U.S. patent application number 15/643427 was filed with the patent office on 2019-01-10 for optical monitoring for power grid systems.
The applicant listed for this patent is Palo Alto Research Center Incorporated. Invention is credited to Peter Kiesel, Ajay Raghavan.
Application Number | 20190011491 15/643427 |
Document ID | / |
Family ID | 62814924 |
Filed Date | 2019-01-10 |
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United States Patent
Application |
20190011491 |
Kind Code |
A1 |
Raghavan; Ajay ; et
al. |
January 10, 2019 |
OPTICAL MONITORING FOR POWER GRID SYSTEMS
Abstract
A monitoring system for a power grid includes one or more power
transformer monitors. Each power transformer monitor includes a
plurality of optical sensors disposed on one or more optical fibers
that sense parameters of the power transformer. Each optical sensor
is configured to sense a power transformer parameter that is
different from a power transformer parameter sensed by at least one
other sensor of the plurality of optical sensors. An optical
coupler spatially disperses optical signals from the optical
sensors according to wavelength. A detector unit converts optical
signals of the optical sensors to electrical signals representative
of the sensed power transformer parameters.
Inventors: |
Raghavan; Ajay; (Mountain
View, CA) ; Kiesel; Peter; (Palo Alto, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Palo Alto Research Center Incorporated |
Palo Alto |
CA |
US |
|
|
Family ID: |
62814924 |
Appl. No.: |
15/643427 |
Filed: |
July 6, 2017 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
G01R 19/2513 20130101;
G01R 31/62 20200101; G02B 6/2938 20130101; G01L 1/246 20130101;
G01B 11/18 20130101; G01J 3/00 20130101; G01J 3/1895 20130101; G01D
5/353 20130101; G02B 6/12009 20130101; H04B 3/46 20130101 |
International
Class: |
G01R 31/02 20060101
G01R031/02; G01D 5/353 20060101 G01D005/353 |
Claims
1. A monitoring system comprising: one or more power transformer
monitors of a power grid system, each power transformer monitor
comprising a plurality of optical sensors disposed on one or more
optical fibers, the optical sensors configured to sense internal
parameters of a power transformer, each optical sensor disposed at
a location within or on a power transformer and configured to sense
an internal transformer parameter that is different from an
internal transformer parameter sensed by at least one other sensor
of the plurality of optical sensors; one or more detector units,
each detector unit configured to convert optical signals of the
optical sensors of a corresponding power transformer monitor to
electrical signals representative of the sensed transformer
parameters; and at least one optical coupler disposed between the
one or more optical fibers and the detector units, the optical
coupler configured to spatially disperse optical signals from the
optical sensors according to wavelength.
2. The system of claim 1, wherein each of the optical sensors are
disposed on a single optical fiber.
3. The system of claim 1, wherein at least one of the optical
sensors is disposed on a first optical fiber and at least one of
the sensors is disposed on a second optical fiber.
4. The system of claim 1, wherein at least one of the optical
sensors is configured to sense core strain.
5. The system of claim 1, wherein at least one of the optical
sensors is configured to sense a dissolved gas.
6. The system of claim 5, wherein the dissolved gas is a
hydrogen-containing gas.
7. The system of claim 1, wherein at least one of the optical
sensors is a Pd-coated fiber Bragg grating.
8. The system of claim 1, wherein at least one of the optical
sensors is configured to sense temperature.
9. The system of claim 1, wherein at least one of the optical
sensors is configured to sense partial discharge.
10. The system of claim 1, wherein at least one of the optical
sensors is configured to sense transformer core strain.
11. The system of claim 1, wherein at least one of the optical
sensors is configured to sense vibration.
12. The system of claim 1, wherein at least one of the optical
sensors is configured to sense a chemical.
13. The system of claim 1, wherein at least one of the optical
sensors is configured to sense corrosion.
14. The system of claim 1, wherein at least one of the optical
sensors is configured to sense moisture.
15. The system of claim 1, further comprising one or more optical
sensor configured to sense an electrical parameter.
16. The system of claim 1, wherein each optical sensor operates
within a different wavelength range and emanates output light in
response to input light, the output light having a centroid
wavelength that changes in response to the sensed internal
parameter of the power transformer.
17. The system of claim 1, wherein the optical coupler spatially
disperses light according to wavelength.
18. The system of claim 1, wherein the optical coupler comprises a
linear variable filter.
19. The system of claim 1, wherein the optical coupler comprises an
arrayed waveguide grating.
20. The system of claim 1, further comprising an optical
multiplexer disposed between the optical fibers and the optical
coupler.
21. The system of claim 20, wherein the optical multiplexer
comprises a time division multiplexer, the time domain multiplexer
comprising at least one of: a set of M optical switches; and a
single 1.times.M optical switch.
22. The system of claim 21, wherein the optical multiplexer
comprises a wavelength division multiplexer.
23. The system of claim 1, wherein the monitoring system comprises:
multiple power transformer monitors; and control circuitry
communicatively coupled to each of the power transformer
monitors.
24. The system of claim 23, wherein the control circuitry includes
the detection units and the detection units are communicatively
coupled to each power transformer monitor by an optical
communication channel.
25. The system of claim 24, wherein the optical communications
channel includes an optical sensor configured to detect intrusion
attacks.
26. The system of claim 23, wherein the control circuitry includes
an analyzer configured to analyze the electrical signals and to
predict, detect and/or diagnose one or more functional, state,
and/or degradation conditions of the power transformer based on
analysis of the electrical signals.
27. A monitoring system comprising: one or more power grid
component monitors for one or more components of a power grid
transmission and distribution system, each power grid component
monitor comprising a plurality of optical sensors disposed on one
or more optical fibers, the optical sensors configured to sense
parameters of the power grid component, each optical sensor
disposed at a location within or on the power grid component and
configured to sense a power grid component parameter that is
different from a power grid component parameter sensed by at least
one other sensor of the plurality of optical sensors; one or more
detector units, each detector unit configured to convert optical
signals of the optical sensors of a corresponding power grid
component monitor to electrical signals representative of the
sensed power grid component parameters; and at least one optical
coupler disposed between the one or more optical fibers and the
detector units, the optical coupler configured to spatially
disperse optical signals from the optical sensors according to
wavelength.
28. The system of claim 27, further comprising an analyzer
configured to analyze the electrical signals and to predict, detect
and/or diagnose one or more functional, state, and/or degradation
conditions of the power grid components based on analysis of the
electrical signals.
29. A method comprising: optically sensing multiple parameters of a
power grid component of a power grid transmission and distribution
system using multiple optical sensors on an optical fiber disposed
within or on the power grid component, at least one of the optical
sensors configured to sense a different parameter than other
optical sensors; combining the optical output signals from each
sensor into a combined optical signal carried on the optical fiber;
spatially dispersing the combined optical signal according to
wavelength; and generating electrical signals in response to the
spatially dispersed optical output signal, the electrical signals
representing the sensed parameters of the power grid component.
30. The method of claim 29, further comprising analyzing the
electrical signals to predict, detect and/or diagnose one or more
of a functional condition, a state, and/or a degradation condition
of the power grid component based on analysis of the electrical
signals.
31. The method of claim 29, wherein: the power grid component is a
power grid transformer; and the optical sensors are configured to
sense internal parameters of the power grid transformer, at least
one of the optical sensors is configured to sense a different
internal parameter than other optical sensors.
Description
TECHNICAL FIELD
[0001] This application relates generally to techniques for
optically monitoring power grid transmission and distribution
systems. The application also relates to components, devices,
systems, and methods pertaining to such techniques.
BACKGROUND
[0002] Global climate change and population growth are driving
increased demands for reliable, sustainable, and clean electricity
around the world. This is creating an even heavier burden on the
already overstressed and aging global power infrastructure. Modern
power grids are complex, tightly interconnected systems. Certain
extraneous conditions at key locations can have unpredictable and
immediate impacts over a wide area. The existing power grid suffers
from a lack of effective distributed communications, monitoring,
fault diagnostics, and automation, which further increase the
possibility of wide-area breakdown due to cascading effects from a
single fault.
SUMMARY
[0003] Various embodiments described herein involve systems and
methods for monitoring power transmission and distribution systems.
Some embodiments are directed to an optical monitoring system. The
monitoring system includes one or more power transformer monitors.
Each power distribution monitor includes a plurality of optical
sensors disposed on one or more optical fibers. The optical sensors
are configured to sense parameters, e.g., internal parameters, of a
power transformer. Each optical sensor is disposed at a location
within or on a power transformer and is configured to sense a
transformer parameter that is different from a transformer
parameter sensed by at least one other sensor of the plurality of
optical sensors. The monitoring system includes one or more
detector units. Each detector unit converts optical signals of the
optical sensors of a corresponding power transformer monitor to
electrical signals representative of the sensed transformer
parameters. At least one optical coupler is disposed between the
one or more optical fibers and the detector units. The optical
coupler spatially disperses optical signals from the optical
sensors according to wavelength.
[0004] Some embodiments involve a method for monitoring optically
power grid transmission and/or distribution components. Multiple
parameters of a power transformer are sensed using multiple optical
sensors on an optical fiber disposed within or on the power
transformer. At least one of the optical sensors senses a different
parameter than others of the optical sensors. The optical output
signals from each sensor are combined into a combined optical
signal that is carried on the optical fiber. The combined optical
signal is spatially dispersed according to wavelength. Electrical
signals are generated in response to the spatially dispersed
combined optical output signal. The electrical signals represent
the sensed parameters of the power transformer.
[0005] According to some aspects, the electrical signals are
analyzed to predict, detect and/or diagnose one or more of a
functional condition, a state, and/or a degradation condition of
the power transformer.
BRIEF DESCRIPTION OF THE DRAWINGS
[0006] FIG. 1 shows a general block diagram of power grid that may
incorporate a monitoring system in accordance with embodiments
described herein;
[0007] FIG. 2 is a general block diagram of a monitoring system for
a power distribution substation in accordance with some
embodiments;
[0008] FIG. 3 is a more detailed block diagram of a power grid
monitoring system in accordance with some embodiments;
[0009] FIG. 4 illustrates reflected spectra for fiber Bragg grating
(FBG) sensors used in a monitoring system in accordance with some
embodiments;
[0010] FIG. 5 is a block diagram showing portions of a detection
unit and analyzer used to detect changes in sensed parameters in
accordance with some embodiments;
[0011] FIG. 6 is a block diagram showing portions of a detection
unit and analyzer that uses a non-pixelated photosensitive detector
in accordance with some embodiments;
[0012] FIG. 7 illustrates wavelength domain multiplexing for
multiple sensors using an arrayed waveguide grating (AWG) designed
for sensing applications in accordance with some embodiments;
[0013] FIGS. 8A, 8B and 9 illustrate in more detail the output
waveguides of an AWG used as a wavelength domain optical
demultiplexer according to some embodiments;
[0014] FIG. 10 is a block diagram of a monitoring system that
includes both time and wavelength division multiplexing in
accordance with some embodiments.
[0015] The figures are not necessarily to scale. Like numbers used
in the figures refer to like components. However, it will be
understood that the use of a number to refer to a component in a
given figure is not intended to limit the component in another
figure labeled with the same number.
DESCRIPTION
[0016] Embodiments described in this disclosure involve optical
monitoring systems for power grid components. The impact of
manufacturing imperfections, structural degradation, equipment
failures, capacity limitations, and natural accidents and
catastrophes, which cause power disturbances and outages, can be
reduced by online system condition monitoring and diagnostics. The
recent increase in distributed energy resources (DER) in the form
of plug-in electric vehicles (PEVs), renewable energy and other
alternative energy sources also presents new challenges, such as
power-grid integration, power system stability, congestion,
atypical power flows, and energy storage gaps. There is a growing
need for intelligent and low-cost monitoring and control with
online sensing technologies to maintain safety, reliability,
efficiency, and uptime of the power grid.
[0017] However, harsh and complex electric-power-system
environments pose great challenges for low-cost sensing in
smart-grid applications. Specifically, electrical sensors may be
subject to radio frequency interference (RFI), highly
caustic/corrosive environments, high moisture/humidity levels,
vibrations, dust, or other conditions that challenge performance
and/or greatly increase cost. While wireless sensor networks (WSNs)
have been explored as a low-cost option in this regard,
electromagnetic interference (EMI) effects make it difficult to
monitor their communication link quality, thereby limiting usage of
WSNs for grids. WSNs also offer additional vulnerabilities to cyber
threats.
[0018] Embodiments described in this disclosure involve optical
monitoring systems for power grid components. The optical
monitoring approaches described herein can be used in a monitoring
system that monitors any type of power grid component and/or
multiple types of power grid components. For example a monitoring
system according to the disclosed approaches may monitor electrical
power grid components such as power distribution transformers,
power transmission transformers, power grid switches, capacitors,
relays and/or other power grid components.
[0019] Among the power grid components of particular interest,
transformers are one of the more expensive pieces of equipment
found in a distribution network. Power transmission transformers
are designed to step up the voltage from the power distribution
plant for long range transmission. Power distribution transformers
step down the high voltage from transmission levels to deliver
power from high voltage transmission networks to customers. Being
relatively simple in construction and at the same time mechanically
robust, they offer a long service life. Transformer sustainability
has become a growing challenge due to transformer aging and the
ongoing trend to supply a growing number of non-linear and variable
DER loads through the power transformers. Growing uncertainties in
transformer aging result from variable loads and other system
complexities due to increasingly high levels of DER.
[0020] Variable and non-linear loads can be a factor that
accelerates transformer aging. For example, battery chargers for
PEVs are high-power devices that employ nonlinear switching which
could result in significant harmonic voltage and currents injected
into the distribution system. Fast charging, the preferred
technique to accelerate PEV adoption, implies precisely these types
of nonlinear loads. Simulation models have suggested that some high
levels of DER adoption scenarios (such as large numbers of PEVs
being fast-charged simultaneously) can significantly accelerate
transformer aging. Other types of distributed generation (DG), such
as rooftop photovoltaics can possibly extend transformer life in
radial networks by relieving them of their peak loads at low to
moderate levels of penetration. However, studies suggest that as DG
penetration increases, voltage limit violations at transformer
secondaries in mesh network-type power distribution systems (common
in large metro areas) become increasingly probable.
[0021] In transformer designs, the use of oil as an insulation
material has become ubiquitous in light of oil enabling superior
electrical performance with low losses. However, the flammability
of oil-filled transformers can pose major public safety risks,
particularly in underground installations as they age and become
less robust to transient over-voltages or other internal failure
mechanisms. Thus, a need is emerging for low-cost sensing to
monitor key internal parameters in transformers, particularly in
distribution transformers, for reliable predictions of degradation
and/or impending failures.
[0022] FIG. 1 is a simplified diagram of a power grid 100. The
power grid 100 includes some type of power generator 105 that
generates power for the grid, e.g., through burning coal or natural
gas, hydroelectric, nuclear, wind, photovoltaics, or other types of
power generation. The output voltage from the power generator 105
may be stepped up by transformers at a transmission substation 110
and carried by high voltage transmission lines 111 to one or more
power distribution substations 120. The voltage is stepped down by
power distribution transformers at the power distribution
substations 120 and is provided to houses 130 and/or other
facilities connected to the power grid 100. Embodiments discussed
in this disclosure are directed to optical systems for monitoring
power grid components. For example, the power distribution
substations 120 may include one or more optical monitoring systems
for power distribution transformers in accordance with embodiments
discussed herein. The transmission substation 110 may include one
or more optical monitoring systems for power transmission
transformers. Although the approaches for power grid monitoring are
explained in this disclosure using the example of power
transformers as the monitored power grid components, it will be
appreciated that the approaches are equally applicable to other
components of the power grid.
[0023] FIG. 2 depicts an optical monitoring system 200 that may be
arranged to monitor power transformers 205 located at a power grid
substation, in accordance with some embodiments. The optical
monitoring system 200 includes one or more power transformer
monitors 220. Each monitor 220 includes a plurality of optical
sensors 222 disposed on one or more optical fibers 221. Each
optical sensor 222 is disposed at a location within or on a
corresponding power transformer and is configured to sense
parameters of the power transformer 205. The parameters sensed may
be internal parameters, such as strain, temperature, vibration,
chemistry, or operational parameters, such as voltage and current.
In some embodiments, each optical sensor may sense a different
parameter of the transformer than other optical sensors monitoring
the same transformer. In some scenarios two or more of the optical
sensors monitoring a transformer may sense the same parameter, for
example, to achieve an average of the sensed parameter or to sense
the same parameter at different locations of the transformer. In
the embodiment depicted in FIG. 2, each transformer 205 is
monitored by multiple sensors 222 disposed on a single optical
fiber 221. Alternatively, a single transformer may be monitored by
multiple sensors disposed on multiple optical fibers and/or
multiple transformers may be monitored by multiple sensors disposed
on a single optical fiber.
[0024] The monitoring system 200 includes control circuitry 210
optically coupled to the optical fibers 221 of the transformer
monitors 220. In various embodiments, the control circuitry may be
arranged for receiving optical output signals from the optical
monitors of one, some, or all of the transformers 205 of the
substation.
[0025] The control circuitry 210 includes a light source 211 that
provides input excitation light to the optical sensors 222. Each of
the sensors 222 reflects a portion of the input light as sensor
output light. The sensor output light exhibits wavelength shifts of
the central wavelength of the sensor according to changes in the
sensed parameters of the transformer. In the embodiment shown in
FIG. 2, the output light from each sensor 222 that monitors a
transformer 205 is multiplexed onto a single optical fiber 221.
Thus, the output light from each of the sensors is multiplexed onto
the optical fiber 221.
[0026] The control circuitry 210 includes an optical wavelength
division demultiplexer 212 that spatially distributes the output
light carried on the optical fiber 221. A detector unit 215
comprising one or more photodetectors converts the output light
into electrical signals representative of the sensed parameters of
the transformer.
[0027] The wavelength shifts associated with the sensed parameters
can be small compared to spacing between the central wavelengths of
the sensors. Therefore, it is feasible to separate the optical
signals from the individual sensors, referred to as the component
signals, using the wavelength division demultiplexer, which may
comprise a linear variable filter, arrayed waveguide grating (AWG),
or other wavelength dispersive optical element. Alternatively or
additionally, a time-domain multiplexing scheme can be employed
that operates by exciting short pulses of light in the optical
fiber which selectively addresses each of the various sensors.
Using various multiplexing configurations, e.g., wavelength
division multiplexing/demultiplexing and/or time division
multiplexing/demultiplexing, several thousand sensors can be
monitored by a single detection unit as described in more detail
below.
[0028] In some embodiments, the control circuitry 210 includes an
analyzer 216 configured to analyze the electrical signals generated
by the detector unit 215. The analyzer may be a processor
configured to predict, detect, and/or diagnose one or more
functional, state, and/or degradation conditions based on analysis
of the electrical signals.
[0029] Cybersecurity is important for power grid systems. In some
embodiments, the monitoring system 200 may include one or more
optical sensors 217 coupled to the optical fibers 218 and
configured to monitor the optical signals carried on the optical
fibers 218 for unusual signal anomalies on that are not
attributable to transformer parameters. These security sensors 217
can provide an alert to attacks or other breaches of security. The
additional sensors for cybersecurity and/or breach detection may be
coupled to the optical fibers 218 within the control circuitry 210
as shown, may be coupled to the optical fibers 221, and/or may
cybersecurity and/or breach detection optical sensors may be
disposed at both locations.
[0030] FIG. 3 provides a more detailed view of a monitoring system
300 in accordance with some embodiments. Multiple optical sensors,
S1, S2, . . . SN, are arranged to respectively sense multiple
internal parameters of the transformer 301. Additional internal
and/or external sensors may be arranged to monitor operational
transformer parameters. For example, internal and/or external
sensors may be configured to sense operational parameters of the
transformer such as input current, output current, input voltage,
output voltage.
[0031] Optical sensors can be used to monitor a number of
parameters. For example, the optical sensors S1, S2, . . . SN may
be disposed within or outside the transformer 301 and configured to
sense one or more transformer parameters such as temperature, core
strain, vibration, presence of various chemicals, corrosion,
presence of gas (including dissolved gas such as a hydrogen
containing dissolved gas) partial discharge, pressure, current,
voltage, and/or other transformer parameters.
[0032] The sensors S1, S2, . . . SN may comprise any type (or
multiple types) of optical sensor, including Fiber Bragg Grating
(FBG) sensors and/or etalon or Fabry-Perot (FP) sensors. Both the
FBG and etalon/FP sensors are collectively referred to herein as
optical sensors or fiber optic sensors. Although some examples
provided herein are based on FBG sensors, it will be understood
that other types of optical sensors could alternatively or
additionally be used in these and other embodiments.
[0033] Fiber optic sensors offer many advantages over their
electrical counterparts. They are thin, (typically about 100-200
.mu.m) in diameter, lightweight, sensitive, robust to harsh
environments, and immune to EMI. Fiber optic sensors can
simultaneously measure multiple parameters with high sensitivity in
multiplexed (muxed) configurations over long optical fiber cables.
Fiber optic sensors have demonstrated robustness to various harsh
environments, including long-term (5+ years) exposure to oil-soak
environments, as shown for downhole sensing. The most common fiber
optic material is silica, which is corrosion resistant, can
withstand 1 GPa tension for more than five years, survive, between
-200.degree. C. and 800.degree. C., and has a dielectric breakdown
strength greater than 470 kV/mm. Various types of plastic are also
useful for optical fibers and optical sensors. Fiber optic sensors
such as FBG sensors are mechanically robust with respect to shock
and vibration. Thus, embedded fiber optic sensors in transformers
offer an attractive solution to reliably measure and monitor
relevant parameters. In addition, the immunity of optical fiber
cables to EMI and radio frequency interference (RFI) make it a
particularly suitable communication medium for high voltage
operating environments in substations and over long distances
across the grid. Thus, the multifunctional nature of optical fiber
cables can be exploited to combine sensing, communications,
shielding, and lightning protection functions in power systems.
[0034] FBG sensors can be formed by a periodic modulation of the
refractive index along a finite length (typically a few mm) of the
core of the optical fiber. In some embodiments the periodic
modulation can be inscribed on the fiber optic through direct
writing using femtosecond lasers. The modulation pattern reflects a
wavelength, called the Bragg wavelength, that is determined by the
periodicity of the refractive index profile of the FBG sensor. In
practice, the sensor typically reflects a narrow band of
wavelengths centered at the Bragg wavelength. The Bragg wavelength
at a characteristic or base value of the external stimulus is
denoted .lamda., and light having a peak, center, or centroid
wavelength .lamda., (and a narrow band of wavelengths near .lamda.)
is reflected from the sensor when it is in a predetermined base
condition. For example, the base condition may correspond to 25
degrees C. and/or zero strain. When the sensor is subjected to
stimulus, the stimulus changes the periodicity of the grating and
the index of refraction of the FBG, and thereby alters the
reflected light so that the reflected light has a peak, center, or
centroid wavelength, .lamda..sub.s, different from the base
wavelength, .lamda.. The resulting wavelength shift,
.DELTA..lamda./.lamda.=(.lamda.-.lamda..sub.s)/.lamda. is a proxy
measure of the stimulus.
[0035] FBG sensors may be sensitive to changes in refractive index
n, strain .epsilon..sub.1, and ambient temperature changes
.DELTA.T, for example. The refractive index n can be made sensitive
to the chemical environment of the sensor by stripping the optical
fiber cladding over the sensor element region and/or by adding
appropriate coatings to this sensitive area. Strain and temperature
shift the output wavelength of the sensor due to changes in the
periodicity of the grating.
[0036] The relation between wavelength shift
(.DELTA..lamda./.lamda.) and simultaneous strain and temperature in
an FBG sensor is:
.DELTA..lamda./.lamda.={1-n.sup.2/2[p.sub.12-n(p.sub.11+p.sub.12)]}.epsi-
lon..sub.1+[.alpha.+1/n(dn/dT)].DELTA.T [1] [0037] where n is the
index of refraction, p.sub.11 and p.sub.12 are strain-optic
constants, .epsilon..sub.1 is longitudinal strain, .alpha. is the
coefficient of thermal expansion and T is the temperature. In some
implementations, by using multiple FBG sensors that are differently
affected by strain and temperature (due to design or mounting),
dual fibers or special FBG sensors in combination with data
evaluation algorithms, the impacts from strain and temperature on
the wavelength shift can be separated. For example, strain and
temperature can be separated using a pair of adjacent FBGs at
different wavelengths attached to the transformer. One of the two
adjacent FBGs can be configured to be sensitive to thermal strain
alone using thermally sensitive paste or by enclosing it in a
special tubing. The measured wavelength shift of the "reference"
FBG sensor in the tubing can be subtracted from the total
wavelength shift of the adjacent FBG strain sensor for temperature
compensation.
[0038] As discussed above, fiber optic sensors are useful for
sensing temperature and strain. Vibration can be detected as
dynamic strain variations. With suitable coatings and
configurations, FBGs and/or other optical sensors can be useful for
monitoring current, voltage, chemical environment, and corrosion.
For example, some parameters of interest can be mapped to a strain
signal on the FBG through special coatings that undergo strain,
typically in a linear relationship, in response to the parameter of
interest. One or more immediately adjacent optical sensors may be
used to compensate for the influence of confounding parameters,
such as temperature and/or vibration effects, in order to recover
the parameter of interest with high fidelity.
[0039] For example, corrosion and/or moisture can be converted into
strain signals using suitable coatings and/or by bonding the
sensors or sensor coatings to structural components that undergo
tensile strain with corrosion.
[0040] As another example, chemical sensing can be accomplished by
depositing specific chemically sensitive coatings that undergo
strain in response to changing concentrations of the chemical
species of interest. For example, Palladium (Pd) coatings undergo
reversible strain in response to hydrogen-containing gases. Both
transformer oil and cellulose have carbon-based molecular
structures rich in hydrogen. The decomposition of oil and cellulose
forms a large number of byproducts, including combustible and
noncombustible gases. Hydrogen is naturally present in most of
those compounds. Up to 0.05% volume H.sub.2 and short-chain
hydrocarbons gas concentration can be an acceptable level for
healthy transformers. Optical sensors with Pd coating are useful
for detecting hydrogen-based gases. Hydrogen gas sensing with FBGs
in free air suggest that Pd-coated FBGs may have about 7 picometer
(pm) wavelength shift response for a 1% volume H.sub.2 gas
concentration change with a response time of about 5 minutes,
without accounting for thermal effects. A similar or greater
response sensitivity may be achieved for hydrocarbons. With a
detection unit resolution of 50 femtometer (fm), a resolution of
0.01-0.02% H.sub.2 may be achieved in free air, after accounting
for thermal effects. Similar resolution levels may be achievable
for dissolved H.sub.2 or H-containing gas in oil, enabling a target
resolution of about 250 ppm dissolved gas detection.
[0041] In some embodiments, the monitoring system disclosed herein
can be used for detecting partial discharge of a transformer. A
partial discharge causes small electrical sparks to be present in
an insulator as a result of the electrical breakdown of a gas (for
example air) contained within a void or in a highly non-uniform
electric field. The sudden release of energy caused when a partial
discharge occurs produces a number of effects, such as chemical and
structural changes in the materials surrounding the partial
discharge location, electromagnetic signal generation and/or
acoustic emission, e.g., in the 50-200 kHz frequency range. With
the high frequency monitoring capability enabled by the approaches
discussed herein, acoustic emission detection of fast (up to 1 MHz)
dynamic strain signals (up to 1.45 fm/ Hz) from partial discharge
acoustic emission may be achieved and used to detect the occurrence
of and/or the severity of the partial discharge.
[0042] In the embodiment shown in FIG. 3, the sensors S1, S2, . . .
SN are disposed on a single optical fiber 330 that is partially
embedded within a transformer 301. Each of the sensors S1, S2, . .
. SN may operate within a different wavelength band from other
sensors on the optical fiber 330. For example, sensor S1 may
operate within a first wavelength band centered at wavelength
.lamda..sub.1, sensor S2 may operate within a second wavelength
band centered at .lamda..sub.2, and sensor SN may operate within an
Nth wavelength band centered at .lamda..sub.N. Each wavelength band
.lamda..sub.1, .lamda..sub.2, . . . .lamda..sub.N may be selected
so that it does not substantially overlap with the wavelength bands
of the other sensors.
[0043] The monitoring system 300 includes control circuitry 335
comprising an input light source 310, optical demultiplexer 340,
and detection unit 350. In some embodiments, the control system
includes an analyzer 360 implementing model-based algorithms
362.
[0044] Optical sensors S1, S2, . . . SN are optically coupled to
the input light source 310, which may be a broadband light source
that supplies input excitation light across a broad wavelength band
that spans the operating wavelength bands of the optical sensors
S1, S2, . . . SN. Output light from optical sensors S1, S2, . . .
SN is carried on optical fiber 330 to a wavelength domain optical
demultiplexer 340 that spatially disperses light from the optical
fiber 330 according to the wavelength of the light. In various
implementations, the optical demultiplexer may comprise a linearly
variable transmission structure and/or an arrayed waveguide
grating, or other optically dispersive element.
[0045] In configurations that include multiple transformers, the
optical signals from each of the transformer monitors (which may
each include sensors S1 through SN) can be coupled through an
optical time multiplexer (not shown in FIG. 3) to the optical
demultiplexer 340. The use of optical time multiplexers is
discussed in greater detail below.
[0046] Light from the demultiplexer 340 is optically coupled to a
detection unit 350 which may comprise one or more photodetectors.
Each photodetector is configured to generate an electrical signal
in response to light that falls on a light sensitive surface of the
photodetector. The electrical signals generated by the
photodetectors of the detection unit 350 are representative of the
parameters sensed by sensors S1, S2, . . . SN. The optical
demultiplexer 340 used in conjunction with the detection unit 350
allows the sensor signal from each of the sensors S1, S2, . . . SN
to be individually detected.
[0047] The electrical signals generated by the detection unit 350
can be used by the analyzer 360 to analyze (predict, detect and/or
diagnose) one or more of a functional condition, a state, and/or a
degradation condition of the power transformer 301 based on
analysis of the electrical signals. Examples of a state of a power
transformer can include the load level of the transformer or the
temperature of the transformer. Examples of a functional condition
includes actual age of transformer, expected time of service based
on expected load levels, present load capacity, etc. Examples of a
degradation condition include short circuit, excessive dissolved
gases, partial discharge events, corrosion, etc.
[0048] Predicting a state or condition is used herein to express
making an estimate that the state or condition will happen at a
future time. Prediction may involve an estimate of the future time
that the state or condition is expected to occur. Detecting a state
or condition involves detecting that the state or condition is
currently present or absent. Diagnosing a state or condition may
identify the degree to which the state or condition is present
and/or may identify the cause or causes of the state or condition.
In some embodiments, the analysis can be used to schedule
maintenance and/or to control operation of the power transformer
and/or other components of the power grid.
[0049] The sensed parameters, as represented by the electrical
signals from the sensors, can be used in conjunction with
theoretical and/or empirical transformer models and model-based
algorithms 362 for real-time estimation of the transformer state,
various degradation conditions and/or various functional
conditions, for example. The models can be adapted based on
detected conditions of the transformer, measures of internal and/or
external parameters and/or correlations between the operational
conditions and measured parameters.
[0050] The availability of real-time transformer state variables
through the disclosed monitoring system can significantly alleviate
many of the problems with grid asset monitoring and grid
distribution management. The model-based algorithms can correlate
sensed parameter values and/or trends with transformer degradation
conditions. As one example, consider dissolved gas concentration
which can be correlated to safety-critical and performance effects
that occur due to degradation in the oil and insulation caused by
high temperatures and/or other aging factors. Gas evolution is
exacerbated in the presence of other transformer faults such as
partial discharges. Thus, dissolved gas levels are reflective of
long-term changes in the transformer health due to high
temperatures (ambient or from high load operation), cycling under
variable distributed energy resource loads, and storage. The
monitoring system disclosed herein can provide information about
transformer degradation based on dissolved gas sensing. The
algorithms executed by the analyzer may take into account trends of
dissolved gas sensing as well as temperature and/or cycling trends
to make predictions about a future degradation state of the
transformer and/or the rate of transformer degradation.
[0051] As an additional example, consider another parameter of
potential interest, coil strain. Coil strain can be separated into
two factors: (a) ohmic and hysteresis-related heating leading to
thermal expansion, and (b) magnetostrictive elastic
(magnetoelastic) deformation induced by the load level within the
core. Because thermal expansion is a slower process than
magnetoelastic deformation from the core expansion cycles,
mechanical equilibrium is established much faster than thermal. The
thermal strain can be isolated from the magnetoelastic deformation
using a tubing, for example, as mentioned earlier. As an
alternative implementation, core thermal expansion can be modeled.
Heat generated by hysteresis losses and electrical resistance in
windings produces repetitive thermal expansion and contraction of
the materials. The optically sensed temperature may be used as an
input to the thermal strain model to determine the temperature
induced strain. This value can be subtracted from the total strain
to isolate magnetoelastic strain.
[0052] Isolation of the thermal strain can allow the residual
magnetoelastic strain to act as a snapshot of the load level of the
transformer. Core in-plane strain values in the range of about
5-50.mu..epsilon. can be expected based on typical results from
numerical simulations. With higher distributed energy resource
penetration leading to more variable loading conditions, the
response behavior of the coil strain under inrush currents can be
used to predict the transformer's ability to function reliably
under a range of variable DER scenarios, including two-way flows
from high levels of distributed generation.
[0053] Inelastic strain behavior, acoustic emission, vibrations,
and/or dynamic oscillations may be generated during partial
discharge or coil short circuit events. Partial discharge and short
circuits can be detected based on sensing inelastic strain,
acoustic emission, vibrations, and/or dynamic oscillations.
[0054] Unusual vibrations can also result from core structural
issues. Thus, parameters such as coil strain and/or vibration,
which change with loads, can correlate to loading on the
transformer while dynamic events offer incipient failure
indications.
[0055] It is possible for mechanical stresses originating from the
grid (e.g. higher harmonics in loads) or the operating environment
(e.g. seismic events or neighboring construction activity) to be
transmitted to the transformer core through the transformer mounts.
These stresses might induce additional strains and sensor readings
that are not accounted for by the model and confound the parameters
sensed by the sensors. A control optical strain sensor can be
placed on the transformer enclosure. The output of the control
sensor can be used to compensate sensed parameters signals of
interest from external sources of strain.
[0056] Optically sensing changes in magnetoelasticity, dissolved
gas evolution, incidence of partial discharge events and/or other
parameters, such as those discussed herein, and trending the
parameters over time can give useful metrics for transformer health
and prognosis. For example, present values of one or more
parameters and/or the rates of change of trends of the one or more
parameters can be compared to threshold present values and/or trend
values (e.g., slopes) as an indication of transformer health and/or
to predict the likelihood of a degradation state and/or safety
event, e.g., such as a transformer coil short circuit.
[0057] A probabilistic regression analysis, such as relevance
vector machines, can be applied to a machine learning approach to
develop the models employed by the model-based algorithms for the
detection, prediction, and/or diagnosis of the transformer
operational state. The machine learning algorithms can collect data
via laboratory training conditions and/or conditions experienced by
transformers deployed in the field. The machine learning algorithms
employed may use probabilistic kernels to reject the effects of
outliers and the varying number of data points under different
operational conditions that can bias conventional curve fitting
methods. The probabilistic techniques can also leverage Bayesian
learning to manage system uncertainty.
[0058] The models and/or model-based algorithms may be adapted over
time through continued machine learning. A variety of filtering
techniques are applicable here. Efficient non-linear filters that
combine Bayesian learning with importance sampling to provide good
state-tracking performance are suitable for this task. The
model-based algorithms that are tuned during the tracking phase,
can then be propagated for expected loads to give short or
long-term prognosis for the transformer.
[0059] In some scenarios, information acquired or developed by the
analyzer 360 may be provided to an operator via an electronic or
printed report. For example, the analyzer 360 may compile, analyze,
trend, and/or summarize the sensed parameters, and/or may perform
other processes using the sensed parameters as input, such as
predicting and/or diagnosing the state of the transformer 301. The
results of these analyses and/or other information derived from
monitoring the transformer 301 may be provided in a report that can
be displayed graphically, textually and/or in any convenient form
to an operator and/or may be provided to another computer system
for storage in a database and/or further analysis and/or to update
the predictive models and/or model-based algorithms. In some
configurations, the information derived from the transformer
monitoring can be provided to the operator of the power grid
through a graphical user interface that includes a dashboard 361
presented on a display. The display dashboard allows for accessing
and configuring reports and/or graphs regarding the status of
individual transformers, multiple transformers and/or other grid
components.
[0060] In some embodiments one or more of the optical
demultiplexer, detection unit and analyzer can be implemented as an
integrated component at a substation which is interoperable with
substation automation systems (SAS). The integrated component can
handle one or more multiplexed embedded optical sensors within one
or more power transformers.
[0061] Optical sensor-based sensing as illustrated in FIG. 3 allows
for incorporating multiple sensing elements, e.g., about 8 sensors,
on a single optical fiber. In some approaches, each of the sensors
S1, S2, . . . SN can be individually interrogated through
wavelength domain multiplexing and demultiplexing. In some
approaches, as illustrated below, sensors disposed in multiple
sensor modules can be individually interrogated through a
combination of time domain multiplexing and wavelength domain
multiplexing and demultiplexing.
[0062] In some implementations, both ends of the sensor waveguide
330 disposed within a transformer may be optically coupled to the
light source 310 and the optical demultiplexer 340 through optical
switches (not shown in FIG. 3). Coupling both ends of the optical
fiber may be useful in the event of a broken optical fiber. For
example, consider the scenario wherein the optical fiber 330 breaks
in two portions between sensors S1 and S2, but both ends of the
optical fiber 330 are connected to the light source 310 and optical
coupler 340 via optical switches. In this example, an optical fiber
initially included all the sensors S1 through SN, but after the
breakage, sensors S1 through SN can be considered to be disposed on
two FO cables. Even with the broken optical fiber, all sensors S1
through SN remain accessible through the two portions of the
optical fiber if both ends of the optical fiber are selectably
optically coupled to the light source 310 and optical demultiplexer
340 through an optical switch. The sensors on each portion of the
broken optical fiber are accessible by time multiplexing the signal
from the optical fiber portions. In the scenario outlined above,
the signal from sensor S1 would be accessible through a first
portion of broken optical fiber when the optical switches are in
the first state and the signals from sensors S2 through SN would be
accessible through the second portion of the broken optical fiber
when the optical switches are in the second state.
[0063] In some embodiments the analyzer 360 may be capable of
detecting that an optical fiber is broken, e.g., based on an
absence of a signal at the wavelengths of the inaccessible sensors.
If the analyzer detects a broken optical fiber, the analyzer may
initiate monitoring of all sensors of the optical fiber through
both portions of the broken optical fiber. Coupling both ends of
the optical fiber may be useful in the implementation wherein only
one sensor is disposed on the optical fiber. For example, consider
the scenario wherein the optical fiber only includes S1. If the
optical fiber breaks between the light source and optical
demultiplexer and S1, then S1 would be inaccessible unless both
ends of the FO cable are optically coupled to the light source and
optical demultiplexer as discussed above.
[0064] Turning now to FIG. 4, the operation of a monitoring system
that monitors multiple parameters of a transformer with sensor
outputs multiplexed using optical wavelength division multiplexing
and demultiplexing is illustrated. Broadband light is transmitted
by the light source 410, which may comprise or be a light emitting
diode (LED) or superluminescent laser diode (SLD), for example. The
spectral characteristic (intensity vs. wavelength) of the broadband
light is shown by inset graph 491. The light is transmitted via the
optical fiber 411 to the first FBG sensor 421. The first FBG sensor
421 reflects a portion of the light in a first wavelength band
having a central or peak wavelength, .lamda..sub.1. Light having
wavelengths other than the first wavelength band is transmitted
through the first FBG sensor 421 to the second FBG sensor 422. The
spectral characteristic of the light transmitted to the second FBG
sensor 422 is shown in inset graph 492 and exhibits a notch at the
first wavelength band centered at .lamda..sub.1 indicating that
light in this wavelength band is reflected by the first sensor
421.
[0065] The second FBG sensor 422 reflects a portion of the light in
a second wavelength band having a central or peak wavelength,
.lamda..sub.2. Light that is not reflected by the second FBG sensor
422 is transmitted through the second FBG sensor 422 to the third
FBG sensor 423. The spectral characteristic of the light
transmitted to the third FBG sensor 423 is shown in inset graph 493
and includes notches centered at .lamda..sub.1 and
.lamda..sub.2.
[0066] The third FBG sensor 423 reflects a portion of the light in
a third wavelength band having a central or peak wavelength,
.lamda..sub.3. Light that is not reflected by the third FBG sensor
423 is transmitted through the third FBG sensor 423. The spectral
characteristic of the light transmitted through the third FBG
sensor 423 is shown in inset graph 494 and includes notches
centered at .lamda..sub.1, .lamda..sub.2, and .lamda.3.
[0067] Light in wavelength bands 481, 482, 483, having central
wavelengths .lamda..sub.1, .lamda..sub.2 and .lamda..sub.3
(illustrated in inset graph 495) is reflected by the first, second,
or third FBG sensors 421, 422, 423, respectively, along the FO
cables 412 to the analyzer 430. The analyzer 430 may compare the
shifts in each the central wavelengths .lamda..sub.1, .lamda..sub.2
and .lamda..sub.3 and/or wavelength bands reflected by the sensors
421-423 to a characteristic base wavelength (a known wavelength) to
determine whether changes in the parameters sensed by the sensors
421-423 have occurred. The analyzer 430 may determine that the one
or more of the sensed parameters have changed based on the
wavelength analysis and may calculate a relative or absolute
measurement of the change.
[0068] In some cases, instead of emitting broadband light, the
light source may scan through a wavelength range, emitting light in
narrow wavelength bands to which the various sensors disposed on
the FO cable are sensitive. The reflected light is sensed during a
number of sensing periods that are timed relative to the emission
of the narrowband light. For example, consider the scenario where
sensors 1, 2, and 3 are disposed on a FO cable. Sensor 1 is
sensitive to a wavelength band (WB1), sensor 2 is sensitive to
wavelength band WB2, and sensor 3 is sensitive to WB3. The light
source may be controlled to emit light having WB1 during time
period 1 and sense reflected light during a time period 1a that
overlaps time period 1. Following time period 1a, the light source
may emit light having WB2 during time period 2 and sense reflected
light during time period 2a that overlaps time period 2. Following
time period 2a, the light source may emit light having WB3 during
time period 3 and sense reflected light during time period 3a that
overlaps time period 3. Using this version of TDM, each of the
sensors may be interrogated during discrete time periods.
[0069] The FO cable used for energy storage/power system monitoring
may comprise a single mode (SM) FO cable or may comprise a
multi-mode (MM) FO cable. While single mode fiber optic cables
offer signals that are easier to interpret, to achieve broader
applicability and lower costs of fabrication, multi-mode fibers may
be used.
[0070] A major challenge of FBG and other wavelength-based FO
sensors is that the obtained wavelength shifts are typically very
small. Sub-picometer wavelength measurement resolution is the key
for achieving high sensitivity. At the same time, it is desirable
to maintain this capability over a wide spectral range.
Additionally, high-speed detection enables monitoring of higher
frequency vibration/acoustic signals. The detection units described
herein use wavelength shift detectors that can resolve wavelength
shifts as small as 50 femtometers, for example.
[0071] In some embodiments, the detector unit comprises
position-sensitive photodetectors and the optical demultiplexer
comprises a detector coating that has laterally varying
transmission properties, a laterally varying transmission structure
(LVTS). The coating converts the wavelength information of the
incident light into a spatial intensity distribution, which can be
detected with high precision with a position-sensitive
photodetector. Differential read-out of the photodetector allows
the determination of the centroid of the light distribution. The
approach used by the optical demultiplexer and detection unit
converts wavelength shifts into a simple centroid detection scheme,
allowing for higher resolution wavelength shift detection and cut
off frequency for monitoring optical signals.
[0072] As described in more detail in conjunction with FIG. 5 and
FIG. 6, in some embodiments, the output light from the monitor is
routed through a linear optical variable filter which serves as the
optical wavelength demultiplexer. Only wavelengths within a
particular range are transmitted and collected by one or more
photodetectors of the detection unit. The difference of the sensor
signals renders the signal independent of the strength of the light
source. This makes it relatively robust to noise source
fluctuations. As a result, the output voltage is proportional to
the spatial distribution of the light.
[0073] FIG. 5 is a block diagram illustrating portions of the
control circuitry 500 of a transformer monitoring system that may
be used to detect and/or interpret optical signals received from an
MM or SM FO cable having multiple optical sensors arranged at
locations in, on or about a power transformer. The light source 505
provides input excitation light to the sensors via optical fiber
506. The control circuitry 500 includes various components that may
optionally be used to detect a shift in the wavelength of light
reflected by the sensors and propagated by optical fiber 510. The
control circuitry 500 optionally includes a spreading component 540
configured to collimate and/or spread the light from the optical
fiber 510 across an input surface of LVTS 530. In arrangements
where sufficient spreading of the light occurs from the optical
fiber, the spreading component may not be used. The LVTS 530 may
comprise a dispersive element, such as a prism, or linear variable
filter. The LVTS 530 receives light at its input surface 531 (from
the optical fiber 510 and (optionally) the spreading component 540)
and transmits light from its output surface 532. At the output
surface 532 of the LVTS 530, the wavelength of the light varies
with distance along the output surface 532. Thus, the LVTS 530
serves to demultiplex the optical signal incident at the input
surface 531 of the LVTS 530 according to the wavelength of the
light.
[0074] FIG. 5 shows two wavelength bands (called emission band)
emitted from the LVTS 530, a first emission band has a central
wavelength of .lamda..sub.a emitted at distance d.sub.a from a
reference position (REF) along the output surface 532. The second
emission band has a central wavelength .lamda..sub.b and is emitted
at distance d.sub.b from the reference position. A position
sensitive detector (PSD) 550 is positioned relative to the LVTS 530
so that light transmitted through the LVTS 530 falls on the PSD.
For example, light having wavelength .lamda..sub.a falls on region
a of the PSD 550 and light having wavelength .lamda..sub.b falls on
region b of the PSD 550. The PSD generates an electrical signal
along output 551 that includes information about the position (and
thus the wavelength) of the light output from the LVTS. The output
signal from the PSD is used by the analyzer 560 to detect shifts in
the wavelengths reflected by the sensors.
[0075] The PSD may be or comprise a non-pixelated detector, such as
a large area photodiode, or a pixelated detector, such as a
photodiode array or charge coupled detector (CCD). Pixelated
one-dimensional detectors include a line of photosensitive elements
whereas a two-dimensional pixelated detector includes an n.times.k
array of photosensitive elements. Where a pixelated detector is
used, each photosensitive element, corresponding to a pixel, can
generate an electrical output signal that indicates an amount of
light incident on the element. The analyzer 560 may be configured
to scan through the output signals to determine the location and
location changes of the transmitted light spot. Knowing the
properties of the LVTS allows determining peak wavelength(s) and
shift of the peak wavelength(s) of the first and/or second emission
band. The wavelength shift of the first or second emission band can
be detected as a shift of the transmitted light spot at location a
orb. This can, for example, be accomplished by determining the
normalized differential current signal of certain pixels or pixel
groups of the PSD.
[0076] For example, consider the example where light spot A having
emission band EB.sub.A is incident on the PSD at location a.
I.sub.a1 is the current generated in the PSD by light spot A by
pixel/pixel group at location a1 and I.sub.a2 is the current
generated in the PSD by light spot A by pixel/pixel group at
location a2. Light spot B having emission band EB.sub.B is incident
on the PSD at location b. I.sub.b1 is the current generated in the
PSD by light spot B by pixel/pixel group at location b1 and
I.sub.b2 is the current generated in the PSD by light spot B by
pixel/pixel group at location b2.
[0077] The normalized differential current signal generated by
pixels or pixel groups at locations a1 and a2 can be written
(I.sub.a1-I.sub.a2)/(I.sub.a1+I.sub.a2), which indicates the
position of light spot A on the PSD. The wavelength of EB.sub.A can
be determined from the position of light spot A on the PSD.
[0078] Similarly, the normalized differential current signal
generated by pixels or pixel groups at locations b1 and b2 can be
written (I.sub.b1-I.sub.b2)/(I.sub.b1+I.sub.b2), which indicates
the position of light spot B on the PSD. The wavelength of EB.sub.B
can be determined from the position of light spot B on the PSD.
[0079] FIG. 6 is a block diagram illustrating portions of the
control circuitry 600 of a monitoring system that includes a
non-pixelated, one-dimensional PSD 650. The control circuitry 600
includes an optional spreading component 640 that is similar to
spreading component 540 as previously discussed. The spreading
component 640 is configured to collimate and/or spread the light
from the optical fiber 610 across an input surface 631 of the LVTS
630. In the implementation depicted in FIG. 10, the LVTS 630
comprises a linear variable filter (LVF) that includes layers
deposited on the PSD 650 to form an integrated structure. The LVF
630 in the illustrated example comprises two mirrors, e.g.,
distributed Bragg reflectors (DBRs) 633, 634 that are spaced apart
from one another to form optical cavity 635. The DBRs 633, 634 may
be formed, for example, using alternating layers of high refractive
index contrast dielectric materials, such as SiO.sub.2 and
TiO.sub.2. One of the DBRs 633 is tilted with respect to the other
DBR 634 forming an inhomogeneous optical cavity 635. It will be
appreciated that the LVF may alternatively use a homogeneous
optical cavity when the light is incident on the input surface at
an angle.
[0080] The PSD 650 shown in FIG. 6 is representative of a
non-pixelated, one-dimensional PSD although two-dimensional,
non-pixelated PSDs (and one or two-dimensional pixelated PSDs) are
also possible. The PSD 650 may comprise, for example, a large area
photodiode comprising a semiconductor such as InGaAs. Two contacts
653, 654 are arranged to run along first and second edges of the
semiconductor of the PSD to collect current generated by light
incident on the surface of the PSD 650. When a light spot 699 is
incident on the PSD 650, the contact nearest the light spot
collects more current when compared to the contact farther from the
light spot which collects a lesser amount of current. The current
from the first contact 653 is denoted I.sub.1 and the current from
the second contact 654 is denoted I.sub.2. The analyzer 660 is
configured to determine the normalized differential current,
(I.sub.1-I.sub.2)/(I.sub.1+I.sub.2), the position of the
transmitted light spot, and therefore the predominant wavelength of
the light incident at the input surface 631 of the LVTS 630 can be
determined. The predominant wavelength may be compared to known
wavelengths to determine an amount of shift in the wavelength. The
shift in the wavelength can be correlated to a change in the sensed
parameter. In case two emission bands (creating two spatially
separated light spots) hitting the detector at the same time the
detector is only capable to provide an average wavelength and
wavelength shifts for both emission bands. If wavelength and
wavelengths shift of both emission bands need to be determined
separately the two emission bands need to hit the detector at
different time (time multiplexing).
[0081] In other embodiments, a two dimensional non-pixelated PSD
may be used, with edge contacts running along all four edges. The
position of the central reflected wavelength may be determined by
analyzing the current collected from each of the four contacts. The
control circuitry (see element 335 of FIG. 3) is also referred to
as a "read-out" and may be packaged with an onboard excitation
light source as a photonic integrated circuit chip with a chip size
between 30-60 mm.sup.2 which can be disposed in a suitable housing,
e.g., a TO5 transistor package. For example, a mass-production
version of the control circuitry with an on-board light source may
fit within a typical integrated optics module having a volume as
small as about 7.5 in.sup.3 and/or with a weight of less than about
0.1 lbs.
[0082] In some embodiments, the wavelength division demultiplexer
(see element 212 in FIG. 2) may comprise an arrayed waveguide
grating (AWG) as shown in the monitoring system 700 of FIG. 7. FIG.
7 illustrates a power transformer 770 having a number of optical
sensors, S1, S2, . . . SN, disposed within, on, or about the power
transformer 770. Although only one transformer is shown in FIG. 7,
it will be appreciated that a monitoring system may include
multiple transformers which are monitored by multiple sensors.
[0083] Referring to FIG. 7, S1 operates in a wavelength band having
peak, center, or centroid wavelength .lamda..sub.i, S2 operates in
a wavelength band having peak, center, or centroid wavelength
.lamda..sub.2, and SN operates in a wavelength band having center
wavelength .lamda..sub.N. Each sensor may be most sensitive to a
different parameter, such that S1 is most sensitive to parameter 1,
S2 is most sensitive to parameter 2, and SN is most sensitive to
parameter N. A change in parameter 1 may shift the wavelength of
the light reflected from S1 from .lamda..sub.1 to
(.lamda..sub.1+/-.DELTA..sub.1), a change in parameter 2 may shift
the wavelength of light reflected from S2 from k.sub.2 to
(k.sub.2+/-.DELTA..sub.2), etc. The wavelength shifts caused by
changes in the sensed parameters are small compared to the spacing
between the characteristic base wavelengths of the individual
sensors.
[0084] Light source 710 is configured to provide input light to the
sensors through circulator 715. The light source 710 has a
bandwidth broad enough to provide input light for each of the
sensors and over the range of reflected wavelengths expected. The
AWG may include N pairs of output waveguides 745, wherein each pair
of output waveguides 745 is centered in wavelength around the
reflection output of a particular sensor. Light from the light
source travels through the circulator and reflects off the sensors
as output light. The output light emanating from the sensors is
carried on sensor optical waveguide 730 through circulator 715 to
the AWG 740 which is used as the optical wavelength domain
demultiplexer. When used as an optical demultiplexer, light from
the AWG input waveguide 741 is dispersed via diffraction to output
waveguides 745 depending on the wavelength of the light. For
example, an AWG might have a center wavelength of 1550 nm, and 16
output channels with a channel spacing of 100 GHz (0.8 nm at that
wavelength). In this scenario, light input at 1549.6 nm will go to
channel 8, and light input at 1550.4 nm will go to channel 9,
etc.
[0085] An AWG may include an input waveguide 741, a first slab
waveguide 742, array waveguides 743, a second slab waveguide 744,
and output waveguides 745. Each of the array waveguides 743 is
incrementally longer than the next. The input light is broken up in
the first slab waveguide 742 among the array waveguides 743. At the
output of each array waveguide 743, the light has accrued a
wavelength-dependent phase shift, which also is incrementally more
from one waveguide to the next. The outputs of the array waveguides
743 resemble an array of coherent sources. Therefore, the
propagation direction of the light emitted from the array
waveguides 743 into the second slab waveguide 744 depends on the
incremental phase shift between the sources and hence the
wavelength, as in a diffraction grating.
[0086] In some embodiments, the optical coupler, e.g., AWG, the
photodiode array and/or the digitizer may be arranged as a planar
lightwave circuit, i.e., integrated optical device. For example,
these system components may be made from silicon-on-insulator (SOI)
wafers using optical and/or electron beam lithography techniques.
The planar lightwave circuit can be coupled to the fiber optic,
aligned using V-grooves anisotropically etched into the silicon.
Hybrid integration with other semiconductors, for example
germanium, is possible to provide photodetection at energies below
the bandgap of silicon.
[0087] In the AWG 740, the outputs of the array waveguides 743 (and
hence the input side of the slab waveguide 744) may be arranged
along an arc with a given radius of curvature such that the light
emanating from them travels in the second slab waveguide 744 and
comes to a focus a finite distance away. The inputs of the output
waveguides 745 are nominally disposed at the focal points
corresponding to specific wavelengths, although they may be set
either in front of or behind the foci to deliberately introduce
"crosstalk" between the output waveguides as will be described
later. Therefore, light at the input 741 of the AWG 740 is
passively routed to a given one of the output waveguides 745
depending on wavelength of the light. Thus, the output light from
the S1, S2, . . . SN is routed to output waveguides 745 depending
on the wavelength of the output light.
[0088] The output waveguides 745 are optically coupled to a
detector unit 750 that includes photodetectors, e.g., 2N
photodetectors. Due to the wavelength-based spatial dispersion in
the AWG, the output light from the sensors S1, S2, . . . SN is
spatially distributed across the surface of the detector unit. The
photodetectors sense the light from the output waveguides and
generate electrical signals that include information about the
sensed parameters.
[0089] FIG. 8A illustrates in more detail the output waveguides of
an AWG used as a wavelength domain optical demultiplexer (e.g.
element 340 of FIG. 3) and a detector unit (e.g., element 350 of
FIG. 3) according to some embodiments. In the illustrated
configuration 2N photodetectors are respectively coupled to receive
light from N sensors. The AWG spatially disperses sensor output
light having centroid wavelengths .lamda..sub.1, .lamda..sub.2, . .
. .lamda..sub.N to the output waveguide pairs 845a,b, 846a,b, . . .
847a,b. Sensor output light having centroid wavelength
.lamda..sub.1 is dispersed to waveguide pairs 845a, 845b; sensor
output light having centroid wavelength .lamda..sub.2 is dispersed
to waveguide pairs 846a, 846b; sensor output light having centroid
wavelength .lamda..sub.N is dispersed to waveguide pairs 847a,
847b, etc. Light from output waveguide 845a is optically coupled to
photodetector 855a which generates signal I.sub.11 in response to
the detected light; light from output waveguide 845b is optically
coupled to photodetector 855b which generates signal I.sub.12 in
response to the detected light; light from output waveguide 846a is
optically coupled to photodetector 856a which generates signal
I.sub.21 in response to the detected light; light from output
waveguide 846b is optically coupled to photodetector 856b which
generates signal I.sub.22 in response to the detected light; light
from output waveguide 847a is optically coupled to photodetector
857a which generates signal I.sub.N1 in response to the detected
light; light from output waveguide 847b is optically coupled to
photodetector 857b which generates signal I.sub.N2 in response to
the detected light.
[0090] As the centroid of a sensor's output light shifts in
response to the sensed parameter, the AWG causes the spatial
position of the sensor's output light to also shift. For example if
sensor output light that initially has a centroid at .lamda..sub.1
shifts to a centroid at .lamda..sub.1+.DELTA..sub.1, as shown in
FIG. 8A, the amount of light carried by output waveguide 845a
decreases and the amount of light carried by output waveguide 845b
increases. Thus, the amount of light detected by photodetector 855a
decreases and the amount of light detected by photodetector 855b
increases with corresponding changes in the photocurrents I.sub.1
and I.sub.2. Thus, a shift in the sensed parameter causes a shift
in the sensor output light centroid from .lamda..sub.1 to
.lamda..sub.1+.DELTA..sub.1 which in turn causes a change in the
ratio of I.sub.11 to I.sub.12.
[0091] The photocurrent of each photodiode may be converted into a
voltage with a resistor or transimpedance amplifier, and sensed and
digitized. The wavelength shift may be calculated for the i.sup.th
FBG with the following formula:
.lamda. i .apprxeq. .lamda. i 0 + .DELTA. .lamda. 2 I 2 i - I 2 i -
1 I 2 i + I 2 i - 1 ##EQU00001##
Here, .lamda..sub.i is the estimated wavelength of the i.sup.th
FBG, .lamda..sub.i0 is the center wavelength of an output waveguide
pair, .DELTA..lamda. is the wavelength spacing between the peak
transmission wavelengths of an output waveguide pair, and I.sub.2i
and I.sub.2i-1 are the light intensities recorded by the
photodetectors at the output of each waveguide in the pair. From
the sensed wavelength shift of a given FBG, it is possible to
calculate values of sensed parameters, and in turn, to calculate
properties of the transformer or other power grid component
corresponding to the parameters sensed by the FBG if it is known
how those properties tend to vary the observed wavelength shift. In
some embodiments, the FBGs have a FWHM roughly equal to
.DELTA..lamda./2, such that as the reflected peak from the FBG
shifts from one photodetector in the pair to the other, there is a
continuous and monotonic change in the differential signal of the
pair (numerator in the formula above).
[0092] FIG. 8B illustrates in more detail another configuration of
the output waveguides of an AWG used as a wavelength domain optical
demultiplexer (e.g. element 212 of FIG. 2) and a detection unit
(e.g., element 215 of FIG. 2) according to some embodiments. In
this configuration N photodetectors are respectively coupled to
receive light from N sensors. The AWG spatially disperses sensor
output light having centroid wavelengths .lamda..sub.1,
.lamda..sub.2, . . . .lamda..sub.N to the output waveguides 845,
846, . . . 847. Sensor output light having centroid wavelength
.lamda..sub.1 is dispersed to waveguide 845; sensor output light
having centroid wavelength .lamda..sub.2 is dispersed to waveguide
846; sensor output light having centroid wavelength is dispersed to
waveguide 847, etc. Light from output waveguide 845 is optically
coupled to photodetector 855 which generates signal I.sub.1 in
response to the detected light; light from output waveguide 846 is
optically coupled to photodetector 856 which generates signal
I.sub.2 in response to the detected light; light from output
waveguide 847 is optically coupled to photodetector 857 which
generates signal I.sub.N in response to the detected light.
[0093] As the centroid of a sensor's output light shifts in
response to the sensed parameter, the AWG causes the spatial
position of the sensor's output light to also shift. For example,
if sensor output light that initially has a centroid at
.lamda..sub.1 shifts to a centroid at .lamda..sub.1+.DELTA..sub.1
as shown in FIG. 8B, the amount of light carried by output
waveguide 845 increases. Thus, the amount of light detected by
photodetector 855 increases with a corresponding change in the
photocurrent I.sub.1. Thus, a shift in the sensed parameter causes
a shift in the sensor output light centroid from .lamda..sub.1 to
.lamda..sub.1+.DELTA..sub.1, which in turn causes a change in the
current I.sub.1.
[0094] Changes in the photodetector current that are caused by
fluctuations of light source intensity (e.g., 310 in FIG. 3) can be
differentiated from changes in photodetector current caused by
wavelength shifts in sensor output light by measuring the light
source intensity with an additional photodetector 899 that
generates current I.sub.N+1. Then, a wavelength shift can be
calculated from the ratio I.sub.1/I.sub.N+1 for sensor 1,
I.sub.2/I.sub.N+1 for sensor 2, etc.
[0095] From the sensed wavelength shift of a given sensor, it is
possible to calculate a value of sensed parameter, and in turn, to
calculate properties of the transformer corresponding to the
parameter sensed by the sensor if it is known how those properties
tend to vary the observed wavelength shift.
[0096] FIG. 9 illustrates in more detail the output waveguides of
an AWG used as a wavelength domain optical demultiplexer, an
additional dispersive element, and a digitizer according to some
embodiments. In this example, the output light from sensors 1, 2 .
. . N having initial centroid wavelengths .lamda..sub.1,
.lamda..sub.2, . . . .lamda..sub.N is respectively spatially
dispersed to output waveguides 945, 946, . . . 947 of the AWG. The
light from output waveguides 945, 946, . . . 947 is incident on
LVTS 965, 966, . . . 967 or other spatially dispersive optical
element.
[0097] Optionally, the LVTS includes spreading components 955, 956
. . . 957 configured to collimate and/or spread the light from the
output waveguide 945, 946 . . . 947 across an input surface of LVTS
965, 966, . . . 967. In arrangements where sufficient spreading of
the light occurs from the output waveguides 945, 946, . . . 947,
the spreading components may not be used. The LVTS 965, 966, . . .
967 comprises a dispersive element, such as a prism or a linear
variable filter. The LVTS 965, 966, . . . 967 receives light at its
input surface 965a, 966a, . . . 967a from the waveguide 945, 946, .
. . 947 and the optional spreading component 955, 956, . . . 957
and transmits light from its output surface 965b, 966b, . . . 967b
to photodetector pairs 975, 976, . . . 977. At the output surface
965b, 966b, . . . 967b of the LVTS 965, 966, . . . 967, the
wavelength of the light varies with distance along the output
surface. Thus, the LVTS 965, 966, . . . 967 can serve to further
demultiplex the optical signal incident at the input surface 965a,
966a, . . . . 967a of the LVTS 965, 966, . . . 967 according to the
wavelength of the light.
[0098] FIG. 9 shows two wavelength bands emitted from the LVTS 965,
an initial emission band has a centroid wavelength of .lamda..sub.1
emitted at distance d.sub.1 from a reference position (REF) along
the output surface 965b. In response to the sensed parameter, the
initial wavelength band shifts to a wavelength band having centroid
wavelength .lamda..sub.1+.DELTA..sub.1. The shifted wavelength band
is emitted at distance d.sub..DELTA.1 from the reference
position.
[0099] A photodetector pair 975 is positioned relative to the LVTS
965 so that light transmitted through the LVTS 965 falls on the
photodetector pair 975. For example, light having wavelength
.lamda..sub.1 may fall predominantly on photodetector 975a and
light having wavelength .lamda..sub.1+.DELTA..sub.1 may fall
predominantly on photodetector 975b. The photodetector 975a
generates signal I.sub.11 in response to light falling on its light
sensitive surface and photodetector 975b generates signal I.sub.12
in response to light falling on its light sensitive surface. The
signals I.sub.11, I.sub.12 include information about the sensed
parameter such that a change in the ratio of I.sub.11 and I.sub.12
indicates a change in the sensed parameter, which can be calculated
using the equation discussed above.
[0100] The high resolution wavelength shift detection schemes
discussed above can be extended to monitor tens to thousands of
multiplexed sensors while maintaining 50 fm or greater wavelength
resolution at an effective sampling rate of 100 Hz. For example, in
one embodiment the control circuitry can be configured to monitor
eight wavelength multiplexed sensor strings of sixteen sensors with
time domain multiplexing, e.g., using an optical switch. In such a
configuration 128 sensors can be monitored at 100 Hz. At lower
frequencies, up to several thousand sensors can be monitored.
[0101] FIG. 10 shows a block diagram of a monitoring system 1000
that incorporates time domain multiplexing to monitor M
transformers wherein each transformer monitor 1021, 1022, . . .
1023 includes N sensors. The optical outputs of the N sensors of
each transformer monitor 1021, 1022, . . . 1023 may be carried on a
single optical fiber 1031, 1032, 1033 where the optical outputs of
the sensors are spatially distributed in wavelength by the optical
demultiplexer. The optical fibers and/or sensors may be identically
constructed.
[0102] Input light is passed from the light source 1010 to the N
sensors of each transformer monitor 1021, 1022, . . . 1023 through
optical time domain multiplexer 1070 and through waveguides 1031,
1032, . . . 1033. The input excitation light interacts with the
sensors S11 . . . SNM. Output light from the sensors of the
transformer monitors 1021, 1022, . . . 1023 is passed to the
optical wavelength domain demultiplexer 1040 through the optical
time domain multiplexer 1070. The transformer monitors 1021
(including sensors S11 through SN1), 1022 (including sensors S12
through SNM), . . . 1023 (including sensors S1M through SNM) are
selected one at a time by the optical time domain multiplexer 1070.
Optical signals from he selected monitor are applied to the optical
demultiplexer 1040, detection unit 1050, and analyzer 1060 during
different time intervals. Implementations that combine time domain
multiplexing and wavelength domain multiplexing and demultiplexing
of sensor output light as disclosed herein are able to monitor a
greater number of transformers than could be addressed by either
time domain multiplexing or wavelength domain
multiplexing/demultiplexing alone.
[0103] The monitoring system approaches discussed herein can
include cybersecurity and interoperability as key built-in
functions. For smart grid asset cybersecurity, the vulnerability of
the physical, computational, and communications interface layers to
deliberate attacks, as well as inadvertent compromises from user
errors, equipment failures, and natural disasters are of concern.
The disclosed approaches have an inherent advantage over
conventional alternatives at least because they are based on
optical fiber cables for embedded sensing. The optical fiber cable
emerging from the embedded sensing configuration within the
transformer is coupled to a modular, dedicated, data-secure
communications bus, e.g., using standard optical fiber connectors.
The communications bus can transmit the sensed signals directly to
a substation control center, e.g., up to 30 km away with 50 fm
resolution at 100 Hz. EMI and RFI immunity characteristics make
optical fiber communications a desirable long-distance
communication bus around substations. Additionally, communications
over optical fiber offers shielding and lightning protection
functions.
[0104] According to some embodiments, the control circuitry, e.g.,
a photonic chip readout with an onboard light source, is located at
a substation directly interfacing with the supervisory control and
data acquisition (SCADA) and SAS. With its embedded sensing and
model-based algorithms, the control circuitry will monitor optical
sensor wavelength shifts for transformer health from the
substation. Note that as previously discussed, the control
circuitry could potentially monitor multiple transformers of
interest and/or could monitor multiple redundant optical fiber
cables from the same transformer from a central location using time
multiplexing strategies. Monitoring multiple redundant optical
fibers from the same transformer may be desirable from a security
perspective, for example. Monitoring from a central location
eliminates the need for a battery or other energy source at the
sensing location. The control circuitry can be powered by the same
energy source powering the automation systems in the substation
control center. Monitoring from a central location also enhances
security because the control circuitry can be physically protected
from attack out on the field. Having additional multiplexed
reference optical sensors monitoring the communication channels for
unusual signal anomalies not attributable to transformer parameters
can provide an alert to attacks and/or other breaches of
security.
[0105] Systems, devices, or methods disclosed herein may include
one or more of the features, structures, methods, or combinations
thereof described herein. For example, a device or method may be
implemented to include one or more of the features and/or processes
described herein. It is intended that such device or method need
not include all of the features and/or processes described herein,
but may be implemented to include selected features and/or
processes that provide useful structures and/or functionality.
[0106] In the above detailed description, numeric values and ranges
are provided for various aspects of the implementations described.
These values and ranges are to be treated as examples only, and are
not intended to limit the scope of the claims. For example,
embodiments described in this disclosure can be practiced
throughout the disclosed numerical ranges. In addition, a number of
materials are identified as suitable for various implementations.
These materials are to be treated as exemplary, and are not
intended to limit the scope of the claims.
[0107] The foregoing description of various embodiments has been
presented for the purposes of illustration and description and not
limitation. The embodiments disclosed are not intended to be
exhaustive or to limit the possible implementations to the
embodiments disclosed. Many modifications and variations are
possible in light of the above teaching.
* * * * *