U.S. patent application number 14/908416 was filed with the patent office on 2017-05-25 for distributed sensor network.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to John L. Maida, JR., David L. Perkins.
Application Number | 20170145819 14/908416 |
Document ID | / |
Family ID | 57104093 |
Filed Date | 2017-05-25 |
United States Patent
Application |
20170145819 |
Kind Code |
A1 |
Maida, JR.; John L. ; et
al. |
May 25, 2017 |
DISTRIBUTED SENSOR NETWORK
Abstract
A system may include a sensor to detect a characteristic of a
fluid and output an electrical signal proportional to the
characteristic, an acoustic signal generator to output an acoustic
signal proportional to the electrical signal, and a signal
detection apparatus to generate a signal proportional to the
acoustic signal and transmit the signal to a remote location.
Inventors: |
Maida, JR.; John L.;
(Houston, TX) ; Perkins; David L.; (The Woodlands,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
57104093 |
Appl. No.: |
14/908416 |
Filed: |
July 2, 2015 |
PCT Filed: |
July 2, 2015 |
PCT NO: |
PCT/US15/39071 |
371 Date: |
January 28, 2016 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/135 20200501;
E21B 47/12 20130101; E21B 49/0875 20200501; E21B 47/14 20130101;
E21B 47/20 20200501; E21B 49/08 20130101 |
International
Class: |
E21B 49/08 20060101
E21B049/08; E21B 47/12 20060101 E21B047/12 |
Claims
1. A system, comprising: a sensor to detect a characteristic of a
fluid and output an electrical signal proportional to the
characteristic; an acoustic signal generator to output an acoustic
signal proportional to the electrical signal; and a signal
detection apparatus to generate a signal proportional to the
acoustic signal and transmit the signal to a remote location.
2. The system of claim 1, wherein the sensor comprises one of a
chemical sensor, an optical sensor, a pH sensor, a density sensor,
a viscosity sensor, a thermal sensor, and a pressure sensor.
3. The system of claim 1, wherein the acoustic signal generator
includes one of a piezoelectric device, a magnetostriction device,
an electro-optic device, and an electrostriction device.
4. The system of claim 1, wherein the signal detection apparatus
generates an optical signal proportional to the acoustic signal
using interferometric phase modulation techniques and transmits the
optical signal to the remote location.
5. The system of claim 4, wherein the signal detection apparatus is
positioned in an annulus defined between a wellbore and a casing
secured within the wellbore.
6. The system of claim 4, wherein the signal detection apparatus is
conveyed into a wellbore on slickline or wireline.
7. The system of claim 1, wherein the signal detection apparatus is
a non-fiber optic based apparatus that detects the acoustic
signal.
8. The system of claim 1, further comprising a frequency generator
that receives the electrical signal and generates a control signal
proportional to the electrical signal.
9. The system of claim 8, wherein the acoustic signal generator
comprises an acoustic transducer to receive the control signal and
generate the acoustic signal proportional to the control
signal.
10. The system of claim 1, wherein the acoustic signal generator
and the signal detection apparatus contact each other.
11. The system of claim 1, wherein the acoustic signal generator
and the signal detection apparatus are separated from each
other.
12. The system of claim 1, further comprising a processing unit
located at the remote location and configured to process the signal
from the signal detection apparatus to determine a location of the
fluid.
13. A method, comprising: monitoring a fluid in a wellbore with a
sensor; generating an electrical signal proportional to a
characteristic of the fluid with the sensor; generating a control
signal proportional to the electrical signal using a frequency
generator; generating an acoustic signal proportional to the
control signal using an acoustic transducer; detecting the acoustic
signal and generating a signal based on the acoustic signal using a
signal detection apparatus; and transmitting the signal to a remote
location.
14. The method of claim 13, further comprising generating an
optical signal proportional to the acoustic signal using the signal
detection apparatus, the optical signal being generated by the
signal detection apparatus using interferometric phase modulation
techniques.
15. The method of claim 13, further comprising generating the
acoustic signal when the electrical signal meets or exceeds a
predetermined threshold level, the threshold level corresponding to
the characteristic of the fluid measured by the sensor.
16. The method of claim 13, further comprising varying a frequency
of the control signal proportional to the electrical signal.
17. The method of claim 13, further comprising varying an amplitude
of the control signal proportional to the electrical signal.
18. The method of claim 13, further comprising varying a frequency
of the acoustic signal proportional to the control signal.
19. The method of claim 13, further comprising varying an amplitude
of the acoustic signal proportional to the control signal.
20. The method of claim 13, further comprising: generating the
acoustic signal having a predetermined base frequency; and shifting
the base frequency proportional to the characteristic of the fluid
measured by the sensor.
Description
BACKGROUND
[0001] In the oil and gas industry, it can be required to measure
the characteristics and/or compositions of substances located at
remote subterranean locations and convey the results to the earth's
surface for processing and analysis. For instance, it may be
required to measure chemical and/or physical properties of
substances located in subterranean hydrocarbon-bearing formations
and convey the results of the measurement over long distances to
the earth's surface. The measurements may be carried out using
electrical devices; however, there is a limited amount of
electrical power available to operate such electrical devices and
transmit the measurements over long distances to the surface using
electrical signals with a high signal-to-noise ratio (SNR).
BRIEF DESCRIPTION OF THE DRAWINGS
[0002] The following figures are included to illustrate certain
aspects of the present disclosure, and should not be viewed as
exclusive embodiments. The subject matter disclosed is capable of
considerable modifications, alterations, combinations, and
equivalents in form and function, without departing from the scope
of this disclosure.
[0003] FIG. 1A illustrates an exemplary well system that may embody
or otherwise employ one or more principles of the present
disclosure.
[0004] FIG. 1B illustrates an enlarged cross-sectional view of the
wellbore shown in FIG. 1A.
[0005] FIG. 2A illustrates an exemplary sensor included in a sensor
system of FIG. 1B.
[0006] FIG. 2B illustrates a cross-sectional side view of an
exemplary integrated computation element (ICE) included in the
sensor of FIG. 2A.
[0007] FIG. 3 illustrates an exemplary fiber optic based
Distributed Acoustic Sensing (DAS) network.
[0008] FIG. 4 illustrates another exemplary fiber optic based
Distributed Acoustic Sensing (DAS) network.
[0009] FIG. 5 illustrates an exemplary processing system for
configuring and/or controlling the sensor system of FIG. 1A and the
DAS networks of FIGS. 3 and 4.
DETAILED DESCRIPTION
[0010] Embodiments described herein relate to a distributed network
of sensors for measuring physical and/or chemical properties of
substances located in deep subterranean hydrocarbon reservoirs. The
distributed network can include a variety of sensors that are
located downhole for sensing chemical or physical properties of
substances located in the hydrocarbon reservoirs. Embodiments may
be directed to systems and methods for converting the electrical
signals obtained from the sensors to acoustic signals, converting
the acoustic signals to optical signals, and subsequently
transmitting the optical signals to the surface via fiber
optics.
[0011] Converting the electrical signals to acoustic signals may
permit deployment of sensors over long downhole distances without
the need for deploying long electrical conductors to the surface or
deploying power consuming processing units to convert and convey a
high SNR electrical signal to the surface.
[0012] As used herein, the term "fluid" refers to any substance
that is capable of flowing, including particulate solids, liquids,
gases, slurries, emulsions, powders, muds, glasses, combinations
thereof, and the like. In some embodiments, the fluid can be an
aqueous fluid, including water or the like. In some embodiments,
the fluid can be a non-aqueous fluid, including organic compounds,
more specifically, hydrocarbons, oil, a refined component of oil,
petrochemical products, and the like. In some embodiments, the
fluid can be a treatment fluid or a formation fluid as found in the
oil and gas industry. Fluids can include various flowable mixtures
of solids, liquids and/or gases. Illustrative gases that can be
considered fluids according to the present embodiments include, for
example, air, nitrogen, carbon dioxide, argon, helium, methane,
ethane, butane, and other hydrocarbon gases, combinations thereof
and/or the like.
[0013] As used herein, the term "characteristic" or "characteristic
of interest" refers to a chemical, mechanical, or physical property
of the fluid or a sample of the fluid, also referred to herein as
the substance or a sample of the substance. The characteristic of
the fluid may include a quantitative or qualitative value of one or
more chemical constituents or compounds present therein or any
physical property associated therewith. Such chemical constituents
and compounds may be referred to herein as "analytes." Illustrative
characteristics of the fluid that can be detected with the sensors
described herein can include, for example, chemical composition
(e.g., identity and concentration in total or of individual
components), phase presence (e.g., gas, oil, water, etc.), impurity
content, pH, alkalinity, viscosity, density, ionic strength, total
dissolved solids, salt content (e.g., salinity), porosity, opacity,
bacteria content, total hardness, transmittance, combinations
thereof, state of matter (solid, liquid, gas, emulsion, mixtures
thereof, etc.), and the like.
[0014] As used herein, the term "component," or variations thereof,
refers to at least a portion of a substance or material of interest
in the fluid to be evaluated using the sensors disclosed herein. In
some embodiments, the component is the characteristic of interest,
as defined above, and may include any integral constituent of the
fluid flowing within the flow path.
[0015] For example, the component may include compounds containing
elements such as barium, calcium (e.g., calcium carbonate), carbon
(e.g., graphitic resilient carbon), chlorine (e.g., chlorides),
manganese, sulfur, iron, strontium, chlorine, etc., and any
chemical substance that may lead to precipitation within a flow
path. The component may also refer to paraffins, waxes,
asphaltenes, clays (e.g., smectite, illite, kaolins, etc.),
aromatics, saturates, foams, salts, particulates, hydrates, sand or
other solid particles (e.g., low and high gravity solids),
combinations thereof, and the like. In yet other embodiments, in
terms of quantifying ionic strength, the component may include
various ions, such as, but not limited to, Ba2+, Sr2+, Fe+, Fe2+(or
total Fe), Mn2+, SO4 2-, CO32-, Ca2+, Mg2 30+, Na+, K+, Cl-.
[0016] In other aspects, the component may refer to any substance
or material added to the fluid as an additive or in order to treat
the fluid or the flow path. For instance, the component may
include, but is not limited to, acids, acid-generating compounds,
bases, base-generating compounds, biocides, surfactants, scale
inhibitors, corrosion inhibitors, gelling agents, crosslinking
agents, anti-sludging agents, foaming agents, defoaming agents,
antifoam agents, emulsifying agents and emulsifiers, de-emulsifying
agents, iron control agents, proppants or other particulates,
gravel, particulate diverters, salts, fluid loss control additives,
gases, catalysts, clay control agents, clay stabilizers, clay
inhibitors, chelating agents, corrosion inhibitors, dispersants,
flocculants, base fluids (e.g., water, brines, oils), scavengers
(e.g., H2S scavengers, CO2 scavengers or O2 scavengers),
lubricants, breakers, delayed release breakers, friction reducers,
bridging agents, viscosifiers, thinners, high-heat polymers, tar
treatments, weighting agents or materials (e.g., barite, etc.),
solubilizers, rheology control agents, viscosity modifiers, pH
control agents (e.g., buffers), hydrate inhibitors, relative
permeability modifiers, diverting agents, consolidating agents,
fibrous materials, bactericides, tracers, probes, nanoparticles,
and the like. Combinations of these substances can be referred to
as a substance as well.
[0017] As used herein, the term "flow path" refers to a route
through which a fluid is capable of being transported between two
points. Exemplary flow paths include, but are not limited to, a
flowline, a pipeline, a hose, a process facility, a storage vessel,
a tanker, a railway tank car, a transport ship or vessel, a trough,
a stream, a sewer, a subterranean formation, etc., combinations
thereof, or the like.
[0018] FIG. 1A illustrates an exemplary well system 10 that may
embody or otherwise employ one or more principles of the present
disclosure, according to one or more embodiments. As illustrated,
the well system 10 may include a service rig 12 that is positioned
on the earth's surface 14 and extends over and around a wellbore 16
that penetrates one or more subterranean formations 18. The service
rig 12 may be a drilling rig, a completion rig, a workover rig, or
the like. In some embodiments, the service rig 12 may be omitted
and replaced with a standard surface wellhead completion or
installation. Moreover, while the well system 10 is depicted as a
land-based operation, it will be appreciated that the principles of
the present disclosure could equally be applied in any sea-based or
sub-sea application where the service rig 12 may be a floating
platform or sub-surface wellhead installation, as generally known
in the art.
[0019] The wellbore 16 may be drilled into the subterranean
formation 18 using any suitable drilling technique and may extend
in a substantially vertical direction away from the earth's surface
14. Although not illustrated, at some point the wellbore 16 may
deviate from vertical relative to the earth's surface 14 and
transition from the substantially vertical direction into a
substantially horizontal direction.
[0020] FIG. 1B illustrates an enlarged cross-sectional view of the
wellbore 16 in the formation 18. As illustrated, the wellbore 16
may be at least partially lined with casing 20, which may comprises
a string of metal tubulars connected end to end and secured within
the wellbore 16 to provide a protective wellbore lining. The casing
20 can alternatively be replaced with liner or other metallic or
non-metallic tubing. Thus, the scope of this disclosure is not
limited to use of any particular type of casing. An annulus 22 is
defined between the casing 20 and the wellbore 16, and the casing
20 may be secured within the wellbore 16 using cement 24 positioned
in the annulus 22, which seals the annulus 22.
[0021] As illustrated, a sensor system 100 may be positioned in the
annulus 22, for instance, during the construction of the wellbore
16. As illustrated, the sensor system 100 may include a plurality
of sensors 101 communicably coupled to a control line 28 that may
supply power to the sensors 101 from a source located on the
surface 14 or a location downhole. The control line 28 and the
sensor system 100 may be secured within the annulus 22 with the
cement 24. The sensors 101 may be deployed as a function of depth
during the deployment of the casing 20.
[0022] The control line 28 may also facilitate communication to
remote locations, such as the surface 14 (FIG. 1A). Accordingly,
the control line 28 may be or otherwise include one or more
transmission media such as, but not limited to, optical fibers,
electrical wires, or the like, via which the output of the sensors
101 may transmitted to the surface 14 for processing and/or control
signals from the surface 14 may be transmitted to the sensor system
100 for controlling operation thereof.
[0023] The sensors 101 of the sensor system 100 may comprise a
variety of sensors capable of sensing chemical or physical
properties associated with the subterranean formations 18. In one
embodiments, for instance, one or more of the sensors 101 may
include chemical sensors that function based on electromagnetic
radiation (commonly referred to as "opticoanalytical devices"),
quasi-distributed chemical sensors, electrochemical sensors (e.g.,
pH sensors), or the like. In other embodiments, or in addition
thereto, one of more of the sensors 101 may include optical
sensors, physical property sensors, density sensors, viscosity
sensors, temperature sensors, pressure sensors (e.g., microphone
based sensors), and electrical sensors, for example, a thermopile
optoelectronic transducer. The sensors 101 can be configured to
detect not only the composition and concentrations of a fluid or a
component therein, but they also can be configured to determine
physical properties and other characteristics of the fluid and/or
components present within the fluid.
[0024] In at least one embodiment, one or more of the sensors 101
may comprise an optical computing device. As used herein, the term
"optical computing device" refers to an optical device that is
configured to receive an input of electromagnetic radiation from a
fluid, or a substance within the fluid, and produce an output of
electromagnetic radiation from a processing element arranged within
the optical computing device. The processing element may be, for
example, an integrated computational element (ICE) used in the
optical computing device. As discussed in greater detail below, the
electromagnetic radiation that optically interacts with the
processing element is changed so as to be readable by a detector,
such that an output of the detector can be correlated to at least
one substance measured or monitored within the fluid. The output of
electromagnetic radiation from the processing element can be
reflected electromagnetic radiation, transmitted electromagnetic
radiation, and/or dispersed electromagnetic radiation. Whether
reflected, transmitted, or dispersed electromagnetic radiation is
eventually analyzed by the detector may be dictated by the
structural parameters of the optical computing device as well as
other considerations known to those skilled in the art. In
addition, emission and/or scattering of the substance, for example
via fluorescence, luminescence, Raman scattering, and/or Raleigh
scattering, can also be monitored by the optical computing devices.
Optical computing devices, however, are merely one example of a
sensor 101 that may be included in the sensor system 100, which may
include (alternatively or in addition thereto) any type of
electrical, chemical, and/or mechanical sensors, without departing
from the scope of the disclosure.
[0025] FIG. 2A illustrates an exemplary sensor 111 that may be
included in the sensor system 100 of FIG. 1B, according to one or
more embodiments. The sensor 111 may be the same as or similar to
any of the sensors 101 depicted in FIG. 1B. As illustrated, the
sensor 111 may include an optical sensor 102, a
voltage-to-frequency convertor 104, and an acoustic signal
generator 106. The optical sensor 102 may be configured
specifically detect and/or measure a particular component or
characteristic of interest of a fluid present within the annulus 22
or any flow lines or pipelines extending to/from the wellbore
16.
[0026] In some embodiments, the optical sensor 102 may include an
electromagnetic radiation source 108 configured to emit or
otherwise generate electromagnetic radiation 110. The
electromagnetic radiation 110 may refer to radio waves, microwave
radiation, infrared and near-infrared radiation, visible light,
ultraviolet light, X-ray radiation, and gamma ray radiation. The
electromagnetic radiation source 108 may be any device capable of
emitting or generating electromagnetic radiation. For example, the
electromagnetic radiation source 108 may be a light bulb, a light
emitting diode (LED), a laser, a blackbody, a photonic crystal, an
X-Ray source, combinations thereof, or the like. In some
embodiments, a lens (not illustrated) may be configured to collect
or otherwise receive the electromagnetic radiation 110 and direct a
beam of the electromagnetic radiation 110 toward the fluid 112.
[0027] The electromagnetic radiation 110 impinges upon and
optically interacts with a fluid, generally indicated as 112, and
any components present within the fluid 112. Herein, "optically
interact" or variations thereof may refer to the reflection,
transmission, scattering, diffraction, or absorption of
electromagnetic radiation. As a result, optically interacted
radiation 114 is generated by the fluid 112. The optically
interacted radiation 114 may be directed to or otherwise be
received by an ICE 118 arranged within the optical sensor 102. In
operation, the ICE 118 may be configured to receive the optically
interacted radiation 114 and produce modified electromagnetic
radiation 120 corresponding to a particular characteristic of the
fluid 112. In particular, the modified electromagnetic radiation
120 is electromagnetic radiation that has optically interacted with
the ICE 118, which is programmed to have an optical profile that
mimics a regression vector corresponding to the characteristic of
the fluid 112.
[0028] Referring briefly to FIG. 2B, illustrated a cross-sectional
side view of the ICE 118 suitable for use in the optical sensor 102
of FIG. 2A. As illustrated, ICE 118 may include a plurality of
alternating layers 202 and 204, such as silicon (Si) and SiO.sub.2
(quartz), respectively. In general, these layers 202, 204 consist
of materials whose index of refraction is high and low,
respectively. Other examples might include niobia and niobium,
germanium and germania, MgF, SiO.sub.x, and other high and low
index materials known in the art. An optical substrate 206 provides
support to layers 202, 204, according to some embodiments. In some
embodiments, optical substrate 206 is BK-7 optical glass. In other
embodiments, optical substrate 206 may be another type of optical
substrate, such as quartz, sapphire, silicon, germanium, zinc
selenide, zinc sulfide, or various plastics such as polycarbonate,
polymethylmethacrylate (PMMA), polyvinylchloride (PVC), diamond,
ceramics, combinations thereof, and the like.
[0029] At the opposite end (e.g., opposite optical substrate 206 in
FIG. 2A), ICE 118 may include a layer 208 that is generally exposed
to the environment of the device or installation. The number of
layers 202, 204 and the thickness of each layer 202, 204 are
determined from the spectral attributes acquired from a
spectroscopic analysis of a characteristic of interest using a
conventional spectroscopic instrument. The spectrum of interest of
a given characteristic of interest typically includes any number of
different wavelengths. The exemplary ICE 118 in FIG. 2A does not in
fact represent any particular characteristic of interest, but is
provided for purposes of illustration only. Consequently, the
number of layers 202, 204 and their relative thicknesses, as shown
in FIG. 2A, bear no correlation to any particular characteristic of
interest. Nor are layers 202, 204 and their relative thicknesses
necessarily drawn to scale, and therefore should not be considered
limiting of the present disclosure. Moreover, those skilled in the
art will readily recognize that the materials that make up each
layer 202, 204 (i.e., Si and SiO.sub.2) may vary, depending on the
application, cost of materials, and/or applicability of the
materials to the monitored substance.
[0030] In some embodiments, the material of each layer 202, 204 can
be doped or two or more materials can be combined in a manner to
achieve the desired optical characteristic. In addition to solids,
ICE 118 may also contain liquids and/or gases, optionally in
combination with solids, in order to produce a desired optical
characteristic. In the case of gases and liquids, ICE 118 can
contain a corresponding vessel (not shown), which houses gases or
liquids. Exemplary variations of ICE 118 may also include
holographic optical elements, gratings, piezoelectric, light pipe,
digital light pipe (DLP), variable optical attenuators, and/or
acousto-optic elements, for example, that can create transmission,
reflection, and/or absorptive properties of interest.
[0031] Layers 202, 204 exhibit different refractive indices. By
properly selecting the materials of layers 202, 204, their relative
thicknesses and spacing ICE 118 may be configured to selectively
pass/reflect/refract predetermined fractions of electromagnetic
radiation at different wavelengths. Each wavelength is given a
predetermined weighting or loading factor. The thickness and
spacing of layers 202, 204 may be determined using a variety of
approximation methods from the spectrograph of the characteristic
of interest. These methods may include inverse Fourier transform
(IFT) of the optical transmission spectrum and structuring ICE 118
as the physical representation of the IFT. The approximations
convert the IFT into a structure based on known materials with
constant refractive indices.
[0032] The weightings that layers 202, 204 of ICE 118 apply at each
wavelength are set to the regression weightings described with
respect to a known equation, or data, or spectral signature.
Briefly, ICE 118 may be configured, in conjunction with the optical
transducer or detector 122 described in more detail below, to
perform the dot product of the input light beam into ICE 118 and a
desired loaded regression vector represented by each layer 202, 204
for each wavelength. As a result, the output light intensity of ICE
118, as measured by detector 122, is related to the characteristic
of interest.
[0033] Referring again to FIG. 2A, the modified electromagnetic
radiation 120 generated by the ICE 118 may subsequently be conveyed
to a detector 122. The detector 122 may be any device capable of
detecting electromagnetic radiation, and may be generally
characterized as an optical transducer. In some embodiments, the
detector 122 may be, but is not limited to, a thermal detector such
as a thermopile or photoacoustic detector, a semiconductor
detector, a piezoelectric detector, a charge coupled device (CCD)
detector, a video or array detector, a split detector, a photon
detector (such as a photomultiplier tube), photodiodes,
combinations thereof, or the like, or other detectors known to
those skilled in the art.
[0034] In some embodiments, the detector 122 may be configured to
produce an output signal 124 in real-time or near real-time in the
form of a voltage (or current) that corresponds to the particular
characteristic of interest in the fluid 112. In at least one
embodiment, the output signal 124 produced by the detector 122 may
be directly proportional to the characteristic of the fluid 112,
such as the concentration of a particular analyte of interest
present therein. In other embodiments, the relationship may be a
polynomial function, an exponential function, and/or a logarithmic
function.
[0035] In some embodiments, the optical sensor 102 may include a
second detector 126, which may be similar to the first detector 122
in that it may be any device capable of detecting electromagnetic
radiation. The second detector 126 can be arranged to detect the
reflected optically interacted light 115. In other embodiments, the
second detector 126 may be arranged to detect the electromagnetic
radiation 114 derived from the fluid 112 or electromagnetic
radiation directed toward or before the fluid 112. Without
limitation, the second detector 126 may be used to detect radiating
deviations stemming from the electromagnetic radiation source 108.
For example, radiating deviations can include such things as, but
not limited to, intensity fluctuations in the electromagnetic
radiation, interferent fluctuations (e.g., dust or other
interferents passing in front of the electromagnetic radiation
source), coatings on windows included with the optical sensor 102,
combinations thereof, or the like. As illustrated, the second
detector 126 may be configured to receive a portion of the
optically interacted radiation 114 via a beamsplitter 130 in order
to detect the radiating deviations. To compensate for these types
of undesirable effects, the second detector 126 may be configured
to generate a compensating signal 128 generally indicative of the
radiating deviations of the electromagnetic radiation source 108.
The compensating signal 128 may be conveyed to or otherwise
received by a signal processor 132 configured to provide an output
signal 134. In an embodiment (not illustrated), the output signal
134 may be provided to the detector 122 in order to normalize the
output signal 124 in view of any radiating deviations detected by
the second detector 126.
[0036] As mentioned above, the sensor 111 is simply an example of a
variety of sensors that may be used in the sensor system 100. As
such, the optical sensor 102 can be replaced with any other sensor
mentioned herein and, thus, the output signal 124 can come from any
of those sensors.
[0037] The output signal 124 may be an electrical signal, for
instance a voltage signal, and may be provided to the
voltage-to-frequency convertor (or, a frequency generator) 104,
which, for instance, may be or include a voltage-controlled
oscillator (VCO) or a phase-locked loop (PLL). In an embodiment,
the output signal 124 may be a current signal, which may be
converted to a voltage signal before being received by the
voltage-to-frequency convertor 104. As mentioned above, the output
signal 124 may be proportional to the characteristic of interest of
the fluid 112. Because the output signal 124 may determine or
control a frequency (also referred to as the oscillation frequency)
of a signal at an output 136 of the voltage-to-frequency convertor
104, the frequency of the signal at the output 136 may be
proportional to the characteristic of interest of the fluid 112.
Accordingly, any variation in the characteristic of interest (e.g.,
concentration of a particular analyte) of the fluid 112 may
proportionally vary the frequency of the signal at the output 136.
Alternatively, the frequency of the signal at the output 136 may be
set at a predetermined base frequency, and an amplitude of the
signal may be proportionally varied based on the variation in the
characteristic of interest in the fluid 112.
[0038] The output 136 of the voltage-to-frequency convertor 104 may
be provided to the acoustic signal generator (e.g., an acoustic
transducer) 106, which, for example, may be or include a
piezoelectric device 107. Alternatively, the acoustic signal
generator 106 may include a magnetostriction device, an
electrostriction device or an electro-optic device. An acoustic
signal (or wave) generated by the acoustic signal generator 106 at
the output 138 thereof may be proportional to the frequency of the
signal at the output 136 of the voltage-to-frequency convertor 104.
In an embodiment, a frequency of the acoustic signal may be
proportionally varied according to the variations in the frequency
of the signal at the output 136. Alternatively, the frequency of
the acoustic signal may be set to a desired base frequency and the
amplitude of the acoustic signal may be varied (or modulated)
according to the variations in the frequency of the signal at the
output 136.
[0039] In an embodiment, the acoustic transducer 106 may include
two (or more) piezoelectric devices, one of which (referred to as a
primary piezoelectric device, for instance, piezoelectric device
107) may be used to generate the acoustic signal and the other
(referred to as a secondary piezoelectric device, not illustrated)
may generate a reference signal that may be used to cancel
background noises. Herein, the second piezoelectric device is not
provided the output 136 of the voltage-to-frequency convertor 104.
A detection system (not illustrated) located on the surface 14 (or
any other location) measures background vibration and acoustic
noise by comparing the output signals of the two collocated
piezoelectric devices, the acoustic signal at the output 138 of the
primary piezoelectric device 107 and the reference signal generated
by the second piezoelectric device. The difference in the output
signals will then be the signal of interest that is impressed on
the primary piezoelectric device 107, assuming the background
vibrations are very small. In another embodiment, the secondary
piezoelectric device may be absent, and the primary piezoelectric
device 107 may be switched between receiving the output 136 of the
voltage-to-frequency convertor 104 and the reference signal. The
reference signal and the signal at the output 138 may then be
decoupled by the detection system located on the surface 14 (or any
other location).
[0040] The acoustic signal generated by the acoustic signal
generator 106 at the output 138 may be provided to and otherwise
detected by the control line 28. For instance, the acoustic signal
may be provided to (e.g., impinge on) one or more optical fibers
included in the control line 28. In an embodiment, the optical
fiber(s) may be directly coupled (e.g., wrapped around) to the
piezoelectric device 107 of the acoustic signal generator 106 to
maximize transmission efficiency of the acoustic signal from the
acoustic signal generator 106 to the control line 28.
[0041] In an operation based on interferometric phase modulation
techniques, coherent light, e.g., a laser pulse, may be transmitted
downhole through the optical fiber from an interrogation unit (not
illustrated) located on the surface 14. Defects in the optical
fiber backscatter the pulse (Rayleigh scattering) as it propagates
along the optical fiber and the backscattered photons are received
in a photodetector located on the surface 14 (FIG. 1A). The
acoustic signal from the acoustic transducer 106 may cause
localized changes in the optical fiber and these changes may affect
the backscatter of the pulse. As the speed of light is constant,
based on the time delay between the moment the pulse is transmitted
downhole and the backscattered pulse is received, the distance to
the sensor 111 can be determined. This may in turn provide the
location of the component present in the fluid 112 or the
characteristic of the fluid 112 at that location.
[0042] In another embodiment, the output 136 of the
voltage-to-frequency convertor 104 may be provided to an
electro-optic modulator (not expressly illustrated). Typically,
electro-optic modulators include conductive plates across a
preferred crystal axis and may be fabricated using titanium
diffusion or proton exchange techniques that create optical index
changes along prescribed pathways in a host crystal material of the
electro-optic modulator. The crystal material may typically include
Lithium Niobate and/or KDP (potassium dihydrogen phosphate). The
varying frequency of the signal at the output 136 varies the
refractive index of the crystal of the electro-optic modulator. In
effect, this modulates either the phase or amplitude of a coherent
light beam that is transmitted downhole through the crystal of the
electro-optic modulator. The modulated optical signal is sensed at
the surface 14 (or any other location) via single or looped optical
fiber included in the control line 28. The electro-optic modulator
may be coupled to the optical fiber using known fiber cable
termination techniques, such as pigtails and fanout kits or
breakout kits.
[0043] FIG. 3 illustrates an exemplary fiber optic based
Distributed Acoustic Sensing (DAS) network 300, according to one or
more embodiments. The DAS network 300 may include one or more
single mode optical fibers 302 (one shown) positioned in the
annulus 22 adjacent the formation 18. Similar to the embodiment of
FIG. 2A, the sensor system 100, including the plurality of
axially-spaced sensors 101, may also be positioned in the annulus
22 at a predetermined distance from the optical fiber 302. The
control line 28 may supply electrical power to the sensor systems
100. However, in this case, the control line 28 may not include
fiber optic cables or lines. The optical fiber 302 may be
positioned (or embedded) in the wellbore 16 during the construction
thereof and may be supported by the cement 24 used to fill the
annulus 22. Although FIG. 3 illustrates the optical fiber 302
located diametrically opposite the sensor system 100, this is
merely for the sake of illustration and the optical fiber 302 may
alternatively be positioned at any desired location in the annulus
22.
[0044] A plurality of Fiber Bragg Gratings (FBG) 304 each
corresponding to a circumferentially adjacent sensor 101 may be
coupled to the optical fiber 302. The acoustic signals (or waves)
produced by the sensors 101 may traverse the annulus 22 and impinge
on the corresponding FBG 304, resulting in a strain in the
corresponding FBG 304, which may be detected at the surface 14
(FIG. 1A) using a variety of interferometric phase modulation
techniques. The backscattered pulse from the FBGs 304 may have
higher amplitude as compared to the backscattered pulse from an
optical fiber without FBGs. Thus, sections of optical fiber 302
that contain FBGs 304 may produce higher amplitude signals, thereby
improving the spatial resolution. The backscattered signals may be
detected over relatively larger distances and in relatively harsh
environments (e.g., high noise environments), while requiring no
downhole electrical power.
[0045] Using the embedded DAS network 300, the acoustic signals
generated by sensor systems 100 may be converted from an electrical
domain to an optical domain and conveyed to the surface 14 (FIG.
1A). As can be appreciated, the conversion of acoustic signals to
the optical domain in the DAS network 300 may be accomplished
without directly coupling the optical fiber 302 to the sensor
system 100. The embedded DAS network 300 may provide the additional
benefit of being able to triangulate the location of the sensors
101 as a function of depth.
[0046] In an embodiment, each sensor 101 may output a corresponding
acoustic signal (or wave) only when the characteristic of interest
of the substance or material of interest in the fluid 112 (FIG. 2A)
reaches or exceeds a predetermined level. For instance, the optical
sensor 102 of FIG. 2A may be configured to monitor or measure
(either continuously or intermittently) the concentration of a
particular analyte of interest present in the fluid 112 and output
a voltage proportional to the concentration. The acoustic signal
corresponding to the voltage, however, may be produced only when
the voltage meets or exceeds a predetermined threshold voltage that
may correspond to a desired concentration of the particular analyte
of interest. As such, until the predetermined threshold voltage is
met or exceeded, the acoustic signal may be OFF and may only be
switched ON once the predetermined threshold voltage has been met
or exceeded.
[0047] In another embodiment including multiple sensors 101, each
sensor 101 may output an acoustic signal having a base frequency
that is different from the base frequencies of acoustic signals
output by other sensors 101. Each sensor 101 may be configured to
shift (increase or decrease) its respective base frequency
proportional to the property (e.g., a concentration of a particular
analyte) being measured by the respective sensor 101. For instance,
an output of a first sensor 101 may have a base frequency 1 kHz, an
output of a second sensor 101 may have a base frequency 2 kHz, and
so on. The first sensor 101 may be configured to increase its base
frequency by 250 Hz or decrease it by 250 Hz proportional to the
property being measured. Similarly, the second sensor 101 may be
configured to increase its base frequency by 250 Hz or decrease it
by 250 Hz proportional to the property being measured, and so
on.
[0048] In such embodiments, the output of each sensor 101 may be
optically multiplexed (e.g. Sagnac or hybrid combinations of
Sagnac, Michelson, Mach-Zehnder, Fabry-Perot distributed fiber
interferometers) and transmitted to the surface 14 (FIG. 1A) where
each base frequency and any shift therein may be demodulated and
monitored. The base frequency of each sensor system 100 may be a
predetermined value (e.g., a value preset by the operator of the
wellbore system) that may be configured either during or after the
installation of the DAS network 300. Further, it may be possible to
change the base frequency during operation as desired.
[0049] The location of each sensor 101 may be obtained based on the
time delay from the time a light pulse is transmitted downhole via
the optical fiber 302 and the time it takes for the corresponding
backscattered pulse to reach the surface 14 (FIG. 1A). The DAS
network 300 may provide a spatial resolution of 1 meter or less at
for a total distance of around 10 km. Alternatively, for spatial
location of particular sensors 101, subcarrier frequency bands or
channels may be allocated to convey local sensor information. For
instance, each sensor 101 (or sensor system 100) may be allocated a
frequency band or channel having a 1 kHz bandwidth. Multiple sensor
channels to be multiplexed onto the same optical fiber.
[0050] In an embodiment, the DAS network 300 may be positioned in
the casing 20 instead of within the annulus 22. In an another
embodiment, the DAS network 300 including the optical fiber 302 may
be directly coupled to each sensor 101, for example, by wrapping
the optical fiber 302 around each sensor 101. Directly coupling the
DAS network 300 may reduce the number of networks in the wellbore
16 and may simplify the installation of the network(s) in the
wellbore 16.
[0051] In an embodiment illustrated in FIG. 4, the DAS network 300
may be lowered in the casing 20 (or in a production tubing disposed
within the casing 20) using tools or systems deployed via a
conveyance, such as slickline or wireline 402. In another
embodiment, the DAS network 300 may be replaced by a non-fiber
optic based acoustic system including one or more non-fiber optic
based acoustic sensors 404 (e.g., hydrophones) and may be
introduced into the casing 20 (FIG. 1A) using the slickline or
wireline 402.
[0052] In both configurations, the DAS 300 and the non-fiber optic
based acoustic system may be introduced in the casing 20 and
measurements may be carried out on an "as needed" basis. Thus, it
may not be required to have a permanently installed DAS network 300
in the wellbore 16. As will be appreciated, these configurations
also permit measuring the acoustic signals without direct contact
with the sensor system 100. Using the non-fiber optic based
acoustic system (e.g., hydrophones 404) may also permit measuring
the acoustic signals generated by the sensors 101 in situations
where an acoustic sensor that is used in conjunction with the
non-fiber optic based acoustic system either has malfunctioned or
is absent.
[0053] FIG. 5 shows an illustrative processing system 500 for
configuring and/or controlling the sensor system 100 and the DAS
network 300 for performing the various tasks as described herein.
The processing system 500 may be located at a remote location
(e.g., the surface 14).
[0054] The system 500 may include a processor 510, a memory 520, a
storage device 530, and an input/output device 540. Each of the
components 510, 520, 530, and 540 may be interconnected, for
example, using a system bus 550. The processor 510 may be
processing instructions for execution within the system 500. In
some embodiments, the processor 510 is a single-threaded processor,
a multi-threaded processor, or another type of processor. The
processor 510 may be capable of processing instructions stored in
the memory 520 or on the storage device 530. The memory 520 and the
storage device 530 can store information within the computer system
500.
[0055] The input/output device 540 may provide input/output
operations for the system 500. In some embodiments, the
input/output device 540 can include one or more network interface
devices, e.g., an Ethernet card; a serial communication device,
e.g., an RS-232 port; and/or a wireless interface device, e.g., an
802.11 card, a 3G wireless modem, or a 4G wireless modem. In some
embodiments, the input/output device can include driver devices
configured to receive input data and send output data to other
input/output devices, e.g., keyboard, printer and display devices
560. In some embodiments, mobile computing devices, mobile
communication devices, and other devices can be used.
[0056] In accordance with at least some embodiments, the disclosed
methods and systems related to scanning and analyzing material may
be implemented in digital electronic circuitry, or in computer
software, firmware, or hardware, including the structures disclosed
in this specification and their structural equivalents, or in
combinations of one or more of them. Computer software may include,
for example, one or more modules of instructions, encoded on
computer-readable storage medium for execution by, or to control
the operation of, a data processing apparatus. Examples of a
computer-readable storage medium include non-transitory medium such
as random access memory (RAM) devices, read only memory (ROM)
devices, optical devices (e.g., CDs or DVDs), and disk drives.
[0057] The term "data processing apparatus" encompasses all kinds
of apparatus, devices, and machines for processing data, including
by way of example a programmable processor, a computer, a system on
a chip, or multiple ones, or combinations, of the foregoing. The
apparatus can include special purpose logic circuitry, e.g., an
FPGA (field programmable gate array) or an ASIC (application
specific integrated circuit). The apparatus can also include, in
addition to hardware, code that creates an execution environment
for the computer program in question, e.g., code that constitutes
processor firmware, a protocol stack, a database management system,
an operating system, a cross-platform runtime environment, a
virtual machine, or a combination of one or more of them. The
apparatus and execution environment can realize various different
computing model infrastructures, such as web services, distributed
computing, and grid computing infrastructures.
[0058] A computer program (also known as a program, software,
software application, script, or code) can be written in any form
of programming language, including compiled or interpreted
languages, declarative, or procedural languages. A computer program
may, but need not, correspond to a file in a file system. A program
can be stored in a portion of a file that holds other programs or
data (e.g., one or more scripts stored in a markup language
document), in a single file dedicated to the program in question,
or in multiple coordinated files (e.g., files that store one or
more modules, sub programs, or portions of code). A computer
program may be executed on one computer or on multiple computers
that are located at one site or distributed across multiple sites
and interconnected by a communication network.
[0059] Some of the processes and logic flows described in this
specification may be performed by one or more programmable
processors executing one or more computer programs to perform
actions by operating on input data and generating output. The
processes and logic flows may also be performed by, and apparatus
may also be implemented as, special purpose logic circuitry, e.g.,
an FPGA (field programmable gate array) or an ASIC (application
specific integrated circuit).
[0060] Processors suitable for the execution of a computer program
include, by way of example, both general and special purpose
microprocessors and processors of any kind of digital computer.
Generally, a processor will receive instructions and data from a
read-only memory or a random access memory or both. A computer
includes a processor for performing actions in accordance with
instructions and one or more memory devices for storing
instructions and data. A computer may also include, or be
operatively coupled to receive data from or transfer data to, or
both, one or more mass storage devices for storing data, e.g.,
magnetic, magneto optical disks, or optical disks. However, a
computer may not have such devices. Devices suitable for storing
computer program instructions and data include all forms of
non-volatile memory, media and memory devices, including by way of
example semiconductor memory devices (e.g., EPROM, EEPROM, flash
memory devices, and others), magnetic disks (e.g., internal hard
disks, removable disks, and others), magneto optical disks, and
CD-ROM and DVD-ROM disks. The processor and the memory can be
supplemented by, or incorporated in, special purpose logic
circuitry.
[0061] To provide for interaction with a user, operations may be
implemented on a computer having a display device (e.g., a monitor,
or another type of display device) for displaying information to
the user and a keyboard and a pointing device (e.g., a mouse, a
trackball, a tablet, a touch sensitive screen, or another type of
pointing device) by which the user can provide input to the
computer. Other kinds of devices can be used to provide for
interaction with a user as well; for example, feedback provided to
the user can be any form of sensory feedback, e.g., visual
feedback, auditory feedback, or tactile feedback; and input from
the user can be received in any form, including acoustic, speech,
or tactile input. In addition, a computer can interact with a user
by sending documents to and receiving documents from a device that
is used by the user; for example, by sending web pages to a web
browser on a user's client device in response to requests received
from the web browser.
[0062] A computer system may include a single computing device, or
multiple computers that operate in proximity or generally remote
from each other and typically interact through a communication
network. Examples of communication networks include a local area
network ("LAN") and a wide area network ("WAN"), an inter-network
(e.g., the Internet), a network comprising a satellite link, and
peer-to-peer networks (e.g., ad hoc peer-to-peer networks). A
relationship of client and server may arise by virtue of computer
programs running on the respective computers and having a
client-server relationship to each other.
[0063] Embodiments disclosed herein include:
[0064] A. A system that includes a sensor to detect a
characteristic of a fluid and output an electrical signal
proportional to the characteristic, an acoustic signal generator to
output an acoustic signal proportional to the electrical signal,
and a signal detection apparatus to generate a signal proportional
to the acoustic signal and transmit the signal to a remote
location.
[0065] B. A method that includes monitoring a fluid in a wellbore
with a sensor, generating an electrical signal proportional to a
characteristic of the fluid with the sensor, generating a control
signal proportional to the electrical signal using a frequency
generator, generating an acoustic signal proportional to the
control signal using an acoustic transducer, detecting the acoustic
signal and generating a signal based on the acoustic signal using a
signal detection apparatus, and transmitting the signal to a remote
location.
[0066] Each of embodiments A and B may have one or more of the
following additional elements in any combination: Element 1:
wherein the sensor comprises one of a chemical sensor, an optical
sensor, a pH sensor, a density sensor, a viscosity sensor, a
thermal sensor, and a pressure sensor.
[0067] Element 2: wherein the acoustic signal generator includes
one of a piezoelectric device, a magnetostriction device, an
electro-optic device, and an electrostriction device. Element 3:
wherein the signal detection apparatus generates an optical signal
proportional to the acoustic signal using interferometric phase
modulation techniques and transmits the optical signal to the
remote location. Element 4: wherein the signal detection apparatus
is positioned in an annulus defined between a wellbore and a casing
secured within the wellbore. Element 5: wherein the signal
detection apparatus is conveyed into a wellbore on slickline or
wireline. Element 6: wherein the signal detection apparatus is a
non-fiber optic based apparatus that detects the acoustic signal.
Element 7: further comprising a frequency generator that receives
the electrical signal and generates a control signal proportional
to the electrical signal. Element 8: wherein the acoustic signal
generator comprises an acoustic transducer to receive the control
signal and generate the acoustic signal proportional to the control
signal. Element 9: wherein the acoustic signal generator and the
signal detection apparatus contact each other. Element 10: wherein
the acoustic signal generator and the signal detection apparatus
are separated from each other. Element 11: further comprising a
processing unit located at the remote location and configured to
process the signal from the signal detection apparatus to determine
a location of the fluid.
[0068] Element 12: further comprising generating an optical signal
proportional to the acoustic signal using the signal detection
apparatus, the optical signal being generated by the signal
detection apparatus using interferometric phase modulation
techniques. Element 13: further comprising generating the acoustic
signal when the electrical signal meets or exceeds a predetermined
threshold level, the threshold level corresponding to the
characteristic of the fluid measured by the sensor. Element 14:
further comprising varying a frequency of the control signal
proportional to the electrical signal. Element 15: further
comprising varying an amplitude of the control signal proportional
to the electrical signal. Element 16: further comprising varying a
frequency of the acoustic signal proportional to the control
signal. Element 17: further comprising varying an amplitude of the
acoustic signal proportional to the control signal. Element 18:
generating the acoustic signal having a predetermined base
frequency, and shifting the base frequency proportional to the
characteristic of the fluid measured by the sensor.
[0069] By way of non-limiting example, exemplary combinations
applicable to A and B: Element 3 with Element 4; Element 3 with
Element 5; and Element 7 with Element 8.
[0070] Therefore, the disclosed systems and methods are well
adapted to attain the ends and advantages mentioned as well as
those that are inherent therein. The particular embodiments
disclosed above are illustrative only, as the teachings of the
present disclosure may be modified and practiced in different but
equivalent manners apparent to those skilled in the art having the
benefit of the teachings herein. Furthermore, no limitations are
intended to the details of construction or design herein shown,
other than as described in the claims below. It is therefore
evident that the particular illustrative embodiments disclosed
above may be altered, combined, or modified and all such variations
are considered within the scope of the present disclosure. The
systems and methods illustratively disclosed herein may suitably be
practiced in the absence of any element that is not specifically
disclosed herein and/or any optional element disclosed herein.
While compositions and methods are described in terms of
"comprising," "containing," or "including" various components or
steps, the compositions and methods can also "consist essentially
of" or "consist of" the various components and steps. All numbers
and ranges disclosed above may vary by some amount. Whenever a
numerical range with a lower limit and an upper limit is disclosed,
any number and any included range falling within the range is
specifically disclosed. In particular, every range of values (of
the form, "from about a to about b," or, equivalently, "from
approximately a to b," or, equivalently, "from approximately a-b")
disclosed herein is to be understood to set forth every number and
range encompassed within the broader range of values. Also, the
terms in the claims have their plain, ordinary meaning unless
otherwise explicitly and clearly defined by the patentee. Moreover,
the indefinite articles "a" or "an," as used in the claims, are
defined herein to mean one or more than one of the elements that it
introduces. If there is any conflict in the usages of a word or
term in this specification and one or more patent or other
documents that may be incorporated herein by reference, the
definitions that are consistent with this specification should be
adopted.
[0071] As used herein, the phrase "at least one of" preceding a
series of items, with the terms "and" or "or" to separate any of
the items, modifies the list as a whole, rather than each member of
the list (i.e., each item). The phrase "at least one of" allows a
meaning that includes at least one of any one of the items, and/or
at least one of any combination of the items, and/or at least one
of each of the items. By way of example, the phrases "at least one
of A, B, and C" or "at least one of A, B, or C" each refer to only
A, only B, or only C; any combination of A, B, and C; and/or at
least one of each of A, B, and C.
* * * * *