U.S. patent application number 12/812779 was filed with the patent office on 2011-05-19 for apparatus and method for detecting pressure signals.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to James H. Dudley, John L. Maida, Paul F. Rodney, Ronald L Spross.
Application Number | 20110116099 12/812779 |
Document ID | / |
Family ID | 40885578 |
Filed Date | 2011-05-19 |
United States Patent
Application |
20110116099 |
Kind Code |
A1 |
Spross; Ronald L ; et
al. |
May 19, 2011 |
APPARATUS AND METHOD FOR DETECTING PRESSURE SIGNALS
Abstract
An apparatus for detecting data in a fluid pressure signal in a
conduit comprises an optical fiber loop comprises a measurement
section and a delay section wherein the measurement section is
disposed substantially circumferentially around at least a portion
of the conduit, and wherein the measurement section changes length
in response to the fluid pressure signal in the conduit. A light
source injects a first optical signal in a first direction into the
measurement section and a second optical signal in a second
direction opposite the first direction into the delay section. An
optical detector senses an interference phase shift between the
first optical signal and the second optical signal and outputs a
first signal related thereto.
Inventors: |
Spross; Ronald L; (Humble,
TX) ; Rodney; Paul F.; (Spring, TX) ; Dudley;
James H.; (Spring, TX) ; Maida; John L.;
(Houston, TX) |
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
40885578 |
Appl. No.: |
12/812779 |
Filed: |
March 18, 2008 |
PCT Filed: |
March 18, 2008 |
PCT NO: |
PCT/US08/57344 |
371 Date: |
July 14, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61021669 |
Jan 17, 2008 |
|
|
|
Current U.S.
Class: |
356/483 |
Current CPC
Class: |
G01B 9/02049 20130101;
G01M 11/085 20130101; E21B 47/18 20130101; G01L 11/025
20130101 |
Class at
Publication: |
356/483 |
International
Class: |
G01B 9/02 20060101
G01B009/02 |
Claims
1. An apparatus for detecting data in a fluid pressure signal in a
conduit comprising: an optical fiber loop comprising a measurement
section and a delay section wherein the measurement section is
disposed substantially circumferentially around at least a portion
of the conduit and wherein the measurement section changes length
in response to the fluid pressure signal in the conduit; a light
source injecting a first optical signal in a first direction into
the measurement section and a second optical signal in a second
direction opposite the first direction into the delay section; and
an optical detector to sense an interference phase shift between
the first optical signal and the second optical signal and
outputting a first signal related thereto.
2. The apparatus of claim 1 wherein the first signal is related to
a time derivative of the fluid pressure signal in the conduit.
3. The apparatus of claim 1 wherein the measurement section and the
delay section are sequentially disposed.
4. The apparatus of claim 1 further comprising a controller in data
communication with the optical detector wherein the controller
integrates the first signal with respect to time and generates an
output signal substantially similar to the fluid pressure
signal.
5. The apparatus of claim 4 wherein the controller decodes the
output signal into the data transmitted in the fluid pressure
signal.
6. The apparatus of claim 1 wherein the light source is chosen from
the group consisting of a laser, a laser diode, and a light
emitting diode.
7. The apparatus of claim 1 further comprising a pliant substrate
having the optical fiber of the measurement section attached
thereto.
8. The apparatus of claim 7 wherein the pliant substrate is
attachable around at least a portion of the conduit.
9. The apparatus of claim 1 wherein the delay section is about 500
meters to about 3000 meters long.
10. The apparatus of claim 1 wherein the measurement section is
about 2 meters to about 10 meters long.
11. A method for detecting data in a fluid pressure signal in a
conduit comprising: providing an optical fiber loop comprising a
measurement section and a delay section; disposing the measurement
section substantially circumferentially around at least a portion
of the conduit wherein the measurement section changes length
responsive to the fluid pressure signal in the conduit; injecting a
first optical signal in a first direction into the measurement
section and a second optical signal in a second direction opposite
the first direction into the delay section; and sensing an
interference phase shift between the first optical signal and the
second optical signal and outputting a first signal related
thereto.
12. The method of claim 11 wherein the first signal is indicative
of a time derivative of the fluid pressure signal in the
conduit
13. The method of claim 12 further comprising integrating the first
signal with respect to time and generating an output signal
substantially similar to the fluid pressure signal in the
conduit.
14. The method of claim 13 further comprising decoding the output
signal into data transmitted in the fluid pressure signal.
15. The method of claim 11 further comprising attaching the
measurement section optical fiber to a pliant substrate.
16. The method of claim 15 further comprising attaching the pliant
substrate at least partially around the conduit.
17. An apparatus for detecting a fluid pressure pulse signal
propagating in a conduit comprising: an optical fiber loop
comprising a measurement section and a sequentially disposed
optical delay section wherein the measurement section is disposed
substantially circumferentially around at least a portion of the
conduit and changes in length in response to the pressure pulse in
the conduit; a light source injecting a first optical signal in a
first direction into the measurement section and a second optical
signal in a second direction opposite the first direction into the
delay section; an optical detector to sense an interference phase
shift between the first optical signal and the second optical
signal to indicate a time derivative of the pressure pulse in the
conduit and generating a first signal indicative thereof; and a
controller in data communication with the optical detector, wherein
the controller integrates the first signal with respect to time and
generates an output signal substantially similar to the fluid
pressure pulse signal.
18. The apparatus of claim 17 wherein the controller decodes the
output signal into data transmitted in the fluid pressure pulse
signal.
19. The apparatus of claim 17 wherein the optical fiber of the
delay section is about 500 meters to about 3000 meters long.
20. The apparatus of claim 17 wherein the optical fiber of the
measurement section is about 2 meters to about 10 meters long.
21. A fluid telemetry system comprising: a transmitter located at a
downhole location transmitting data as an encoded pressure signal
through a fluid flowing in a conduit; an optical sensing system
detecting the encoded pressure signal proximate a surface location
wherein the optical sensing system comprises: an optical fiber loop
comprising a measurement section and a sequentially disposed
optical delay section wherein the measurement section is disposed
substantially circumferentially around at least a portion of the
conduit and changes in length in response to the encoded pressure
signal in the conduit; a light source injecting a first optical
signal in a first direction into the measurement section and a
second optical signal in a second direction opposite the first
direction into the delay section; an optical detector sensing an
interference phase shift between the first optical signal and the
second optical signal indicative of a time derivative of the
encoded pressure signal in the conduit and generating a first
signal indicative thereof; and a controller in data communication
with the optical detector wherein the controller integrates the
first signal with respect to time and generates an output signal
substantially similar to the encoded pressure signal.
22. The fluid telemetry system of claim 21 wherein the controller
decodes the output signal into the data.
23. The fluid telemetry system of claim 21 further comprising a
pliant substrate having the optical fiber of the measurement
section attached thereto wherein the pliant substrate is attachable
around at least a portion of the conduit.
24. The fluid telemetry system of claim 21 wherein the optical
fiber of the delay section is about 500 meters to about 3000 meters
long.
25. The fluid telemetry system of claim 21 wherein the optical
fiber of the measurement section is about 2 meters to about 10
meters long.
Description
BACKGROUND OF THE INVENTION
[0001] The present disclosure relates generally to the field of
telemetry systems for transmitting information through a flowing
fluid. More particularly, the disclosure relates to the field of
signal detection in such a system.
[0002] Sensors may be positioned at the lower end of a well
drilling string which, while drilling is in progress, continuously
or intermittently monitor predetermined drilling parameters and
formation data and transmit the information to a surface detector
by some form of telemetry. Such techniques are termed "measurement
while drilling" or MWD. MWD may result in a major savings in
drilling time and improve the quality of the well compared, for
example, to conventional logging techniques. The MWD system may
employ a system of telemetry in which the data acquired by the
sensors is transmitted to a receiver located on the surface. Fluid
signal telemetry is one of the most widely used telemetry systems
for MWD applications.
[0003] Fluid signal telemetry creates pressure signals in the
drilling fluid that is circulated under pressure through the drill
string during drilling operations. The information that is acquired
by the downhole sensors is transmitted by suitably timing the
formation of pressure signals in the fluid stream. The pressure
signals are commonly detected by a pressure transducer tapped into
a high pressure flow line at the surface. Access to, and
penetration of, the high pressure flow line may be restricted due
to operational and/or safety issues.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] A better understanding of the present invention can be
obtained when the following detailed description of example
embodiments are considered in conjunction with the following
drawings, in which:
[0005] FIG. 1 shows schematic example of a drilling system;
[0006] FIG. 2 shows an example block diagram of the acquisition of
downhole data and the telemetry of such data to the surface in an
example drilling operation;
[0007] FIGS. 3A-3D show examples of pressure signal transmitter
assemblies suitable for use in a fluid telemetry system;
[0008] FIG. 4 shows an example embodiment of an optical
interferometer system used to detect downhole transmitted pressure
signals;
[0009] FIG. 5 shows an example of a measurement section fiber
adhered to a pliant substrate;
[0010] FIG. 6 is a block diagram showing an example of the
processing of a received optical signal; and
[0011] FIG. 7 is a chart of laboratory test data showing raw
interferometer data and integrated interferometer data compared to
conventional pressure sensor data for pressure signal
detection.
[0012] While the invention is susceptible to various modifications
and alternative forms, specific embodiments thereof are shown by
way of example in the drawings and will herein be described in
detail. It should be understood, however, that the drawings and
detailed description thereto are not intended to limit the
invention to the particular form disclosed, but on the contrary,
the intention is to cover all modifications, equivalents and
alternatives falling within the scope of the present invention as
defined by the appended claims.
DETAILED DESCRIPTION
[0013] Referring to FIG. 1, a typical drilling installation is
illustrated which includes a drilling derrick 10, constructed at
the surface 12 of the well, supporting a drill string 14. The drill
string 14 extends through a rotary table 16 and into a borehole 18
that is being drilled through earth formations 20. The drill string
14 may include a kelly 22 at its upper end, drill pipe 24 coupled
to the kelly 22, and a bottom hole assembly 26 (BHA) coupled to the
lower end of the drill pipe 24. The BHA 26 may include drill
collars 28, an MWD tool 30, and a drill bit 32 for penetrating
through earth formations to create the borehole 18. In operation,
the kelly 22, the drill pipe 24 and the BHA 26 may be rotated by
the rotary table 16. Alternatively, or in addition to the rotation
of the drill pipe 24 by the rotary table 16, the BHA 26 may also be
rotated, as will be understood by one skilled in the art, by a
downhole motor (not shown). The drill collars add weight to the
drill bit 32 and stiffen the BHA 26, thereby enabling the BHA 26 to
transmit weight to the drill bit 32 without buckling. The weight
applied through the drill collars to the bit 32 permits the drill
bit to crush the underground formations.
[0014] As shown in FIG. 1, BHA 26 may include an MWD tool 30, which
may be part of the drill collar section 28. As the drill bit 32
operates, drilling fluid (commonly referred to as "drilling mud")
may be pumped from a mud pit 34 at the surface by pump 15 through
standpipe 11 and kelly hose 37, through drill string 14, indicated
by arrow 5, to the drill bit 32. The drilling mud is discharged
from the drill bit 32 and functions to cool and lubricate the drill
bit, and to carry away earth cuttings made by the bit. After
flowing through the drill bit 32, the drilling fluid flows back to
the surface through the annular area between the drill string 14
and the borehole wall 19, indicated by arrow 6, where it is
collected and returned to the mud pit 34 for filtering. The
circulating column of drilling mud flowing through the drill string
may also function as a medium for transmitting pressure signals 21
carrying information from the MWD tool 30 to the surface. In one
embodiment, a downhole data signaling unit 35 is provided as part
of MWD tool 30. Data signaling unit 35 may include a pressure
signal transmitter 100 for generating the pressure signals
transmitted to the surface.
[0015] MWD tool 30 may include sensors 39 and 41, which may be
coupled to appropriate data encoding circuitry, such as an encoder
38, which sequentially produces encoded digital data electrical
signals representative of the measurements obtained by sensors 39
and 41. While two sensors are shown, one skilled in the art will
understand that a smaller or larger number of sensors may be used
without departing from the principles of the present invention. The
sensors 39 and 41 may be selected to measure downhole parameters
including, but not limited to, environmental parameters,
directional drilling parameters, and formation evaluation
parameters. Such parameters may comprise downhole pressure,
downhole temperature, the resistivity or conductivity of the
drilling mud and earth formations, the density and porosity of the
earth formations, as well as the orientation of the wellbore.
[0016] The MWD tool 30 may be located proximate to the bit 32. Data
representing sensor measurements of the parameters discussed may be
generated and stored in the MWD tool 30. Some or all of the data
may be transmitted in the form of pressure signals by data
signaling unit 35, through the drilling fluid in drill string 14. A
pressure signal travelling in the column of drilling fluid may be
detected at the surface by a signal detector unit 36 employing
optical fiber loop 230. The detected signal may be decoded in
controller 33. The pressure signals may be encoded binary
representations of measurement data indicative of the downhole
drilling parameters and formation characteristics measured by
sensors 39 and 41. Controller 33 may be located proximate the rig
floor. Alternatively, controller 33 may be located away from the
rig floor. In one embodiment, controller 33 may be incorporated as
part of a logging unit.
[0017] FIG. 2 shows a block diagram of the acquisition of downhole
data and the telemetry of such data to the surface in an example
drilling operation. Sensors 39 and 41 acquire measurements related
to the surrounding formation and/or downhole conditions and
transmit them to encoder 38. Encoder 38 may have circuits 202
comprising analog circuits and analog to digital converters (A/D).
Encoder 38 may also comprise a processor 204 in data communication
with a memory 206. Processor 204 acts according to programmed
instructions to encode the data into digital signals according to a
preprogrammed encoding technique. One skilled in the art will
appreciate that there are a number of encoding schemes that may be
used for downhole telemetry. The chosen telemetry technique may
depend upon the type of pressure signal transmitter 100 used.
Encoder 38 outputs encoded data 208 to data signaling unit 35. Data
signaling unit 35 generates encoded pressure signals 21 that
propagate through the drilling fluid in drill string 14 to the
surface. Pressure signals 21 are detected at the surface by signal
detector 36 and are transmitted to controller 33 for decoding. In
one example embodiment, signal detector 36 may be a fiber optic
signal detector, described below. Controller 33 may comprise
interface circuitry 65 and a processor 66 for decoding pressure
signals 21 into data 216. Data 216 may be output to a user
interface 218 and/or an information handling system such as logging
unit 220. Alternatively, in one embodiment, the controller
circuitry and processor may be an integral part of the logging unit
220.
[0018] FIGS. 3A-3D show example embodiments of pressure signal
transmitter 100. FIG. 3A shows a pressure signal transmitter 100a
disposed in data signaling unit 35a. Pressure signal transmitter
100a has drilling fluid 5 flowing therethrough and comprises an
actuator 105 that moves a gate 110 back and forth against seat 115
allowing a portion of fluid 5 to intermittently pass through
opening 102 thereby generating a negative pressure signal 116 that
propagates to the surface through drilling fluid 5.
[0019] FIG. 3B shows a pressure signal transmitter 100b disposed in
data signaling unit 35b. Pressure signal transmitter 100b has
drilling fluid 5 flowing therethrough and comprises an actuator 122
that moves a poppet 120 back and forth toward orifice 121 partially
obstructing the flow of drilling fluid 5 thereby generating a
positive pressure signal 126 that propagates to the surface through
drilling fluid 5.
[0020] FIG. 3C shows a pressure signal transmitter 100c disposed in
data signaling unit 35c. Pressure signal transmitter 100c has
drilling fluid 5 flowing therethrough and comprises an actuator 132
that continuously rotates a rotor 130 in one direction relative to
stator 131. Stator 131 has flow passages 133 allowing fluid 5 to
pass therethrough. Rotor 130 has flow passages 134 and the movement
of flow passages 134 past flow passages 133 of stator 131 generates
a continuous wave pressure signal 136 that propagates to the
surface through drilling fluid 5. Modulation of the continuous wave
pressure signal may be used to encode data therein. Modulation
schemes may comprise frequency modulation and phase shift
modulation.
[0021] FIG. 3D shows a pressure signal transmitter 100d disposed in
data signaling unit 35d. Pressure signal transmitter 100d has
drilling fluid 5 flowing there through and comprises an actuator
142 that rotates a rotor 140 back and forth relative to stator 141.
Stator 141 has flow passages 143 allowing fluid 5 to pass
therethrough. Rotor 140 has flow passages 144 and the alternating
movement of flow passages 144 past the flow passages 143 of stator
141 generates a continuous wave pressure signal 146 that propagates
to the surface through drilling fluid 5. Modulation of the
continuous wave pressure signal may be used to encode data therein.
Modulation schemes may comprise frequency modulation and phase
shift modulation.
[0022] FIG. 4 shows an example of signal detector 36 configured as
an optical interferometer 200 for detecting pressure signals in
conduit 211. Interferometer 200 comprises a light source 202, an
optical fiber loop 230, an optical coupler/splitter 215, and an
optical detector 210. Light source 200 may be a laser diode, a
laser, or a light emitting diode that emits light into optical
coupler/splitter 215 where the light is split into two beams 231
and 232. Beam 231 travels clockwise (CW) through loop 230, and beam
232 travels counter-clockwise (CCW) through loop 230.
[0023] Loop 230 has a length, L, and comprises measurement section
220 and delay section 225. In one embodiment, measurement section
220 may be 2-10 meters in length. In this example, measurement
section 220 is wrapped at least partially around conduit 211, which
may be standpipe 11 of FIG. 1. Alternatively, measurement section
220 may be wrapped around any section of flow conduit that has
pressure signals travelling therein. The length of measurement
section 220 is designated by X in FIG. 4, and represents the length
of fiber that reacts to hoop strains in standpipe 11 caused by the
pressure signals therein. The optical fibers of measurement section
220 may be physically adhered to conduit 211. Alternatively, see
FIG. 5, measurement section 220 may comprise a length, X, of
optical fiber 302 adhered in a folded pattern to a pliant substrate
300 that is attachable to a conduit. In one embodiment, pliant
substrate 300 may be a biaxially-oriented polyethylene
terephthalate material, for example a Mylar.RTM. material
manufactured by E.I. Dupont de Nemours & Co. Pliant substrate
300 may be adhesively attached, for example, to standpipe 11 of
FIG. 1 using any suitable adhesive, for example an epoxy material
or a cyanoacrylate material.
[0024] Delay section 225 may be on the order of 500-3000 meters in
length. The small diameter of optical fibers contemplated (on the
order of 250 .mu.m) allows such a length to be wound on a
relatively small spool. As shown in FIG. 4, delay section 225
comprises a length identified as L-X. It will be seen that L is a
factor in the sensitivity of the sensor.
[0025] Counter-propagating beams 231, 232 traverse loop 230 and
recombine through coupler/splitter 215, and detected by
photo-detector 210. Under uniform (constant in time) conditions,
beams 231, 232 will recombine in phase at the detector 210 because
they have both traveled equal distances around loop 230. Consider
counter-propagating beams 231, 232 and a time varying pressure P(t)
in standpipe 11. Beams 231, 232 will be in phase after they have
traveled the distance X in their two paths, and they will be in
phase after they have continued through the distance L-X as well.
Now, let the pressure within the pipe be changing at a rate of
dP/dt during the time .DELTA.t while beams 231, 232 travel the
distance L-X, then
.DELTA.t=(L-X)n/c,
[0026] where c is the speed of light, and n is the refractive index
of the optical fiber. During this time interval, the pressure
within the pipe changes by an amount .DELTA.P, which acts to
radially expand standpipe 11. This expansion results in a change
.DELTA.X in the length, X, of the measurement section 220 of
optical fiber 230 wrapped around conduit 211. Although at the end
of the interval .DELTA.t the two beams are in phase, they will go
out of phase for the last portion of the circuit before they
recombine, because the length of measurement section 220 has
changed during the previous interval .DELTA.t. For the final leg of
the trip around the loop, the counter-clockwise beam 232 will
travel a distance that is different by an amount .DELTA.X from the
clockwise rotating beam 231. When the beams combine at detector
210, they will be out of phase by a phase difference, .DELTA..phi.,
where
.DELTA..phi.=2.pi.(.DELTA.X)/n.lamda.,
[0027] where .lamda. is the wavelength of the light emitted by
source 202. As beams 231, 232 are combined, it can be shown that a
factor in the signal will be cos(.DELTA..phi./2). Thus, counter
propagating beams 231, 232 will be out of phase when
.DELTA.X=.lamda..
[0028] The change of the pressure in the pipe during the interval
.DELTA.t is given by
.DELTA.P=(dP/dt).DELTA.t=(dP/dt)(L-X)(n/c).
Let K be the sensitivity of the pipe to internal pressure; that is,
the change in circumference of the pipe .DELTA.C due to a change in
pressure .DELTA.P given by,
.DELTA.C=K(.DELTA.P)
K can be computed from dimensions and material properties of the
pipe materials. For example, for a thin-walled pipe, where
D.sub.pipe>10*pipe thickness, t, it can be shown that
K=.pi.D.sub.pipe.sup.2/2Et
[0029] where E is the modulus of elasticity of the pipe
material.
For a thick walled pipe, where D.sub.pipe.ltoreq.10*pipe thickness,
t, it can be shown that
K=2.pi.D.sub.oD.sub.i.sup.2/E(D.sub.o.sup.2-D.sub.i.sup.2)
[0030] where D.sub.o and D.sub.i are the outer and inner pipe
diameters, respectively.
If N.sub.coil is the number of turns of fiber around the pipe,
then
.DELTA.X=N(.DELTA.C)=N.sub.coilK(dP/dt)(L-X)(n/c).
Thus, the change in length indicated by the interferometer is a
function of the time derivative of the pressure signal, the number
of turns N.sub.coil of fiber on the pipe, and the length L of the
delay portion of the fiber.
[0031] FIG. 6 is a block diagram showing an example of the
processing of a received optical signal using interferometer 200.
Counter propagating beams 231, 232 travel through optical fiber 230
comprising measurement section 220 and delay section 225. In this
example, delay section 225 comprises multiple loops of optical
fiber around a spool. Pressure signal 21 causes a lengthening of
measurement section 220 which produces a phase shift in the
recombined beams at detector 210, as described previously. Detector
210 outputs a phase shift signal that is conditioned by signal
conditioner 312 and outputs as an analog signal proportional to the
time derivative of pressure dp/dt at 314. The signal 314 is
transmitted to A/D in block 316 where the dp/dt signal is
digitized. The digitized dp/dt signal is integrated in block 318 to
produce a digital signal similar to the original pressure signal
P(t). The P(t) signal is then decoded in block 320 to produce data
216. Data 216 may be used in log modules 324 to produce logs 326.
In one embodiment, optical source 202, optical detector 210, and
signal conditioner 312 may be physically located close to conduit
211 in signal detector 36. Alternatively, some of these items may
be located away from conduit 211, for example in controller 33. The
functional modules 316, 318, 320, 324, and 326 may comprise
hardware and software and may be located in controller 33. In one
embodiment, controller 33 may be a stand alone unit located in a
separate location, for example a logging unit. Alternatively,
controller 33 may be an integral part of a logging unit using
shared hardware and software resources. While described above with
reference to a single optical signal detector on a conduit, it is
intended that the present disclosure cover any number of such
detectors space out along such a conduit.
[0032] FIG. 7 is a chart of laboratory test data showing raw
interferometer data and integrated interferometer data compared to
conventional pressure sensor data for pressure signal detection.
Pressure signals are generated in a flowing fluid in a flow loop. A
pressure signal transmitter generates pressure signals into the
flowing fluid. An interferometer similar to interferometer 200 is
installed on a section of conduit. A conventional strain gauge
pressure sensor is mounted within 2 m of the interferometer. FIG. 7
shows the raw interferometer data proportional to dp/dt in curve
700. The raw data is processed as described above to produce an
integrated interferometer curve 710. Curve 705 is the reading from
the conventional pressure transducer. As shown in FIG. 7,
integrated interferometer curve 710 is substantially similar to
conventional pressure transducer curve 705.
[0033] Numerous variations and modifications will become apparent
to those skilled in the art. It is intended that the following
claims be interpreted to embrace all such variations and
modifications.
* * * * *