to the
intended target node 940 at regular intervals to cause the target
node 940 to awaken sooner and more reliably than would have been
otherwise possible. Likewise, a sleeping target node 940 does not
need to send transmissions to indicate when it is able to receive a
wakeup packet 910, thereby saving the energy otherwise needed to
transmit such transmissions.
[0175] In one aspect, each communications node is optionally
configured to transmit a message packet comprising a collection 800
of tones used in acoustic telemetry, such as 16 tones, and
determine the amplitudes and reverberation times of each tone when
receiving such a packet 800. The node can preferably use this
information to minimize energy usage and maximize data rate while
maintaining reliable communication. In one embodiment, a packet
consisting of all of the tones of interest is sent directly (with
no relay nodes) from a transmitter node to a receiver node. The
receiving node and the transmitting node together form a pair of
nodes.
[0176] The receiving node detects the received amplitude and
reverberation time for each tone in the packet. The receiving node
then sends the same data back to the transmitting node. The
transmitting node adjusts its transmit energy so that the weakest
tone will be received at the weakest signal amplitude for which
communication is still robust. The transmitting node may further
reduce the waiting time between tones to the smallest time required
for the reverberation to substantially subside. The transmitting
node may also instruct the receiving node that it has made these
changes in the communication protocol. In some cases, the results
of such an amplitude assessment may conclude that tonal amplitudes
at one band edge are weaker than all the other tones. Such a
finding may suggest a manual or automated shift in the frequency
band for the tonal alphabet. The aforementioned bi-lingual
capability can facilitate a frequency band shift.
[0177] In one embodiment, each communications node has a query
capability so that only logged data which meet certain criteria is
retrieved, for example, retrieving only the measurements from a
particular sensor such as a thermistor or strain gauge or acoustic
transducer, or retrieving only measurements which were collected
within a particular time window, or retrieving only every Nth
measurement where N is an integer greater than 1. This can reduce
the necessary volume of data transmission from a servicing node,
which can reduce the node's energy consumption and extend the
node's effective life.
[0178] In another aspect, each node is configured to automatically
discharge its batteries when certain criteria are met. In this way,
consuming reactants in the battery that might otherwise create a
risk to the node electronics or node housing by remaining unreacted
within the battery for an extended period of time are removed. For
example, a node may be configured to discharge lithium primary
batteries on a certain date and time, thereby reacting the
remaining lithium metal within the batteries and transforming it
into more chemically stable compounds. The criteria for discharging
the batteries include reaching a certain date and time, the passing
of a certain period of time since the last communication with the
node, or observing a certain sensor measurement in a certain range,
such as a temperature that exceeds some threshold, or observing a
combination of sensor measurements that indicate that external or
internal conditions have occurred that make it prudent to discharge
the batteries.
[0179] Various forms of error correction may also be applied in the
acoustic telecommunications network. An example of one form is
presented here to account for the irregularity of the frequency
response of acoustic transducers across the band used for
telemetry. In this respect, some tones are produced and received
more weakly than others. Successful telemetry requires that even
the weakest tone be audible amidst the ambient noise. It is
typically necessary to increase the transmit signal amplitudes of
all tones until the very weakest tone becomes audible. As an
alternative, each communications node may employ a sequence of
redundant tones, with at least two of the tones differing in
frequency, to represent each data value. By using a sequence of two
or more redundant tones for each data value, the system can still
communicate if one or more of the redundant tones happens to be
particularly weak. The node preferentially combines detection
statistics for each group of redundant tones to enable successful
communication even in cases for which all the redundant tones in a
group are particularly weak. Both redundancy and pooling of
detection statistics make the communication more reliable.
[0180] In one embodiment, the electro-acoustic telemetry network of
the present invention uses a sliding alphabet as a method of
reducing adverse impact of reverberation during transmission and
reception of message packets 800. One way such adverse impact could
occur involves the transmission of two successive tones that happen
to be identical in frequency. Such a circumstance may lead to
ambiguity for the receiving node 940 in distinguishing between a
distinct second tone as opposed to reverberant noise from the first
tone.
[0181] FIG. 10 presents an example of the use of a sliding alphabet
in an multi-frequency shift keying (MFSK) process. In this figure,
a message packet is shown in four forms. The first form is shown at
1050; this is the sending node's original acoustic message. The
second form is shown at 1060; this is the sending node's modified
message. The third form is shown at 1070; this is the acoustic
message received by the target node. Finally, the fourth form is
shown at 1080; this is the message as deconstructed by the target
node.
[0182] In the example of FIG. 10, messages are acoustic signals
sent by a transceiver along a tubular body that represent a logical
alphabet. The logical alphabet consists of integer values between,
for example, 0 and 15, inclusive. This means that the message
packets consist of a sequence of logical alphabet values,
representing tones. In practice, each communications node in the
network is configured to associate the same set of distinct
frequencies with the same physical alphabet consisting of
consecutive integer values, beginning with "0." This will allow for
at least one excess value of the physical alphabet.
[0183] To transmit a message packet, a transmitting node iterates
through the message packet's constituent logical alphabet values
1050 from beginning to end of the message packet. In each case, the
transmitting node either transmits a physical alphabet value equal
to the logical alphabet value when the logical alphabet value is
less than the previously transmitted physical alphabet value, or
transmits a physical alphabet value equal to the logical alphabet
value +1 when the logical alphabet value is equal to or greater
than the previously transmitted physical alphabet value 1060. This
technique is one example of a sliding alphabet algorithm.
[0184] The receiving node deconstructs the received message packet
by combining the received physical alphabet values 1070 from
beginning to end of the message packet, in each case assigning a
logical alphabet value equal to the physical alphabet value when
the physical alphabet value is less than the previous physical
alphabet value, or assigning a logical alphabet value equal to the
physical alphabet value -1 when the physical alphabet value is
equal to or greater than the previous physical alphabet value 1080.
This deconstruction technique is one example of a complement to the
sliding alphabet algorithm.
[0185] It is noted that a sliding alphabet incorporates both an
algorithm and a complement to the algorithm. In essence, the
algorithm encodes the message packet while the complement to the
algorithm decodes a message packet encoded by that specific
algorithm. Thus, the algorithm is an encoder, while the complement
to the algorithm is a decoder.
[0186] In one embodiment, the method for modulating acoustic waves
comprises the steps of:
[0187] generating a first set of tones from a first
electro-acoustic transceiver, with each tone being associated with
a defined frequency, and with each tone being associated with a
logical alphabet value;
[0188] reviewing the first set of tones to determine if two
consecutive tones have the same logical alphabet value;
[0189] if two consecutive tones do have the same logical alphabet
value, modifying the first set of tones to provide that no two same
tones are sent consecutively, thereby generating a modified first
set of tones;
[0190] transmitting the modified first set of tones from the first
electro-acoustic transceiver;
[0191] receiving the modified first set of tones from the first
electro-acoustic transceiver at a second electro-acoustic
transceiver as a message packet;
[0192] reviewing the modified first set of tones; and
[0193] deconstructing the modified first set of tones back to its
original first set of tones.
[0194] In one aspect, the modifying step comprises determining
whether a tone in the first set of tones is equal to or greater
than an immediately preceding tone in the first set of tones and,
if a tone in the first set of tones is equal to or greater than an
immediately preceding tone in the first set of tones, increasing
the logical alphabet value by a defined alphabet value. In this
instance, the deconstruction step comprises determining whether a
tone in the modified first set of tones is greater than an
immediately preceding tone in the modified first set of tones and,
if a tone in the modified first set of tones is equal to or greater
than an immediately preceding tone in the modified first set of
tones, decreasing the logical alphabet value by the defined
alphabet value. Preferably, the defined alphabet value is a next
higher frequency. However, the defined alphabet value may be any
sum (such as x+2), any difference (such as x-2), or product (such
as x3), or any algebraic formula (such as x2-1).
[0195] In another aspect, the modifying step comprises determining
whether a tone in the first set of tones is equal to or less than
an immediately preceding tone in the first set of tones and, if a
tone in the first set of tones is equal to or less than an
immediately preceding tone in the first set of tones, decreasing
the logical alphabet value by a defined alphabet value. In this
instance, the deconstruction step comprises determining whether a
tone in the modified first set of tones is equal to or less than an
immediately preceding tone in the modified first set of tones and,
if a tone in the modified first set of tones is equal to or less
than an immediately preceding tone in the modified first set of
tones, increasing the logical alphabet value by the defined
alphabet value. Preferably, the defined alphabet value is a next
lower frequency.
[0196] In either instance, each of the first and second
electro-acoustic transceivers may reside either in a wellbore or
along a pipeline as part of a telemetry system.
[0197] While it will be apparent that the inventions herein
described are well calculated to achieve the benefits and
advantages set forth above, it will be appreciated that the
inventions are susceptible to modification, variation and change
without departing from the spirit thereof.
* * * * *