U.S. patent application number 13/059673 was filed with the patent office on 2011-08-25 for wireless telemetry systems for downhole tools.
Invention is credited to Erwann Lemenager.
Application Number | 20110205847 13/059673 |
Document ID | / |
Family ID | 40427432 |
Filed Date | 2011-08-25 |
United States Patent
Application |
20110205847 |
Kind Code |
A1 |
Lemenager; Erwann |
August 25, 2011 |
WIRELESS TELEMETRY SYSTEMS FOR DOWNHOLE TOOLS
Abstract
Apparatus and method for transmitting data in a borehole (10)
between a downhole installation including one or more tools (20)
(for example downhole testing tools) and a surface installation
(62), wherein the downhole installation is connected to the surface
installation by means of a tubular conduit (such as a drill string
or production tubing 14)). The apparatus comprises: an acoustic
modem (26) associated with each tool, the modem acting to convert
tool signals such as electrical tool signals into acoustic signals;
and a hub (90) forming part of the downhole installation to which
the tools and tubular conduit are connected and comprising an
acoustic receiver (74) and an electromagnetic transmitter (80). The
acoustic modems operate to generate acoustic signals in the
downhole installation representative of the tool signals, the
acoustic signals passing along the downhole installation to be
received at the acoustic receiver of the hub, the received acoustic
signals being used to operate the electromagnetic transmitter to
transmit electromagnetic signals to the surface for reception at
the surface installation.
Inventors: |
Lemenager; Erwann; (Paris,
FR) |
Family ID: |
40427432 |
Appl. No.: |
13/059673 |
Filed: |
August 4, 2009 |
PCT Filed: |
August 4, 2009 |
PCT NO: |
PCT/EP2009/005715 |
371 Date: |
April 26, 2011 |
Current U.S.
Class: |
367/82 |
Current CPC
Class: |
E21B 47/13 20200501;
E21B 47/16 20130101 |
Class at
Publication: |
367/82 |
International
Class: |
E21B 47/16 20060101
E21B047/16 |
Foreign Application Data
Date |
Code |
Application Number |
Aug 22, 2008 |
EP |
08162854.7 |
Claims
1. Apparatus for transmitting data in a borehole between a downhole
installation including one or more tools and a surface
installation, wherein the downhole installation is connected to the
surface installation by means of a tubular conduit, the apparatus
comprising: an acoustic modem associated with each tool, the modem
acting to convert electrical tool signals into acoustic signals;
and a hub forming part of the downhole installation to which the
tools and tubular conduit are connected and comprising an acoustic
receiver and an electromagnetic transmitter; wherein the acoustic
modems operate to generate acoustic signals in the downhole
installation representative of the electrical tool signals, the
acoustic signals passing along the downhole installation to be
received at the acoustic receiver of the hub, the received acoustic
signals being used to operate the electromagnetic transmitter to
transmit electromagnetic signals to the surface for reception at
the surface installation.
2. Apparatus as claimed in claim 1, wherein the hub further
comprises an acoustic transmitter which is operable to transmit the
acoustic signals received by the hub to the surface installation
via the tubular conduit.
3. Apparatus as claimed in claim 2, further comprising one or more
acoustic repeaters disposed along the tubular conduit and operable
to retransmit the acoustic signal received from the hub.
4. Apparatus as claimed in claim 1, wherein at least one tool is
located below the hub.
5. Apparatus as claimed in claim 1, wherein at least one tool is
located above the hub.
6. Apparatus as claimed in claim 1, wherein the downhole
installation comprises at least one packer to isolate a zone of the
borehole below the hub.
7. Apparatus as claimed in claim 6, comprising multiple packers
arranged to isolate multiple zones of the well below the hub.
8. Apparatus as claimed in claim 7, wherein the downhole
installation comprises separate tools in each zone.
9. Apparatus as claimed in claim 1, wherein the hub further
comprises an electromagnetic receiver for receiving electromagnetic
signals from the surface installation, and an acoustic transmitter
for transmitting acoustic signals derived from the received
electromagnetic signals.
10. A method of communicating between one or more tools comprising
a downhole installation and a surface installation, wherein the
downhole installation and surface installation are connected by
means of a tubular conduit, the method comprising: using electrical
signal produced by the tools to generate acoustic signals which
pass along the downhole installation to a hub; receiving the
acoustic signals at the hub; and using the received acoustic
signals to generate electromagnetic signals that pass from the hub
to the surface location.
11. A method as claimed in claim 10, further comprising generating
acoustic signals at the hub which pass along the tubular conduit to
the surface installation.
12. A method as claimed in claim 11, further comprising receiving
the acoustic signals and retransmitting them at multiple locations
along the tubular conduit.
13. A method as claimed in claim 10, further comprising
transmitting electromagnetic signals from the surface installation
to the hub and converting these signals into acoustic signals for
transmission to the tools in the installation.
14. A method of testing a well, comprising: locating testing tools
in a borehole in a number of zones to be tested; isolating the
zones from each other and the rest of the well; operating the
testing tools in each zone; and transmitting data from the testing
tools in each zone to a surface installation by means of a method
according to any of claims 10.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] The present application is based on and claims priority to
European Patent Application No. EP08162854, filed Aug. 22,
2008.
TECHNICAL FIELD
[0002] The present invention relates to telemetry systems for use
with installations in oil and gas wells or the like. In particular,
the present invention relates to wireless telemetry systems for
transmitting data and control signals between a location down a
borehole and the surface, or between downhole locations
themselves.
BACKGROUND ART
[0003] One of the more difficult problems associated with any
borehole is to communicate measured data between one or more
locations down a borehole and the surface, or between downhole
locations themselves. For example, in the oil and gas industry it
is desirable to communicate data generated downhole to the surface
during operations such as drilling, perforating, fracturing, and
drill stem or well testing; and during production operations such
as reservoir evaluation testing, pressure and temperature
monitoring. Communication is also desired to transmit intelligence
from the surface to downhole tools or instruments to effect,
control or modify operations or parameters.
[0004] Accurate and reliable downhole communication is particularly
important when complex data comprising a set of measurements or
instructions is to be communicated, i.e., when more than a single
measurement or a simple trigger signal has to be communicated. For
the transmission of complex data it is often desirable to
communicate encoded digital signals.
[0005] Downhole testing is traditionally performed in a "blind
fashion": downhole tools and sensors are deployed in a well at the
end of a tubing string for several days or weeks after which they
are retrieved at surface. During the downhole testing operations,
the sensors may record measurements that will be used for
interpretation once retrieved at surface. It is only after the
downhole testing tubing string is retrieved that the operators will
know whether the data are sufficient and not corrupted. Similarly
when operating some of the downhole testing tools from surface,
such as tester valves, circulating valves, packer, samplers or
perforating charges, the operators do not obtain a direct feedback
from the downhole tools.
[0006] In this type of downhole testing operations, the operator
can greatly benefit from having a two-way communication between
surface and downhole. However, it can be difficult to provide such
communication using a cable since inside the tubing string it
limits the flow diameter and requires complex structures to pass
the cable from the inside to the outside of the tubing. A cable
inside the tubing is also an additional complexity in case of
emergency disconnect for an offshore platform. Space outside the
tubing is limited and a cable can easily be damaged. Therefore a
wireless telemetry system is preferred.
[0007] A number of proposals have been made for wireless telemetry
systems based on acoustic and/or electromagnetic communications.
Examples of various aspects of such systems can be found in: U.S.
Pat. No. 5,050,132; U.S. Pat. No. 5,056,067; U.S. Pat. No.
5,124,953; U.S. Pat. No. 5,128,901; U.S. Pat. No. 5,128,902; U.S.
Pat. No. 5,148,408; U.S. Pat. No. 5,222,049; U.S. Pat. No.
5,274,606; U.S. Pat. No. 5,293,937; U.S. Pat. No. 5,477,505; U.S.
Pat. No. 5,568,448; U.S. Pat. No. 5,675,325; U.S. Pat. No.
5,703,836; U.S. Pat. No. 5,815,035; U.S. Pat. No. 5,923,937; U.S.
Pat. No. 5,941,307; U.S. Pat. No. 5,995,449; U.S. Pat. No.
6,137,747; U.S. Pat. No. 6,147,932; U.S. Pat. No. 6,188,647; U.S.
Pat. No. 6,192,988; U.S. Pat. No. 6,272,916; U.S. Pat. No.
6,320,820; U.S. Pat. No. 6,321,838; U.S. Pat. No. 6,912,177;
EP0550521; EP0636763; EP0773345; EP0919696; EP1076245; EP1193368;
EP1320659; EP1882811; WO96/024751; WO92/06275; WO05/05724;
WO02/27139; WO01/39412; WO00/77345; WO07/095111.
[0008] In EP0550521, an acoustic telemetry system is used to pass
data across an obstruction in the tubing, such as a valve. The data
is then stored for retrieval by a wireline tool passed inside the
tubing from the surface. It is also proposed to retransmit the
signal as an acoustic signal. EP1882811 discloses an acoustic
transducer structure that can be used as a repeater along the
tubing.
[0009] EP0919696 proposes a downhole telemetry system using
parallel electromagnetic and acoustic signal transmission for
communicating data between a surface location and equipment located
in the vicinity of a drill bit.
[0010] It is an object of this invention to provide a system that
combines different types of telemetry so as to take advantage of
the best features of the different types of telemetry while
providing alternatives to avoid the limitations of any of them.
BRIEF DISCLOSURE OF THE INVENTION
[0011] A first aspect of this invention provides apparatus for
transmitting data in a borehole between a downhole installation
including one or more tools (for example downhole testing tools)
and a surface installation, wherein the downhole installation is
connected to the surface installation by means of a tubular conduit
(such as a drill string or production tubing), the apparatus
comprising:
[0012] an acoustic modem associated with each tool, the modem
acting to convert tool signals such as electrical tool signals into
acoustic signals; and
[0013] a hub forming part of the downhole installation to which the
tools and tubular conduit are connected and comprising an acoustic
receiver and an electromagnetic transmitter; wherein the acoustic
modems operate to generate acoustic signals in the installation
representative of the tool signals, the acoustic signals passing
along the downhole installation to be received at the acoustic
receiver of the hub, the received acoustic signals being used to
operate the electromagnetic transmitter to transmit electromagnetic
signals to the surface for reception at the surface
installation.
[0014] Preferably, the hub further comprises an acoustic
transmitter which is operable to transmit the acoustic signals
received by the hub to the surface installation via the tubular
conduit.
[0015] One or more acoustic repeaters can be disposed along the
tubular conduit and operated to retransmit the acoustic signal
received from the hub.
[0016] At least one tool can be located below and/or above the
hub.
[0017] The downhole installation typically comprises at least one
packer to isolate a zone of the borehole below the hub. In one
embodiment multiple packers are arranged to isolate multiple zones
of the well below the hub. In this case, the downhole installation
can comprise separate tools in each zone.
[0018] The hub can further comprise an electromagnetic receiver for
receiving electromagnetic signals from the surface installation,
and an acoustic transmitter for transmitting acoustic signals
derived from the received electromagnetic signals.
[0019] A second aspect of the invention provides a method of
communicating between one or more tools comprising a downhole
installation and a surface installation, wherein the downhole
installation and surface installation are connected by means of a
tubular conduit, the method comprising:
[0020] using signals produced by the tools to generate acoustic
signals which pass along the downhole installation to a hub;
[0021] receiving the acoustic signals at the hub; and
[0022] using the received acoustic signals to generate
electromagnetic signals that pass from the hub to the surface
location.
[0023] The tool signals can be preferably electrical signals or
digital signals.
[0024] In one embodiment, the method further comprises generating
acoustic signals at the hub which pass along the tubular conduit to
the surface installation. In this case, the method can also include
receiving the acoustic signals and retransmitting them at multiple
locations along the tubular conduit.
[0025] One preferred embodiment further comprised transmitting
electromagnetic signals from the surface installation to the hub
and converting these signals into acoustic signals for transmission
to the tools in the installation.
[0026] Further aspects of the invention will be apparent from the
following description.
BRIEF DESCRIPTION OF THE DRAWINGS
[0027] Certain embodiments of the invention will hereafter be
described with reference to the accompanying drawings, wherein like
reference numerals denote like elements, and:
[0028] FIG. 1 shows a schematic view of an acoustic telemetry
system according to an embodiment of the present invention;
[0029] FIG. 2 shows a schematic of a modem as used in accordance
with the embodiment of FIG. 1;
[0030] FIG. 3 shows a variant of the embodiment of FIG. 1;
[0031] FIG. 4 shows a hybrid telemetry system according to an
embodiment of the present invention;
[0032] FIG. 5 shows a schematic view of a modem;
[0033] FIG. 6 shows a detailed view of a downhole installation
incorporating the modem of FIG. 5;
[0034] FIG. 7 shows one embodiment of mounting the modem according
to an embodiment of the present invention;
[0035] FIG. 8 shows one embodiment of mounting a repeater modem
according to an embodiment of the present invention;
[0036] FIG. 9 shows a dedicated modem sub for mounting according to
an embodiment of the present invention;
[0037] FIGS. 10, 11 and 12 illustrate applications of a hybrid
telemetry system according to an embodiment of the present
invention;
DETAILED DESCRIPTION
[0038] The present invention is particularly applicable to testing
installations such as are used in oil and gas wells or the like.
FIG. 1 shows a schematic view of such a system. Once the well has
been drilled through a formation, the drill string can be used to
perform tests, and determine various properties of the formation
though which the well has been drilled. In the example of FIG. 1,
the well 10 has been lined with a steel casing 12 (cased hole) in
the conventional manner, although similar systems can be used in
unlined (open hole) environments. In order to test the formations,
it is preferable to place testing apparatus in the well close to
the regions to be tested, to be able to isolate sections or
intervals of the well, and to convey fluids from the regions of
interest to the surface. This is commonly done using a jointed
tubular drill pipe, drill string, production tubing, or the like
(collectively, tubing 14) which extends from the well-head
equipment 16 at the surface (or sea bed in subsea environments)
down inside the well to the zone of interest. The well-head
equipment 16 can include blow-out preventers and connections for
fluid, power and data communication.
[0039] A packer 18 is positioned on the tubing 14 and can be
actuated to seal the borehole around the tubing 14 at the region of
interest. Various pieces of downhole test equipment 20 are
connected to the tubing 14 above or below the packer 18. Such
downhole equipment 20 may include, but is not limited to:
additional packers; tester valves; circulation valves; downhole
chokes; firing heads; TCP (tubing conveyed perforator) gun drop
subs; samplers; pressure gauges; downhole flow meters; downhole
fluid analyzers; and the like.
[0040] In the embodiment of FIG. 1, a sampler 22 is located below
the packer 18 and a tester valve 24 located above the packer 18.
The downhole equipment 20 is connected to a downhole modem 26 which
is mounted in a gauge carrier 28 positioned between the sampler 22
and tester valve 24. The modem 26, also referred to as an acoustic
transceiver or transducer, operates to allow electrical signals
from the equipment 20 to be converted into acoustic signals for
transmission to the surface via the tubing 14, and to convert
acoustic tool control signals from the surface into electrical
signals for operating the downhole equipment 20. The term "data,"
as used herein, is meant to encompass control signals, tool status,
and any variation thereof whether transmitted via digital or
analog.
[0041] FIG. 2 shows a schematic of the modem 26 in more detail. The
modem 26 comprises a housing 30 supporting a piezo electric
actuator or stack 32 which can be driven to create an acoustic
signal in the tubing 14 when the modem 26 is mounted in the gauge
carrier 28. The modem 26 can also include an accelerometer 34 or
monitoring piezo sensor 35 for receiving acoustic signals. Where
the modem 26 is only required to act as a receiver, the piezo
actuator 32 may be omitted. Transmitter electronics 36 and receiver
electronics 38 are also located in the housing 30 and power is
provided by means of a battery, such as a lithium rechargeable
battery 40. Other types of power supply may also be used.
[0042] The transmitter electronics 36 are arranged to receive an
electrical output signal from a sensor 42, for example from the
downhole equipment 20 provided from an electrical or
electro/mechanical interface. Such signals are typically digital
signals which can be provided to a micro-controller 43 which uses
the signal to derive a modulation to be applied to a base band
signal in one of a number of known ways FSK, PSK, QPSK, QAM, OFDM,
and the like. This modulation is applied via a D/A
(digital-to-analog) converter 44 which outputs an analog signal
(typically a voltage signal) to a signal conditioner 46. The
conditioner 46 operates to modify the signal to match the
characteristics of the piezo actuator 32. The analog signals are
stacked and applied as a drive signal to the piezo stack 32 so as
to generate an acoustic signal in the material of the tubing 14.
The acoustic signal comprises a carrier signal with an applied
modulation to provide a digital signal that passes along the tubing
14 as a longitudinal and/or flexural wave. The acoustic signal
typically has, but is not limited to, a frequency in the range 1-10
kHz, preferably in the range 2-5 kHz, and is configured to pass
data at a rate of, but is not limited to, about 1 bps to about 1000
bps, preferably from about 5 to about 100 bps, and more preferably
from over about 80 bps. The data rate is dependent upon the
conditions such as the signal-to-noise ratio and the distance
between the repeaters. A preferred embodiment of the invention is
directed to a combination of a short hop acoustic telemetry system
for transmitting data between a hub located above the main packer
18 and a plurality of downhole tools and valves below and/or above
said packer 18. Then the data and/or control signals can be
transmitted from the hub to a surface module either via a plurality
of repeaters as acoustic signals or by converting into
electromagnetic signals and transmitting straight to the top. The
combination of a short hop acoustic with a plurality of repeaters
and/or the use of the electromagnetic waves allows an improved data
rate over existing systems. The system may be designed to transmit
data as high as 1000 bps. Other advantages of the present system
exist.
[0043] The receiver electronics are arranged to receive the
acoustic signal passing along the tubing 14 and are capable of
converting the acoustic signal into an electric signal. The
acoustic signal passing along the tubing 14 excites the
accelerometer 34 or monitor stack 35 so as to generate an electric
output signal (voltage). This signal is essentially an analog
signal carrying digital information. The analog signal is applied
to a filter 48 and then to an A/D (analog-to-digital) converter 50
to provide a digital signal which can be applied to a
microcontroller 52. The microcontroller 52 which implements signal
processing. The type of processing applied to the signal depends on
whether it is a data signal or a command signal. The signal is then
passed on to an actuator 54.
[0044] The modem 26 can therefore operate to transmit acoustic data
signals from the sensors in the downhole equipment 20 along the
tubing 14. In this case, the electrical signals from the equipment
20 are applied to the transmitter electronics 36 (described above)
which operate to generate the acoustic signal. The modem 26 can
also operate to receive acoustic signals control signals to be
applied to the downhole equipment 20. In this case, the acoustic
signals are detected and applied to the receiver electronics 38
(described above) which operate to generate the electric control
signal that is applied to the equipment 20.
[0045] In order to support acoustic signal transmission along the
tubing 14 between the downhole location and the surface, a series
of repeater modems 56a, 56b, etc. may be positioned along the
tubing 14. These repeater modems 56a and 56b can operate to receive
an acoustic signal generated in the tubing 14 by a preceding modem
and to amplify and retransmit the signal for further propagation
along the drill string. The number and spacing of the repeater
modems 56a and 56b will depend on the particular installation
selected, for example on the distance that the signal must travel.
A typical minimum spacing to the modems is 500 m in order to
accommodate all possible testing tool configurations. When acting
as a repeater, the acoustic signal is received and processed by the
receiver electronics 38 and the output signal is provided to the
microcontroller 52 of the transmitter electronics 36 and used to
drive the piezo stack 32 in the manner described above. Thus an
acoustic signal can be passed between the surface and the downhole
location in a series of short hops.
[0046] The role of a repeater is to detect an incoming signal, to
decode it, to interpret it and to subsequently rebroadcast it if
required. In some implementations, the repeater does not decode the
signal but merely amplifies the signal (and the noise). In this
case the repeater is acting as a simple signal booster. However,
this is not the preferred implementation selected for wireless
telemetry systems of the invention.
[0047] Repeaters are positioned along the tubing/piping string. A
repeater will either listen continuously for any incoming signal or
may listen from time to time.
[0048] The acoustic wireless signals, conveying commands or
messages, propagate in the transmission medium (the tubing) in an
omni-directional fashion, that is to say up and down. It is not
necessary for the detector to detect whether the physical wireless
signal is coming from another repeater above or below. The
direction of the message is embedded in the message itself Each
message contains several network addresses: the address of the
transmitter (last and/or first transmitter) and the address of the
destination modem at least. Based on the addresses embedded in the
messages, the repeater will interpret the message and construct a
new message with updated information regarding the transmitter and
destination addresses. Messages will be transmitted from repeaters
to repeaters and slightly modified to include new network
addresses.
[0049] If the repeater includes an array of sensors, and if the
channel is non-reverberant, then it is possible to determine the
direction of the incoming signal, using classical array processing
(similar to that found in borehole seismics, acoustic sonic tools,
phased array radars or ultrasonic, etc). This processing technique
applies for a propagating wave (acoustic or high frequency
electromagnetic, for example), but not for a diffusive wave such as
a low frequency electromagnetic wave.
[0050] Referring again to FIG. 1, a surface modem 58 is provided at
the well head 16 which provides a connection between the tubing 14
and a data cable or wireless connection 60 to a control system 62
that can receive data from the downhole equipment 20 and provide
control signals for its operation.
[0051] In the embodiment of FIG. 1, the acoustic telemetry system
is used to provide communication between the surface and the
downhole location. FIG. 3 shows another embodiment in which
acoustic telemetry is used for communication between tools in
multi-zone testing. In this case, two zones A, B of the well are
isolated by means of packers 18a, 18b. Test equipment 20a, 20b is
located in each isolated zone A, B, corresponding modems 26a, 26b
being provided in each case. Operation of the modems 26a, 26b
allows the equipment 20a, 20b in each zone to communicate with each
other as well as allowing communication from the surface with
control and data signals in the manner described above.
[0052] FIG. 4 shows an embodiment of the invention with a hybrid
telemetry system. The testing installation shown in FIG. 4
comprises a lower section 64 which corresponds to that described
above in relation to FIGS. 1 and 3. As before, downhole equipment
66 and packer(s) 68 are provided with acoustic modems 70. However,
in this case, the uppermost modem 72 differs in that signals are
converted between acoustic and electromagnetic formats. FIG. 5
shows a schematic of the modem 72. Acoustic transmitter and
receiver electronics 74, 76 correspond essentially to those
described above in relation to FIG. 2, receiving and emitting
acoustic signals via piezo stacks 32 (or accelerometers).
Electromagnetic (EM) receiver and transmitter electronics 78, 80
are also provided, each having an associated microcontroller 82,
84. A typical EM signal will be a digital signal typically in the
range of 0.25 Hz to about 8 Hz, and more preferably around 1 Hz.
This signal is received by the receiver electronics 78 and passed
to an associated microcontroller 82. Data from the microcontroller
82 can be passed to the acoustic receiver microcontroller 86 and on
to the acoustic transmitter microcontroller 88 where it is used to
drive the acoustic transmitter signal in the manner described
above. Likewise, the acoustic signal received at the receiver
microcontroller 86 can also be passed to the EM receiver
microcontroller 82 and then on to the EM transmitter
microcontroller 84 where it is used to drive an EM transmitter
antenna to create the digital EM signal that can be transmitted
along the well to the surface. A corresponding EM transceiver (not
shown) can be provided at the surface for connection to a control
system.
[0053] FIG. 6 shows a more detailed view of a downhole installation
in which the modem 72 forms part of a downhole hub 90 that can be
used to provide short hop acoustic telemetry X with the various
downhole tools 20 (e.g. test and circulation valves (i), flowmeter
(ii), fluid analyzer (iii) and packer (iv), and other tools below
the packer (iv)), and long hop EM telemetry Y to the surface. It
should be understood that while not show, the EM telemetry signal
may be transmitted further downhole to another downhole hub or
downhole tools.
[0054] FIG. 7 shows the manner in which a modem 92 can be mounted
in downhole equipment. In the case shown, the modem 92 is located
in a common housing 94 with a pressure gauge 96, although other
housings and equipment can be used. The housing 94 is positioned in
a recess 97 on the outside of a section of tubing 98 provided for
such equipment and is commonly referred to as a gauge carrier 97.
By securely locating the housing 94 in the gauge carrier 97, the
acoustic signal can be coupled to the tubing 98. Typically, each
piece of downhole equipment will have its own modem for providing
the short hop acoustic signals, either for transmission via the hub
and long hop EM telemetry, or by long hop acoustic telemetry using
repeater modems. The modem is hard wired into the sensors and
actuators of the equipment so as to be able to receive data and
provide control signals. For example, where the downhole equipment
comprises an operable device such as a packer, valve or choke, or a
perforating gun firing head, the modem will be used to provide
signals to set/unset, open/close or fire as appropriate. Sampling
tools can be instructed to activate, pump out, etc.; and sensors
such as pressure and flow meters can transmit recorded data to the
surface. In most cases, data will be recorded in tool memory and
then transmitted to the surface in batches. Likewise tool settings
can be stored in the tool memory and activated using the acoustic
telemetry signal.
[0055] FIG. 8 shows one embodiment for mounting the repeater modem
100 on tubing 104. In this case, the modem 100 is provided in an
elongate housing 102 which is secured to the outside of the tubing
104 by means of clamps 106. Each modem 100 may be a stand-alone
installation, the tubing 104 providing both the physical support
and signal path.
[0056] FIG. 9 shows an alternative embodiment for mounting the
repeater modem 108. In this case, the modem 108 is mounted in an
external recess 110 of a dedicated tubular sub 112 that can be
installed in the drill string between adjacent sections of drill
pipe, or tubing. Multiple modems can be mounted on the sub for
redundancy.
[0057] The preferred embodiment of the invention comprises a
two-way wireless communication system between downhole and surface,
combining different modes of electromagnetic and acoustic wave
propagations. It may also include a wired communication locally,
for example in the case of offshore operations. The system takes
advantage of the different technologies and combines them into a
hybrid system, as presented in FIG. 4.
[0058] The purpose of combining the different types of telemetry is
to take advantage of the best features of the different types of
telemetry without having the limitations of any single telemetry
means. The preferred applications for embodiments of this invention
are for single zone and multi-zone well testing in land and
offshore environments. In the case of the deep and ultra-deep
offshore environments, the communication link has to be established
between the floating platform (not shown) and the downhole
equipment 66 above and below the packer 68. The distance between
the rig floor (on the platform) and the downhole tools can be
considerable, with up to 3 km of sea water and 6 km of
formation/well depth. There is a need to jump via a `Long Hop` from
the rig floor to the top of the downhole equipment 66 but
afterwards it is necessary to communicate locally between the tools
66 (sensors and actuators) via a `Short Hop` within a zone or
across several zones. The Short Hop is used as a communication
means that supports distributed communication between the Long Hop
system and the individual tools that constitute the downhole
equipment 66, as well as between some of these tools within the
downhole installation. The Short Hop communication supports:
measurement data; gauge pressure and temperature; downhole
flowrates; fluid properties; and downhole tool status and
activation commands, such as but not limited to: IRDV; samplers
(multiple); firing heads (multiple); packer activation; other
downhole tools (i.e., tubing tester, circulating valve, reversing
valve); and the like.
[0059] All telemetry channels, being wireless or not, have
limitations from a bandwidth, deployment, cost or reliability point
of view. These are summarized in FIG. 10.
[0060] At low frequency (.about.1 Hz), electromagnetic waves 120
propagate very far with little attenuation through the formation
122. The higher the formation resistivity, the longer the wireless
communication range. The main advantages of electromagnetic wave
communication relate to the long communication range, the
independence of the flow conditions and the tubing string
configuration 124.
[0061] Acoustic wave propagation 126 along the tubing string 124
can be made in such a way that each element of the system is small
and power effective by using high frequency sonic wave (1 to 10
kHz). In this case, the main advantages of this type of acoustic
wave communication relate to the small footprint and the medium
data rate of the wireless communication.
[0062] Electrical or optical cable technology 128 can provide the
largest bandwidth and the most predictable communication channel.
The energy requirements for digital communication are also limited
with electrical or optical cable, compared to wireless telemetry
systems. It is however costly and difficult to deploy cable over
several kilometers in a well (rig time, clamps, subsea tree)
especially in the case of a temporary well installation, such as a
well test.
[0063] In the case of deep-offshore single zone or multi-zone well
testing, an appropriate topology for the hybrid communication
system is to use a cable 128 (optical or electrical) from the rig
floor to the seabed, an electromagnetic wireless communication 120
from the seabed to the top of the downhole equipment and an
acoustic communication 126 for the local bus communication.
[0064] Another way to combine the telemetry technologies is to
place the telemetry channels in parallel to improve the system
reliability through redundancy.
[0065] FIGS. 11 and 12 represent two cases where two or three
communication channels are placed in parallel. In FIG. 11, both
electromagnetic 120 and acoustic 126 wireless communication is used
to transmit data to the wellhead; and a cable 128 leads from the
wellhead to the rig floor (not shown). In such configurations,
common nodes 130 to the different communication channels can be
used. Such nodes 130 have essentially the similar functions to the
hub described above in relation to FIG. 6. In FIG. 12,
electromagnetic 120 and acoustic 126 wireless, and cable 128 are
all provided down to the downhole location, the acoustic wireless
signal being used between the downhole tools. The selection of the
particular communication channel used can be done at surface or
downhole or at any common node between the channels. Multiple paths
exist for commands to go from surface to downhole and for data and
status to go from downhole to surface. In the event of
communication loss on one segment of one channel, an alternate path
can be used between two common nodes.
[0066] A particularly preferred embodiment of the invention relates
to multi-zone testing (see FIG. 4). In this case, the well is
isolated into separate zones by packers 68, and one or more testing
tools are located in each zone. A modem is located in each zone and
operates to send data to the hub 72 located above the uppermost
packer. In this case, the tools in each zone operate either
independently or in synchronization. The signals from each zone are
then transmitted to the hub for forwarding to the surface via any
of the mechanisms discussed above. Likewise, control signals from
the surface can be sent down via these mechanisms and forwarded to
the tools in each zone so as to operate them either independently
or in concert.
[0067] Although only a few embodiments of the present invention
have been described in detail above, those of ordinary skill in the
art will readily appreciate that many modifications are possible
without materially departing from the teachings of this invention.
Accordingly, such modifications are intended to be included within
the scope of this invention as defined in the claims.
* * * * *