Note: Descriptions are shown in the official language in which they were submitted.
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Technique And System For MeasurinR A Characteristic In A Subterranean Well
Back rg ound
The invention generally relates to a technique and system for measuring
temperature
in a subterranean well.
It is often desirable to measure the temperature at several locations in a
subterranean
well. For example, temperature measurements may be used to observe the
movement of an
artificially-induced or naturally-occurring temperature region (a "cold spot"
or a "hot spot") in
a particular region in the well for purposes of determining a fluid velocity,
or flow rate, in that
region of the well. Temperature measurements from the well may be used for a
variety of
other purposes.
There are several different types of temperature measurement systems for use
in
subterranean wells. A distributed temperature sensor (DTS)-based temperature
measurement
system uses a sensor that can provide data that is spatially distributed over
many thousands of
individual measurement points inside the well. One such DTS is an optical
fiber, an element
whose optical properties are sensitive to its temperature.
When used as a sensor, the optical fiber is deployed downhole so that the
optical fiber
extends into the region where temperature measurements are to be made. As
examples of
possible deployment mechanisms, the optical fiber may be deployed downhole
with the well
casing string or deployed downhole in a conduit that may extend through the
central
passageway of the casing string.
As a more specific example of a DTS-based temperature measurement system, an
optical time domain reflectometry (OTDR) technique may be used to detect the
spatial
distribution of temperature along the length of an optical fiber. More
specifically, pursuant to
the OTDR technique, temperature measurements may be made by introducing
optical energy
into the optical fiber by opto-electronics at the surface of the well. The
optical energy that is
introduced into the optical fiber produces backscattered light. The phrase
"backscattered
light" refers to the optical energy that returns at various points along the
optical fiber back to
the opto-electronics at the surface of the well. More specifically, in
accordance with OTDR,
a pulse of optical energy typically is introduced to the optical fiber at the
well surface, and the
resultant backscattered optical energy that returns from the fiber to the
surface is observed as
a function of time. The time at which the backscattered light propagates from
the various
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points along the fiber to the surface is proportional to the distance along
the fiber from which
the backscattered light is received.
In a uniform optical fiber, the intensity of the backscattered light as
observed from the
surface of the well exhibits an exponential decay with time. Therefore,
knowing the speed of
light in the fiber yields the distances that the light has traveled along the
fiber. Variations in
the temperature show up as variations from a perfect exponential decay of
intensity with
distance. Thus, these variations are used to derive the distribution of
temperature along the
optical fiber.
In the frequency domain, the backscattered light includes the Rayleigh
spectrum, the
Brillouin spectrum and the Raman spectrum. The Raman spectrum is the most
temperature
sensitive with the intensity of the spectrum varying with temperature,
although all three
spectrums of the backscattered light contain temperature information. The
Raman spectrum
typically is observed to obtain a temperature distribution from the
backscattered light.
Another technique that may be used in conjunction with a DTS-based temperature
measurement system is an optical frequency domain reflectometry (OFDR)
technique. As is
known in the art, OFDR is not time domain based like the OTDR technique.
Rather, OFDR
is based on frequency.
Another type of temperature measurement system embeds gratings, called fiber
Bragg
gratings (FBGs), in an optical fiber for purposes of sensing downhole
temperatures. An FBG-
based temperature measurement system is described in, for example, U.S. Patent
No.
5,380,995. These Bragg gratings may also measure strain.
Fiber Bragg gratings are manufactured by a variety of methods inside the core
of
standard telecommunications grade single mode fiber. Referring to Fig. 1, a
standard single
mode fiber 1 includes an eight micron diameter core glass material 2 that is
surrounded by a
125 micron cladding glass material 3, of a different index of refraction, that
gives the fiber 1
its waveguide properties. A fiber Bragg grating 4 is photowritten onto the
core material 2 by
ultraviolet laser radiation and represents a 4-6mm long periodic modulation in
the core's
index of refraction by approximately 0.01%.
This perturbation in the core yields a Bragg wavelength, )43, given by Bragg's
law:
)B =2nc A, Eq.(1)
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where n, is the effective core index of refraction and "A" is the period of
the index
modulation. The reflection peak , "XB," is linear with strain (called "E") and
temperature
(called "T") and is described by the following equation:
~~ =(1+~)OT+(1- pe)E, Eq. (2)
where ~ and pe are the thermal optics (dn/dT) coefficient and the photo
elastic coefficient,
respectively. Effectively a strain and temperature gauge inside an optical
fiber, the FBG has
demonstrated linear response down to nanostrain levels and up to 500 degrees
Centigrade.
During the manufacturing process, the period of modulation in the index of
refraction can be
adjusted to produce multiple FBGs on a single fiber each with a unique center
Bragg
wavelength, XB . The FBG-based system is therefore suitable for a multi-
sensing system with
a single optical fiber line because wavelength domain multiplexing (WDM) and
time domain
multiplexing (TDM) can be applied.
Fig. 2 depicts a conventional system 5 that uses FBGs. The system 5 includes
an
incoherent broadband light source 6 (with 50nm bandwidth) that is inserted
into a fiber optic
cable 7 that has several FBG's 8 written onto it at different spatial
locations. The system 5
also includes a detection subsystem 9. Each FBG 8 reflects a narrow band
fraction (typically,
0.2 nanometers) of the broadband source light with a unique wavelength (^, ^
uencoded tag.
The FBG's may be a few millimeters or kilometers apart, but they will maintain
the same
wavelength separation. As each Bragg grating 8 is subjected to strain or
temperature
variations, the center Bragg wavelength will move to shorter or longer
wavelengths,
independently of the others, and it is this wavelength change that is measured
by the
demodulation detection system shown.
Fig. 3 shows a spectral waveform 12 of a single Bragg grating as a function of
wavelength. Also depicted in Fig. 3 is a waveform 10 of the source light
emitting diode
(LED) 12. Typically, the demodulation system is attached via a fiber optic
beamsplitter
where a fraction of the returned light from the FBG is diverted from its
return to the light
source and into the demodulation system. Fig. 4 depicts the reflection
response of two FBG's
(depicted by spectral waveforms 13 and 14) when illuminated with a broadband
light emitting
diode (having a spectral waveform 15) in the near infrared band centered at
1300 nanometers.
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It will be understood by those skilled in the art that all
the Bragg gratings in Figures 3 and 4 may have the same
wavelength and the light source and demodulation system may
operate in a time division multiplexing mode thereby
identifying each FBG by light travel time in the fiber,
rather than wavelength. The thermal sensitivity of each
grating is still governed by equation 2. It is further
understood that the thermal response of the grating may be
enhanced mechanically by utilizing the strain response of a
Bragg grating by coupling the FBG to a material with a large
Coefficient of Thermal Expansion. A method for this is
described in US Patent Number 6,246,048.
Other kinds of sensors to measure physical and
chemical sensors include interferometric sensors and
attenuation based sensors.
Summary
In an embodiment of the invention, a technique
that is usable in a subterranean well includes deploying a
first sensor in a remote location to measure a distribution
of a characteristic along a segment at the location. The
technique includes deploying a second sensor downhole to
measure the characteristic at discrete points within the
segment. The second sensor is separate from the first
sensor.
According to one aspect of the present invention,
there is provided a method usable with a subterranean well,
comprising: deploying a distributed temperature sensor
downhole to measure a distribution of temperature along a
portion of the well; and deploying a multi-point sensor
system downhole to measure temperature at discrete points
within the portion with greater resolution than afforded by
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the distributed temperature sensor, the multi-point sensor
system being separate from the distributed temperature
sensor.
According to another aspect of the present
invention, there is provided a system usable with a
subterranean well, comprising: a first sensor extending
downhole in the form of a distributed sensor system to
measure a distribution of a characteristic along a portion
of the well; and a second sensor extending downhole to
measure the characteristic at discrete points within the
portion, the second sensor being separate from the first
sensor.
According to still another aspect of the present
invention, there is provided a characteristic measuring
method comprising: deploying a first sensor in a remote
location to measure a distribution of a characteristic along
a segment of the remote location; and deploying a second
sensor in the remote location to measure the characteristic
at discrete points within the segment, the second sensor
being separate from the first sensor.
According to yet another aspect of the present
invention, there is provided a characteristic measuring
system comprising: a first sensor located at a remote
portion to measure a distribution of a characteristic along
a segment at the remote portion; a second sensor extending
downhole to measure the characteristic at discrete points
within the remote portion, the second sensor being separate
from the first sensor; and a processor coupled to the first
sensor and the second sensor to control both the distributed
sensing of the characteristic and the sensing of the
characteristic at discrete points to obtain an improved
profile of the characteristic at the remote portion.
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Advantages and other features of the invention
will become apparent from the following description,
drawings and claims.
Brief Description Of The Drawings
Fig. 1 is a schematic diagram of a fiber Bragg
grating inside a single mode optical fiber of the prior art.
Fig. 2 is a schematic diagram of a Bragg grating
sensor system of the prior art.
Fig. 3 is an illustration of a wavelength spectrum
of a single Bragg grating of the prior art.
Fig. 4 is an illustration of the reflection
spectrum of two wavelength separated Bragg gratings along
with an LED light source spectrum of the prior art.
Figs. 5, 6 and 9 are schematic diagrams of systems
to measure the temperature inside a subterranean well
according to different embodiments of the invention.
Fig. 7 is a flow diagram depicting a technique to
measure temperature inside a subterranean well according to
an embodiment of the invention.
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Fig. 8 is a flow diagram depicting a technique to measure a flow velocity in a
subterranean well according to an embodiment of the invention.
Fig. 10 is a schematic diagram of a single mode optical fiber according to an
embodiment of the invention.
Detailed Description
Referring to Fig. 5, in accordance with an embodiment of the invention, a
temperature
measurement system 19 for a subterranean well includes at least two types of
temperature
measurement subsystems, each of which is associated with a different and
separate downhole
temperature sensor. One of these temperature measurement subsystems may be a
distributed
temperature sensor (DTS)-based temperature measurement system that observes
the intensity
of backscattered light from an optical fiber 38 that extends into a wellbore
18 of the well.
Another one of the temperature measurement subsystems may be a fiber Bragg
grating
(FBG)-based temperature measurement system that observes the spectral energy
of light that
is reflected from FBGs that are embedded in an optical fiber 34 that extends
into the wellbore
18.
The installation of DTS-based temperature measurement systems within the oil
industry has had significant acceptance. Unlike any combination of discrete
electrical or fiber
optic sensors, the DTS system produces a unique distributed measurement of
temperature that
cannot be achieved by any other technology. This application has been
especially accelerated
in permanent installations for vertical and deviated oil wells, where a single
"snapshot" of the
geothermal profile of the entire well length can be taken in a few minutes.
The typical
geothermal gradient is 3 to 6 degrees C per 30 meters of depth.
In addition to measurements of the geothermal gradient, for production logging
purposes, analysis of DTS results has replaced the traditional wireline
temperature
measurement for the location of open channels in cement behind casing, fluid
entries in
perforated wells and fluid front movement in steam-injected wells. These are
typical
production monitoring applications where the measurement precision of a
typical DTS
system, typically 0.5 degree C but as low as 0.1 degree C would be acceptable.
Other
production quantities, such as the temperature profile near an electrical
submersible pump
(ESP) to produce artificial lift, has had a great diagnostic benefit.
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Near positions where the reservoir fluid enters the wellbore, very small
thermal
changes can occur over extended periods of time that can indicate fluid
movement at a
distance away from the wellbore. To determine this movement, it is generally
agreed that a
temperature measurement with a minimum 0.1 degree C resolution and as low as
millidegrees
is required. The resolution afforded by a fiber optic temperature sensor based
on FBG sensor
element can achieve this level of measurement quality. Also, the spatial
resolution from the
FBG sensor element placement can be as low as millimeters. DTS systems
typically give a
true minimum spatial resolution of 1 meter.
The placement of an array of FBGs within a vertical or deviated well can be
optimized
to minimize sensor and deployment costs. When the natural temperature
variation along a
well is small, as in a horizontal well, high precision discrete sensors may be
required to
measure the temperature changes induced by produced fluids. However, cost or
complexity
may limit the number of discrete sensors, so that they are widely spaced or
monitor only a
small part of the well. In that case, a DTS system can monitor the rest of the
well, to detect or
quantify events that can cause larger changes in temperature, such as fluid
arriving from a
different vertical depth or fluids of different temperature injected into the
formation by
another well.
However, a Bragg array alone would not be able to cover the entire well from
surface
to the well bottom due to cost and technology limitations. For FBG technology
to mimic a
DTS system with 1-meter resolution for a 10km well would require 10,000 Bragg
sensor
elements. An array of this size would be technologically challenging and
perhaps very costly.
Therefore the system 19 provides a way to measure both small and large
temperature
variations simultaneously. In some embodiments of the invention, the system 19
delivers the
thermal profile of the entire well, along with an optimized placement of
highly precise and
accurate sensor arrays in a specified zone of interest in the well.
There are several applications where the combination of a distributed
measurement,
such as temperature, can be intelligently combined with a optimized placement
of discrete
measurements (i.e. temperature) to produce a unique measurement of both large
and small
thermal changes important to the oil field specialist.
One application for the combination of a distributed and multi-point
temperature array
to provide coarse and fine resolutions for the measurement of temperature is
in extended
reach oil wells, i.e., wells that exceed 5 kilometers in length. Generally it
is known that for
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DTS systems using multimode fiber, the resolution of the system decreases with
the fiber
distance from the DTS electronics. Although there are various ways to extend
the range of
the DTS system, the resolution at greater distances deviates from 0.1 degree C
significantly.
Also, the DTS opto-electronics has typically a dynamic range of 20dB. Using
normal
multimode fiber with attenuation per unit length of 2 dB/km, the maximum DTS
range would
be 10 km. Acquiring measurements beyond some range can become difficult due to
lack of
sufficient signal. I
Bragg grating technology, which operates in a more favorable wavelength range
where the attenuation per unit length is less than 0.5dB/km and where the
power return is
significantly greater than from the Raman process, can produce 0.0 10 degree C
precision at
distances to 20km or greater. Generally, the most interesting location for
high precision
temperature measurements is at the farthest or most extended reach of the oil
well.
It is therefore desired, for extended reach weils, to have a combined system
that can
give an inexpensive distributed temperature profile of the entire well up to
the limit capable
by a DTS-like system (e.g. Raman or Brillouin) followed by a well designed
placement of a
Bragg based temperature sensor array or arrays, in one or more zones, that can
provide 1) a
measurement and/or 2) better resolution and accuracy.
Generally, however, the combination of a distributed and multi-point
temperature
array to provide coarse and fine resolutions for the measurement of
temperature may be used
in any application requiring a higher degree of resolution and/or accuracy
than provided by a
stand-alone distributed temperature measurement. Another such application is
the
determination of fluid velocity as previously disclosed.
Turning now to a more specific discussion of the DTS-based temperature
measurement system, in some embodiments of the invention, the DTS-based
temperature
measurement system uses an optical time domain reflectometry (OTDR) technique
to
measure a temperature distribution along a region (the entire length, for
example) of the
optical fiber 38. Thus, the optical fiber 38 forms at last part of a sensor to
measure a
distribution of a characteristic along a portion of the well. The DTS-based
temperature
measurement system is capable of providing a spatial distribution of thousands
of
temperatures measured in a region of the well along which the optical fiber 38
extends. It is
noted that a DTS-based temperature measurement system other that OTDR, such as
OFDR,
may be used in other embodiments of the invention. In addition, a Brillouin
spectrum-based
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DTS system may be used in some embodiments of the invention (instead of
Raman).
Alternatively, a Rayleigh spectrum-based DTS system may be used, etc.
As noted above, a potential shortcoming of the DTS-based temperature
measurement
system is that the temperature resolution and accuracy of the DTS temperature
measurement
system may be inadequate for some applications. For example, in some
embodiments of the
invention, the DTS temperature measurement system may be limited to a
temperature
resolution of about 0.1 Celsius (C). This means that, in this scenario, the
DTS temperature
measurement system cannot be relied on to resolve temperature differences less
than 0.1 C.
This resolution limit, in turn, may affect the measurement of various well
properties, such as
(for example) the determination of a fluid velocity inside a particular zone
in the well.
For example, it may be desirable to determine a fluid velocity in an exemplary
zone
50 of interest that is depicted in Fig. 5. However, with the above-described
resolution
limitation of DTS temperature measurement system, the fluid velocity may not
be able to be
determined. As a more specific example, to measure the fluid velocity, a
tubular member 40
may be inserted into the wellbore 18, and this tubular member 40 may extend
into the zone
50. The tubular member 40 has ports 42 through which a temperature-altering
fluid may be
introduced into the zone 50 for purposes of creating a temperature pocket, or
spot, in the zone
50. For example, via the tubular member 40, a relatively cool fluid may be
introduced into
the zone 50 for purposes of creating a cool spot in the zone 50. With the use
of temperature
measurements, the fluid velocity may be determined by observing the movement
of this spot.
However, the cool spot may be quite small, and may not be detectable due to
the resolution
constraints of the DTS-based temperature measurement system.
Not only may artificially-injected cool spots be introduced into the well for
purposes
of measuring fluid velocity, naturally-occurring cool spots may be observed in
the well to
determine a fluid velocity. However, these naturally-occurring cool spots
typically are quite
small and may not be detectable with the DTS-based temperature measurement
system due to
its resolution limits. The DTS-based temperature measurement system may also
be
inadequate to derive a flow velocity for flow velocity determinants
techniques. For example,
the tubular member 40 may alternatively include a heater coil for purposes of
injecting a hot
spot (instead of a cold spot) into the zone to accomplish the above-described
temperature
movement observation. Likewise, although a vertical wellbore 18 is depicted in
Fig. 5, flow
velocity may also be determined in a lateral, or generally horizontal,
wellbore. In lateral
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wellbores, there is no naturally occurring large thermal differences through
the wellbore.
However, a small thermal anomaly may occur in the horizontal well in which a
thermal
region of a particular temperature may be observed moving laterally through
the wellbore.
These anomalies are also quite small and may present challenges when using a
DTS-based
temperature measurement system.
It has been discovered that an FBG-based temperature measurement system may be
used in combination with the DTS-based temperature measurement system for
purposes of
enhancing the resolution of the temperature measurement. In this manner, the
FBG-based
measurement system may aid the DTS-based temperature measurement system for
purposes
of resolving small temperature differences and improving measurement accuracy,
in some
embodiments of the invention. The optical fiber 34 of the FBG-based
temperature
measurement system includes an array of fiber Bragg gratings (FBGs) 36, such
as the FBGs
36 that are depicted inside the zone 50 of Fig. 1. Thus, the optical fiber 34
forms at least part
of a sensor to measure a characteristic at discrete points with a portion of
the well; and this
sensor may include one or more FBGs 36.
In some embodiments of the invention, each FBG 36 provides one temperature
measurement, and this temperature measurement has a resolution of about 10
millidegrees
Celsius (m C), a resolution that may overcome the resolution limits of the
above-described
DTS-based temperature measurement system. A method to increase the fundamental
thermal
resolution of a FBG is described in US Patent Number 6,246,048 by utilizing
the strain
response of a Bragg grating by coupling the FBG to a material with a large
Coefficient of
Thermal Expansion.
In some embodiments of the invention, the DTS-based temperature measurement
system may tend to lose resolution over greater lengths (above 7 kilometers
(km), for
example), whereas the FBG-based measurement system may suffer little
degradation in
temperature readings for lengths of 20 km or more. The FBG-based temperature
measurement system, in some embodiments of the invention, may provide
temperature
measurements in the order of seconds, as compared to the temperature
distribution from the
DTS-based temperature measurement system that may take in the order of
minutes.
As depicted in Fig. 5, the array may include several FBGs 36 that are spaced
over a
particular zone of interest, such as the zone 50. Each FBG 36 provides a
temperature
measurement. Each FBG 36 reflects at a Bragg wavelength, 1, and the
wavelengths that the
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FBG 36 reflects is a function of the effective core index of refraction, n,
and the period of the
index modulation, L of the FBG 36 as described by Eq 1. Therefore, temperature
affects the
wavelength location of the spectral band of energy that is reflected by the
FBG 36. Thus, a
temperature may be measured via a particular FBG 36 by introducing optical
energy (into the
optical fiber 34) that has wavelengths that include the possible wavelengths
of the reflected
spectral band. The wavelengths of the reflected spectral band are then
observed to derive a
temperature measurement at the location of the FBG 36 as described by Eq 2. In
some
embodiments of the invention, each FBG may have a different grating spacing or
wavelength
1, for purposes of distinguishing one FBG-based measurement from another. In
another
embodiment of the invention, each FBG may have the same grating spacing or
wavelength 1c
and the array of FBG 36 is distinguished via time. Other FBG interrogations
electronics or
combinations of interrogation methods are possible and not excluded by this
invention. In
one embodiment, more than one FBG array 36 may be incorporated at different
zones of
interest along the optical fiber 34.
A potential shortcoming of the FBG-based temperature measurement system is
that
the system FBG provides a limited number of discrete temperature measurements,
as
compared to the thousands of spatially distributed temperature measurements
that are
provided by a DTS-based temperature measurement system. Furthermore, each FBG
may be
relatively expensive to make on a per unit length of fiber basis. However,
unlike the DTS
system that provides a distributed temperature measurement along the entire
length of the
optical fiber 38, in the FBG temperature measurement system, the FBG 36 are
located only in
certain zones of interest along the optical fiber 34.
Therefore, the DTS-based measurement system may be used to obtain temperature
measurements outside of regions in which the FBG arrays 36 of the optical
fiber 34 are
located. In this manner, in some embodiments of the invention, the FBG arrays
36 may be
used to obtain discrete, higher resolution measurements in a particular zone
of the well, and
the optical fiber 38 may be used to obtain spatially distributed, lower
resolution
measurements outside of these zones. Thus, the measurements from both
temperature
measurement systems may be selectively combined to yield a spatially
distributed set of
temperature measurements that have high resolution where desired.
In some embodiments of the invention, the FBG-based temperature system may
provide more accurate temperature measurements than the measurements that are
provided by
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the DTS-based temperature measurement system. Thus, in some embodiments of the
invention, the measurements from these two temperature measurement systems may
be
combined for purposes of increasing the accuracy of temperature measurements
from a
particular zone, such as the zone 50. As an example, to increase the accuracy
of the
temperature measurements, the measurements derived from the DTS temperature
measurement system along a particular region of the wellbore may be combined
with the
measurements derived from the FBG-based temperature measurement system along
the same
region. For instance, the FBG measurements may be used to correct any
discrepancies in the
DTS measurements for the given interval. As previously disclosed, the FBG
system has a
higher accuracy than the DTS system. At the same spatial location, the
difference between
the FBG measurement and the DTS measurement may be applied to the DTS
measurements
to correct any discrepancy in the DTS measurement. This and other examples of
similar
methods are in U.S. Patent Publication No. 2003-023492 1.
Referring now to a more specific configuration of the system 19, in some
embodiments of the invention, a processor (a microprocessor, for example) 20
may execute a
program 32 that is stored in a memory 30 for purposes of performing the FBG
and DTS based
temperature measurements. In this manner, the processor 20 may control a
demodulation
system (spectrum analyzer for example) 28 and two wavelength-tunable light
sources 22 and
24. The system 19 may also include other optical components not shown in Fig.
5. For
example, for each optical fiber 34, 38 the system 19 may include a directional
coupler and
optical filtering subsystem. Other variations are possible. As an example, in
some
embodiments of the invention, the system 19 may include a single light source
(instead of
two) that is multiplexed between the optical fibers 34 and 38.
For purposes of performing a DTS temperature measurement, the processor 20 may
control the light source 22 so that the light source 22 emits pulses of light
at a predefined
wavelength (a Stokes wavelength, for example) into the optical fiber 38. In
response to the
pulses of light, backscattered light is produced by the optical fiber 38, and
this backscattered
light retums to the spectrum analyzer 28. The demodulation system 28, in turn,
measures the
intensity of the resultant backscattered light at the predefined wavelength.
Using OTDR
techniques, the processor 20 processes the intensities that are detected by
the optical spectrum
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analyzer 28 to calculate the temperature distribution along some portion (the
entire length, for
example) of the optical fiber 38.
The processor 20 also operates the light source 24 to introduce optical energy
into the
optical fiber 34 at the appropriate frequencies/wavelengths. The processor 20,
via the
demodulation system 28, uses the array of FBGs 36 to obtain temperature
measurements at
discrete points, each of which is associated with a particular FBG 36. The
spatial locations of
the FBGs 36 may be distinguishable, in some embodiments of the invention, by
the different
wavelength or time delay that is associated with each FBG 36. The FBGs 36 are
installed in a
strain free manner, and they may be mechanically enhanced for better
temperature resolution.
The FBGs may be interrogated in a variety and combination of ways, such as
wavelength
division multiplexing (WDM), time division multiplexing (TDM), or systems to
interrogate a
series of weak or low reflectivity Bragg gratings with a reference
interferometer as described
in US Patent Number 5,798,521 and developed by the US space agency NASA.
In some embodiments of the invention, both sensors 34 and 38 are deployed in
control
conduits that may be clamped to a tubular string (such as the tubular member
40) or located
outside of the casing string 18.
Referring to Fig. 6, in some embodiments of the invention, the system 19 may
be
replaced by the system 60. The two systems 10 and 60 are similar, except that
the single-
ended optical fiber 38 of Fig. 1 is replaced by a U-shaped, double-ended
optical fiber 39. In
this manner, the U-shaped optical fiber 39 extends along the length of the
wellbore 18 and
returns at its bottom point 63 to the surface of the well so that the two ends
of the fiber 39 are
present at the surface of the well. This arrangement may be particularly
desirable due to the
resultant increase in accuracy. In this manner, the optical fiber 39 provides
two sets of
measurements that may be combined together to improve the accuracy of DTS
measurements
from the optical fiber 39. Furthermore, should one of the strands become
damaged, the
remaining strand may be used in a single-ended mode.
Referring to Fig. 7, in some embodiments of the invention, a technique 80 may
be
used for purposes of integrating the temperature measurements provided by both
temperature
measurement subsystems to enhance the accuracy/resolution of these
measurements. More
specifically, in some embodiments of the invention, in the technique 80, the
DTS (i.e., the
optical fiber 38) is deployed downhole, as depicted in block 82. Also, the FBG-
based sensor
(i.e., the optical fiber 34 having the embedded FBGs 36) is deployed downhole
in the zone 50
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or zones 50, as depicted in block 84. As described above, the FBG-based sensor
may be used
to measure temperatures at discrete points in the zone 50 or zones 50, and the
DTS may be
used to measure a temperature distribution inside and outside of the zone 50.
As also
described above, the discrete temperature measurements provided by the FBG-
based
temperature measurements generally provide higher resolution and more accurate
readings in
the zone 50. Thus, for purposes of increasing the accuracy of temperature
measurements
from the zone 50, the processor 20 may combine both sets of measurements
together. For
purposes of resolving small temperatures (i.e., temperatures less than 0.1
C), the processor
20 may, for the zone 50, use only the measurements that are provided by the
FBGs 36 and use
the temperature measurements provided by the DTS outside of the zone 50. To
perform the
temperature measurements, averaging and selective substitution of the
temperature
measurements, the processor 20 may execute a program such as the program 36
(stored in the
memory 30).
Referring to Fig. 8, in some embodiments of the invention, a technique 100 may
be
used for purposes of performing a technique 100 to determine a flow velocity
inside the zone
50. In this manner, in the technique 100, a thermal, or temperature, spot is
injected (block
102) into a particular zone, such as the zone 50 (Fig. 5). This temperature
spot has a
temperature that is different from the overall temperature of the zone so that
the temperature
spot may be detected. Alternatively, the movement of a naturally-occurring
temperature spot
or an artificially-injected temperature spot may be observed in the zone 50.
Thus, the DTS-
based temperature measurement system may be used to track the temperature spot
inside and
outside of the zone 50, as depicted in block 104, and the FBG-based
temperature
measurement system may be used to track movement of the spot inside the zone
50, as
depicted in block 106. From this observed movement of the spot, the processor
20 (Fig. 5)
may then calculate (block 108) the flow velocity in a particular of the well,
such as in the
zone 50.
Although a vertical wellbore 18 is depicted in Fig. 8, the above-described
temperature
measurement techniques may be used in lateral wellbores. For example, Fig. 9
depicts a
system 200 for use in a lateral wellbore 202. In this system, the optical
fiber 38 that is part of
the DTS-based temperature measurement system and extends into the lateral
wellbore 202,
including a zone 204 of interest of the wellbore 202; and the optical fiber 34
that is part of the
FBG-based temperature measurement system extends into the wellbore 202,
including the
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zone 204. For purposes of enhancing the resolution of temperature
measurements, the optical
fiber 38 may be used for purposes of obtaining temperature measurements
outside of the zone
204; and inside the zone 204, the optical fiber 34 with its FBGs 36 may be
used for purposes
of obtaining higher resolution temperature measurements. For purposes of
enhancing the
accuracy of temperature measurements, both optical fibers 34 and 38 may be
used for
purposes of obtaining temperature measurements inside and outside of the zone
204; and
these measurements may be combined together. Other variations are possible.
For example,
the single-ended fiber 38 depicted in Fig. 5 may be replaced by a double-ended
fiber, in some
embodiments of the invention.
Other embodiments are within the scope of the following claims. For example,
in
some embodiments of the invention, one or both of the sensors, such as the
sensor 38 and/or
sensor 34 may be pumped downhole with a fluid for purposes of running the
sensor 38 and/or
sensor 34 downhole. As a more specific example, a conduit may be run downhole,
and fluid
may be pumped through the passageway of the conduit. At surface of the well,
the lower end
of the sensor 38 may be introduced into the fluid flow and for purposes of
permitting the fluid
flow to unwind the sensor 38 and/or sensor 34 from a spool at the surface of
the well to carry
the sensor 38 downhole.
As another example of another embodiment of the invention, the system 19 may
be
used in environments other than in a subterranean well. For example, in some
embodiments
of the invention, the system 19 may be used to measure temperature along a
segment (a pipe,
for example) of a remote location. For example, the system 18 may be used in
conjunction
with power cables or pipelines. As further examples, this remote location may
include
chemical processing equipment of a chemical plant (for example) or food
processing
equipment of a food processing/preparation plant (for example). Other remote
locations are
possible.
In some embodiments of the invention, the system 19 may measure a
characteristic
other than temperature. For example, in some embodiments of the invention, the
DTS-based
measurement may measure a distribution of stress, and the FBG-based
measurement system
may measure the stress at specific points. Characteristics other than
temperature and/or stress
may be measured, in other embodiments of the invention.
In some embodiments of the invention, the zone 50 may include part of a
formation,
an entire formation, several formations, etc.
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In some embodiments of the invention, the DTS-based and FBG-based measurement
systems may be used to obtain production as well as reservoir information from
the wellbore.
Typically, DTS is used only to obtain production data (data from the flowing
fluid). FBGs,
which give much better resolution, can be used to obtain reservoir data (data
about the fluids
while they are still in the reservoir).
As yet another example, in some embodiments of the invention, both sensors 34
and
38 may be formed from a single, single mode optical fiber 300 that is depicted
in Fig. 10. In
some embodiments of the invention, if a particular FBG array 302 is located at
the bottom of
the fiber 300, the FBG array 300 may be attached via an adhesive to a bottom
segment 304 of
the optical sensor 34. Thus, in the context of this application, the sensors
34 and 38 are
deemed as being formed from a single optical fiber shared in common even if
the sensors 34
and 38 are formed from different optical fiber segments that are concatenated
to form the
single optical fibers. Incorporating both FBG-based aiid DTS-based
measurements into the
same optical fiber is possible because the FBG-based measurements may be
wavelength
selective (as an example), and the DTS-based measurements may be time
multiplexed (as an
example). One benefit of using a single fiber for both sensors 34, 38 is that
correlation
between separate fibers would not be necessary, which may be the case if each
sensor 34, 38
is part of a separate fiber.
While the present invention has been described with respect to a limited
number of
embodiments, those skilled in the art, having the benefit of this disclosure,
will appreciate
numerous modifications and variations therefrom. It is intended that the
appended claims
cover all such modifications and variations as fall within the true spirit and
scope of this
present invention.
