U.S. patent application number 13/735404 was filed with the patent office on 2014-07-10 for apparatus and method for communication between downhole components.
This patent application is currently assigned to Baker Hughes Incorporated. The applicant listed for this patent is Stanislav Wilhelm Forgang, Steven A. Morris, Shobha Sundar Ram. Invention is credited to Stanislav Wilhelm Forgang, Steven A. Morris, Shobha Sundar Ram.
Application Number | 20140192621 13/735404 |
Document ID | / |
Family ID | 51060848 |
Filed Date | 2014-07-10 |
United States Patent
Application |
20140192621 |
Kind Code |
A1 |
Ram; Shobha Sundar ; et
al. |
July 10, 2014 |
APPARATUS AND METHOD FOR COMMUNICATION BETWEEN DOWNHOLE
COMPONENTS
Abstract
A method of synchronization between downhole components
includes: generating a dual tone synchronization signal by a signal
generator in a first downhole component disposed in a borehole in
an earth formation, the dual tone signal including a first
constituent periodic signal having a first frequency f.sub.1 and a
second constituent periodic signal having a second frequency
f.sub.2 that is different from the first frequency; transmitting
the synchronization signal to a second downhole component disposed
in the borehole; receiving the synchronization signal by a signal
processor in the second downhole component, calculating a phase
difference between the first constituent signal and the second
constituent signal, and calculating a transmission delay based on
the phase difference; and synchronizing operation of the first and
second downhole components based on the delay.
Inventors: |
Ram; Shobha Sundar;
(Houston, TX) ; Morris; Steven A.; (Spring,
TX) ; Forgang; Stanislav Wilhelm; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Ram; Shobha Sundar
Morris; Steven A.
Forgang; Stanislav Wilhelm |
Houston
Spring
Houston |
TX
TX
TX |
US
US
US |
|
|
Assignee: |
Baker Hughes Incorporated
Houston
TX
|
Family ID: |
51060848 |
Appl. No.: |
13/735404 |
Filed: |
January 7, 2013 |
Current U.S.
Class: |
367/81 |
Current CPC
Class: |
G01V 1/26 20130101; E21B
47/14 20130101; G01V 3/30 20130101 |
Class at
Publication: |
367/81 |
International
Class: |
E21B 47/14 20060101
E21B047/14 |
Claims
1. A method of synchronization between downhole components, the
method comprising: generating a dual tone synchronization signal by
a signal generator in a first downhole component disposed in a
borehole in an earth formation, the dual tone signal including a
first constituent periodic signal having a first frequency f.sub.1
and a second constituent periodic signal having a second frequency
f.sub.2 that is different from the first frequency; transmitting
the synchronization signal to a second downhole component disposed
in the borehole; receiving the synchronization signal by a signal
processor in the second downhole component, calculating a phase
difference between the first constituent signal and the second
constituent signal, and calculating a transmission delay based on
the phase difference; and synchronizing operation of the first and
second downhole components based on the delay.
2. The method of claim 1, wherein the synchronization signal is
transmitted directly to the second downhole component over a
transmission line connected between the downhole components and a
surface unit.
3. The method of claim 2, wherein the transmission line is a single
conductor power and telemetry bus.
4. The method of claim 2, wherein the synchronization signal is
transmitted in a first frequency band that is different than a
second frequency band used to transmit communications between the
surface unit and the downhole components.
5. The method of claim 1, further comprising transmitting a trigger
signal from the first downhole component to the second downhole
component, the trigger signal indicating a time value measured by
the first downhole component.
6. The method of claim 5, wherein the time value is a zero crossing
point at a selected cycle of the synchronization signal.
7. The method of claim 5, wherein the first downhole component
includes a transient electromagnetic (TEM) transmitter, the second
downhole component includes a TEM receiver, and the trigger signal
indicates a time at which the TEM transmitter commences
transmitting TEM signals into the earth formation.
8. The method of claim 1, wherein the first downhole component and
the second downhole component are connected via a current loop
communication system.
9. The method of claim 8, wherein the first downhole component
includes a current loop transmitter configured to convert voltage
signals from the first downhole component to current signals and
transmit the current signals over a current loop formed by the
transmission line.
10. An apparatus for communicating between downhole components,
comprising: an interface coupled to a first downhole component, the
interface configured to communicatively couple the first downhole
component to a transmission line and transmit signals to a second
downhole component over the transmission line, the interface
including a current loop transmitter configured to convert voltage
signals from the first downhole component to current signals and
transmit the current signals on a current loop formed by the
transmission line.
11. The apparatus of claim 10, further comprising a second
interface coupled to the second downhole component, the second
interface including a current loop receiver configured to convert
current signals received from the first downhole component over the
transmission line to voltage signals.
12. The apparatus of claim 10, wherein the current loop is formed
by the transmission line coupled to a surface power source and a
return path formed by a borehole string that includes the downhole
components.
13. The apparatus of claim 12, wherein the transmission line is a
single conductor power and telemetry bus.
14. The apparatus of claim 12, wherein the current loop transmitter
is configured to transmit the current signals in a first frequency
band that is different than a second frequency band used to
transmit communications between the surface unit and the downhole
components.
15. The apparatus of claim 14, wherein the current loop transmitter
includes a resonant decoupling device configured to prevent
coupling of signals in the second frequency band with the current
loop transmitter.
16. The apparatus of claim 14, wherein the current loop transmitter
includes a band pass filter tuned to frequencies in the first
frequency band.
17. The apparatus of claim 11, wherein the first interface and the
second interface are configured to both transmit and receive
current loop signals.
18. The apparatus of claim 17, wherein the first interface and the
second interface are configured as a half-duplex system to allow
for two-way communication.
19. The apparatus of claim 17, wherein the first interface and the
second interface are configured as a full-duplex system to allow
for simultaneous two-way communication.
20. The apparatus of claim 10, wherein the first downhole component
includes a signal generator configured to generate a dual tone
synchronization signal, the dual tone signal including a first
constituent periodic signal having a first frequency f.sub.1 and a
second constituent periodic signal having a second frequency
f.sub.2 that is different from the first frequency, and the second
downhole component includes a processor configured to receive the
synchronization signal, calculating a phase difference between the
first constituent signal and the second constituent signal, and
calculate a transmission delay based on the phase difference.
Description
BACKGROUND
[0001] Various techniques are used to measure formation properties,
such as transient electromagnetic (EM) measurement techniques.
Transient EM methods such as transient logging while drilling
(LWD), especially using "look-ahead" capability, have been shown to
have great use in geologic formation evaluation and measurement.
Transient EM techniques involve disposing a tool including at least
one transmitter and receiver, and transmitting transient pulses of
current into a formation. The induced electromagnetic field and
decay responses are measured. For proper operation of the transient
EM tool, the transmitter and receiver must be well synchronized,
i.e., the receiver data acquisition should start at the same
instant of the transmit trigger, to within an error of, e.g., a few
hundred nanoseconds.
[0002] It has been conventional to the industry to assemble a LWD
or wireline tool string from individual modules (also referred to
as subassemblies or "subs") which perform various functions and
carry out various measurements while the string has been lowered in
the borehole. However, even though these subs are mechanically
attached to each other and share common power, the string
communication abilities remains limited. For instance, in
operations such as LWD or production logging where a single
conductor carries power and telemetry signals, the telemetry uses a
unique master controller which respectively sends commands to a
particular sub and/or accepts a reply. This type of data transfer
in general denies the modules the ability to communicate directly
with each other which in turn may severely limit some applications,
e.g., multicomponent transient EM (TEM) and multicomponent
induction applications.
SUMMARY
[0003] A method of synchronization between downhole components
includes: generating a dual tone synchronization signal by a signal
generator in a first downhole component disposed in a borehole in
an earth formation, the dual tone signal including a first
constituent periodic signal having a first frequency f.sub.1 and a
second constituent periodic signal having a second frequency
f.sub.2 that is different from the first frequency; transmitting
the synchronization signal to a second downhole component disposed
in the borehole; receiving the synchronization signal by a signal
processor in the second downhole component, calculating a phase
difference between the first constituent signal and the second
constituent signal, and calculating a transmission delay based on
the phase difference; and synchronizing operation of the first and
second downhole components based on the delay.
[0004] An apparatus for communicating between downhole components
includes: an interface coupled to a first downhole component, the
interface configured to communicatively couple the first downhole
component to a transmission line and transmit signals to a second
downhole component over the transmission line, the interface
including a current loop transmitter configured to convert voltage
signals from the first downhole component to current signals and
transmit the current signals on a current loop formed by the
transmission line.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] The following descriptions should not be considered limiting
in any way. With reference to the accompanying drawings, like
elements are numbered alike:
[0006] FIG. 1 depicts an embodiment of a drilling, formation
evaluation and/or production system;
[0007] FIG. 2 depicts an embodiment of a portion of a borehole
string including transient electromagnetic (TEM) transmitter and
receiver subassemblies;
[0008] FIG. 3 depicts an embodiment of a communication
assembly;
[0009] FIG. 4 depicts an embodiment of an interface of the
communication assembly of FIG. 3;
[0010] FIG. 5 depicts an embodiment of a one-way dual tone
synchronization signal;
[0011] FIG. 6 is a state diagram showing the operation of a TEM
transmitter subassembly during a synchronization and measurement
operation;
[0012] FIG. 7 is a state diagram showing the operation of a TEM
receiver subassembly during a synchronization and measurement
operation;
[0013] FIG. 8 depicts an embodiment of a subassembly current loop
communication configuration;
[0014] FIG. 9 depicts an embodiment of the configuration of FIG. 8
in a half-duplex arrangement; and
[0015] FIG. 10 depicts an embodiment of the configuration of FIG. 8
in a full-duplex arrangement.
DETAILED DESCRIPTION
[0016] Apparatuses and methods are provided for performing downhole
operations such as electromagnetic (EM) measurement operations,
including logging-while-drilling (LWD) and/or wireline operations.
The apparatuses and methods also provide for direct communication
between downhole components over a power and/or communication line
extending along a borehole string. An exemplary method is provided
for performing transient EM (TEM) logging operations, and for
direct communication between downhole components. An exemplary
apparatus and method provides for direct communication between
subassemblies for, e.g., synchronization between a master
subassembly (e.g., an EM transmitter) and another subassembly
(e.g., an EM receiver). In one embodiment, synchronization is
performed via a dual frequency one-way time delay measurement
method. An embodiment of a communication apparatus or assembly
includes interfaces for implementing a data channel in a bus or
other transmission line for sending high-speed data from the master
subassembly to affected subassemblies without interfering with
other telemetry and power signals (e.g., between downhole
components and surface units) already present on the transmission
line.
[0017] Referring to FIG. 1, an exemplary embodiment of a well
drilling, logging and/or production system 10 includes a borehole
string 12 that is shown disposed in a wellbore or borehole 14 that
penetrates at least one earth formation 16 during a drilling or
other downhole operation. A surface structure 18 includes various
components such as a wellhead, derrick and/or rotary table for
deploying and supporting the borehole string. In one embodiment,
the borehole string 12 is a drillstring including one or more drill
pipe sections that extend downward into the borehole 14, and is
connected to a drilling assembly 20. In one embodiment, system 10
includes any number of downhole tools or other components 24 for
various processes including communication, measurement, drilling,
geosteering, and formation evaluation (FE) for measuring versus
depth and/or time one or more physical quantities in or around a
borehole. The tool 24 may be included in or embodied as a
bottomhole assembly (BHA) 22, drillstring component or other
suitable carrier. In the embodiment shown in FIG. 1, various tools
and other components are configured as subassemblies or "subs" that
are connected together and/or with other portions of the string
12.
[0018] The BHA 22 and/or other portions of the borehole string 12
include sensor devices configured to measure various parameters of
the formation and/or borehole. In one embodiment, the sensor
devices include one or more transmitters and receivers configured
to transmit and receive electromagnetic signals for measurement of
formation properties such as composition, resistivity and
permeability. An exemplary measurement technique is a transient EM
(TEM) technique.
[0019] In one embodiment, the tool 24, BHA 22 and/or sensor devices
include and/or are configured to communicate with a processor to
receive, measure and/or estimate directional and other
characteristics of the downhole components, borehole and/or the
formation. For example, the tool 24 is equipped with transmission
equipment including a power and/or data transmission line 30 to
communicate with a processor such as a downhole processor 26 or a
surface processing unit 28. Such transmission equipment may take
any desired form, and different transmission media and connections
may be used. Examples of connections include wired, fiber optic,
acoustic, wireless connections and mud pulse telemetry.
[0020] FIG. 2 illustrates an embodiment of the downhole tool 24. In
this embodiment, the tool 24 includes one or more sections or
assemblies for performing electromagnetic (EM) measurements. For
example, the tool 24 is configured as a transient EM (TEM) tool,
which may be configured as a logging while drilling (LWD) tool. The
TEM tool includes a transmitter that periodically produces fast
magnetic dipole reversals that induce eddy currents in the
surrounding earth formation. These eddy currents induce voltage in
one or more receiver sensors. The received voltage signals are
processed to produce a model of the geometrical structure of the
resistivity surrounding the borehole. Such models may be used to
estimate characteristics of the formation or may be used for
steering a drill bit to locate the borehole for maximum hydrocarbon
production.
[0021] In one embodiment, the downhole tool 24 includes separate
subassemblies or "subs" that incorporate the transmitter and
receiver(s). For example, a transmitter sub 32 houses an EM
transmitter 34 (including, e.g., a transmitter antenna or coil) and
associated electronics, which is configured to transmit EM pulses
into the formation and is connected to the transmission line 30.
The transmitter sub 32 is connected to a receiver sub 36 that
houses one or more EM receivers 38 and 40 (e.g., receiver coils)
and associated electronics, which is configured to receive EM
signals from the formation and is also connected to the
transmission line 30. The subs 32 and 36 are connected together via
connection mechanism 42 (e.g. a pin-box connector). An electric
source, which may be disposed downhole or at a surface location, is
configured to apply electric current to the transmitter 34 through,
e.g., the transmission line 30. Although the subs 32 and 36 are
shown in direct connection, they are not so limited, as other subs,
pipe sections or tools may be connected between them.
[0022] Although the tool 24, EM transmitter 34 and EM receivers 38
and 40 are described as being incorporated in downhole subs, they
may be incorporated into any suitable downhole component, module or
other carrier. A "carrier" as described herein means any device,
device component, combination of devices, media and/or member that
may be used to convey, house, support or otherwise facilitate the
use of another device, device component, combination of devices,
media and/or member. Exemplary non-limiting carriers include drill
strings of the coiled tubing type, of the jointed pipe type and any
combination or portion thereof. Other carrier examples include
casing pipes, wirelines, wireline sondes, slickline sondes, drop
shots, downhole subs, bottom-hole assemblies, and drill
strings.
[0023] In one embodiment, the transmitter and the receivers are
disposed axially relative to one another. An "axial" location
refers to a location along the Z axis that extends along a length
of the tool 24 and/or borehole 14. The receiver 40 is positioned at
a selected axial distance L.sub.1 from the transmitter 34, and the
receiver 38 is positioned at a shorter axial distance L.sub.2 from
the transmitter.
[0024] Referring to FIGS. 3 and 4, in one embodiment, the tool 24
includes a communication or telemetry system or apparatus 44 for
communication between downhole components or subassemblies that
utilizes the data and/or power transmission line 30. In the
embodiment shown in FIG. 3, the transmission line 30 is a single
conductor bus capable of transmitting power and communications. For
example, the transmission line 30 is configured to transmit DC
voltage and communications. An exemplary communication scheme
incorporates a communications signal (e.g., using frequency shift
keying modulation) having a 250 kHz carrier. Digital transmission
can be accomplished at, e.g., a 9600 baud rate. The transmission
line 30, in this example, powers separate subassemblies on the
string 12 by the transmission line 30 with return current through
the string 12.
[0025] The EM transmitter sub 32 and the EM receiver sub 34 each
include a communication assembly that connects the EM
transmitter/receiver electronics to the transmission line 30. For
example, the EM transmitter sub 32 includes a synchronization
signal generation assembly 46 and the EM receiver sub 34 includes a
synchronization signal processing assembly 48. An interface 50 is
included in each communication assembly that adds a communication
channel to the transmission line 30.
[0026] In one embodiment, each interface 50 is a relatively
narrow-band high frequency interface (e.g., around 4 MHz) added
between the sub electronics and the transmission line 30. In one
embodiment, shown in FIG. 4, the interface 50 is designed with a
trap or high frequency band-pass filter 52 to block signals having
frequencies corresponding to carrier frequencies used in the
transmission line's main communication channel (e.g., around 250
kHz), so that the channel does not interfere with other
communications transmitted over the transmission line 30.
[0027] In one embodiment, one of the subassemblies (e.g., the EM
transmitter sub 32) is configured as a master subassembly and has
the capability to inject signals into the interface 50 to be
broadcast to selected subassemblies or individual receivers (e.g.,
the EM receiver sub 36 or one of the EM receivers 38, 40) over the
transmission line 30. The injected narrow-band (e.g., 4 MHz)
signals can be either synchronization signals for time
synchronization purposes or data transmission signals over the
injected carrier.
[0028] For example, the transmitter communication assembly 46
includes a modem 54 for modulating data signals 56 from the
transmitter, and a synchronization (sync) signal generator 58 for
transmitting synchronization signals. The receiver sub 36 (or each
receiver 38 and 40) includes a modem 54 for demodulating data
signals and a sync processor 60 for receiving and processing
synchronization signals.
[0029] In one embodiment, for time synchronization between
transmitters and receivers, the sync generator 58 includes a dual
tone signal generator capable of generating tones with fixed phase
difference. The sync generator outputs a signal generated by two
constituent signals having a fixed initial phase relationship. Each
constituent signal has a different frequency or tone. In one
embodiment, the constituent signals each have a frequency that
falls within the frequency band of the channel added to the
transmission line 30 by the interface 50.
[0030] In order to receive the dual tone signal, the sync processor
60 includes a phase sensitive receiver connected to the added
channel of the transmission line 30. The sync processor 60 is
configured to measure or calculate the difference in phase of the
two tones transmitted by the master subassembly. In one example,
the signal processing assembly 48 includes a digitizer followed by
a Fourier transform processing routine that measures phase
difference of the received tones.
[0031] It is noted that the subassemblies are not limited to the
embodiments and configurations described herein. For example, the
EM receiver sub 36, described as a synchronization signal receiver
in FIG. 3, may be configured as a communication signal transmitter
and/or master for communicating the with other subassemblies and/or
the EM transmitter sub 32. Likewise, the EM transmitter sub 32 may
be configured as a communication signal receiver. In other
embodiments, the subassemblies 32, 36 and/or other subassemblies
may be configured to both transmit and receive communication
signals over the communication line 30. As described herein,
"communication signals" refer to signals transmitted directly
between downhole components over the transmission line 30, and can
be distinguished from power and/or telemetry signals transmitted
between downhole components and a surface and/or control unit.
[0032] FIGS. 5-7 illustrate a method for synchronizing components
of a borehole string or carrier using signals transmitted over a
downhole transmission line, using a one-way synchronization signal.
The method includes one or more stages described herein. The method
may be performed by one or more processors or other devices capable
of receiving and processing measurement data. In one embodiment,
the method includes the execution of all of stages in the order
described. However, certain stages may be omitted, stages may be
added, or the order of the stages changed.
[0033] In the first stage, the borehole string 12, including
downhole components such as the EM transmitter sub 32 and the EM
receiver sub 36, is lowered in the borehole. The string 12 may be
lowered, for example, during a drilling operation, LWD operation or
via a wireline.
[0034] In the second stage, the master component (e.g., the EM
transmitter sub 32), transmits a synchronization signal to another
downhole component (e.g., the EM receiver sub 36). In one
embodiment, the master component transmits a trigger signal to the
downhole component in addition to the synchronization signal. The
trigger signal is a signal indicating a time value associated with
the master component. For example, the trigger signal indicates the
time value at which the EM transmitter sub 32 commences
transmission of transient EM signals into the formation.
[0035] An exemplary synchronization signal is shown in FIG. 5,
which illustrates a dual tone signal 62 including frequencies
f.sub.1 and f.sub.2 that is sent from the EM transmitter sub 32
that includes two signals having different frequencies and having a
fixed phase relationship. As shown in FIG. 5, the dual tone signal
forms a two-tone envelope. Signal 64 is the dual tone signal as
received by the EM receiver sub 36 and is used to calculate a
transmission delay based on the phase difference,
.phi.(f.sub.2)-.phi.(f.sub.1), between the two frequencies. The
trigger signal indicates the time as measured by the transmitter in
which the transmitter fired an EM pulse into the formation. For
example, the trigger signal indicates that the EM pulse was fired
by the transmitter at a time corresponding to a zero-crossing point
of a selected cycle of the dual tone envelope, although any
temporal point on the dual tone signal may be used to correspond to
the trigger time.
[0036] FIG. 6 is a state diagram 70 showing an example of the EM
transmitter sub operation during the second stage. At state 71, the
sync generator 58 is enabled to generate a dual tone signal with
zero phase between tones. After a selected number (N1) of dual tone
cycles (state 72), the transient EM transmitter 34 is triggered to
emit a series of EM pulses into the formation (state 73). The dual
tone signal is transmitted to the EM receiver sub 36 along with a
trigger signal indicating the trigger point (e.g., zero crossing at
N1 cycle). In state 74, the EM transmitter sub 32 collects data
indicating the axis and polarity of each dipole reversal for each
pulse. This polarity and axis information is also transmitted to
the receiver subassembly over the transmission line 30, using the
modem 54 (state 75 and 76).
[0037] In the third stage, the other downhole component (e.g., EM
receiver sub 36) receives the trigger signal and the
synchronization signal. The time of the trigger is noted, i.e., its
position in the synchronization signal, and recording of TEM
voltage signals from the formation by the EM receiver 38 or 40 is
commenced. In one embodiment, the EM receiver sub 36 includes a
circular buffer, and the trigger causes the EM receiver sub 36 to
store data from the buffer at the trigger time and record
subsequent data as needed. The EM receiver sub 36 also analyzes the
synchronization to calculate the time delay .tau. that corresponds
to the amount of time required to transmit the trigger to the EM
receiver sub 36. This delay is used to adjust the trigger time for
the receiver data so that the received TEM data is synchronized
with the transmitter.
[0038] In one embodiment, the receiver calculates the delay .tau.
based on the phase difference between the two tones or frequencies
f.sub.1 and f.sub.2. For example, a fast Fourier transform (FFT) is
used to calculate the phase difference
.phi.(f.sub.2)-.phi.(f.sub.1). The delay may then be calculated
based on:
.tau. = .phi. ( f 2 ) - .phi. ( f 1 ) 2 .pi. ( f 2 - f 1 ) .
##EQU00001##
[0039] FIG. 7 is a state diagram 80 showing an example of the
receiver subassembly operation during the third stage. In state 81,
the EM receiver sub 36 is idle and awaiting a synchronization
signal. The EM receiver sub 36 may also receive a trigger signal
indicating the trigger point. Upon receiving a dual tone signal,
the EM receiver sub 36 waits for N1 cycles, notes the end time of
the trigger and commences FFT processing to calculate the delay
(state 82). At this point, the EM receiver sub 36 commences
recording voltage signals, and may also store data recorded in a
buffer. In state 83, the EM receiver sub 36 enables the modem 54
and awaits receipt of data from the EM transmitter sub 32
indicating, e.g., dipole shape, polarity and sensor axis for each
pulse. After all TEM voltage signal data has been acquired and
information data received, the voltage signal data is matched to
the delay and the voltage data is processed (or transmitted to a
remote processor) to analyze the formation, e.g., by generating or
updating a formation model.
[0040] In the fourth stage, a measurement operation is performed
using the transmitter and receiver subassemblies. The measured
voltage signals may be transformed, e.g., using a Fourier
transform. The measured or transformed signals may be inverted or
otherwise analyzed to estimate characteristics of the formation
and/or borehole for the purpose of, e.g., formation evaluation and
geosteering. For example, measured or transformed frequency domain
TEM signals are inverted to provide estimations of formation
properties, such as resistivities and distances to interfaces or
boundaries in the formation.
[0041] FIGS. 8-10 illustrate embodiments of an interface 50 that
allows for electrical and communicative coupling between downhole
tools or other components (e.g., the EM transmitter sub 32 and the
EM receiver sub 36) and a communication line such as the bus 30. In
many configurations, borehole strings such as LWD and wireline tool
string include individual subs, modules or other components that
are mechanically attached to each other and receive power from the
communication line such as the transmission line 30, which may
include one or more electrical conductors and/or other components
such as optical fibers. The communication line allows the subs to
be in communication with a master controller (e.g., the surface
processing unit 28) for sending data, receiving commands from the
controller and sending replies. The interface 50 allows individual
subs to directly communicate with one another, in contrast to
forcing the subs to communicate via the master controller. The
interface allows communication modules installed in different and
separate subs in the downhole string to communicate directly with
each other utilizing an existing single conductor bus or other
telemetry configuration without interfering with pre-existing
telemetry and power signals already present on the bus.
[0042] In one embodiment, the EM transmitter sub 32 and the EM
receiver sub 36 each include a current loop transmitter and/or
current loop receiver that form part of a current loop
communication system for direct communication between the EM
transmitter sub 32 and the EM receiver sub 36 over the
communication line. The current loop transmitter is configured to
receive a voltage signal (e.g., data, commands or other
communications) from the EM transmitter or receiver, convert the
sensor signal to a current and inject the current into a current
loop formed by the communication line. The current signal generated
by the current loop transmitter is tuned to a frequency that is
different than the communication line's pre-existing carrier
frequency or frequencies.
[0043] An example of a current loop communication configuration is
shown in the circuit diagram of FIG. 8. In this example, downhole
components such as the EM transmitter sub 32 and the EM receiver
sub 36 each include a current loop transceiver 90 connected to the
sub electronics and having the capability to both transmit and
receive current signals. Each transceiver has a termination network
L1, C4, X1, C1 and R1, which is designed to present a low impedance
to the transmission line 30 at the carrier frequency (e.g. 4 MHz),
but presents a high impedance to the line at all other frequencies
(e.g. the preexisting telemetry system 250 kHz carrier
frequency).
[0044] A first transceiver 90 (e.g., in the EM transmitter 34)
converts voltage signals to current via the low impedance looking
into the termination network of a second transceiver 90 through the
transmission line 30 and transmits the current to the second
transceiver 90 over the communication line 30. The second
transceiver 90 (e.g., in the EM receiver 36) receives the current
signal and converts the current signal to a voltage signal to be
detected by the subassembly electronics. The communication line 30
in this configuration forms part of a current loop at the carrier
frequency that includes, e.g., a power supply from the surface
processing unit 28, the communication line 30 and return through
the borehole string.
[0045] In one embodiment, each transceiver 90 includes circuitry
for resonant decoupling of the transceiver from telemetry/power
signals transmitted over the communication line 30. For example,
resonant decoupling is achieved for the transceivers via a
decoupling capacitor 92 ("C1" in the transmitter sub and "C2" in
the receiver sub) and a transformer 94 ("X1" in the transmitter sub
and "X2" in the receiver sub). The capacitors 92 allow for
elimination of passing DC voltage acting on the bus 30 to the
transformer primary winding which could cause excessive power
losses and saturate the transformer's core.
[0046] In one embodiment, each transformer 94, together with an
inductor 96 ("L1" or "L2") and an additional capacitor 98 ("C3" or
"C4") forms a high quality band pass filter that can be tuned to
the transceiver's operating frequency (e.g., 4 MHz). This also
allows for effective suppression of low frequency telemetry signals
that may be propagated to the transceiver inputs.
[0047] If the input impedance of a current loop receiver "R" were
maintained high, a change of the communication line's impedance
could de-tune the above mentioned band pass filter. This impedance
change could occur if more downhole subs have been connected to the
bus and/or their power/telemetry characteristics changed.
[0048] In one embodiment, to mitigate this issue, the current loop
receiver module includes a very low impedance front-end amplifier,
i.e., operating as a current amplifier, or in transimpedance mode.
In this embodiment, the input impedance of the current loop
receiver at the transceiver frequency is negligible while remain
sufficiently high for telemetry signals. The transceivers'
information is delivered from the current loop transmitter to the
current loop receiver by current owing from the current loop
transmitter output to the current loop receiver input, and the
amount of current diverted to connected extra subs will be in
reverse proportion to the ratio of their input impedances to the
impedance of the current loop receiver. In this way, additional
subs or components added to the communication line 30 do not result
in an appreciable change in performance of the current loop.
[0049] The current loop communication system can be configured as a
one-way system, where a first component includes only a current
loop transmitter and is configured to transmit current signals to a
second component that includes only a current loop receiver. In
other embodiments, the communication system is configures as a
half-duplex or a full-duplex system.
[0050] FIG. 9 shows an exemplary half-duplex arrangement, in which
both modules send and receive data at the same frequency, but do so
one way at a time. For example, each transceiver 90 includes
circuitry for receiving signals (receiving circuitry 100) and
transmitting current signals (transmitting circuitry 102), which
are connected to the communication line 30 via a solid state switch
104. Initially and when in stand-by mode, the receiver 100 is
connected to the communication line 30. Optionally, one of the
transceivers operates as a master and another as a slave. When
either of the transceivers 90 needs to transmit data, the switch is
actuated (via, e.g., a controller 106 following commands from
respective tool's electronics) to connect the transmitting
circuitry 102 to the communication line 30.
[0051] FIG. 10 shows an exemplary full-duplex arrangement, in which
both modules can exchange data independently and asynchronously. In
this example, the receiver 100 in the first component and the
transmitter 102 in the second component operate at a first
frequency F1, and the receiver 100 in the second component and the
transmitter 102 in the first component operate at a first frequency
F2.
[0052] The apparatuses and methods described herein provide various
advantages over prior art techniques, including providing a method
for effective synchronization between downhole components over
existing communication/power lines.
[0053] The dual tone synchronization method overcomes disadvantages
inherent in prior art methods. For example, for transient EM tools,
synchronization of the receiver using the rising edge of voltage
signals induced in receiver coils (due to current in the formation
induced by the EM transmitter) is possible, however the
conductivity of the formation between the transmitter and receiver
tends to distort and lengthen the rise time of the rising edge,
making synchronization variable, inaccurate and unreliable.
Furthermore, this synchronization method can be badly affected by
random noise. Algorithms for distinguishing the axis and polarity
of dipole reversals by the receiver will likely be complicated and
may be unreliable, thus reducing the reliability of a
synchronization method using the receiver voltage signals.
[0054] The dual tone synchronization methods overcome these
deficiencies and provide an accurate method for time
synchronization of transmitters and receivers, e.g., that are
placed on separate subassemblies. In addition, the method may be a
one-way syncing method that doesn't require two-way communication
and handshaking among the affected subassemblies.
[0055] The communication systems and interfaces described herein
provide for direct communication between subassemblies by
implementing a data channel in a bus or other transmission line
that allows for sending high-speed data between subassemblies
without interfering with other telemetry and power signals (e.g.,
between downhole components and surface units) already present on
the transmission line. The systems thus are compatible with current
tools without requiring engineering modifications to unaffected
tools on the string, and allow for transmission of digital
communication so that receiver information can be transmitted to
the affected subassemblies. In the case of the transient EM tool,
the transmit subassembly needs to send the transmit axis and
transmit polarity associated with each dipole reversal.
[0056] For example, in the transient EM tool the transmitter and
receiver are located on separate subassemblies that have very
limited communication capabilities between them. Typically,
separate subassemblies on the drill string are powered by a single
common wire or other communication line. It is possible for
subassemblies to communicate over this bus over a narrow band data
channel around 250 kHz. This channel is not suitable for passing
sync signals from transmitter to receiver, since the data channel
is dedicated to tool control and data acquisition, and cannot be
preempted to pass sync signals. The communication systems and
interfaces described herein address these deficiencies by providing
for direct communication between subassemblies over the
communication line via one or more separate data channels that do
not interfere with power and/or telemetry channels.
[0057] Generally, some of the teachings herein are reduced to an
algorithm that is stored on machine-readable media. The algorithm
is implemented by a computer and provides operators with desired
output.
[0058] The systems described herein may be incorporated in a
computer coupled to various downhole components, subassemblies
and/or surface processing units. Exemplary components include,
without limitation, at least one processor, storage, memory, input
devices, output devices and the like. As these components are known
to those skilled in the art, these are not depicted in any detail
herein. The computer may be disposed in at least one of a surface
processing unit and a downhole component.
[0059] In support of the teachings herein, various analyses and/or
analytical components may be used, including digital and/or analog
systems. The system may have components such as a processor,
storage media, memory, input, output, communications link (wired,
wireless, pulsed mud, optical or other), user interfaces, software
programs, signal processors (digital or analog) and other such
components (such as resistors, capacitors, inductors and others) to
provide for operation and analyses of the apparatus and methods
disclosed herein in any of several manners well-appreciated in the
art. It is considered that these teachings may be, but need not be,
implemented in conjunction with a set of computer executable
instructions stored on a computer readable medium, including memory
(ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, hard drives),
or any other type that when executed causes a computer to implement
the method of the present invention. These instructions may provide
for equipment operation, control, data collection and analysis and
other functions deemed relevant by a system designer, owner, user
or other such personnel, in addition to the functions described in
this disclosure.
[0060] While the invention has been described with reference to
exemplary embodiments, it will be understood by those skilled in
the art that various changes may be made and equivalents may be
substituted for elements thereof without departing from the scope
of the invention. In addition, many modifications will be
appreciated by those skilled in the art to adapt a particular
instrument, situation or material to the teachings of the invention
without departing from the essential scope thereof. Therefore, it
is intended that the invention not be limited to the particular
embodiment disclosed as the best mode contemplated for carrying out
this invention, but that the invention will include all embodiments
falling within the scope of the appended claims.
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