U.S. patent application number 13/758465 was filed with the patent office on 2014-08-07 for fiberoptic systems and methods for acoustic telemetry.
This patent application is currently assigned to Halliburton Energy Services, Inc. ("HESI"). The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC. ("HESI"). Invention is credited to John L. Maida, Etienne M. Samson, David P. Sharp.
Application Number | 20140219056 13/758465 |
Document ID | / |
Family ID | 51259116 |
Filed Date | 2014-08-07 |
United States Patent
Application |
20140219056 |
Kind Code |
A1 |
Samson; Etienne M. ; et
al. |
August 7, 2014 |
FIBEROPTIC SYSTEMS AND METHODS FOR ACOUSTIC TELEMETRY
Abstract
A disclosed acoustic telemetry system includes a downhole
acoustic telemetry module that generates an acoustic uplink signal
such as a pulsed fluid flow or compressional waves in a tubing
string wall. An optical waveguide transports an optical signal
representing the acoustic uplink signal to the surface interface. A
related telemetry method includes acquiring measurements downhole,
transmitting the measurements in the form of an acoustic signal,
and sensing the acoustic signal via an optical waveguide.
Inventors: |
Samson; Etienne M.;
(Cypress, TX) ; Sharp; David P.; (Houston, TX)
; Maida; John L.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. ("HESI") |
Duncan |
OK |
US |
|
|
Assignee: |
Halliburton Energy Services, Inc.
("HESI")
Duncan
OK
|
Family ID: |
51259116 |
Appl. No.: |
13/758465 |
Filed: |
February 4, 2013 |
Current U.S.
Class: |
367/81 |
Current CPC
Class: |
E21B 47/13 20200501;
E21B 47/135 20200501; E21B 47/14 20130101 |
Class at
Publication: |
367/81 |
International
Class: |
E21B 47/14 20060101
E21B047/14 |
Claims
1. A downhole telemetry method that comprises: acquiring
measurements downhole; transmitting downhole measurements in the
form of an acoustic signal; and sensing the acoustic signal
downhole via an optical waveguide.
2. The method of claim 1, wherein the optical waveguide comprises
an optical fiber and said sensing comprises distributed acoustic
sensing along said optical fiber.
3. The method of claim 1, wherein the optical waveguide comprises
an optical fiber and said sensing includes transducing motion or
pressure associated with the acoustic signal into applied stress or
deformation of the optical fiber to modulate passing light.
4. The method of claim 1, wherein said sending includes converting
motion or pressure associated with the acoustic signal into a
modulated optical signal for transmission via the optical
waveguide.
5. The method of claim 4, wherein said converting includes
modulating an optical signal received via said optical
waveguide.
6. The method of claim 4, wherein said converting includes
obtaining an electrical response to said motion or pressure and
applying the electrical response to a downhole light emitter that
transmits said modulated optical signal.
7. The method of claim 4, wherein said converting includes
obtaining an electrical response to said motion or pressure and
applying the electrical response to a transducer that deforms or
applies stress to the optical fiber to modulate passing light.
8. The method of claim 1, further comprising: transmitting one or
more commands via the optical waveguide to a downhole transducer;
and generating an acoustic downlink signal representing said one or
more commands.
9. An acoustic telemetry system that comprises: a downhole acoustic
telemetry module that generates an acoustic uplink signal; and an
optical waveguide that transports an optical signal representing
the acoustic uplink signal to a surface interface.
10. The system of claim 9, further comprising one or more downhole
sensors coupled to the optical waveguide, wherein the one or more
sensors convert the acoustic uplink signal into said optical
signal.
11. The system of claim 9, wherein the optical waveguide comprises
an optical fiber that converts the acoustic signal into modulation
of light provided by distributed acoustic sensing electronics
coupled to the surface interface.
12. The system of claim 9, wherein the acoustic signal comprises
modulation of a fluid flow.
13. The system of claim 12, wherein the fluid flow comprises a
circulated fluid.
14. The system of claim 12, wherein the fluid flow comprises a
produced fluid.
15. The system of claim 9, wherein the acoustic signal comprises at
least one of compressional, shear, or torsional waves in a tubing
string wall.
16. The system of claim 15, wherein the tubing string comprises
coiled tubing.
17. The system of claim 15, wherein the tubing string comprises
production tubing or a casing string.
18. The system of claim 9, further comprising a downhole
optical-to-acoustic transducer that converts an optical downlink
signal into an acoustic downlink signal.
19. The system of claim 18, wherein the optical waveguide also
transports the optical downlink signal from the surface interface
to the downhole transducer.
Description
BACKGROUND
[0001] Modern oil field operators demand access to a great quantity
of information regarding the parameters and conditions encountered
downhole. Such information typically includes characteristics of
the earth formations traversed by the borehole and data relating to
the size and configuration of the borehole itself. The collection
of information relating to conditions downhole, which commonly is
referred to as "logging," can be performed by several methods
including wireline logging and "logging while drilling" (LWD). A
closely related information collection technique is "permanent
monitoring".
[0002] In wireline logging, a sonde is lowered into the borehole
after some or all of the well has been drilled. The sonde hangs at
the end of a long wireline cable that provides mechanical support
to the sonde and also provides an electrical connection between the
sonde and electrical equipment located at the surface of the well.
In accordance with existing logging techniques, various parameters
of the earth's formations are measured and correlated with the
position of the sonde in the borehole as the sonde is pulled
uphole.
[0003] In LWD, the drilling assembly includes sensing instruments
that measure various parameters as the formation is being
penetrated, thereby enabling measurements of the formation while it
is less affected by fluid invasion. In permanent monitoring,
sensing instruments are installed in a borehole for long-term
monitoring of the downhole conditions. Telemetry can be a challenge
for both LWD and permanent monitoring environments. One commonly
proposed solution is the use of mud pulse telemetry, a telemetry
technique in which a flow of fluid along the well is modulated to
create pressure fluctuations representing telemetry data. While
this telemetry technique is robust and proven, its range and rate
are severely limited by the dissipative properties of the fluid
flow. Other acoustic telemetry techniques have been proposed to
overcome these limitations by generating acoustic waves that
propagate along the walls of a tubing string and/or borehole
casing, but have thus far met with limited success.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] Accordingly, there are disclosed herein various fiberoptic
systems and methods for facilitating acoustic telemetry. In the
drawings:
[0005] FIG. 1A shows an illustrative logging environment with a
tubing-conveyed sonde.
[0006] FIGS. 1B-1D are tubing cross-sections shows illustrative
cable dispositions relative to a tubing string.
[0007] FIG. 1E shows an illustrative logging environment with cable
disposed behind casing.
[0008] FIG. 2 shows an illustrative fiberoptic system for acoustic
telemetry.
[0009] FIGS. 3A-3C show illustrative acoustic-to-optical
transducers.
[0010] FIG. 4 shows an illustrative optical-to-acoustic
transducer.
[0011] FIG. 5 shows an illustrative fiberoptic-facilitated acoustic
telemetry method.
[0012] It should be understood, however, that the specific
embodiments given in the drawings and detailed description below do
not limit the disclosure. On the contrary, they provide the
foundation for one of ordinary skill to discern the alternative
forms, equivalents, and other modifications that are encompassed in
the scope of the appended claims.
DETAILED DESCRIPTION
[0013] The following disclosure presents the use of fiberoptic
sensing for acoustic telemetry in a downhole environment. One or
more fiberoptic sensors detect an acoustic telemetry signal near
where the acoustic telemetry signal is generated, permitting the
acoustic telemetry signal to be optically conveyed between the
downhole environment and the surface logging equipment. The signal
thus avoids nearly all of the dissipative effects of the fluid
stream, thereby permitting significantly greater range and
communications bandwidth to be achieved with existing telemetry
tools.
[0014] The disclosed systems, devices and methods are suitable for
use in any context where acoustic telemetry (including mud pulse
telemetry) might be employed. Selected contexts are now discussed
in detail, but they are not exhaustive. FIG. 1A shows an
illustrative environment for coiled-tubing conveyed logging. Coiled
tubing 54 is drawn from a tubing reel 52 by an injector 56 that
straightens the tubing and feeds it through a packer 58 into the
well. The packer 58 is attached to the borehole casing 62 by a tree
60 of gates, valves, feedthroughs, outlets, and other elements that
enable controlled access to the well. At the distal end of tubing
54 is a bottomhole assembly having a telemetry module 64, one or
more logging instruments 65, and any other potentially desirable
components such as a drill bit coupled to a drilling motor and any
tractors, collars, stabilizers, and/or steering mechanisms that may
be employed to extend the borehole.
[0015] Fluid can be circulated through the tubing 54 and the
annular space around tubing 54 during the logging (and optionally
drilling) operations via a hub in reel 52 and an outlet from tree
60. Circulation clears debris from the borehole and reduces
friction between the tubing and the borehole wall. Further coupled
to the hub is a rotary connector that provides a communication link
between cable 78 and a communication pathway along the tubing 54.
As discussed further below, the communication pathway includes an
optical fiber. In some embodiments, the rotary connector optically
couples the optical fiber to cable 78. In some alternative
embodiments, electronics mounted to reel 52 convert between optical
signals transported on the optical fiber and electrical signals
coupled to the cable 78 via the rotary connector. In still other
embodiments, cable 78 is replaced by a wireless connection that
obviates any requirement for a rotary connector.
[0016] A surface interface 67 accepts the optical, electrical, or
wireless signals from the reel 52 and converts them to digital data
for transmission a computer system 66. The surface interface 67 may
further accept digital data from computer system 66 and convert it
to signals for transmission to reel 52 for communication downhole
via the communication pathway. Computer system 66 can take many
forms ranging from a personal digital assistant (PDA), mobile
phone, tablet, laptop or desktop computer in the field to a
workstation or large data processing facility at a remote location.
Computer system 66 includes a user interface that in FIG. 1A takes
the form of a display monitor 68 and keyboard 70. Software on
information storage media 72 configures the computer system 66 to
process the received signals to extract the acoustic telemetry data
for storage and analysis. The software may further display the data
and/or analysis results to the user and accept input. Automatically
or in response to user input, the software may further configure
the computer 66 to generate commands to be communicated downhole
and translated into acoustic signals for communication to the
telemetry module 64.
[0017] As mentioned above, a communications pathway is provided
along the coiled tubing 54. FIG. 1B shows a first illustrative
embodiment in which the communications pathway is a fiberoptic
cable 80 suspended within the coiled tubing. FIG. 1C shows a second
illustrative embodiment in which the communications pathway is a
fiberoptic cable 80 attached to the outside of tubing 54 with a
protective molding 82. Alternatively, the fiberoptic cable 80 can
be strapped to the tubing 54 and/or wound helically on the tubing
54 to provide the communications pathway. FIG. 1D shows a third
illustrative embodiment in which the communications pathway is an
optical waveguide or fiber 84 embedded in the wall of tubing
54.
[0018] It is not required that the communications pathway be
attached to the tubing 54. For example, FIG. 1E shows an
illustrative embodiment in which the communications pathway is a
fiberoptic cable 86 positioned in an annular space outside casing
62 and attached to the casing with straps 88. Cement may be pumped
into the annular space to secure the casing and improve acoustic
coupling between the casing and the fiberoptic cable. In this
embodiment, the portion of the communications pathway that is
proximate to the bottomhole assembly (and hence to telemetry module
64) may change as the bottomhole assembly progresses along the
borehole. Moreover, there may be some distance that accumulates
between the communication pathway and the bottomhole assembly,
particularly if the bottomhole assembly moves beyond the cased
portion of the borehole and into an uncased zone of the borehole.
In such a case, the acoustic signal traverses that distance before
it is detected and converted to an optical form. Some system
embodiments may employ acoustic signal repeaters to assure that an
adequate signal-to-noise ratio is preserved as the acoustic signal
traverses this distance. While the exact limits will depend on
circumstances, it is expected that sensing within 100 meters of the
acoustic transmitter will yield a robust telemetry channel, and
greater distances can be tolerated with data rate adjustments to
account for dispersion in the acoustic channel.
[0019] FIG. 2 shows an illustrative acoustic telemetry system
configuration in which a light source 202 is coupled to an optical
circulator 204 which in turn is coupled to a receiver 206. The
circulator directs light from the source 202 to the communication
path 208 and directs light received from the communication path to
the receiver 206. The communication path 208 supports bidirectional
transport of optical signals. As explained further below, the
communication path 208 may be terminated near a telemetry module
210 by an acoustic sensor and/or an optical-to-acoustic transducer.
However, this is not necessarily the case and there are also
disclosed certain embodiments where the communication path 208
terminates with a reflector or dissipation configuration.
[0020] An acoustic coupling 212 is provided between the
communication path 208 and an acoustic signal transmitter 214. In
the illustrated example, acoustic signal transmitter 214 includes a
stack 216 of piezoelectric washers positioned between a transmitter
mount 218 and a reaction mass 220. A controller 224 drives the
piezoelectric stack 216 (via an electrical connection 222) to
transmit an acoustic signal. In at least some embodiments, the
controller 224 transmits measurement data as specially shaped
acoustic busts having frequencies adapted to the characteristics of
a fluid filled coiled tubing string. The transmitter mount 218
couples the acoustic signal into the walls of the coiled tubing
where it propagates towards the surface. Alternative embodiments of
acoustic signal transmitter may generate pressure fluctuations in
fluid flow along the coiled tubing string, or generate torsional
waves and/or shear waves.
[0021] Some acoustic telemetry system embodiments employ
distributed acoustic sensing (DAS) techniques, sometimes called
distributed vibration sensing (DVS), to detect the acoustic signal
from transmitter 214. Although various DAS techniques exist, they
generally rely on monitoring the scattering of light pulses from
imperfections in the fiber. Some particular implementations employ
pairs of light pulses that scatter light with a phase difference
that varies with acoustic wave-associated strain. In any case, the
DAS systems enable detection of acoustic signals at each point
along the length of the communications path.
[0022] As mentioned previously, at least some embodiments have the
communication path 208 terminated by a sensor that detects the
acoustic signal and converts it into a modulated optical signal.
Certain illustrative sensor embodiments are shown in FIGS. 3A-3C.
FIG. 3A shows communication path 208 as an optical fiber that
terminates in a sensor 302. The sensor accepts an incident light
beam 304 and provides a return light beam 306. The sensor includes
a cantilevered mass 308 on a support 312 over a substrate 314.
Vibration of substrate 314 (e.g., in response to an acoustic signal
from transmitter 214) causes mass 308 to transition between an
equilibrium position and a deflected position 316. A reflective
surface 310 is provided on mass 308 such that in the equilibrium
position, incident light beam 304 is reflected to form return light
beam 306. In the deflected position 316, the reflective surface 310
directs at least some of the light away from communication path
208, causing the return light beam 306 to be attenuated relative to
incident light beam 304. The vibration of substrate 314 is thereby
translated into amplitude modulation of the return light beam
306.
[0023] FIG. 3B shows an alternative sensor configuration having an
optical fiber 208 with a residual length represented by a coil 320,
and reflective end 322. The sensor includes a mounting surface 324
that experiences vibration associated with the acoustic signal,
e.g., the coiled tubing wall. Between the mounting surface 324 and
a reaction mass 326, the sensor includes mating plates 328A, 328B
having ridges 329 to induce bending in the optical fiber 208. As
vibrations cause the plates 328A, 328B to move together and apart,
the bending of the optical fiber causes varying amounts of light
loss, attenuating the incident light beam 304 and the return light
beam 306 reflected from end 322. The return light beam 306 is
thereby provided with amplitude modulation representing the
acoustic signal.
[0024] FIG. 3C provides an illustrative sensor 330 having a
piezoelectric element 332 between the mounting surface 324 and the
reaction mass 326. Vibration of the mounting surface 324 produces
compression and expansion of the piezoelectric element 332,
resulting in a signal voltage across resistor 334. At input nodes
341-342, the bridge rectifier formed from diodes 337, 338, 339, 340
accepts the signal voltage together with a bias voltage from a
battery 336 or other power source, and produces a rectified signal
voltage between output nodes 344, 346. A light-emitting diode (LED)
or other light source 348 converts the rectified signal voltage
into light. A lens 350 directs the light along communication path
208 as light beam 306. As the emitted light varies in accordance
with the rectified signal voltage, beam 306 represents the envelope
of the acoustic signal.
[0025] Additional functionality can be provided for sensor 330 by
including one or more other signal sources 352 in series or
parallel with resistor 334 and bias voltage 336. One illustrative
example is a coil for casing collar location such as that disclosed
in co-pending U.S. applications Ser. Nos. 13/226,578 and
13/432,206, each titled "Optical Casing Collar Locator Systems and
Methods". Alternative embodiments of the casing collar location
system may configured the coil to be sensitive to acoustic signals
in addition to being sensitive to casing collars. Such embodiments
may soft-mount the coil on silicone rubber that enables the coil to
act as a reaction mass when the tool body (and static magnets)
vibrates in response to the acoustic signal. Other examples of
added functionality include temperature sensors, pressure sensors,
and flow sensors. In any event, the information from signal
source(s) 352 is preferably provided in a separate frequency band
than the acoustic signal band. We note here that in some
embodiments, the response of the LED itself can be employed as a
measure of temperature, e.g., by monitoring the turn-on and
turn-off rates associated with light pulses.
[0026] Due to the use of a downhole light source, sensor 330 does
not require the presence of a surface light source 202 (FIG. 2) to
provide light for modulation. The surface light source 202 may
nevertheless be employed in acoustic telemetry systems designed to
support bi-directional communication. In addition to the
measurement data being communicated from the bottomhole assembly to
the surface, commands may be communicated from the surface to the
bottomhole assembly. A beam splitter or downhole circulator
separates the up-going light beam 306 (FIG. 3C) from a down-going
light signal 304 from the surface light source 202 (FIG. 4).
[0027] FIG. 4 shows an optical-to-acoustic transducer that converts
an optical downlink signal into an acoustic downlink signal. A lens
402 focuses the down-going light signal 304 onto a photodetector
404. An amplifier 406 with a feedback impedance 408 amplifies and
filters the signal from the photodetector 404 to drive an acoustic
generator 410. The acoustic generator 410 may take the form of a
piezoelectric driver that generates compressional, shear, or
torsional waves in the coiled tubing walls, or a valve or siren
that generates pressure modulation of the fluid flow. The acoustic
generation technique is chosen to match the downlink sensing design
of the bottomhole assembly. Illustrative acoustic modulation
techniques include frequency shift keying, amplitude shift keying,
phase shift keying, quadrature modulation, and orthogonal frequency
division multiplexing. Store-and-forwarding techniques, alone or
combined with caching, compression, and expanded signal
constellations, can be employed to increase bandwidth utilization
by the acoustic signal and/or the optical signal.
[0028] Alternative system embodiments replace the acoustic
generator 410 with an electromagnetic signal generator to support
an electromagnetic telemetry downlink. The signal generator
generates low frequency or radio frequency signals to communicate
the downlink information to the bottomhole assembly. One suitable
RF frequency is 455 kHz, for which existing intermediate frequency
(IF) components can be used to amplify and transmit the signal
detected by the photodetector. This signal frequency will readily
penetrate the borehole fluid for several meters to enable `out of
band` communications to the various tool string components.
[0029] The short travel of the acoustic signals from the bottomhole
assembly to the optical communication path (and for downlink
signals, from the optical-to-acoustic transducer to the bottomhole
assembly) means that the signals are not subject to any significant
signal-to-noise ratio (SNR) losses such as those attributable to
attenuation, internal reflections, Doppler shifts, dispersion, or
environmental noise. As the signal conversion between acoustic and
optical regimes is expected to support signal bandwidths of at
least hundreds of kilohertz, the acoustic transmitter and receiver
in the bottomhole assembly can be configured to support much higher
data rates than the typical tens of bits per second, even when
driven at much lower power to extend operating life. Indeed,
transmission rate of at least tens of thousands of bits per second
are expected to be achievable with only minor changes to existing
acoustic telemetry modules.
[0030] The use of the optical communications link greatly reduces
signal losses, enabling communication over a greater range than
that achievable by electrical conductor or direct acoustic
communication, perhaps extending to between 30 and 50 km, or even
more. Another potentially advantageous feature of at least some
system embodiments is the protection against electrical damage to
the bottomhole assembly provided by the wireless (acoustic) link,
and the intrinsically safe surface system configuration achievable
due to the optical form of the telemetry signal at the surface.
[0031] FIG. 5 is a flowchart illustrating a method that can be
implemented by one or more of the acoustic telemetry systems
disclosed herein. In block 502, a tool or bottomhole assembly
equipped with an acoustic telemetry module is deployed in a
borehole. Either separately or as part of the deployed assembly, an
optical fiber is also provided as a communication pathway from the
surface to the vicinity of the tool. In block 504, the tool
acquires measurement data and transmits the data in the form of an
acoustic signal. In block 506, the system converts the acoustic
signal into an optical signal. In some system embodiments, this
conversion is performed by a discrete sensor coupled to the optical
fiber. In other embodiments, this conversion is performed using
distributed acoustic sensing with the fiber itself. In block 508,
the optical signal is received at the surface and demodulated to
extract the measurement data.
[0032] In block 510, the system sends a command in the form of an
optical signal. This downlink signal may be multiplexed with the
uplink signal, e.g., using frequency division multiplexing, wave
division multiplexing, spin division multiplexing, time division
multiplexing, or sent on a separate optical fiber. In block 512,
the system converts the downlink optical signal into a downhole
acoustic signal in the vicinity of the downhole tool. In block 514,
the tool receives the acoustic signal and demodulates it to extract
the command.
[0033] Though various examples of acoustic-to-optical sensors have
been described above, these examples are not limiting. Other
suitable sensors include fiber Bragg grating (FBG) sensors
integrated into the fiber and acoustically ballasted to detect the
acoustic signals from the tool. Single-point accelerometers,
hydrophones, dynamic pressure, or acoustic sensors of all suitable
types can be employed to convert the acoustic signal into optical
form. A fast pressure sensor configured to measure dynamic pressure
signals may be particularly well suited for coupling the borehole
fluid signals to the communication pathway. The sensors may be
entirely optical, optionally employing interferometric sensing,
electrical, or hybrid in design. Interferometric optical sensors
may illustratively be based on Fabry-Perot, Michelson,
Mach-Zehnder, Sagnac, or resonant optical cavity
configurations.
[0034] Hybrid sensor designs may employ a piezoelectric crystal
stack to convert mechanical vibrations into electrical signals
which are then used to modulate the light passing through the
optical fiber, e.g., with a second piezoelectric element coupled to
a FBG. Suitably configured FBGs are available from Ibsen Photonics
under the `I-MON` brand name, offering bandwidths of several tens
of kilohertz. Micron Optics offers a similar sensor module "sm690"
having a signal bandwidth of 350 kHz. Some alternative tool designs
may even bypass the first piezoelectric crystal stack, instead
employing a directly-wired electrical conductor to couple the
electrical drive signal for the acoustic transmitter to an FBG
modulator of the light passing through the optical fiber. Another
potentially suitable electrical-to-optical conversion technique is
disclosed in U.S. Pat. No. 6,313,056 titled "Fiber optic sensor
system and method". Still another potentially suitable
electrical-to-optical conversion method employs an NRL magnetometer
configuration such as that disclosed by Koo and Sigel,
"Characteristics of fiber-optic magnetic-field sensors employing
metallic glasses", Optics Letters v7(7) p334-336, July 1982.
[0035] The foregoing telemetry systems and methods are suitable for
use in logging while drilling (LWD) environments, reservoir
monitoring and production logging environments, tubing-conveyed
logging environments, and potentially even in wireline logging
environments. Those embodiments employing point sensors rather than
distributed sensing may configure the point sensors in series, in
parallel, or in a combination of both configurations, using time
division and/or frequency division multiplexing to separate the
readings of the multiple sensors. Having multiple sensors provides
the system with redundancy and may further improve performance by
having readings from multiple sensor positions which can be
combined to improve signal to noise ratio.
[0036] Numerous other variations and modifications will become
apparent to those skilled in the art once the above disclosure is
fully appreciated. It is intended that the following claims be
interpreted to embrace all such variations and modifications.
* * * * *