SYSTEMES ET PROCEDES DE CREATION D'UNE INTERFACE UTILISATEUR SCHEMATIQUE SERVANT A CONTROLER ET PREDIRE L'ETAT, LA FIABILITE ET LES PERFORMANCES EN TEMPS REEL D'UN SYSTEME D'ALIMENTATION ELECTRIQUE

SYSTEMS AND METHODS FOR CREATION OF A SCHEMATIC USER INTERFACE FOR MONITORING AND PREDICTING THE REAL- TIME HEALTH, RELIABILITY AND PERFORMACE OF AN ELECTRICAL POWER SYSTEM

Abrégé français

L'invention concerne un système destiné à générer automatiquement une interface utilisateur schématique d'un système électrique. Le système selon l'invention comprend un composant d'acquisition de données, un serveur analytique d'alimentation et un terminal client. Le composant d'acquisition de données acquière une sortie de données en temps réel du système électrique. Le serveur analytique d'alimentation est constitué d'un moteur de modélisation de système virtuel, d'un moteur analytique, d'un moteur d'apprentissage machine et d'un moteur de création d'interface utilisateur schématique. Le moteur de modélisation de système virtuel génère une sortie de données prévues pour le système électrique. Le moteur analytique contrôle la sortie de données en temps réel et la sortie de données prévues du système électrique. Le moteur d'apprentissage machine stocke et traite des schémas observés à partir de la sortie de données en temps réel et de la sortie de données prévues, de sorte à prévoir un aspect du système électrique. Le moteur de création d'interface utilisateur schématique est configuré pour créer une interface utilisateur schématique représentative du modèle de système virtuel et pour associer l'interface utilisateur schématique au composant d'acquisition de données.

Abrégé anglais

A system for automatically generating a schematic user interface of an electrical system is disclosed. The system includes a data acquisition component, a power analytics server and a client terminal. The data acquisition component acquires real-time data output from the electrical system. The power analytics server is comprised of a virtual system modeling engine, an analytics engine, a machine learning engine and a schematic user interface creator engine. The virtual system modeling engine generates predicted data output for the electrical system. The analytics engine monitors real-time data output and predicted data output of the electrical system. The machine learning engine stores and processes patterns observed from the real-time data output and the predicted data output to forecast an aspect of the electrical system. The schematic user interface creator engine is configured to create a schematic user interface that is representative of the virtual system model and link the schematic user interface to the data acquisition component.

Revendications

CLAIMS
1. A system for generating a schematic user interface of an electrical system,
comprising:
a data acquisition component communicatively connected to a sensor configured
to
acquire real-time data output from the electrical system;
a power analytics server communicatively connected to the data acquisition
component,
comprising,
a virtual system modeling engine configured to generate predicted data output
for
the electrical system utilizing a virtual system model of the electrical
system,
an analytics engine configured to monitor the real-time data output and the
predicted data output of the electrical system, the analytics engine further
configured to initiate a
calibration and synchronization operation to update the virtual system model
when a difference
between the real-time data output and the predicted data output exceeds a
threshold,
a machine learning engine configured to store and process patterns observed
from
the real-time data output and the predicted data output, the machine learning
engine further
configured to forecast an aspect of the electrical system, and
a schematic interface creator engine configured to create a schematic user
interface that is representative of the virtual system model and link the
schematic user interface
to the data acquisition component; and
a client terminal communicatively connected to the power analytics server and
configured to display the schematic user interface.
2. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein, the machine learning engine includes,
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an associative memory layer,
a sensory layer, and
a neocortical model.
3. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the virtual system model includes current system components
and operational
parameters comprising the electrical system.
4. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the forecasted aspect is a predicted ability of the
electrical system to resist
system output deviations from defined tolerance limits of the electrical
system.
5. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the forecasted aspect is a predicted reliability and
availability of the electrical
system.
6. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the forecasted aspect is a predicted total power capacity of
the electrical
system.
7. The system for generating a schematic user interface of an electrical
system, as recited in
claim 6, wherein the forecasted aspect is a predicted ability of the
electrical system to maintain
availability of total power capacity.
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8. The system for generating a schematic user interface of an electrical
system, as recited in
claim 6, wherein the forecasted aspect is a predicted utilization of the total
power capacity of the
electrical system.
9. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the forecasted aspect is a predicted ability of the
electrical system to withstand
a contingency event that results in stress to the electrical system.
10. The system for generating a schematic user interface of an electrical
system, as recited in
claim 9, wherein the contingency event relates to load shedding.
11. The system for generating a schematic user interface of an electrical
system, as recited in
claim 9, wherein the contingency event relates to load adding.
12. The system for generating a schematic user interface of an electrical
system, as recited in
claim 9, wherein the contingency event relates to loss of utility power supply
to the electrical
system.
13. The system for generating a schematic user interface of an electrical
system, as recited in
claim 9, wherein the contingency event relates to a loss of distribution
infrastructure associated
with the electrical system.
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14. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the client terminal is a thin client computing device.
15. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the client terminal is a wide area network capable computing
device.
16. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the client terminal is a mobile computing device.
17. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the schematic user interface is rendered in 3-D.
18. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the schematic user interface is based on a one-line diagram
construct.
19. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the schematic user interface is based on a technical system
schematic diagram
construct.
20. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the virtual system model is stored on a virtual system model
database
communicatively connected with the power analytics server.
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21. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the schematic user interface includes a visual representation
of each piece of
electrical equipment that comprise the electrical system.
22. The system for generating a schematic user interface of an electrical
system, as recited in
claim 21, wherein each piece of electrical equipment is associated with a
unique identifier.
23. The system for generating a schematic user interface of an electrical
system, as recited in
claim 1, wherein the schematic user interface is configured to allow an
operator to monitor
operational aspects of the electrical system.
24. A method for generating a schematic user interface of an electrical
system, comprising:
extracting system configuration data from a virtual system model of the
electrical system;
creating a logical construct of the virtual system model using the system
configuration
data;
generating one or more graphical objects to represent one or more pieces of
electrical
equipment included in the logical construct;
organizing the one or more graphical objects to generate a schematic user
interface layout
of the electrical system; and
communicatively linking each of the one or more graphical objects in the
schematic user
interface layout to sensors configured to monitor the real-time operational
status of the one or
more pieces of electrical equipment represented by the one or more graphical
objects.

25. The method for generating a schematic user interface of an electrical
system, as recited in
claim 24, further including:
applying a self-executing algorithm to generate the schematic user interface
layout out of
the organized graphical objects.
26. The method for generating a schematic user interface of an electrical
system, as recited in
claim 25, wherein the self-executing algorithm is a NET application.
27. The method for generating a schematic user interface of an electrical
system, as recited in
claim 25, wherein the self-executing algorithm is an ACTIVE X application.
28. The method for generating a schematic user interface of an electrical
system, as recited in
claim 25, wherein the self-executing algorithm is a JAVA based application.
29. The method for generating a schematic user interface of an electrical
system, as recited in
claim 25, wherein the self-executing algorithm is in a tree layout format.
30. The method for generating a schematic user interface of an electrical
system, as recited in
claim 25, wherein the self-executing algorithm is in a force directed layout
format.
31. The method for generating a schematic user interface of an electrical
system, as recited in
claim 25, wherein the self-executing algorithm is in a layered diagraph layout
format.
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32. The method for generating a schematic user interface of an electrical
system, as recited in
claim 25, wherein the virtual system model is stored on a virtual system model
database.
33. The method for generating a schematic user interface of an electrical
system, as recited in
claim 25, wherein the logical construct is an XML representation of the
virtual system model.
34. The method for generating a schematic user interface of an electrical
system, as recited in
claim 25, wherein each of the one or more pieced of electrical equipment is
associated with a
unique identifier.
35. The method for generating a schematic user interface of an electrical
system, as recited in
claim 25, further including:
scanning the schematic user interface layout; and
re-aligning the one or more graphical objects to optimize the schematic user
interface layout.
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Description

CA 02684566 2009-10-19
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SYSTEMS AND METHODS FOR CREATION OF A SCHEMATIC USER INTERFACE
FOR MONITORING AND PREDICTING THE REAL-TIME HEALTH, RELIABILITY
AND PERFORMANCE OF AN ELECTRICAL POWER SYSTEM
BACKGROUND
1. Field
[0001] The present invention relates generally to computer modeling and
management of
systems and, more particularly, to computer simulation techniques with real-
time system
monitoring of electrical system health and performance.
II. Background
[0002] Computer models of complex systems enable improved system design,
development,
and implementation through techniques for off-line simulation of system
operation. That is,
system models can be created on computers and then "operated" in a virtual
environment to
assist in the determination of system design parameters. All manner of systems
can be modeled,
designed, and operated in this way, including machinery, factories, electrical
power and
distribution systems, processing plants, devices, chemical processes,
biological systems, and the
like. Such simulation techniques have resulted in reduced development costs
and superior
operation.
[0003] Design and production processes have benefited greatly from such
computer
simulation techniques, and such techniques are relatively well developed, but
they have not been
applied in real-time, e.g., for real-time operational monitoring and
management. In addition,
predictive failure analysis techniques do not generally use real-time data
that reflect actual
system operation. Greater efforts at real-time operational monitoring and
management would
provide more accurate and timely suggestions for operational decisions, and
such techniques
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applied to failure analysis would provide improved predictions of system
problems before they
occur.
[0004] That is, an electrical network model that can age and synchronize
itself in real-time
with the actual facility's operating conditions is critical to obtaining
predictions that are
reflective of the system's reliability, availability, health and performance
in relation to the life
cycle of the system. Static systems simply cannot adjust to the many daily
changes to the
electrical system that occur at a facility (e.g., motors and pumps switching
on or off, changes to
on-site generation status, changes to utility electrical feed. .. etc.) nor
can they age with the
facility to accurately predict the required indices. Without a synchronization
or aging ability,
reliability indices and predictions are of little value as they are not
reflective of the actual
operational status of the facility and may lead to false conclusions. With
such improved
techniques, operational costs and risks can be greatly reduced.
[0005] For example, mission critical electrical systems, e.g., for data
centers or nuclear
power facilities, must be designed to ensure that power is always available.
Thus, the systems
must be as failure proof as possible, and many layers of redundancy must be
designed in to
ensure that there is always a backup in case of a failure. It will be
understood that such systems
are highly complex, a complexity made even greater as a result of the required
redundancy.
Computer design and modeling programs allow for the design of such systems by
allowing a
designer to model the system and simulate its operation. Thus, the designer
can ensure that the
system will operate as intended before the facility is constructed.
[0006] As with all analytical tools, predictive or otherwise, the manner in
which data and
results are communicated to the user is often as important as the choice of
analytical tool itself.
Ideally, the data and results are communicated in a fashion that is simple to
understand while
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also painting a comprehensive and accurate picture for the user. For example,
graphical displays
(e.g., two-dimensional and three-dimensional views) of the operational aspects
of an electrical
system greatly enhances the ability of a system operator, owner and/or
executive to understand
the health and predicted performance of the electrical system.
[0007] Currently, no solution exists for an automatic and intelligent
electrical power system
schematic creation and visualization tool for the rapid development and
deployment of
schematic-based user interfaces for real-time monitoring the health,
performance, and reliability
of an electrical power system.
SUMMARY
[0008] Systems and methods for automatically generating a schematic user
interface of an
electrical system are disclosed.
[0009] In one aspect, a system for automatically generating a schematic user
interface of an
electrical system is disclosed. The system includes a data acquisition
component, a power
analytics server and a client terminal. The data acquisition component is
communicatively
connected to a sensor configured to acquire real-time data output from the
electrical system. The
power analytics server is communicatively connected to the data acquisition
component and is
comprised of a virtual system modeling engine, an analytics engine, a machine
learning engine
and a schematic user interface creator engine.
[0010] The virtual system modeling engine is configured to generate predicted
data output
for the electrical system utilizing a virtual system model of the electrical
system. The analytics
engine is configured to monitor the real-time data output and the predicted
data output of the
electrical system initiating a calibration and synchronization operation to
update the virtual
system model when a difference between the real-time data output and the
predicted data output
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exceeds a threshold. The machine learning engine is configured to store and
process patterns
observed from the real-time data output and the predicted data output then
forecast an aspect of
the electrical system. The schematic user interface creator engine is
configured to create a
schematic user interface that is representative of the virtual system model
and link the schematic
user interface to the data acquisition component.
[0011] The client terminal is communicatively connected to the power analytics
server and
configured to display the schematic user interface.
[0012] In another aspect, a method for automatically generating a schematic
user interface of
an electrical system is disclosed. System configuration data is extracted from
a virtual system
model of the electrical system. A logical construct of the virtual system
model is created using
the system configuration data. On or more graphical objects are generated to
represent one or
more pieces of electrical equipment included in the logical construct. The one
or more graphical
objects are organized to generate a schematic user interface layout of the
electrical system. The
one or more graphical objects are communicatively linked to sensors configured
to monitor the
real-time operational status of the one or more pieces of electrical equipment
represented by the
one or more graphical objects.
[0013] These and other features, aspects, and embodiments are described below
in the
section entitled "Detailed Description."
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] For a more complete understanding of the principles disclosed herein,
and the
advantages thereof, reference is now made to the following descriptions taken
in conjunction
with the accompanying drawings, in which:
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[0015] Figure 1 is an illustration of a system for utilizing real-time data
for predictive
analysis of the performance of a monitored system, in accordance with one
embodiment.
[0016] Figure 2 is a diagram illustrating a detailed view of an analytics
server included in the
system of figure 1, in accordance with one embodiment.
[0017] Figure 3 is a diagram illustrating how the system of figure 1 operates
to synchronize
the operating parameters between a physical facility and a virtual system
model of the facility, in
accordance with one embodiment.
[0018] Figure 4 is an illustration of the scalability of a system for
utilizing real-time data for
predictive analysis of the performance of a monitored system, in accordance
with one
embodiment.
[0019] Figure 5 is a block diagram that shows the configuration details of the
system
illustrated in Figure 1, in accordance with one embodiment.
[0020] Figure 6 is an illustration of a flowchart describing a method for real-
time monitoring
and predictive analysis of a monitored system, in accordance with one
embodiment.
[0021] Figure 7 is an illustration of a flowchart describing a method for
managing real-time
updates to a virtual system model of a monitored system, in accordance with
one embodiment.
[0022] Figure 8 is an illustration of a flowchart describing a method for
synchronizing real-
time system data with a virtual system model of a monitored system, in
accordance with one
embodiment.
[0023] Figure 9 is a flow chart illustrating an example method for updating
the virtual model,
in accordance with one embodiment.

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[0024] Figure 10 is a diagram illustrating an example process for monitoring
the status of
protective devices in a monitored system and updating a virtual model based on
monitored data,
in accordance with one embodiment.
[0025] Figure 11 is a flowchart illustrating an example process for
determining the protective
capabilities of the protective devices being monitored, in accordance with one
embodiment.
[0026] Figure 12 is a diagram illustrating an example process for determining
the protective
capabilities of a High Voltage Circuit Breaker (HVCB), in accordance with one
embodiment.
[0027] Figure 13 is a flowchart illustrating an example process for
determining the protective
capabilities of the protective devices being monitored, in accordance with
another embodiment.
[0028] Figure 14 is a diagram illustrating a process for evaluating the
withstand capabilities
of a MVCB, in accordance with one embodiment
[0029] Figure 15 is a flow chart illustrating an example process for analyzing
the reliability
of an electrical power distribution and transmission system, in accordance
with one embodiment.
[0030] Figure 16 is a flow chart illustrating an example process for analyzing
the reliability
of an electrical power distribution and transmission system that takes weather
information into
account, in accordance with one embodiment.
[0031] Figure 17 is a diagram illustrating an example process for predicting
in real-time
various parameters associated with an alternating current (AC) arc flash
incident, in accordance
with one embodiment.
[0032] Figure 18 is a flow chart illustrating an example process for real-time
analysis of the
operational stability of an electrical power distribution and transmission
system, in accordance
with one embodiment.
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[0033] Figure 19 is a flow chart illustrating an example process for
conducting a real-time
power capacity assessment of an electrical power distribution and transmission
system, in
accordance with one embodiment.
[0034] Figure 20 is a flow chart illustrating an example process for
performing real-time
harmonics analysis of an electrical power distribution and transmission
system, in accordance
with one embodiment.
[0035] Figure 21 is a diagram illustrating how the HTM Pattern Recognition and
Machine
Learning Engine works in conjunction with the other elements of the analytics
system to make
predictions about the operational aspects of a monitored system, in accordance
with one
embodiment.
[0036] Figure 22 is an illustration of the various cognitive layers that
comprise the
neocortical catalyst process used by the HTM Pattern Recognition and Machine
Learning Engine
to analyze and make predictions about the operational aspects of a monitored
system, in
accordance with one embodiment.
[0037] Figure 23 is an example process for real-time three-dimensional (3D)
visualization of
the health, reliability, and performance of an electrical system, in
accordance with one
embodiment.
[0038] Figure 24 is a diagram illustrating how the 3D Visualization Engine
works in
conjunction with the other elements of the analytics system to provide 3D
visualization of the
health, reliability, and performance of an electrical system, in accordance
with one embodiment.
[0039] Figure 25 provides a client terminal screenshot of some 2D and 3D model
views that
are generated by the power analytics server, in accordance with one
embodiment.
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[0040] Figure 26 is a diagram illustrating how the Schematic Interface Creator
Engine works
in conjunction with the other elements of the analytics system to
automatically generate a
schematic user interface for visualizing the health, reliability, and
performance of an electrical
system, in accordance with one embodiment.
[0041] Figure 27 is an example process for automatically generating a
schematic user
interface for visualizing the health, reliability, and performance of an
electrical system, in
accordance with one embodiment.
DETAILED DESCRIPTION
[0042] Systems and methods for automatically generating a schematic user
interface of
an electrical system are disclosed. It will be clear, however, that the
present invention may be
practiced without some or all of these specific details. In other instances,
well known process
operations have not been described in detail in order not to unnecessarily
obscure the present
invention.
[0043] As used herein, a system denotes a set of components, real or abstract,
comprising
a whole where each component interacts with or is related to at least one
other component within
the whole. Examples of systems include machinery, factories, electrical
systems, processing
plants, devices, chemical processes, biological systems, data centers,
aircraft carriers, and the
like. An electrical system can designate a power generation and/or
distribution system that is
widely dispersed (i.e., power generation, transformers, and/or electrical
distribution components
distributed geographically throughout a large region) or bounded within a
particular location
(e.g., a power plant within a production facility, a bounded geographic area,
on board a ship, a
factory, a data center, etc.).
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[0044] A network application is any application that is stored on an
application server
connected to a network (e.g., local area network, wide area network, etc.) in
accordance with any
contemporary client/server architecture model and can be accessed via the
network. In this
arrangement, the network application programming interface (API) resides on
the application
server separate from the client machine. The client interface would typically
be a web browser
(e.g. INTERNET EXPLORERTM, FIREFOXTM, NETSCAPETM, etc) that is in
communication
with the network application server via a network connection (e.g., HTTP,
HTTPS, RSS, etc.).
[0045] Figure 1 is an illustration of a system for utilizing real-time data
for predictive
analysis of the performance of a monitored system, in accordance with one
embodiment. As
shown herein, the system 100 includes a series of sensors (i.e., Sensor A 104,
Sensor B 106,
Sensor C 108) interfaced with the various components of a monitored system
102, a data
acquisition hub 112, an analytics server 116, and a thin-client device 128. In
one embodiment,
the monitored system 102 is an electrical power generation plant. In another
embodiment, the
monitored system 102 is an electrical power transmission infrastructure. In
still another
embodiment, the monitored system 102 is an electrical power distribution
system. In still
another embodiment, the monitored system 102 includes a combination of one or
more electrical
power generation plant(s), power transmission infrastructure(s), and/or an
electrical power
distribution system. It should be understood that the monitored system 102 can
be any
combination of components whose operations can be monitored with conventional
sensors and
where each component interacts with or is related to at least one other
component within the
combination. For a monitored system 102 that is an electrical power
generation, transmission, or
distribution system, the sensors can provide data such as voltage, frequency,
current, power,
power factor, and the like.
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[0046] The sensors are configured to provide output values for system
parameters that
indicate the operational status and/or "health" of the monitored system 102.
For example, in an
electrical power generation system, the current output or voltage readings for
the various
components that comprise the power generation system is indicative of the
overall health and/or
operational condition of the system. In one embodiment, the sensors are
configured to also
measure additional data that can affect system operation. For example, for an
electrical power
distribution system, the sensor output can include environmental information,
e.g., temperature,
humidity, etc., which can impact electrical power demand and can also affect
the operation and
efficiency of the power distribution system itself.
[0047] Continuing with Figure 1, in one embodiment, the sensors are configured
to
output data in an analog format. For example, electrical power sensor
measurements (e.g.,
voltage, current, etc.) are sometimes conveyed in an analog format as the
measurements may be
continuous in both time and amplitude. In another embodiment, the sensors are
configured to
output data in a digital format. For example, the same electrical power sensor
measurements
may be taken in discrete time increments that are not continuous in time or
amplitude. In still
another embodiment, the sensors are configured to output data in either an
analog or digital
format depending on the sampling requirements of the monitored system 102.
[0048] The sensors can be configured to capture output data at split-second
intervals to
effectuate "real time" data capture. For example, in one embodiment, the
sensors can be
configured to generate hundreds of thousands of data readings per second. It
should be
appreciated, however, that the number of data output readings taken by a
sensor may be set to
any value as long as the operational limits of the sensor and the data
processing capabilities of
the data acquisition hub 112 are not exceeded.

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[0049] Still with Figure 1, each sensor is communicatively connected to the
data
acquisition hub 112 via an analog or digital data connection 110. The data
acquisition hub 112
may be a standalone unit or integrated within the analytics server 116 and can
be embodied as a
piece of hardware, software, or some combination thereof. In one embodiment,
the data
connection 110 is a "hard wired" physical data connection (e.g., serial,
network, etc.). For
example, a serial or parallel cable connection between the sensor and the hub
112. In another
embodiment, the data connection 110 is a wireless data connection. For
example, a radio
frequency (RF), BLUETOOTHTM, infrared or equivalent connection between the
sensor and the
hub 112.
[0050] The data acquisition hub 112 is configured to communicate "real-time"
data from
the monitored system 102 to the analytics server 116 using a network
connection 114. In one
embodiment, the network connection 114 is a "hardwired" physical connection.
For example,
the data acquisition hub 112 may be communicatively connected (via Category 5
(CAT5), fiber
optic or equivalent cabling) to a data server (not shown) that is
communicatively connected (via
CAT5, fiber optic or equivalent cabling) through the Internet and to the
analytics server 116
server. The analytics server 116 being also communicatively connected with the
Internet (via
CAT5, fiber optic, or equivalent cabling). In another embodiment, the network
connection 114
is a wireless network connection (e.g., Wi-Fi, WLAN, etc.). For example,
utilizing an 802.1 lb/g
or equivalent transmission format. In practice, the network connection
utilized is dependent
upon the particular requirements of the monitored system 102.
[0051] Data acquisition hub 112 can also be configured to supply warning and
alarms
signals as well as control signals to monitored system 102 and/or sensors 104,
106, and 108 as
described in more detail below.
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[0052] As shown in Figurel, in one embodiment, the analytics server 116 hosts
an
analytics engine 118, virtual system modeling engine 124 and several databases
126, 130, and
132. The virtual system modeling engine can, e.g., be a computer modeling
system, such as
described above. In this context, however, the modeling engine can be used to
precisely model
and mirror the actual electrical system. Analytics engine 118 can be
configured to generate
predicted data for the monitored system and analyze difference between the
predicted data and
the real-time data received from hub 112.
[0053] Figure 2 is a diagram illustrating a more detailed view of analytic
server 116. As
can be seen, analytic server 116 is interfaced with a monitored facility 102
via sensors 202, e.g.,
sensors 104, 106, and 108. Sensors 202 are configured to supply real-time data
from within
monitored facility 102. The real-time data is communicated to analytic server
116 via a hub 204.
Hub 204 can be configure to provide real-time data to server 116 as well as
alarming, sensing
and control featured for facility 102.
[0054] The real-time data from hub 204 can be passed to a comparison engine
210,
which can form part of analytics engine 118. Comparison engine 210 can be
configured to
continuously compare the real-time data with predicted values generated by
simulation engine
208. Based on the comparison, comparison engine 210 can be further configured
to determine
whether deviations between the real-time and the expected values exists, and
if so to classify the
deviation, e.g., high, marginal, low, etc. The deviation level can then be
communicated to
decision engine 212, which can also comprise part of analytics engine 118.
[0055] Decision engine 212 can be configured to look for significant
deviations between
the predicted values and real-time values as received from the comparison
engine 210. If
significant deviations are detected, decision engine 212 can also be
configured to determine
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whether an alarm condition exists, activate the alarm and communicate the
alarm to Human-
Machine Interface (HMI) 214 for display in real-time via, e.g., thin client
128. Decision engine
212 can also be configured to perform root cause analysis for significant
deviations in order to
determine the interdependencies and identify the parent-child failure
relationships that may be
occurring. In this manner, parent alarm conditions are not drowned out by
multiple children
alarm conditions, allowing the user/operator to focus on the main problem, at
least at first.
[0056] Thus, in one embodiment, and alarm condition for the parent can be
displayed via
HMI 214 along with an indication that processes and equipment dependent on the
parent process
or equipment are also in alarm condition. This also means that server 116 can
maintain a parent-
child logical relationship between processes and equipment comprising facility
102. Further, the
processes can be classified as critical, essential, non-essential, etc.
[0057] Decision engine 212 can also be configured to determine health and
performance
levels and indicate these levels for the various processes and equipment via
HMI 214. All of
which, when combined with the analytic capabilities of analytics engine 118
allows the operator
to minimize the risk of catastrophic equipment failure by predicting future
failures and providing
prompt, informative information concerning potential/predicted failures before
they occur.
Avoiding catastrophic failures reduces risk and cost, and maximizes facility
performance and up
time.
[0058] Simulation engine 208 operates on complex logical models 206 of
facility 102.
These models are continuously and automatically synchronized with the actual
facility status
based on the real-time data provided by hub 204. In other words, the models
are updated based
on current switch status, breaker status, e.g., open-closed, equipment on/off
status, etc. Thus, the
models are automatically updated based on such status, which allows simulation
engine to
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produce predicted data based on the current facility status. This in turn,
allows accurate and
meaningful comparisons of the real-time data to the predicted data.
[0059] Example models 206 that can be maintained and used by server 116
include
power flow models used to calculate expected kW, kVAR, power factor values,
etc., short circuit
models used to calculate maximum and minimum available fault currents,
protection models
used to determine proper protection schemes and ensure selective coordination
of protective
devices, power quality models used to determine voltage and current
distortions at any point in
the network, to name just a few. It will be understood that different models
can be used
depending on the system being modeled.
[0060] In certain embodiments, hub 204 is configured to supply equipment
identification
associated with the real-time data. This identification can be cross
referenced with
identifications provided in the models.
[0061] In one embodiment, if the comparison performed by comparison engine 210
indicates that the differential between the real-time sensor output value and
the expected value
exceeds a Defined Difference Tolerance (DDT) value (i.e., the "real-time"
output values of the
sensor output do not indicate an alarm condition) but below an alarm condition
(i.e., alarm
threshold value), a calibration request is generated by the analytics engine
118. If the differential
exceeds, the alarm condition, an alarm or notification message is generated by
the analytics
engine 118. If the differential is below the DTT value, the analytics engine
does nothing and
continues to monitor the real-time data and expected data.
[0062] In one embodiment, the alarm or notification message is sent directly
to the client
(i.e., user) 128, e.g., via HMI 214, for display in real-time on a web
browser, pop-up message
box, e-mail, or equivalent on the client 128 display panel. In another
embodiment, the alarm or
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notification message is sent to a wireless mobile device (e.g., BLACKBERRYTM,
laptop, pager,
etc.) to be displayed for the user by way of a wireless router or equivalent
device interfaced with
the analytics server 116. In still another embodiment, the alarm or
notification message is sent to
both the client 128 display and the wireless mobile device. The alarm can be
indicative of a
need for a repair event or maintenance to be done on the monitored system. It
should be noted,
however, that calibration requests should not be allowed if an alarm condition
exists to prevent
the models form being calibrated to an abnormal state.
[0063] Once the calibration is generated by the analytics engine 118, the
various
operating parameters or conditions of model(s) 206 can be updated or adjusted
to reflect the
actual facility configuration. This can include, but is not limited to,
modifying the predicted data
output from the simulation engine 208, adjusting the logic/processing
parameters utilized by the
model(s) 206, adding/subtracting functional elements from model(s) 206, etc.
It should be
understood, that any operational parameter of models 206 can be modified as
long as the
resulting modifications can be processed and registered by simulation engine
208.
[0064] Referring back to figure 1, models 206 can be stored in the virtual
system model
database 126. As noted, a variety of conventional virtual model applications
can be used for
creating a virtual system model, so that a wide variety of systems and system
parameters can be
modeled. For example, in the context of an electrical power distribution
system, the virtual
system model can include components for modeling reliability, voltage
stability, and power flow.
In addition, models 206 can include dynamic control logic that permits a user
to configure the
models 206 by specifying control algorithms and logic blocks in addition to
combinations and
interconnections of generators, governors, relays, breakers, transmission
line, and the like. The
voltage stability parameters can indicate capacity in terms of size, supply,
and distribution, and

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can indicate availability in terms of remaining capacity of the presently
configured system. The
power flow model can specify voltage, frequency, and power factor, thus
representing the
"health" of the system.
[0065] All of models 206 can be referred to as a virtual system model. Thus,
virtual
system model database can be configured to store the virtual system model. A
duplicate, but
synchronized copy of the virtual system model can be stored in a virtual
simulation model
database 130. This duplicate model can be used for what-if simulations. In
other words, this
model can be used to allow a system designer to make hypothetical changes to
the facility and
test the resulting effect, without taking down the facility or costly and time
consuming analysis.
Such hypothetical can be used to learn failure patterns and signatures as well
as to test proposed
modifications, upgrades, additions, etc., for the facility. The real-time
data, as well as trending
produced by analytics engine 118 can be stored in a real-time data acquisition
database 132.
[0066] As discussed above, the virtual system model is periodically calibrated
and
synchronized with "real-time" sensor data outputs so that the virtual system
model provides data
output values that are consistent with the actual "real-time" values received
from the sensor
output signals. Unlike conventional systems that use virtual system models
primarily for system
design and implementation purposes (i.e., offline simulation and facility
planning), the virtual
system models described herein are updated and calibrated with the real-time
system operational
data to provide better predictive output values. A divergence between the real-
time sensor
output values and the predicted output values generate either an alarm
condition for the values in
question and/or a calibration request that is sent to the calibration engine
134.
[0067] Continuing with Figure 1, the analytics engine 118 can be configured to
implement pattern/sequence recognition into a real-time decision loop that,
e.g., is enabled by a
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new type of machine learning called associative memory, or hierarchical
temporal memory
(HTM), which is a biological approach to learning and pattern recognition.
Associative memory
allows storage, discovery, and retrieval of learned associations between
extremely large numbers
of attributes in real time. At a basic level, an associative memory stores
information about how
attributes and their respective features occur together. The predictive power
of the associative
memory technology comes from its ability to interpret and analyze these co-
occurrences and to
produce various metrics. Associative memory is built through "experiential"
learning in which
each newly observed state is accumulated in the associative memory as a basis
for interpreting
future events. Thus, by observing normal system operation over time, and the
normal predicted
system operation over time, the associative memory is able to learn normal
patterns as a basis for
identifying non-normal behavior and appropriate responses, and to associate
patterns with
particular outcomes, contexts or responses. The analytics engine 118 is also
better able to
understand component mean time to failure rates through observation and system
availability
characteristics. This technology in combination with the virtual system model
can be
characterized as a "neocortical" model of the system under management.
[0068] This approach also presents a novel way to digest and comprehend alarms
in a
manageable and coherent way. The neocortical model could assist in uncovering
the patterns
and sequencing of alarms to help pinpoint the location of the (impending)
failure, its context, and
even the cause. Typically, responding to the alarms is done manually by
experts who have
gained familiarity with the system through years of experience. However, at
times, the amount
of information is so great that an individual cannot respond fast enough or
does not have the
necessary expertise. An "intelligent" system like the neocortical system that
observes and
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recommends possible responses could improve the alarm management process by
either
supporting the existing operator, or even managing the system autonomously.
[0069] Current simulation approaches for maintaining transient stability
involve
traditional numerical techniques and typically do not test all possible
scenarios. The problem is
further complicated as the numbers of components and pathways increase.
Through the
application of the neocortical model, by observing simulations of circuits,
and by comparing
them to actual system responses, it may be possible to improve the simulation
process, thereby
improving the overall design of future circuits.
[0070] The virtual system model database 126, as well as databases 130 and
132, can be
configured to store one or more virtual system models, virtual simulation
models, and real-time
data values, each customized to a particular system being monitored by the
analytics server 118.
Thus, the analytics server 118 can be utilized to monitor more than one system
at a time. As
depicted herein, the databases 126, 130, and 132 can be hosted on the
analytics server 116 and
communicatively interfaced with the analytics engine 118. In other
embodiments, databases
126, 130, and 132 can be hosted on a separate database server (not shown) that
is
communicatively connected to the analytics server 116 in a manner that allows
the virtual system
modeling engine 124 and analytics engine 118 to access the databases as
needed.
[0071] Therefore, in one embodiment, the client 128 can modify the virtual
system model
stored on the virtual system model database 126 by using a virtual system
model development
interface using well-known modeling tools that are separate from the other
network interfaces.
For example, dedicated software applications that run in conjunction with the
network interface
to allow a client 128 to create or modify the virtual system models.
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[0072] The client 128 may utilize a variety of network interfaces (e.g., web
browser,
CITRIXTM, WINDOWS TERMINAL SERVICESTM, telnet, or other equivalent thin-client
terminal applications, etc.) to access, configure, and modify the sensors
(e.g., configuration files,
etc.), analytics engine 118 (e.g., configuration files, analytics logic,
etc.), calibration parameters
(e.g., configuration files, calibration parameters, etc.), virtual system
modeling engine 124 (e.g.,
configuration files, simulation parameters, etc.) and virtual system model of
the system under
management (e.g., virtual system model operating parameters and configuration
files).
Correspondingly, data from those various components of the monitored system
102 can be
displayed on a client 128 display panel for viewing by a system administrator
or equivalent.
[0073] As described above, server 116 is configured to synchronize the
physical world
with the virtual and report, e.g., via visual, real-time display, deviations
between the two as well
as system health, alarm conditions, predicted failures, etc. This is
illustrated with the aid of
figure 3, in which the synchronization of the physical world (left side) and
virtual world (right
side) is illustrated. In the physical world, sensors 202 produce real-time
data 302 for the
processes 312 and equipment 314 that make up facility 102. In the virtual
world, simulations
304 of the virtual system model 206 provide predicted values 306, which are
correlated and
synchronized with the real-time data 302. The real-time data can then be
compared to the
predicted values so that differences 308 can be detected. The significance of
these differences
can be determined to determine the health status 310 of the system. The health
stats can then be
communicated to the processes 312 and equipment 314, e.g., via alarms and
indicators, as well
as to thin client 128, e.g., via web pages 316.
[0074] Figure 4 is an illustration of the scalability of a system for
utilizing real-time data
for predictive analysis of the performance of a monitored system, in
accordance with one
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embodiment. As depicted herein, an analytics central server 422 is
communicatively connected
with analytics server A 414, analytics server B 416, and analytics server n
418 (i.e., one or more
other analytics servers) by way of one or more network connections 114. Each
of the analytics
servers is communicatively connected with a respective data acquisition hub
(i.e., Hub A 408,
Hub B 410, Hub n 412) that communicates with one or more sensors that are
interfaced with a
system (i.e., Monitored System A 402, Monitored System B 404, Monitored System
n 406) that
the respective analytical server monitors. For example, analytics server A 414
is communicative
connected with data acquisition hub A 408, which communicates with one or more
sensors
interfaced with monitored system A 402.
[0075] Each analytics server (i.e., analytics server A 414, analytics server B
416,
analytics server n 418) is configured to monitor the sensor output data of its
corresponding
monitored system and feed that data to the central analytics server 422.
Additionally, each of the
analytics servers can function as a proxy agent of the central analytics
server 422 during the
modifying and/or adjusting of the operating parameters of the system sensors
they monitor. For
example, analytics server B 416 is configured to be utilized as a proxy to
modify the operating
parameters of the sensors interfaced with monitored system B 404.
[0076] Moreover, the central analytics server 422, which is communicatively
connected
to one or more analytics server(s) can be used to enhance the scalability. For
example, a central
analytics server 422 can be used to monitor multiple electrical power
generation facilities (i.e.,
monitored system A 402 can be a power generation facility located in city A
while monitored
system B 404 is a power generation facility located in city B) on an
electrical power grid. In this
example, the number of electrical power generation facilities that can be
monitored by central
analytics server 422 is limited only by the data processing capacity of the
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422. The central analytics server 422 can be configured to enable a client 128
to modify and
adjust the operational parameters of any the analytics servers communicatively
connected to the
central analytics server 422. Furthermore, as discussed above, each of the
analytics servers are
configured to serve as proxies for the central analytics server 422 to enable
a client 128 to
modify and/or adjust the operating parameters of the sensors interfaced with
the systems that
they respectively monitor. For example, the client 128 can use the central
analytics server 422,
and vice versa, to modify and/or adjust the operating parameters of analytics
server A 414 and
utilize the same to modify and/or adjust the operating parameters of the
sensors interfaced with
monitored system A 402. Additionally, each of the analytics servers can be
configured to allow
a client 128 to modify the virtual system model through a virtual system model
development
interface using well-known modeling tools.
[0077] In one embodiment, the central analytics server 422 can function to
monitor and
control a monitored system when its corresponding analytics server is out of
operation. For
example, central analytics server 422 can take over the functionality of
analytics server B 416
when the server 416 is out of operation. That is, the central analytics server
422 can monitor the
data output from monitored system B 404 and modify and/or adjust the operating
parameters of
the sensors that are interfaced with the system 404.
[0078] In one embodiment, the network connection 114 is established through a
wide
area network (WAN) such as the Internet. In another embodiment, the network
connection is
established through a local area network (LAN) such as the company intranet.
In a separate
embodiment, the network connection 114 is a "hardwired" physical connection.
For example,
the data acquisition hub 112 may be communicatively connected (via Category 5
(CAT5), fiber
optic or equivalent cabling) to a data server that is communicatively
connected (via CAT5, fiber
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optic or equivalent cabling) through the Internet and to the analytics server
116 server hosting
the analytics engine 118. In another embodiment, the network connection 114 is
a wireless
network connection (e.g., Wi-Fi, WLAN, etc.). For example, utilizing an
802.1lb/g or
equivalent transmission format.
[0079] In certain embodiments, regional analytics servers can be placed
between local
analytics servers 414, 416, . . ., 418 and central analytics server 422.
Further, in certain
embodiments a disaster recovery site can be included at the central analytics
server 4221eve1.
[0080] Figure 5 is a block diagram that shows the configuration details of
analytics
server 116 illustrated in Figure 1 in more detail. It should be understood
that the configuration
details in Figure 5 are merely one embodiment of the items described for
Figure 1, and it should
be understood that alternate configurations and arrangements of components
could also provide
the functionality described herein.
[0081] The analytics server 116 includes a variety of components. In the
Figure 5
embodiment, the analytics server 116 is implemented in a Web-based
configuration, so that the
analytics server 116 includes (or communicates with) a secure web server 530
for
communication with the sensor systems 519 (e.g., data acquisition units,
metering devices,
sensors, etc.) and external communication entities 534 (e.g., web browser,
"thin client"
applications, etc.). A variety of user views and functions 532 are available
to the client 128 such
as: alarm reports, Active X controls, equipment views, view editor tool,
custom user interface
page, and XML parser. It should be appreciated, however, that these are just
examples of a few
in a long list of views and functions 532 that the analytics server 116 can
deliver to the external
communications entities 534 and are not meant to limit the types of views and
functions 532
available to the analytics server 116 in any way.
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[0082] The analytics server 116 also includes an alarm engine 506 and
messaging engine
504, for the aforementioned external communications. The alarm engine 506 is
configured to
work in conjunction with the messaging engine 504 to generate alarm or
notification messages
502 (in the form of text messages, e-mails, paging, etc.) in response to the
alarm conditions
previously described. The analytics server 116 determines alarm conditions
based on output data
it receives from the various sensor systems 519 through a communications
connection (e.g.,
wireless 516, TCP/IP 518, Seria1520, etc) and simulated output data from a
virtual system model
512, of the monitored system, processed by the analytics engines 118. In one
embodiment, the
virtual system model 512 is created by a user through interacting with an
external
communication entity 534 by specifying the components that comprise the
monitored system and
by specifying relationships between the components of the monitored system. In
another
embodiment, the virtual system model 512 is automatically generated by the
analytics engines
118 as components of the monitored system are brought online and interfaced
with the analytics
server 508.
[0083] Continuing with Figure 5, a virtual system model database 526 is
communicatively connected with the analytics server 116 and is configured to
store one or more
virtual system models 512, each of which represents a particular monitored
system. For
example, the analytics server 116 can conceivably monitor multiple electrical
power generation
systems (e.g., system A, system B, system C, etc.) spread across a wide
geographic area (e.g.,
City A, City B, City C, etc.). Therefore, the analytics server 116 will
utilize a different virtual
system model 512 for each of the electrical power generation systems that it
monitors. Virtual
simulation model database 538 can be configured to store a synchronized,
duplicate copy of the
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virtual system mode1512, and real-time data acquisition database 540 can store
the real-time and
trending data for the system(s) being monitored.
[0084] Thus, in operation, analytics server 116 can receive real-time data for
various
sensors, i.e., components, through data acquisition system 202. As can be
seen, analytics server
116 can comprise various drivers configured to interface with the various
types of sensors, etc.,
comprising data acquisition system 202. This data represents the real-time
operational data for
the various components. For example, the data may indicate that a certain
component is
operating at a certain voltage level and drawing certain amount of current.
This information can
then be fed to a modeling engine to generate a virtual system model 612 that
is based on the
actual real-time operational data.
[0085] Analytics engine 118 can be configured to compare predicted data based
on the
virtual system model 512 with real-time data received from data acquisition
system 202 and to
identify any differences. In some instances, analytics engine can be
configured to identify these
differences and then update, i.e., calibrate, the virtual system model 512 for
use in future
comparisons. In this manner, more accurate comparisons and warnings can be
generated.
[0086] But in other instances, the differences will indicate a failure, or the
potential for a
failure. For example, when a component begins to fail, the operating
parameters will begin to
change. This change may be sudden or it may be a progressive change over time.
Analytics
engine 118 can detect such changes and issue warnings that can allow the
changes to be detected
before a failure occurs. The analytic engine 118 can be configured to generate
warnings that can
be communicated via interface 532.
[0087] For example, a user can access information from server 116 using thin
client 534.
For example, reports can be generate and served to thin client 534 via server
540. These reports
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can, for example, comprise schematic or symbolic illustrations of the system
being monitored.
Status information for each component can be illustrated or communicated for
each component.
This information can be numerical, i.e., the voltage or current level. Or it
can be symbolic, i.e.,
green for normal, red for failure or warning. In certain embodiments,
intermediate levels of
failure can also be communicated, i.e., yellow can be used to indicate
operational conditions that
project the potential for future failure. It should be noted that this
information can be accessed in
real-time. Moreover, via thin client 534, the information can be accessed form
anywhere and
anytime.
[0088] Continuing with Figure 5, the Analytics Engine 118 is communicatively
interfaced with a HTM Pattern Recognition and Machine Learning Engine 551. The
HTM
Engine 551 is configured to work in conjunction with the Analytics Engine 118
and a virtual
system model of the monitored system to make real-time predictions (i.e.,
forecasts) about
various operational aspects of the monitored system. The HTM Engine 551 works
by processing
and storing patterns observed during the normal operation of the monitored
system over time.
These observations are provided in the form of real-time data captured using a
multitude of
sensors that are imbedded within the monitored system. In one embodiment, the
virtual system
model is also updated with the real-time data such that the virtual system
model "ages" along
with the monitored system. Examples of a monitored system includes machinery,
factories,
electrical systems, processing plants, devices, chemical processes, biological
systems, data
centers, aircraft carriers, and the like. It should be understood that the
monitored system can be
any combination of components whose operations can be monitored with
conventional sensors
and where each component interacts with or is related to at least one other
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[0089] Figure 6 is an illustration of a flowchart describing a method for real-
time
monitoring and predictive analysis of a monitored system, in accordance with
one embodiment.
Method 600 begins with operation 602 where real-time data indicative of the
monitored system
status is processed to enable a virtual model of the monitored system under
management to be
calibrated and synchronized with the real-time data. In one embodiment, the
monitored system
102 is a mission critical electrical power system. In another embodiment, the
monitored system
102 can include an electrical power transmission infrastructure. In still
another embodiment, the
monitored system 102 includes a combination of thereof. It should be
understood that the
monitored system 102 can be any combination of components whose operations can
be
monitored with conventional sensors and where each component interacts with or
is related to at
least one other component within the combination.
[0090] Method 600 moves on to operation 604 where the virtual system model of
the
monitored system under management is updated in response to the real-time
data. This may
include, but is not limited to, modifying the simulated data output from the
virtual system model,
adjusting the logic/processing parameters utilized by the virtual system
modeling engine to
simulate the operation of the monitored system, adding/subtracting functional
elements of the
virtual system model, etc. It should be understood, that any operational
parameter of the virtual
system modeling engine and/or the virtual system model may be modified by the
calibration
engine as long as the resulting modifications can be processed and registered
by the virtual
system modeling engine.
[0091] Method 600 proceeds on to operation 606 where the simulated real-time
data
indicative of the monitored system status is compared with a corresponding
virtual system model
created at the design stage. The design stage models, which may be calibrated
and updated
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based on real-time monitored data, are used as a basis for the predicted
performance of the
system. The real-time monitored data can then provide the actual performance
over time. By
comparing the real-time time data with the predicted performance information,
difference can be
identified a tracked by, e.g., the analytics engine 118. Analytics engines 118
can then track
trends, determine alarm states, etc., and generate a real-time report of the
system status in
response to the comparison.
[0092] In other words, the analytics can be used to analyze the comparison and
real-time
data and determine if there is a problem that should be reported and what
level the problem may
be, e.g., low priority, high priority, critical, etc. The analytics can also
be used to predict future
failures and time to failure, etc. In one embodiment, reports can be displayed
on a conventional
web browser (e.g. INTERNET EXPLORERTM, FIREFOXTM, NETSCAPETM, etc) that is
rendered on a standard personal computing (PC) device. In another embodiment,
the "real-time"
report can be rendered on a "thin-client" computing device (e.g., CITRIXTM,
WINDOWS
TERMINAL SERVICESTM, telnet, or other equivalent thin-client terminal
application). In still
another embodiment, the report can be displayed on a wireless mobile device
(e.g.,
BLACKBERRYTM, laptop, pager, etc.). For example, in one embodiment, the "real-
time" report
can include such information as the differential in a particular power
parameter (i.e., current,
voltage, etc.) between the real-time measurements and the virtual output data.
[0093] Figure 7 is an illustration of a flowchart describing a method for
managing real-
time updates to a virtual system model of a monitored system, in accordance
with one
embodiment. Method 700 begins with operation 702 where real-time data output
from a sensor
interfaced with the monitored system is received. The sensor is configured to
capture output
data at split-second intervals to effectuate "real time" data capture. For
example, in one
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embodiment, the sensor is configured to generate hundreds of thousands of data
readings per
second. It should be appreciated, however, that the number of data output
readings taken by the
sensor may be set to any value as long as the operational limits of the sensor
and the data
processing capabilities of the data acquisition hub are not exceeded.
[0094] Method 700 moves to operation 704 where the real-time data is processed
into a
defined format. This would be a format that can be utilized by the analytics
server to analyze or
compare the data with the simulated data output from the virtual system model.
In one
embodiment, the data is converted from an analog signal to a digital signal.
In another
embodiment, the data is converted from a digital signal to an analog signal.
It should be
understood, however, that the real-time data may be processed into any defined
format as long as
the analytics engine can utilize the resulting data in a comparison with
simulated output data
from a virtual system model of the monitored system.
[0095] Method 700 continues on to operation 706 where the predicted (i.e.,
simulated)
data for the monitored system is generated using a virtual system model of the
monitored system.
As discussed above, a virtual system modeling engine utilizes dynamic control
logic stored in
the virtual system model to generate the predicted output data. The predicted
data is supposed to
be representative of data that should actually be generated and output from
the monitored
system.
[0096] Method 700 proceeds to operation 708 where a determination is made as
to
whether the difference between the real-time data output and the predicted
system data falls
between a set value and an alarm condition value, where if the difference
falls between the set
value and the alarm condition value a virtual system model calibration and a
response can be
generated. That is, if the comparison indicates that the differential between
the "real-time"
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sensor output value and the corresponding "virtual" model data output value
exceeds a Defined
Difference Tolerance (DDT) value (i.e., the "real-time" output values of the
sensor output do not
indicate an alarm condition) but below an alarm condition (i.e., alarm
threshold value), a
response can be generated by the analytics engine. In one embodiment, if the
differential
exceeds, the alarm condition, an alarm or notification message is generated by
the analytics
engine 118. In another embodiment, if the differential is below the DTT value,
the analytics
engine does nothing and continues to monitor the "real-time" data and
"virtual" data. Generally
speaking, the comparison of the set value and alarm condition is indicative of
the functionality of
one or more components of the monitored system.
[0097] Figure 8 is an illustration of a flowchart describing a method for
synchronizing
real-time system data with a virtual system model of a monitored system, in
accordance with one
embodiment. Method 800 begins with operation 802 where a virtual system model
calibration
request is received. A virtual model calibration request can be generated by
an analytics engine
whenever the difference between the real-time data output and the predicted
system data falls
between a set value and an alarm condition value.
[0098] Method 800 proceeds to operation 804 where the predicted system output
value
for the virtual system model is updated with a real-time output value for the
monitored system.
For example, if sensors interfaced with the monitored system outputs a real-
time current value of
A, then the predicted system output value for the virtual system model is
adjusted to reflect a
predicted current value of A.
[0099] Method 800 moves on to operation 806 where a difference between the
real-time
sensor value measurement from a sensor integrated with the monitored system
and a predicted
sensor value for the sensor is determined. As discussed above, the analytics
engine is configured
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to receive "real-time" data from sensors interfaced with the monitored system
via the data
acquisition hub (or, alternatively directly from the sensors) and "virtual"
data from the virtual
system modeling engine simulating the data output from a virtual system model
of the monitored
system. In one embodiment, the values are in units of electrical power output
(i.e., current or
voltage) from an electrical power generation or transmission system. It should
be appreciated,
however, that the values can essentially be any unit type as long as the
sensors can be configured
to output data in those units or the analytics engine can convert the output
data received from the
sensors into the desired unit type before performing the comparison.
[00100] Method 800 continues on to operation 808 where the operating
parameters of the
virtual system model are adjusted to minimize the difference. This means that
the logic
parameters of the virtual system model that a virtual system modeling engine
uses to simulate the
data output from actual sensors interfaced with the monitored system are
adjusted so that the
difference between the real-time data output and the simulated data output is
minimized.
Correspondingly, this operation will update and adjust any virtual system
model output
parameters that are functions of the virtual system model sensor values. For
example, in a power
distribution environment, output parameters of power load or demand factor
might be a function
of multiple sensor data values. The operating parameters of the virtual system
model that mimic
the operation of the sensor will be adjusted to reflect the real-time data
received from those
sensors. In one embodiment, authorization from a system administrator is
requested prior to the
operating parameters of the virtual system model being adjusted. This is to
ensure that the
system administrator is aware of the changes that are being made to the
virtual system model. In
one embodiment, after the completion of all the various calibration
operations, a report is

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generated to provide a summary of all the adjustments that have been made to
the virtual system
model.
[00101] As described above, virtual system modeling engine 124 can be
configured to
model various aspects of the system to produce predicted values for the
operation of various
components within monitored system 102. These predicted values can be compared
to actual
values being received via data acquisition hub 112. If the differences are
greater than a certain
threshold, e.g., the DTT, but not in an alarm condition, then a calibration
instruction can be
generated. The calibration instruction can cause a calibration engine 134 to
update the virtual
model being used by system modeling engine 124 to reflect the new operating
information.
[00102] It will be understood that as monitored system 102 ages, or more
specifically the
components comprising monitored system 102 age, then the operating parameters,
e.g., currents
and voltages associated with those components will also change. Thus, the
process of calibrating
the virtual model based on the actual operating information provides a
mechanism by which the
virtual model can be aged along with the monitored system 102 so that the
comparisons being
generated by analytics engine 118 are more meaningful.
[00103] At a high level, this process can be illustrated with the aid of
Figure 9, which is a
flow chart illustrating an example method for updating the virtual model in
accordance with one
embodiment. In step 902, data is collected from, e.g., sensors 104, 106, and
108. For example,
the sensors can be configured to monitor protective devices within an
electrical distribution
system to determine and monitor the ability of the protective devices to
withstand faults, which
is describe in more detail below.
[00104] In step 904, the data from the various sensors can be processed by
analytics engine
118 in order to evaluate various parameters related to monitored system 102.
In step 905,
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simulation engine 124 can be configured to generate predicted values for
monitored system 102
using a virtual model of the system that can be compared to the parameters
generated by
analytics engine 118 in step 904. If there are differences between the actual
values and the
predicted values, then the virtual model can be updated to ensure that the
virtual model ages with
the actual system 102.
[00105] It should be noted that as the monitored system 102 ages, various
components can be
repaired, replaced, or upgraded, which can also create differences between the
simulated and
actual data that is not an alarm condition. Such activity can also lead to
calibrations of the
virtual model to ensure that the virtual model produces relevant predicted
values. Thus, not only
can the virtual model be updated to reflect aging of monitored system 102, but
it can also be
updated to reflect retrofits, repairs, etc.
[00106] As noted above, in certain embodiments, a logical model of a
facilities electrical
system, a data acquisition system (data acquisition hub 112), and power system
simulation
engines (modeling engine 124) can be integrated with a logic and methods based
approach to the
adjustment of key database parameters within a virtual model of the electrical
system to evaluate
the ability of protective devices within the electrical distribution system to
withstand faults and
also effectively "age" the virtual system with the actual system.
[00107] Only through such a process can predictions on the withstand abilities
of protective
devices, and the status, security and health of an electrical system be
accurately calculated.
Accuracy is important as the predictions can be used to arrive at actionable,
mission critical or
business critical conclusions that may lead to the re-alignment of the
electrical distribution
system for optimized performance or security.
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[00108] Figures 10-12 are flow charts presenting logical flows for determining
the ability of
protective devices within an electrical distribution system to withstand
faults and also effectively
"age" the virtual system with the actual system in accordance with one
embodiment. Figure 10
is a diagram illustrating an example process for monitoring the status of
protective devices in a
monitored system 102 and updating a virtual model based on monitored data.
First, in step 1002,
the status of the protective devices can be monitored in real time. As
mentioned, protective
devices can include fuses, switches, relays, and circuit breakers.
Accordingly, the status of the
fuses/switches, relays, and/or circuit breakers, e.g., the open/close status,
source and load status,
and on or off status, can be monitored in step 1002. It can be determined, in
step 1004, if there is
any change in the status of the monitored devices. If there is a change, then
in step 1006, the
virtual model can be updated to reflect the status change, i.e., the
corresponding virtual
components data can be updated to reflect the actual status of the various
protective devices.
[00109] In step 1008, predicted values for the various components of monitored
system 102
can be generated. But it should be noted that these values are based on the
current, real-time
status of the monitored system. Real time sensor data can be received in step
1012. This real
time data can be used to monitor the status in step 1002 and it can also be
compared with the
predicted values in step 1014. As noted above, the difference between the
predicted values and
the real time data can also be determined in step 1014.
[00110] Accordingly, meaningful predicted values based on the actual condition
of monitored
system 102 can be generated in steps 1004 to 1010. These predicted values can
then be used to
determine if further action should be taken based on the comparison of step
1014. For example,
if it is determined in step 1016 that the difference between the predicted
values and the real time
sensor data is less than or equal to a certain threshold, e.g., DTT, then no
action can be taken
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e.g., an instruction not to perform calibration can be issued in step 1018.
Alternatively, if it is
determined in step 1020 that the real time data is actually indicative of an
alarm situation, e.g., is
above an alarm threshold, then a do not calibrate instruction can be generated
in step 1018 and
an alarm can be generated as described above. If the real time sensor data is
not indicative of an
alarm condition, and the difference between the real time sensor data and the
predicted values is
greater than the threshold, as determined in step 1022, then an initiate
calibration command can
be generated in step 1024.
[00111] If an initiate calibration command is issued in step 1024, then a
function call to
calibration engine 134 can be generated in step 1026. The function call will
cause calibration
engine 134 to update the virtual model in step 1028 based on the real time
sensor data. A
comparison between the real time data and predicted data can then be generated
in step 1030 and
the differences between the two computed. In step 1032, a user can be prompted
as to whether
or not the virtual model should in fact be updated. In other embodiments, the
update can be
automatic, and step 1032 can be skipped. In step 1034, the virtual model could
be updated. For
example, the virtual model loads, buses, demand factor, and/or percent running
information can
be updated based on the information obtained in step 1030. An initiate
simulation instruction
can then be generated in step 1036, which can cause new predicted values to be
generated based
on the update of virtual model.
[00112] In this manner, the predicted values generated in step 1008 are not
only updated to
reflect the actual operational status of monitored system 102, but they are
also updated to reflect
natural changes in monitored system 102 such as aging. Accordingly, realistic
predicted values
can be generated in step 1008.
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[00113] Figure 11 is a flowchart illustrating an example process for
determining the protective
capabilities of the protective devices being monitored in step 1002. Depending
on the
embodiment, the protective devices can be evaluated in terms of the
International
Electrotechnical Commission (IEC) standards or in accordance with the United
States or
American National Standards Institute (ANSI) standards. It will be understood,
that the process
described in relation to Figure 11 is not dependent on a particular standard
being used.
[00114] First, in step 1102, a short circuit analysis can be performed for the
protective device.
Again, the protective device can be any one of a variety of protective device
types. For example,
the protective device can be a fuse or a switch, or some type of circuit
breaker. It will be
understood that there are various types of circuit breakers including Low
Voltage Circuit
Breakers (LVCBs), High Voltage Circuit Breakers (HVCBs), Mid Voltage Circuit
Breakers
(MVCBs), Miniature Circuit Breakers (MCBs), Molded Case Circuit Breakers
(MCCBs),
Vacuum Circuit Breakers, and Air Circuit Breakers, to name just a few. Any one
of these
various types of protective devices can be monitored and evaluated using the
processes
illustrated with respect to Figures 10-12.
[00115] For example, for LVCBs, or MCCBs, the short circuit current, symmetric
(Isym) or
asymmetric (Iasym), and/or the peak current (IpeA) can be determined in step
1102. For, e.g.,
LVCBs that are not instantaneous trip circuit breakers, the short circuit
current at a delayed time
(Isymdeiay) can be determined. For HVCBs, a first cycle short circuit current
(Isym) and/or Ipeak can
be determined in step 1102. For fuses or switches, the short circuit current,
symmetric or
asymmetric, can be determined in step 1102. And for MVCBs the short circuit
current
interrupting time can be calculated. These are just some examples of the types
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analysis that can be performed in Step 1102 depending on the type of
protective device being
analyzed.
[00116] Once the short circuit analysis is performed in step 1102, various
steps can be carried
out in order to determine the bracing capability of the protective device. For
example, if the
protective device is a fuse or switch, then the steps on the left hand side of
Figure 11 can be
carried out. In this case, the fuse rating can first be determined in step
1104. In this case, the
fuse rating can be the current rating for the fuse. For certain fuses, the X/R
can be calculated in
step 1105 and the asymmetric short circuit current (Iasym) for the fuse can be
determined in step
1106 using equation 1.
Eq 1: IasI = - Is,, 1+ 2Cp~(X/R)
[00117] In other implementations, the inductants/reactants (X/R) ratio can be
calculated instep
1108 and compared to a fuse test X/R to determine if the calculated X/R is
greater than the fuse
test X/R. The calculated X/R can be determined using the predicted values
provided in step
1008. Various standard tests X/R values can be used for the fuse test X/R
values in step 1108.
For example, standard test X/R values for a LVCB can be as follows:
PCB, ICCB = 6.59
MCCB, ICCB rated <= 10,000 A = 1.73
MCCB, ICCB rated 10,001- 20,000A = 3.18
MCCB, ICCB rated > 20,000 A = 4.9
[00118] If the calculated X/R is greater than the fuse test X/R, then in step
1112, equation 12
can be used to calculate an adjusted symmetrical short circuit current
(I,,djsym).
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1 + rLe 2p/(CALCX/R)
Eq 12: IA,1s, - Isym 1+2e 2pi(TEST X/R)
[00119] If the calculated X/R is not greater than the fuse test X/R then
Iadjsym can be set
equal to Isym in step 1110. In step 1114, it can then be determined if the
fuse rating (step 1104) is
greater than or equal to Iadjsym or lasym. If it is, then it can determine in
step 1118 that the
protected device has passed and the percent rating can be calculated in step
1120 as follows:
% rating = IAD'sYM
Device rating
or
% rating = IAsYM
Device rating
[00120] If it is determined in step 1114 that the device rating is not greater
than or equal to
Iadjsym, then it can be determined that the device as failed in step 1116. The
percent rating can
still be calculating in step 1120.
[00121] For LVCBs, it can first be determined whether they are fused in step
1122. If it is
determined that the LVCB is not fused, then in step 1124 can be determined if
the LVCB is an
instantaneous trip LVCB. If it is determined that the LVCB is an instantaneous
trip LVCB, then
in step 1130 the first cycle fault X/R can be calculated and compared to a
circuit breaker test X/R
(see example values above) to determine if the fault X/R is greater than the
circuit breaker test
X/R. If the fault X/R is not greater than the circuit breaker test X/R, then
in step 1132 it can be
determined if the LVCB is peak rated. If it is peak rated, then Ipeak can be
used in step 1146
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below. If it is determined that the LVCB is not peak rated in step 1132, then
I,,djsym can be set
equal to Isym in step 1140. In step 1146, it can be determined if the device
rating is greater or
equal to Iadjsym, or to Ipeak as appropriate, for the LVCB.
[00122] If it is determined that the device rating is greater than or equal to
Iadjsym, then it can
be determined that the LVCB has passed in step 1148. The percent rating can
then be
determined using the equations for Iadisym defined above (step 1120) in step
1152. If it is
determined that the device rating is not greater than or equal to Iadjsym,
then it can be determined
that the device has failed in step 1150. The percent rating can still be
calculated in step 1152.
[00123] If the calculated fault X/R is greater than the circuit breaker test
X/R as determined in
step 1130, then it can be determined if the LVCB is peak rated in step 1134.
If the LVCB is not
peak rated, then the Iadjsym can be determined using equation 12. If the LVCB
is peak rated, then
Ipeak can be determined using equation 11.
Eq 11: IPEAK F2 ISYM {1.02 + 0.98e 3(x/R) }
[00124] It can then be determined if the device rating is greater than or
equal to Iadjsym or Ipeak
as appropriate. The pass/fail determinations can then be made in steps 1148
and 1150
respectively, and the percent rating can be calculated in step 1152.
% rating = IAD'sYM
Device rating
or
% rating = IPEAK
Device rating
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[00125] If the LVCB is not an instantaneous trip LVCB as determined in step
1124, then a
time delay calculation can be performed at step 1128 followed by calculation
of the fault X/R
and a determination of whether the fault X/R is greater than the circuit
breaker test X/R. If it is
not, then Iadjsym can be set equal to Isym in step 1136. If the calculated
fault at X/R is greater
than the circuit breaker test X/R, then Iadjsymdelay can be calculated in step
1138 using the
following equation with, e.g., a 0.5 second maximum delay:
1 + 2e-60p,,CALCX/R>
Eq 14 : IAD1sYM - IsYM 6opi~TEST ~>
DELAY DELAY 1+2,e
[00126] It can then be determined if the device rating is greater than or
equal to Iadjsym or
hajsymdeiay. The pass/fail determinations can then be made in steps 1148 and
1150, respectively
and the percent rating can be calculated in step 1152.
[00127] If it is determined that the LVCB is fused in step 1122, then the
fault X/R can be
calculated in step 1126 and compared to the circuit breaker test X/R in order
to determine if the
calculated fault X/R is greater than the circuit breaker test X/R. If it is
greater, then Iadjsym can be
calculated in step 1154 using the following equation:
1.02 + 0.98 e-3'(cALCX/R)
Eq 13: hJsYVi - IsYVi 1.02 + 0.98 e-3i(TEST X/R)
[00128] If the calculated fault X/R is not greater than the circuit breaker
test X/R, then Iadjsym
can be set equal to Isym in step 1156. It can then be determined if the device
rating is greater than
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or equal to I~,djsym in step 1146. The pass/fail determinations can then be
carried out in steps 1148
and 1150 respectively, and the percent rating can be determined in step 1152.
[00129] Figure 12 is a diagram illustrating an example process for determining
the protective
capabilities of a HVCB. In certain embodiments, X/R can be calculated in step
1157 and a peak
current (Ipeak) can be determined using equation 11 in step 1158. In step
1162, it can be
determined whether the HVCB's rating is greater than or equal to Ipeak as
determined in step
1158. If the device rating is greater than or equal to Ipeak, then the device
has passed in step
1164. Otherwise, the device fails in step 1166. In either case, the percent
rating can be
determined in step 1168 using the following:
% rating = IPEAK
Device rating
[00130] In other embodiments, an interrupting time calculation can be made in
step 1170. In
such embodiments, a fault X/R can be calculated and then can be determined if
the fault X/R is
greater than or equal to a circuit breaker test X/R in step 1172. For example,
the following
circuit breaker test X/R can be used;
50 Hz Test X/R = 13.7
60 Hz Test X/R =16.7
(DC Time contant = 0.45ms)
[00131] If the fault X/R is not greater than the circuit breaker test X/R then
I~'dj,,,tsym can be set
equal to Isym in step 1174. If the calculated fault X/R is greater than the
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then contact parting time for the circuit breaker can be determined in step
1176 and equation 15
can then be used to determine I,,dj,,,tsym in step 1178.
1 + 2e 4pf*U(CAECx/R)
Eq 15 : I~NT = I~ 4pf*U(TEST X/R)
1+2e
[00132] In step 1180, it can be determined whether the device rating is
greater than or equal to
Iadj,,,tsym. The pass/fail determinations can then be made in steps 1182 and
1184 respectively and
the percent rating can be calculated in step 1186 using the following:
% rating = IADJINT SYM
Device rating
[00133] Figure 13 is a flowchart illustrating an example process for
determining the protective
capabilities of the protective devices being monitored in step 1002 in
accordance with another
embodiment. The process can start with a short circuit analysis in step 1302.
For systems
operating at a frequency other than 60hz, the protective device X/R can be
modified as follows:
(X/R)mod = (X/R) * 60H/(system Hz).
[00134] For fuses/switches, a selection can be made, as appropriate, between
use of the
symmetrical rating or asymmetrical rating for the device. The Multiplying
Factor (MF) for the
device can then be calculated in step 1304. The MF can then be used to
determine Iadjasym or
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I~,djsym. In step 1306, it can be determined if the device rating is greater
than or equal to ladjasym or
Iadjsym. Based on this determination, it can be determined whether the device
passed or failed in
steps 1308 and 1310 respectively, and the percent rating can be determined in
step 1312 using
the following:
% rating = I,,djas~- * 100/device rating; or
% rating = I.,djs~- * 100/device rating.
[00135] For LVCBs, it can first be determined whether the device is fused in
step 1314. If the
device is not fused, then in step 1315 it can be determined whether the X/R is
known for the
device. If it is known, then the LVF can be calculated for the device in step
1320. It should be
noted that the LVF can vary depending on whether the LVCB is an instantaneous
trip device or
not. If the X/R is not known, then it can be determined in step 1317, e.g.,
using the following:
PCB, ICCB = 6.59
MCCB, ICCB rated <= 10,000 A = 1.73
MCCB, ICCB rated 10,001- 20,000A = 3.18
MCCB, ICCB rated > 20,000 A = 4.9
[00136] If the device is fused, then in step 1316 it can again be determined
whether the X/R is
known. If it is known, then the LVF can be calculated in step 1319. If it is
not known, then the
X/R can be set equal to, e.g., 4.9.
[00137] In step 1321, it can be determined if the LVF is less than 1 and if it
is, then the LVF
can be set equal to 1. In step 1322 I,,,tadi can be determined using the
following:
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MCCB/ICCB/PCBWith Instantaneous :
lint, adj = LVF * Isym,rms
PCB Without Instantaneous :
lint, adj = LVFp * Isym,rms(Y2 Cyc)
int, adj = LVFasym * Isym,rms(3 - 8 Cyc)
[00138] In step 1323, it can be determined whether the device's symmetrical
rating is greater
than or equal to I,,,t~,dj, and it can be determined based on this evaluation
whether the device
passed or failed in steps 1324 and 1325 respectively. The percent rating can
then be determined
in step 1326 using the following:
% rating = I,ntaai * 100/device rating.
[00139] Figure 14 is a diagram illustrating a process for evaluating the
withstand capabilities
of a MVCB in accordance with one embodiment. In step 1328, a determination can
be made as
to whether the following calculations will be based on all remote inputs, all
local inputs or on a
No AC Decay (NACD) ratio. For certain implementations, a calculation can then
be made of the
total remote contribution, total local contribution, total contribution
(I,,,tr,,ssym), and NACD. If the
calculated NACD is equal to zero, then it can be determined that all
contributions are local. If
NACD is equal to 1, then it can be determined that all contributions are
remote.
[00140] If all the contributions are remote, then in step 1332 the remote MF
(MFr) can be
calculated and I,,t can be calculated using the following:
I;nt = MFr*I;n,,Mssym
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[00141] If all the inputs are local, then MF1 can be calculated and I,,,t can
be calculated using
the following:
I;,,t = MF 1*I;,,,,nissym
[00142] If the contributions are from NACD, then the NACD, MFr, MF1, and AMF1
can be
calculated. If AMF1 is less than 1, then AMF1 can be set equal to 1. I,,,t can
then be calculated
using the following:
I,,,t = AMF 1* I;,, , ssym/S
[00143] In step 1338, the 3-phase device duty cycle can be calculated and then
it can be
determined in step 1340, whether the device rating is greater than or equal to
I,,,t. Whether the
device passed or failed can then be determined in steps 1342 and 1344,
respectively. The
percent rating can be determined in step 1346 using the following:
% rating = I,,,t * 100/3p device rating.
[00144] In other embodiments, it can be determined, in step 1348, whether the
user has
selected a fixed MF. If so, then in certain embodiments the peak duty (crest)
can be determined
in step 1349 and MFp can be set equal to 2.7 in step 1354. If a fixed MF has
not been selected,
then the peak duty (crest) can be calculated in step 1350 and MFp can be
calculated in step 1358.
In step 1362, the MFp can be used to calculate the following:
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Imompeak MFY * Isymrxns
[00145] In step 1366, it can be determined if the device peak rating (crest)
is greater than or
equal to Imompeak. It can then be determined whether the device passed or
failed in steps 1368 and
1370 respectively, and the percent rating can be calculated as follows:
% rating = Imompeak * 100/device peak (crest) rating.
[00146] In other embodiments, if a fixed MF is selected, then a momentary duty
cycle (C&L)
can be determined in step 1351 and MFm can be set equal to, e.g., 1.6. If a
fixed MF has not
been selected, then in step 1352 MFm can be calculated. MFm can then be used
to determine the
following:
I =MFm*I
momsym symrms
[00147] It can then be determined in step 1374 whether the device C&L, rms
rating is greater
than or equal to Imomsym. Whether the device passed or failed can then be
determined in steps
1376 and 1378 respectively, and the percent rating can be calculated as
follows:
% rating = Imomasym* 100/device C & L, rms rating.

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[00148] Thus, the above methods provide a mean to determine the withstand
capability of
various protective devices, under various conditions and using various
standards, using an aged,
up to date virtual model of the system being monitored.
[00149] The influx of massive sensory data, e.g., provided via sensors 104,
106, and 108,
intelligent filtration of this dense stream of data into manageable and easily
understandable
knowledge. For example, as mentioned, it is important to be able to assess the
real-time ability
of the power system to provide sufficient generation to satisfy the system
load requirements and
to move the generated energy through the system to the load points.
Conventional systems do
not make use of an on-line, real-time system snap shot captured by a real-time
data acquisition
platform to perform real time system availability evaluation.
[00150] Figure 15 is a flow chart illustrating an example process for
analyzing the reliability
of an electrical power distribution and transmission system in accordance with
one embodiment.
First, in step 1502, reliability data can be calculated and/or determined. The
inputs used in step
1502 can comprise power flow data, e.g., network connectivity, loads,
generations,
cables/transformer impedances, etc., which can be obtained from the predicted
values generated
in step 1008, reliability data associated with each power system component,
lists of
contingencies to be considered, which can vary by implementation including by
region, site, etc.,
customer damage (load interruptions) costs, which can also vary by
implementation, and load
duration curve information. Other inputs can include failure rates, repair
rates, and required
availability of the system and of the various components.
[00151] In step 1504 a list of possible outage conditions and contingencies
can be evaluated
including loss of utility power supply, generators, UPS, and/or distribution
lines and
infrastructure. In step 1506, a power flow analysis for monitored system 102
under the various
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contingencies can be performed. This analysis can include the resulting
failure rates, repair
rates, cost of interruption or downtime versus the required system
availability, etc. In step 1510,
it can be determined if the system is operating in a deficient state when
confronted with a
specific contingency. If it is, then is step 1512, the impact on the system,
load interruptions,
costs, failure duration, system unavailability, etc. can all be evaluated.
[00152] After the evaluation of step 1512, or if it is determined that the
system is not in a
deficient state in step 1510, then it can be determined if further
contingencies need to be
evaluated. If so, then the process can revert to step 1506 and further
contingencies can be
evaluated. If no more contingencies are to be evaluated, then a report can be
generated in step
1514. The report can include a system summary, total and detailed reliability
indices, system
availability, etc. The report can also identify system bottlenecks are
potential problem areas.
[00153] The reliability indices can be based on the results of credible system
contingencies
involving both generation and transmission outages. The reliability indices
can include load
point reliability indices, branch reliability indices, and system reliability
indices. For example,
various load/bus reliability indices can be determined such as probability and
frequency of
failure, expected load curtailed, expected energy not supplied, frequency of
voltage violations,
reactive power required, and expected customer outage cost. The load point
indices can be
evaluated for the major load buses in the system and can be used in system
design for comparing
alternate system configurations and modifications.
[00154] Overall system reliability indices can include power interruption
index, power supply
average MW curtailment, power supply disturbance index, power energy
curtailment index,
severity index, and system availability. For example, the individual load
point indices can be
aggregated to produce a set of system indices. These indices are indicators of
the overall
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adequacy of the composite system to meet the total system load demand and
energy
requirements and can be extremely useful for the system planner and
management, allowing
more informed decisions to be made both in planning and in managing the
system.
[00155] The various analysis and techniques can be broadly classified as being
either Monte
Carlo simulation or Contingency Enumeration. The process can also use AC, DC
and fast linear
network power flow solutions techniques and can support multiple contingency
modeling,
multiple load levels, automatic or user-selected contingency enumeration, use
a variety of
remedial actions, and provides sophisticated report generation.
[00156] The analysis of step 1506 can include adequacy analysis of the power
system being
monitored based on a prescribed set of criteria by which the system must be
judged as being in
the success or failed state. The system is considered to be in the failed
state if the service at load
buses is interrupted or its quality becomes unacceptable, i.e., if there are
capacity deficiency,
overloads, and/or under/over voltages
[00157] Various load models can be used in the process of figure 15 including
multi-step load
duration curve, curtailable and Firm, and Customer Outage Cost models.
Additionally, various
remedial actions can be proscribed or even initiated including MW and MVAR
generation
control, generator bus voltage control, phase shifter adjustment, MW
generation rescheduling,
and load curtailment (interruptible and firm).
[00158] In other embodiments, the effect of other variables, such as the
weather and human
error can also be evaluated in conjunction with the process of figure 15 and
indices can be
associated with these factors. For example, figure 16 is a flow chart
illustrating an example
process for analyzing the reliability of an electrical power distribution and
transmission system
that takes weather information into account in accordance with one embodiment.
Thus, in step
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1602, real-time weather data can be received, e.g., via a data feed such as an
XML feed from
National Oceanic and Atmosphere Administration (NOAA). In step 1604, this data
can be
converted into reliability data that can be used in step 1502.
[00159] It should also be noted that National Fire Protection Association
(NFPA) and the
Occupational Safety and Health Association (OSHA) have mandated that
facilities comply with
proper workplace safety standards and conduct Arc Flash studies in order to
determine the
incident energy, protection boundaries and PPE levels needed to be worn by
technicians.
Unfortunately, conventional approaches/systems for performing such studies do
not provide a
reliable means for the real-time prediction of the potential energy released
(in calories per
centimeter squared) for an arc flash event. Moreover, no real-time system
exists that can predict
the required personal protective equipment (PPE) required to safely perform
repairs as required
by NFPA 70E and IEEE 1584.
[00160] When a fault in the system being monitored contains an arc, the heat
released can
damage equipment and cause personal injury. It is the latter concern that
brought about the
development of the heat exposure programs referred to above. The power
dissipated in the arc
radiates to the surrounding surfaces. The further away from the arc the
surface is, the less the
energy is received per unit area.
[00161] As noted above, conventional approaches are based on highly
specialized static
simulation models that are rigid and non-reflective of the facilities
operational status at the time
a technician may be needed to conduct repairs on electrical equipment. But the
PPE level
required for the repair, or the safe protection boundary may change based on
the actual
operational status of the facility and alignment of the power distribution
system at the time
repairs are needed. Therefore, a static model does not provide the real-time
analysis that can be
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critical for accurate PPE level determination. This is because static systems
cannot adjust to the
many daily changes to the electrical system that occur at a facility, e.g.,
motors and pumps may
be on or off, on-site generation status may have changed by having diesel
generators on-line,
utility electrical feed may also change, etc., nor can they age with the
facility to accurately
predict the required PPE levels.
[00162] Accordingly, existing systems rely on exhaustive studies to be
performed off-line by
a power system engineer or a design professional/specialist. Often the
specialist must manually
modify a simulation model so that it is reflective of the proposed facility
operating condition and
then conduct a static simulation or a series of static simulations in order to
come up with
recommended safe working distances, energy calculations and PPE levels. But
such a process is
not timely, accurate nor efficient, and as noted above can be quite costly.
[00163] Using the systems and methods described herein a logical model of a
facility
electrical system can be integrated into a real-time environment, with a
robust AC Arc Flash
simulation engine (system modeling engine 124), a data acquisition system
(data acquisition hub
112), and an automatic feedback system (calibration engine 134) that
continuously synchronizes
and calibrates the logical model to the actual operational conditions of the
electrical system. The
ability to re-align the simulation model in real-time so that it mirrors the
real facility operating
conditions, coupled with the ability to calibrate and age the model as the
real facility ages, as
describe above, provides a desirable approach to predicting PPE levels, and
safe working
conditions at the exact time the repairs are intended to be performed.
Accordingly, facility
management can provide real-time compliance with, e.g., NFPA 70E and IEEE 1584
standards
and requirements.

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[00164] Figure 17 is a diagram illustrating an example process for predicting
in real-time
various parameters associated with an alternating current (AC) arc flash
incident. These
parameters can include for example, the arc flash incident energy, arc flash
protection boundary,
and required Personal Protective Equipment (PPE) levels, e.g., in order to
comply with NFPA-
70E and IEEE-1584. First, in step 1702, updated virtual model data can be
obtained for the
system being model, e.g., the updated data of step 1006, and the operating
modes for the system
can be determined. In step 1704, an AC 3-phase short circuit analysis can be
performed in order
to obtain bolted fault current values for the system. In step 1706, e.g., IEEE
1584 equations can
be applied to the bolted fault values and any corresponding arcing currents
can be calculated in
step 1708.
[00165] The ratio of arc current to bolted current can then be used, in step
1710, to determine
the arcing current in a specific protective device, such as a circuit breaker
or fuse. A coordinated
time-current curve analysis can be performed for the protective device in step
1712. In step
1714, the arcing current in the protective device and the time current
analysis can be used to
determine an associated fault clearing time, and in step 1716 a corresponding
arc energy can be
determined based on, e.g., IEEE 1584 equations applied to the fault clearing
time and arcing
current.
[00166] In step 1718, the 100% arcing current can be calculated and for
systems operating at
less than 1kV the 85% arcing current can also be calculated. In step 1720, the
fault clearing time
in the protective device can be determined at the 85% arcing current level. In
step 1722, e.g.,
IEEE 1584 equations can be applied to the fault clearing time (determined in
step 1720) and the
arcing current to determine the 85% arc energy level, and in step 1724 the
100% arcing current
can be compared with the 85% arcing current, with the higher of the two being
selected. IEEE
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1584 equations, for example, can then be applied to the selected arcing
current in step 1726 and
the PPE level and boundary distance can be determined in step 1728. In step
1730, these values
can be output, e.g., in the form of a display or report.
[00167] In other embodiments, using the same or a similar procedure as
illustrated in figure
17, the following evaluations can be made in real-time and based on an
accurate, e.g., aged,
model of the system:
Arc Flash Exposure based on IEEE 1584;
Arc Flash Exposure based on NFPA 70E;
Network-Based Arc Flash Exposure on AC Systems/Single Branch Case;
Network-Based Arc Flash Exposure on AC Systems/Multiple Branch Cases;
Network Arc Flash Exposure on DC Networks;
Exposure Simulation at Switchgear Box, MCC Box, Open Area and Cable
Grounded and Ungrounded;
Calculate and Select Controlling Branch(s) for Simulation of Arc Flash;
Test Selected Clothing;
Calculate Clothing Required;
Calculate Safe Zone with Regard to User Defined Clothing Category;
Simulated Art Heat Exposure at User Selected locations;
User Defined Fault Cycle for 3-Phase and Controlling Branches;
User Defined Distance for Subject;
100% and 85% Arcing Current;
100% and 85% Protective Device Time;
Protective Device Setting Impact on Arc Exposure Energy;
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User Defined Label Sizes;
Attach Labels to One-Line Diagram for User Review;
Plot Energy for Each Bus;
Write Results into Excel;
View and Print Graphic Label for User Selected Bus(s); and
Work permit.
[00168] With the insight gained through the above methods, appropriate
protective measures,
clothing and procedures can be mobilized to minimize the potential for injury
should an arc flash
incident occur. Facility owners and operators can efficiently implement a real-
time safety
management system that is in compliance with NFPA 70E and IEEE 1584
guidelines.
[00169] Figure 18 is a flow chart illustrating an example process for real-
time analysis of the
operational stability of an electrical power distribution and transmission
system in accordance
with one embodiment. The ability to predict, in real-time, the capability of a
power system to
maintain stability and/or recover from various contingency events and
disturbances without
violating system operational constraints is important. This analysis
determines the real-time
ability of the power system to: 1. sustain power demand and maintain
sufficient active and
reactive power reserve to cope with ongoing changes in demand and system
disturbances due to
contingencies, 2. operate safely with minimum operating cost while maintaining
an adequate
level of reliability, and 3. provide an acceptably high level of power quality
(maintaining voltage
and frequency within tolerable limits) when operating under contingency
conditions.
[00170] In step 1802, the dynamic time domain model data can be updated to re-
align the
virtual system model in real-time so that it mirrors the real operating
conditions of the facility.
The updates to the domain model data coupled with the ability to calibrate and
age the virtual
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system model of the facility as it ages (i.e., real-time condition of the
facility), as describe above,
provides a desirable approach to predicting the operational stability of the
electrical power
system operating under contingency situations. That is, these updates account
for the natural
aging effects of hardware that comprise the total electrical power system by
continuously
synchronizing and calibrating both the control logic used in the simulation
and the actual
operating conditions of the electrical system
[00171] The domain model data includes data that is reflective of both the
static and non-
static (rotating) components of the system. Static components are those
components that are
assumed to display no changes during the time in which the transient
contingency event takes
place. Typical time frames for disturbance in these types of elements range
from a few cycles of
the operating frequency of the system up to a few seconds. Examples of static
components in an
electrical system include but are not limited to transformers, cables,
overhead lines, reactors,
static capacitors, etc. Non-static (rotating) components encompass synchronous
machines
including their associated controls (exciters, governors, etc), induction
machines, compensators,
motor operated valves (MOV), turbines, static var compensators, fault
isolation units (FIU),
static automatic bus transfer (SABT) units, etc. These various types of non-
static components
can be simulated using various techniques. For example:
= For Synchronous Machines: thermal (round rotor) and hydraulic (salient pole)
units can be both simulated either by using a simple model or by the most
complete two-axis including damper winding representation.
= For Induction Machines: a complete two-axis model can be used. Also it is
possible to model them by just providing the testing curves (current, power
factor,
and torque as a function of speed).
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= For Motor Operated Valves (MOVs): Two modes of MOV operation are of
interest, namely, opening and closing operating modes. Each mode of operation
consists of five distinct stages, a) start, b) full speed, c) unseating, d)
travel, and e)
stall. The system supports user-defined model types for each of the stages.
That
is, "start" may be modeled as a constant current while "full speed" may be
modeled by constant power. This same flexibility exists for all five distinct
stages
of the closing mode.
= For AVR and Excitation Systems: There are a number of models ranging form
rotating (DC and AC) and analogue to static and digital controls.
Additionally,
the system offers a user-defined modeling capability, which can be used to
define
a new excitation model.
= For Governors and Turbines: The system is designed to address current and
future technologies including but not limited to hydraulic, diesel, gas, and
combined cycles with mechanical and/or digital governors.
= For Static Var Compensators (SVCs): The system is designed to address
current
and future technologies including a number of solid-state (thyristor)
controlled
SVC's or even the saturable reactor types.
= For Fault Isolation Units (FIUs): The system is designed to address current
and
future technologies of FIUs also known as Current Limiting Devices, are
devices
installed between the power source and loads to limit the magnitude of fault
currents that occur within loads connected to the power distribution networks.

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= For Static Automatic Bus Transfers (SABT): The system is designed to address
current and future technologies of SABT (i.e., solid-state three phase, dual
position, three-pole switch, etc.)
[00172] In one embodiment, the time domain model data includes "built-in"
dynamic model
data for exciters, governors, transformers, relays, breakers, motors, and
power system stabilizers
(PSS) offered by a variety of manufactures. For example, dynamic model data
for the electrical
power system may be OEM manufacturer supplied control logic for electrical
equipment such as
automatic voltage regulators (AVR), governors, under load tap changing
transformers, relays,
breakers motors, etc. In another embodiment, in order to cope with recent
advances in power
electronic and digital controllers, the time domain model data includes "user-
defined" dynamic
modeling data that is created by an authorized system administrator in
accordance with user-
defined control logic models. The user-defined models interacts with the
virtual system model
of the electrical power system through "Interface Variables" 1816 that are
created out of the
user-defined control logic models. For example, to build a user-defined
excitation model, the
controls requires that generator terminal voltage to be measured and compared
with a reference
quantity (voltage set point). Based on the specific control logic of the
excitation and AVR, the
model would then compute the predicted generator field voltage and return that
value back to the
application. The user-defined modeling supports a large number of pre-defined
control blocks
(functions) that are used to assemble the required control systems and put
them into action in a
real-time environment for assessing the strength and security of the power
system. In still
another embodiment, the time domain model data includes both built-in dynamic
model data and
user-defined model data.
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[00173] Moving on to step 1804, a contingency event can be chosen out of a
diverse list of
contingency events to be evaluated. That is, the operational stability of the
electrical power
system can be assessed under a number of different contingency event scenarios
including but
not limited to a singular event contingency or multiple event contingencies
(that are
simultaneous or sequenced in time). In one embodiment, the contingency events
assessed are
manually chosen by a system administrator in accordance with user
requirements. In another
embodiment, the contingency events assessed are automatically chosen in
accordance with
control logic that is dynamically adaptive to past observations of the
electrical power system.
That is the control logic "learns" which contingency events to simulate based
on past
observations of the electrical power system operating under various
conditions.
[00174] Some examples of contingency events include but are not limited to:
Application/removal of three-phase fault.
Application/removal of phase-to-ground fault
Application/removal of phase-phase-ground fault.
Application/removal of phase-phase fault.
Branch Addition.
Branch Tripping
Starting Induction Motor.
Stopping Induction Motor
Shunt Tripping.
Shunt Addition (Capacitor and/or Induction)
Generator Tripping.
SVC Tripping.
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Impact Loading (Load Changing Mechanical Torque on Induction Machine. With
this option it is actually possible to turn an induction motor to an induction
generator)
Loss of Utility Power Supply/Generators/UPS/Distribution Lines/System
Infrastructure
Load Shedding
[00175] In step 1806, a transient stability analysis of the electrical power
system operating
under the various chosen contingencies can be performed. This analysis can
include
identification of system weaknesses and insecure contingency conditions. That
is, the analysis
can predict (forecast) the system's ability to sustain power demand, maintain
sufficient active and
reactive power reserve, operate safely with minimum operating cost while
maintaining an
adequate level of reliability, and provide an acceptably high level of power
quality while being
subjected to various contingency events. The results of the analysis can be
stored by an
associative memory engine 1818 during step 1814 to support incremental
learning about the
operational characteristics of the system. That is, the results of the
predictions, analysis, and
real-time data may be fed, as needed, into the associative memory engine 1818
for pattern and
sequence recognition in order to learn about the logical realities of the
power system. In certain
embodiments, engine 1818 can also act as a pattern recognition engine or a
Hierarchical
Temporal Memory (HTM) engine. Additionally, concurrent inputs of various
electrical,
environmental, mechanical, and other sensory data can be used to learn about
and determine
normality and abnormality of business and plant operations to provide a means
of understanding
failure modes and give recommendations.
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[00176] In step 1810, it can be determined if the system is operating in a
deficient state when
confronted with a specific contingency. If it is, then in step 1812, a report
is generated providing
a summary of the operational stability of the system. The summary may include
general
predictions about the total security and stability of the system and/or
detailed predictions about
each component that makes up the system.
[00177] Alternatively, if it is determined that the system is not in a
deficient state in step
1810, then step 1808 can determine if further contingencies needs to be
evaluated. If so, then the
process can revert to step 1806 and further contingencies can be evaluated.
[00178] The results of real-time simulations performed in accordance with
figure 18 can be
communicated in step 1812 via a report, such as a print out or display of the
status. In addition,
the information can be reported via a graphical user interface (thick or thin
client) that illustrated
the various components of the system in graphical format. In such embodiments,
the report can
simply comprise a graphical indication of the security or insecurity of a
component, subsystem,
or system, including the whole facility. The results can also be forwarded to
associative memory
engine 1818, where they can be stored and made available for predictions,
pattern/sequence
recognition and ability to imagine, e.g., via memory agents or other
techniques, some of which
are describe below, in step 1820.
[00179] The process of figure 18 can be applied to a number of needs including
but not
limited to predicting system stability due to: Motor starting and motor
sequencing, an example is
the assessment of adequacy of a power system in emergency start up of
auxiliaries; evaluation of
the protections such as under frequency and under-voltage load shedding
schemes, example of
this is allocation of required load shedding for a potential loss of a power
generation source;
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determination of critical clearing time of circuit breakers to maintain
stability; and determination
of the sequence of protective device operations and interactions.
[00180] Figure 19 is a flow chart illustrating an example process for
conducting a real-time
power capacity assessment of an electrical power distribution and transmission
system, in
accordance with one embodiment. The stability of an electrical power system
can be classified
into two broad categories: transient (angular) stability and voltage stability
(i.e., power
capacity). Voltage stability refers to the electrical system's ability to
maintain acceptable voltage
profiles under different system topologies and load changes (i.e., contingency
events). That is,
voltage stability analyses determine bus voltage profiles and power flows in
the electrical system
before, during, and immediately after a major disturbance. Generally speaking,
voltage
instability stems from the attempt of load dynamics to restore power
consumption beyond the
capability of the combined transmission and generation system. One factor that
comes into play
is that unlike active power, reactive power cannot be transported over long
distances. As such, a
power system rich in reactive power resources is less likely to experience
voltage stability
problems. Overall, the voltage stability of a power system is of paramount
importance in the
planning and daily operation of an electrical system.
[00181] Traditionally, transient stability has been the main focus of power
system
professionals. However, with the increased demand for electrical energy and
the regulatory
hurdles blocking the expansion of existing power systems, the occurrences of
voltage instability
has become increasingly frequent and therefore has gained increased attention
from power
system planners and power system facility operators. The ability to learn,
understand and make
predictions about available power system capacity and system susceptibility to
voltage
instability, in real-time would be beneficial in generating power trends for
forecasting purposes.

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[00182] In step 1902, the voltage stability modeling data for the components
comprising the
electrical system can be updated to re-align the virtual system model in "real-
time" so that it
mirrors the real operating conditions of the facility. These updates to the
voltage stability
modeling data coupled with the ability to calibrate and age the virtual system
model of the
facility as it ages (i.e., real-time condition of the facility), as describe
above, provides a desirable
approach to predicting occurrences of voltage instability (or power capacity)
in the electrical
power system when operating under contingency situations. That is, these
updates account for
the natural aging effects of hardware that comprise the total electrical power
system by
continuously synchronizing and calibrating both the control logic used in the
simulation and the
actual operating conditions of the electrical system
[00183] The voltage stability modeling data includes system data that has
direct influence on
the electrical system's ability to maintain acceptable voltage profiles when
the system is
subjected to various contingencies, such as when system topology changes or
when the system
encounters power load changes. Some examples of voltage stability modeling
data are load
scaling data, generation scaling data, load growth factor data, load growth
increment data, etc.
[00184] In one embodiment, the voltage stability modeling data includes "built-
in" data
supplied by an OEM manufacturer of the components that comprise the electrical
equipment. In
another embodiment, in order to cope with recent advances power system
controls, the voltage
stability data includes "user-defined" data that is created by an authorized
system administrator
in accordance with user-defined control logic models. The user-defined models
interact with the
virtual system model of the electrical power system through "Interface
Variables" 1916 that are
created out of the user-defined control logic models. In still another
embodiment, the voltage
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stability modeling data includes a combination of both built-in model data and
user-defined
model data
[00185] Moving on to step 1904, a contingency event can be chosen out of a
diverse list of
contingency events to be evaluated. That is, the voltage stability of the
electrical power system
can be assessed under a number of different contingency event scenarios
including but not
limited to a singular event contingency or multiple event contingencies (that
are simultaneous or
sequenced in time). In one embodiment, the contingency events assessed are
manually chosen
by a system administrator in accordance with user requirements. In another
embodiment, the
contingency events assessed are automatically chosen in accordance with
control logic that is
dynamically adaptive to past observations of the electrical power system. That
is the control
logic "learns" which contingency events to simulate based on past observations
of the electrical
power system operating under various conditions. Some examples of contingency
events include
but are not limited to: loss of utility supply to the electrical system, loss
of available power
generation sources, system load changes/fluctuations, loss of distribution
infrastructure
associated with the electrical system, etc.
[00186] In step 1906, a voltage stability analysis of the electrical power
system operating
under the various chosen contingencies can be performed. This analysis can
include a prediction
(forecast) of the total system power capacity, available system power capacity
and utilized
system power capacity of the electrical system of the electrical system under
various
contingencies. That is, the analysis can predict (forecast) the electrical
system's ability to
maintain acceptable voltage profiles during load changes and when the overall
system topology
undergoes changes. The results of the analysis can be stored by an associative
memory engine
1918 during step 1914 to support incremental learning about the power capacity
characteristics
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of the system. That is, the results of the predictions, analysis, and real-
time data may be fed, as
needed, into the associative memory engine 1918 for pattern and sequence
recognition in order
to learn about the voltage stability of the electrical system in step 1920.
Additionally, concurrent
inputs of various electrical, environmental, mechanical, and other sensory
data can be used to
learn about and determine normality and abnormality of business and plant
operations to provide
a means of understanding failure modes and give recommendations.
[00187] In step 1910, it can be determined if there is voltage instability in
the system when
confronted with a specific contingency. If it is, then in step 1912, a report
is generated providing
a summary of the specifics and source of the voltage instability. The summary
may include
general predictions about the voltage stability of the overall system and/or
detailed predictions
about each component that makes up the system.
[00188] Alternatively, if it is determined that the system is not in a
deficient state in step
1910, then step 1908 can determine if further contingencies needs to be
evaluated. If so, then the
process can revert to step 1906 and further contingencies can be evaluated.
[00189] The results of real-time simulations performed in accordance with
figure 19 can be
communicated in step 1912 via a report, such as a print out or display of the
status. In addition,
the information can be reported via a graphical user interface (thick or thin
client) that illustrated
the various components of the system in graphical format. In such embodiments,
the report can
simply comprise a graphical indication of the capacity of a subsystem or
system, including the
whole facility. The results can also be forwarded to associative memory engine
1918, where
they can be stored and made available for predictions, pattern/sequence
recognition and ability to
imagine, e.g., via memory agents or other techniques, some of which are
describe below, in step
1920
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[00190] The systems and methods described above can also be used to provide
reports (step
1912) on, e.g., total system electrical capacity, total system capacity
remaining, total capacity at
all busbars and/or processes, total capacity remaining at all busbars and/or
processes, total
system loading, loading at each busbar and/or process, etc.
[00191] Thus, the process of figure 19 can receive input data related to power
flow, e.g.,
network connectivity, loads, generations, cables/transformers, impedances,
etc., power security,
contingencies, and capacity assessment model data and can produce as outputs
data related to the
predicted and designed total system capacity, available capacity, and present
capacity. This
information can be used to make more informed decisions with respect to
management of the
facility.
[00192] Figure 20 is a flow chart illustrating an example process for
performing real-time
harmonics analysis of an electrical power distribution and transmission
system, in accordance
with one embodiment. As technological advances continue to be made in the
field of electronic
devices, there has been particular emphasis on the development of energy
saving features.
Electricity is now used quite differently from the way it used be used with
new generations of
computers and peripherals using very large-scale integrated circuitry
operating at low voltages
and currents. Typically, in these devices, the incoming alternating current
(AC) voltage is diode
rectified and then used to charge a large capacitor. The electronic device
then draws direct
current (DC) from the capacitor in short non-linear pulses to power its
internal circuitry. This
sometimes causes harmonic distortions to arise in the load current, which may
result in
overheated transformers and neutrals, as well as tripped circuit breakers in
the electrical system.
[00193] The inherent risks (to safety and the operational life of components
comprising the
electrical system) that harmonic distortions poses to electrical systems have
led to the inclusion
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of harmonic distortion analysis as part of traditional power analysis.
Metering and sensor
packages are currently available to monitor harmonic distortions within an
electrical system.
However, it is not feasible to fully sensor out an electrical system at all
possible locations due to
cost and the physical accessibility limitations in certain parts of the
system. Therefore, there is a
need for techniques that predict, through real-time simulation, the sources of
harmonic
distortions within an electrical system, the impacts that harmonic distortions
have or may have,
and what steps (i.e., harmonics filtering) may be taken to minimize or
eliminate harmonics from
the system.
[00194] Currently, there are no reliable techniques for predicting, in real-
time, the potential
for periodic non-sinusoidal waveforms (i.e. harmonic distortions) to occur at
any location within
an electrical system powered with sinusoidal voltage. In addition, existing
techniques do not
take into consideration the operating conditions and topology of the
electrical system or utilizes
a virtual system model of the system that "ages" with the actual facility or
its current condition.
Moreover, no existing technique combines real-time power quality meter
readings and predicted
power quality readings for use with a pattern recognition system such as an
associative memory
machine learning system to predict harmonic distortions in a system due to
changes in topology
or poor operational conditions within an electrical system.
[00195] The process, described herein, provides a harmonics analysis solution
that uses a real-
time snap shot captured by a data acquisition system to perform a real-time
system power quality
evaluation at all locations regardless of power quality metering density. This
process integrates,
in real-time, a logical simulation model (i.e., virtual system model) of the
electrical system, a
data acquisition system, and power system simulation engines with a logic
based approach to
synchronize the logical simulation model with conditions at the real
electrical system to

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effectively "age" the simulation model along with the actual electrical
system. Through this
approach, predictions about harmonic distortions in an electrical system may
be accurately
calculated in real-time. Condensed, this process works by simulating harmonic
distortions in an
electrical system through subjecting a real-time updated virtual system model
of the system to
one or more simulated contingency situations.
[00196] In step 2002, the harmonic frequency modeling data for the components
comprising
the electrical system can be updated to re-align the virtual system model in
"real-time" so that it
mirrors the real operating conditions of the facility. These updates to the
harmonic frequency
modeling data coupled with the ability to calibrate and age the virtual system
model of the
facility as it ages (i.e., real-time condition of the facility), as describe
above, provides a desirable
approach to predicting occurrences of harmonic distortions within the
electrical power system
when operating under contingency situations. That is, these updates account
for the natural
aging effects of hardware that comprise the total electrical power system by
continuously
synchronizing and calibrating both the control logic used in the simulation
and the actual
operating conditions of the electrical system.
[00197] Harmonic frequency modeling data has direct influence over how
harmonic
distortions are simulated during a harmonics analysis. Examples of data that
is included with the
harmonic frequency modeling data include: IEEE 519 and/or Mil 1399 compliant
system
simulation data, generator/cable/motor skin effect data, transformer phase
shifting data,
generator impedance data, induction motor impedance data, etc.
[00198] Moving on to step 2004, a contingency event can be chosen out of a
diverse list of
contingency events to be evaluated. That is, the electrical system can be
assessed for harmonic
distortions under a number of different contingency event scenarios including
but not limited to a
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singular event contingency or multiple event contingencies (that are
simultaneous or sequenced
in time). In one embodiment, the contingency events assessed are manually
chosen by a system
administrator in accordance with user requirements. In another embodiment, the
contingency
events assessed are automatically chosen in accordance with control logic that
is dynamically
adaptive to past observations of the electrical power system. That is the
control logic "learns"
which contingency events to simulate based on past observations of the
electrical power system
operating under various conditions. Some examples of contingency events
include but are not
limited to additions (bringing online) and changes of equipment that
effectuate a non-linear load
on an electrical power system (e.g., as rectifiers, arc furnaces, AC/DC
drives, variable frequency
drives, diode-capacitor input power supplies, uninterruptible power supplies,
etc.) or other
equipment that draws power in short intermittent pulses from the electrical
power system.
[00199] Continuing with Figure 20, in step 2006, a harmonic distortion
analysis of the
electrical power system operating under the various chosen contingencies can
be performed.
This analysis can include predictions (forecasts) of different types of
harmonic distortion data at
various points within the system. Harmonic distortion data may include but are
not limited to:
Wave-shape Distortions/Oscillations data
Parallel and Series Resonant Condition data
Total Harmonic Distortion Level data (both Voltage and Current type)
Data on the true RMS system loading of lines, transformers, capacitors, etc.
Data on the Negative Sequence Harmonics being absorbed by the AC motors
Transformer K-Factor Level data
Frequency scan at positive, negative, and zero angle response throughout the
entire scanned spectrum in the electrical system.
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[00200] That is, the harmonics analysis can predict (forecast) various
indicators (harmonics
data) of harmonic distortions occurring within the electrical system as it is
being subjected to
various contingency situations. The results of the analysis can be stored by
an associative
memory engine 2016 during step 2014 to support incremental learning about the
harmonic
distortion characteristics of the system. That is, the results of the
predictions, analysis, and real-
time data may be fed, as needed, into the associative memory engine 2016 for
pattern and
sequence recognition in order to learn about the harmonic distortion profile
of the electrical
system in step 2018. Additionally, concurrent inputs of various electrical,
environmental,
mechanical, and other sensory data can be used to learn about and determine
normality and
abnormality of business and plant operations to provide a means of
understanding failure modes
and give recommendations.
[00201] In step 2010, it can be determined if there are harmonic distortions
within the system
when confronted with a specific contingency. If it is, then in step 2012, a
report is generated
providing a summary of specifics regarding the characteristics and sources of
the harmonic
distortions. The summary may include forecasts about the different types of
harmonic distortion
data (e.g., Wave-shape Distortions/Oscillations data, Parallel and Series
Resonant Condition
data, etc.) generated at various points throughout the system. Additionally,
through these
forecasts, the associative memory engine 2016 can make predictions about the
natural oscillation
response(s) of the facility and compare those predictions with the harmonic
components of the
non-linear loads that are fed or will be fed from the system as indicated form
the data acquisition
system and power quality meters. This will give an indication of what harmonic
frequencies that
the potential resonant conditions lie at and provide facility operators with
the ability to
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effectively employ a variety of harmonic mitigation techniques (e.g., addition
of harmonic filter
banks, etc.)
[00202] Alternatively, if it is determined that the system is not in a
deficient state in step
2010, then step 2008 can determine if further contingencies needs to be
evaluated. If so, then the
process can revert to step 2006 and further contingencies can be evaluated.
[00203] The results of real-time simulations performed in accordance with
figure 20 can be
communicated in step 2012 via a report, such as a print out or display of the
status. In addition,
the information can be reported via a graphical user interface (thick or thin
client) that illustrated
the various components of the system in graphical format. In such embodiments,
the report can
simply comprise a graphical indication of the harmonic status of subsystem or
system, including
the whole facility. The results can also be forwarded to associative memory
engine 2016, where
they can be stored and made available for predictions, pattern/sequence
recognition and ability to
imagine, e.g., via memory agents or other techniques, some of which are
describe below, in step
2018
[00204] Thus, the process of Figure 20 can receive input data related to power
flow, e.g.,
network connectivity, loads, generations, cables/transformers, impedances,
etc., power security,
contingencies, and can produce as outputs data related to Point Specific Power
Quality Indices,
Branch Total Current Harmonic Distortion Indices, Bus and Node Total Voltage
Harmonic
Distortion Indices, Frequency Scan Indices for Positive Negative and Zero
Sequences, Filter(s)
Frequency Angle Response, Filter(s) Frequency Impedance Response, and Voltage
and Current
values over each filter elements (r, xl, xc).
[00205] Figure 21 is a diagram illustrating how the HTM Pattern Recognition
and Machine
Learning Engine works in conjunction with the other elements of the analytics
system to make
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predictions about the operational aspects of a monitored system, in accordance
with one
embodiment. As depicted herein, the HTM Pattern Recognition and Machine
Learning Engine
551 is housed within an analytics server 116 and communicatively connected via
a network
connection 114 with a data acquisition hub 112, a client terminal 128 and a
virtual system model
database 526. The virtual system model database 526 is configured to store the
virtual system
model of the monitored system. The virtual system model is constantly updated
with real-time
data from the data acquisition hub 112 to effectively account for the natural
aging effects of the
hardware that comprise the total monitored system, thus, mirroring the real
operating conditions
of the system. This provides a desirable approach to predicting the
operational aspects of the
monitored power system operating under contingency situations.
[00206] The HTM Machine Learning Engine 551 is configured to store and process
patterns
observed from real-time data fed from the hub 112 and predicted data output
from a real-time
virtual system model of the monitored system. These patterns can later be used
by the HTM
Engine 551 to make real-time predictions (forecasts) about the various
operational aspects of the
system.
[00207] The data acquisition hub 112 is communicatively connected via data
connections 110
to a plurality of sensors that are embedded throughout a monitored system 102.
The data
acquisition hub 112 may be a standalone unit or integrated within the
analytics server 116 and
can be embodied as a piece of hardware, software, or some combination thereof.
In one
embodiment, the data connections 110 are "hard wired" physical data
connections (e.g., serial,
network, etc.). For example, a serial or parallel cable connection between the
sensors and the
hub 112. In another embodiment, the data connections 110 are wireless data
connections. For

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example, a radio frequency (RF), BLUETOOTHTM, infrared or equivalent
connection between
the sensor and the hub 112.
[00208] Examples of a monitored system includes machinery, factories,
electrical systems,
processing plants, devices, chemical processes, biological systems, data
centers, aircraft carriers,
and the like. It should be understood that the monitored system can be any
combination of
components whose operations can be monitored with conventional sensors and
where each
component interacts with or is related to at least one other component within
the combination.
[00209] Continuing with Figure 21, the client 128 is typically a conventional
"thin-client" or
"thick client" computing device that may utilize a variety of network
interfaces (e.g., web
browser, CITRIXTM, WINDOWS TERMINAL SERVICESTM, telnet, or other equivalent
thin-
client terminal applications, etc.) to access, configure, and modify the
sensors (e.g.,
configuration files, etc.), power analytics engine (e.g., configuration files,
analytics logic, etc.),
calibration parameters (e.g., configuration files, calibration parameters,
etc.), virtual system
modeling engine (e.g., configuration files, simulation parameters, etc.) and
virtual system model
of the system under management (e.g., virtual system model operating
parameters and
configuration files). Correspondingly, in one embodiment, the data from the
various components
of the monitored system and the real-time predictions (forecasts) about the
various operational
aspects of the system can be displayed on a client 128 display panel for
viewing by a system
administrator or equivalent. In another embodiment, the data may be summarized
in a hard copy
report 2102.
[00210] As discussed above, the HTM Machine Learning Engine 551 is configured
to work in
conjunction with a real-time updated virtual system model of the monitored
system to make
predictions (forecasts) about certain operational aspects of the monitored
system when it is
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subjected to a contingency event. For example, where the monitored system is
an electrical
power system, in one embodiment, the HTM Machine Learning Engine 551 can be
used to make
predictions about the operational reliability of an electrical power system in
response to
contingency events such as a loss of power to the system, loss of distribution
lines, damage to
system infrastructure, changes in weather conditions, etc. Examples of
indicators of operational
reliability include but are not limited to failure rates, repair rates, and
required availability of the
power system and of the various components that make up the system.
[00211] In another embodiment, the operational aspects relate to an arc flash
discharge
contingency event that occurs during the operation of the power system.
Examples of arc flash
related operational aspects include but are not limited to quantity of energy
released by the arc
flash event, required personal protective equipment (PPE) for personnel
operating within the
confines of the system during the arc flash event, and measurements of the arc
flash safety
boundary area around components comprising the power system. In still another
embodiment,
the operational aspect relates to the operational stability of the system
during a contingency
event. That is, the system's ability to sustain power demand, maintain
sufficient active and
reactive power reserve, operate safely with minimum operating cost while
maintaining an
adequate level of reliability, and provide an acceptably high level of power
quality while being
subjected to a contingency event.
[00212] In still another embodiment, the operational aspect relates to the
voltage stability of
the electrical system immediately after being subjected to a major disturbance
(i.e., contingency
event). Generally speaking, voltage instability stems from the attempt of load
dynamics to
restore power consumption, after the disturbance, in a manner that is beyond
the capability of the
combined transmission and generation system. Examples of predicted operational
aspects that
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are indicative of the voltage stability of an electrical system subjected to a
disturbance include
the total system power capacity, available system power capacity and utilized
system power
capacity of the electrical system under being subjected to various
contingencies. Simply, voltage
stability is the ability of the system to maintain acceptable voltage profiles
while under the
influence of the disturbances.
[00213] In still yet another embodiment, the operational aspect relates to
harmonic distortions
in the electrical system subjected to a major disturbance. Harmonic
distortions are characterized
by non-sinusoidal (non-linear) voltage and current waveforms. Most harmonic
distortions result
from the generation of harmonic currents caused by nonlinear load signatures.
A nonlinear load
is characteristic in products such as computers, printers, lighting and motor
controllers, and
much of today's solid-state equipment. With the advent of power semiconductors
and the use of
switching power supplies, the harmonics distortion problem has become more
severe.
[00214] Examples of operational aspects that are indicative of harmonic
distortions include
but are not limited to: wave-shape distortions/oscillations, parallel and
series resonance, total
harmonic distortion level, transformer K-Factor levels, true RMS loading of
lines/transformers/capacitors, indicators of negative sequence harmonics being
absorbed by
alternating current (AC) motors, positive/negative/zero angle frequency
response, etc.
[00215] Figure 22 is an illustration of the various cognitive layers that
comprise the
neocortical catalyst process used by the HTM Pattern Recognition and Machine
Learning Engine
to analyze and make predictions about the operational aspects of a monitored
system, in
accordance with one embodiment. As depicted herein, the neocortical catalyst
process is
executed by a neocortical model 2202 that is encapsulated by a real-time
sensory system layer
2204, which is itself encapsulated by an associative memory model layer 2206.
Each layer is
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essential to the operation of the neocortical catalyst process but the key
component is still the
neocortical model 2202. The neocortical model 2202 represents the "ideal"
state and
performance of the monitored system and it is continually updated in real-time
by the sensor
layer 2204. The sensory layer 2204 is essentially a data acquisition system
comprised of a
plurality of sensors imbedded within the electrical system and configured to
provide real-time
data feedback to the neocortical model 2202. The associative memory layer
observes the
interactions between the neocortical model 2202 and the real-time sensory
inputs from the
sensory layer 2204 to learn and understand complex relationships inherent
within the monitored
system. As the neocortical model 2202 matures over time, the neocortical
catalyst process
becomes increasingly accurate in making predictions about the operational
aspects of the
monitored system. This combination of the neocortical model 2202, sensory
layer 2204 and
associative memory model layer 2206 works together to learn, refine, suggest
and predict
similarly to how the human neocortex operates.
[00216] Figure 23 is an example process for real-time three-dimensional (3D)
visualization of
the health, reliability, and performance of an electrical system, in
accordance with one
embodiment. The complexity of electrical power systems coupled with the many
operational
conditions the systems can be asked to operate under pose significant
challenges to owners,
operators and managers of critical electrical networks. It is vital for owners
and operators alike
to have a precise and well understood perspective of the overall health and
performance of the
electrical network. Communication of such status through three-dimensional
(3D) visualization
views (such as 3D Plant Lifecycle Models), in addition to the traditional two-
dimensional (2D)
views, greatly enhances the ability of operators, owners and executives to
understand the health
and predicted performance of their power networks, elegantly and efficiently.
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[00217] In step 2302, the power analytics server can determine which operating
mode(s) that
the electrical system is being simulated under. That is, the virtual system
model of the electrical
system can be modified by the user to simulate the system operating under
multiple different
operating scenarios (conditions) and system contingencies. The power analytics
server is
configured to utilize the operating mode settings while simulating the
operation of the electrical
system to make predictions about the system's health, performance,
availability and reliability.
In one embodiment, the operating mode(s) relate to the multiple contingency
events that the
electrical system may be subjected to during regular operations. The
contingency events can be
chosen out of a diverse list of contingency events to be evaluated. That is,
the operational health,
performance, availability and reliability of the electrical power system can
be assessed under a
number of different contingency event scenarios including but not limited to a
singular event
contingency or multiple event contingencies (that are simultaneous or
sequenced in time). That
is, in one embodiment, the contingency events assessed are manually chosen by
a user in
accordance with the his/her requirements. In another embodiment, the
contingency events
assessed are automatically chosen in accordance with control logic that is
dynamically adaptive
to past observations of the electrical power system. That is the control logic
"learns" which
contingency events to simulate based on past observations of the electrical
power system
operating under various conditions.
[00218] Some examples of contingency events include but are not limited to:
Application/removal of three-phase fault
Application/removal of phase-to-ground fault
Application/removal of phase-phase-ground fault
Application/removal of phase-phase fault

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Branch Addition
Branch Tripping
Starting Induction Motor
Stopping Induction Motor
Shunt Tripping
Shunt Addition (Capacitor and/or Induction)
Generator Tripping
SVC Tripping
Impact Loading (Load Changing Mechanical Torque on Induction Machine. With
this option it is actually possible to turn an induction motor to an induction
generator)
Loss of Utility Power Supply/Generators/UPS/Distribution Lines/System
Infrastructure
Load Shedding
[00219] In another embodiment, the operating mode(s) can relate to the
multiple load levels
that the electrical system operates under. That is, the virtual system model
of the electrical
system can be simulated under various power system load configurations or
capacity conditions.
In one embodiment, the system is simulated as operating under a base load
power configuration.
That is, the electrical system can be simulated as operating continuously at
its maximum rated
power output. Under this configuration, power systems only shut down to
perform maintenance
or if something breaks. Accordingly, the ability to test under such conditions
cannot be achieved
in conventional systems. In another embodiment, the electrical system can be
simulated as
operating under a load following power configuration. That is, the electrical
system is simulated
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as operating in a fluctuating manner by adjusting its power output as demand
for electricity
fluctuates throughout the day. In still another embodiment, the electrical
system is simulated as
operating at various different power load capacity levels. For example, the
electrical system may
be simulated as operating at 10%, 25%, 50%, 75%, or 100% of its rated power
generation
capacity.
[00220] Continuing with Figure 23, the operating mode(s) can relate to
different system and
load point reliability indices assigned to the components that make up the
electrical system. In
one embodiment, for example, changes can be made to the reliability indices of
individual
components. In another embodiment, changes can be made to all the components
that make up
the system.
[00221] In still yet another embodiment, the operating mode(s) relate to the
different remedial
measures or actions that are implemented on the electrical system to respond
to the various
contingency situations that the system may be subjected to. For example,
remedial measures can
relate to: the various types of uninterruptible power supply (UPS) systems
operating on the
electrical system, various protective devices that are integrated to the
system, various operating
limits and conditions that are placed on the system, etc.
[00222] In step 2304, the power analytics server is configured to utilize the
operating mode
settings, determined in step 2302, and the updated virtual system model of the
electrical system
to simulate and predict aspects relating to the real-time health, performance,
reliability and
availability of the electrical system. For example, the power analytics server
can simulate and
predict aspects relating to:
= Power System Health and Performance
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- Variations or deviations of electrical system performance from the power
system design parameters. That is, the ability of the electrical system to
resist system output variations or deviations from defined tolerance limits
of the electrical system
- Incorporation of performance and behavioral specifications for all the
equipment and components that comprise the electrical system into a real-
time management environment
= System Reliability and Availability
- As a function of different system, process and load point reliability
indices
- Implementation of different technological solutions to achieve reliability
centered maintenance targets and goals
= Power System Capacity levels
- As-designed total power capacity of the power system.
- How much of the total power capacity remains or is available (ability of
the electrical system to maintain availability of its total power capacity)
- Present utilized power capacity.
= Power System Strength and Resilience
- Dynamic stability predictions across all contingency events
- Determination of protection system stress and withstand status
[00223] Additionally, the predictions may also relate to the real-time ability
of the electrical
system to: 1. sustain power demand and maintain sufficient active and reactive
power reserve to
cope with ongoing changes in demand and system disturbances due to
contingencies, 2. operate
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safely with minimum operating cost while maintaining an adequate level of
reliability, and 3.
provide an acceptably high level of power quality (maintaining voltage and
frequency within
tolerable limits) when operating under contingency conditions.
[00224] Continuing with Figure 23, in step 2306, the power analytics server is
configured to
output the predictions in the form of a print out or display of text,
graphics, charts, labels, and
model views that readily communicates the health and predicted performance of
the electrical
system in an elegant and efficient fashion. The information can be reported
via a graphical user
interface ("thick" or "thin" client) that illustrates the various components
of the system in
graphical format. In such embodiments, the report can simply comprise a
graphical indication of
the capacity of a subsystem or system, including the whole facility. The
results can also be
forwarded to associative memory engine 2308, where they can be stored and made
available for
predictions, pattern/sequence recognition and ability to imagine, e.g., via
memory agents or other
techniques, some of which are describe below, in step 2308.
[00225] In one embodiment, the model views are 3D (i.e., 3D Plant Lifecycle
Model) model
views of the various components, equipment and sub-systems that comprise the
electrical
system. Examples of some 3D model views 2502 are depicted in a client
interface screenshot in
Figure 25. The 3D model views 2502, can be generated by an integrated 3D
visualization engine
that is an integrated part of the power analytics server. In another
embodiment, the model views
are 2D model views of the various components, equipment and sub-systems making
up the
electrical system. An example of a 2D model view 2504 is also depicted in
Figure 25.
[00226] As alluded to above, in step 2308, the results of the simulation and
predictive analysis
can be stored by an associative memory engine to support incremental learning
about the power
capacity characteristics of the system. That is, the results of the
predictions, analysis, and real-
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time data may be fed, as needed, into an machine learning engine for pattern
and sequence
recognition in order to learn about the health, performance, reliability and
availability of the
electrical system. Additionally, concurrent inputs of various electrical,
environmental,
mechanical, and other sensory data can be used to learn about and determine
normality and
abnormality of business and plant operations to provide a means of
understanding failure modes
and generate recommendations.
[00227] Figure 24 is a diagram illustrating how the 3D Visualization Engine
works in
conjunction with the other elements of the analytics system to provide 3D
visualization of the
health, reliability, and performance of an electrical system, in accordance
with one embodiment.
As depicted herein, the 3D Visualization Engine 2402 is integrated within a
power analytics
server 116 that is communicatively connected via a network connection 114 with
a data
acquisition hub 112, a client terminal 128 and a virtual system model database
526. The virtual
system model database 526 is configured to store the virtual system model of
the electrical
system. The virtual system model is constantly updated with real-time data
from the data
acquisition hub 112 to effectively account for the natural aging effects of
the hardware that
comprise the total electrical power system, thus, mirroring the real operating
conditions of the
system. This provides a desirable approach to predicting the operational
aspects of the
monitored power system and for communicating the predicted aspects through 3D
visualization
models of the facility.
[00228] The 3D visualization engine 2402 is interfaced with the predictive
elements of the
power analytics server and communicatively connected to the data acquisition
hub 112 and the
client 128. The data acquisition hub 112 is communicatively connected via data
connections 110
to a plurality of sensors that are embedded throughout the electrical system
102. The data

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acquisition hub 112 may be a standalone unit or integrated within the
analytics server 116 and
can be embodied as a piece of hardware, software, or some combination thereof.
In one
embodiment, the data connections 110 are "hard wired" physical data
connections (e.g., serial,
network, etc.). For example, a serial or parallel cable connection between the
sensors and the
hub 112. In another embodiment, the data connections 110 are wireless data
connections. For
example, a radio frequency (RF), BLUETOOTHTM, infrared or equivalent
connection between
the sensor and the hub 112. Real-time system data readings can be fed
continuously to the data
acquisition hub 112 from the various sensors that are embedded within the
electrical system 102.
[00229] Continuing with Figure 24, the client 128 is typically a conventional
thin-client or
thick-client computing device that may utilize a variety of network interfaces
(e.g., web browser,
CITRIXTM, WINDOWS TERMINAL SERVICESTM, telnet, or other equivalent thin-client
terminal applications, etc.) to access, configure, and modify the sensors
(e.g., configuration files,
etc.), analytics engine (e.g., configuration files, analytics logic, etc.),
calibration parameters (e.g.,
configuration files, calibration parameters, etc.), virtual system modeling
engine (e.g.,
configuration files, simulation parameters, choice of contingency event to
simulate, etc.), 3D
visualization engine (e.g., configuration files, 3D visualization parameters,
etc.) and virtual
system model of the system under management (e.g., virtual system model
operating parameters
and configuration files). Correspondingly, in one embodiment, the data from
the various
components of the electrical system and the real-time predictions (forecasts)
about the health,
performance, reliability and availability of the electrical system can be
displayed on a client 128
display panel for viewing by a system administrator or equivalent. In another
embodiment, the
data may be summarized in a hard copy report 2404.
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[00230] Figure 26 is a diagram illustrating how the Schematic User Interface
Creator Engine
works in conjunction with the other elements of the analytics system to
automatically generate a
schematic user interface for visualizing the health, reliability, and
performance of an electrical
system, in accordance with one embodiment. Conventional electrical power
system monitoring
technologies typically rely on custom graphical design and user-interface
development efforts in
order to create a system schematic user interface (displayable on a client
terminal) that can be
linked to real-time sensory data output by the various components that
comprise an electrical
power system. In general, custom development efforts tend to be cumbersome and
often require
an extraordinarily amount of time to implement.
[00231] Given the complexity of modem electrical power systems and the
significant
challenges they pose to owners, operators and managers of critical (regional,
national and
intemational) electrical networks; there is a need for automated software
tools that can allow the
rapid deployment of schematic based user interfaces to provide precise and
well understood
perspective of the overall health and performance of the various components
that comprise an
electrical power system. Ideally, the tools can be configured to automatically
read electrical
system configuration data from a database containing a virtual system
representation (i.e., virtual
system model) of the electrical system, generate a schematic user interface
view of the electrical
system, and intelligently link the various components included in the user
interface to the
predicted, monitored and/or derived output/values of those various components.
[00232] As depicted herein, the Schematic User Interface Creator Engine 2602
can be
integrated within a power analytics server 116 that can be communicatively
connected via a
network connection 114 with a data acquisition hub 112, a client terminal 128
and a virtual
system model database 526. The virtual system model database 526 can be
configured to store
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the virtual system model of the electrical system. The virtual system model
can be constantly
updated with real-time data from the data acquisition hub 112 to effectively
account for the
natural aging effects of the hardware that comprise the total electrical power
system, thus,
mirroring the real operating conditions of the system. The Schematic User
Interface Creator
Engine 2602 can be configured to automatically create a schematic user
interface that is
representative of the electrical system and link that interface to the sensors
monitoring the
components (i.e., electrical equipment) that comprise the electrical system to
enable real-time
monitoring of the derived output/values from those components. The user
interface can include
a visual representation of each piece of electrical equipment
(associated/tagged with a unique
identifier) that comprises the electrical system. In one embodiment, the
schematic user interface
is based on a one-line diagram construct. In another embodiment, the schematic
user interface is
based on a technical system schematic diagram construct. However, it should be
appreciated
that the user interface can be based on any engineering diagram construct as
long as the resulting
interface can be displayed on a client terminal 128 to allow viewing by an
operator/administrator.
[00233] In addition to being communicatively connected to the data acquisition
hub 112 and
the client 128, the Schematic User Interface Creator Engine 2602 can also be
interfaced with the
predictive elements of the power analytics server. The predictive elements of
the power
analytics server may relate to the real-time health, performance, reliability
and availability of the
electrical system. For example, the predictions can be indicative of the real-
time ability of the
electrical system to: 1. sustain power demand and maintain sufficient active
and reactive power
reserve to cope with ongoing changes in demand and system disturbances due to
contingencies,
2. operate safely with minimum operating cost while maintaining an adequate
level of reliability,
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and 3. provide an acceptably high level of power quality (maintaining voltage
and frequency
within tolerable limits) when operating under contingency conditions.
[00234] The data acquisition hub 112 can be communicatively connected via data
connections
110 to a plurality of sensors that can be embedded throughout the electrical
system 102. The
data acquisition hub 112 can be a standalone unit or integrated within the
analytics server 116
and can be embodied as a piece of hardware, software, or some combination
thereof. In one
embodiment, the data connections 110 are "hard wired" physical data
connections (e.g., serial,
network, etc.). For example, a serial or parallel cable connection between the
sensors and the
hub 112. In another embodiment, the data connections 110 are wireless data
connections. For
example, a radio frequency (RF), BLUETOOTHTM, infrared or equivalent
connection between
the sensor and the hub 112. Real-time system data readings can be fed
continuously to the data
acquisition hub 112 from the various sensors that are embedded within the
electrical system 102.
[00235] Continuing with Figure 26, the client 128 can be a conventional thin-
client or thick-
client computing device that can utilize a variety of network interfaces
(e.g., web browser,
CITRIXTM, WINDOWS TERMINAL SERVICESTM, telnet, or other equivalent thin-client
terminal applications, etc.) to access, configure, and modify the sensors
(e.g., configuration files,
etc.), power analytics engine (e.g., configuration files, analytics logic,
etc.), calibration
parameters (e.g., configuration files, calibration parameters, etc.), virtual
system modeling
engine (e.g., configuration files, simulation parameters, choice of
contingency event to simulate,
etc.), Schematic User Interface Creator Engine 2602 (e.g., configuration
files, schematic
interface algorithms, etc.) and virtual system model of the electrical system
under management
(e.g., virtual system model operating parameters and configuration files).
Correspondingly, in
one embodiment, the real-time data from the various monitored components of
the electrical
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system and the real-time predictions (forecasts) about the health,
performance, reliability and
availability of the electrical system can be simultaneously visualized on the
schematic user
interface that is displayed on a client terminal 128 for viewing by a system
administrator or
equivalent. This schematic user interface can provide a desirable approach to
communicating
the monitored and predicted operational aspects of an electrical system to an
operator/administrator. In one embodiment, the schematic user interface is
rendered in a 2-
dimensional (2D) graphical image format. In another embodiment, the schematic
user interface
is rendered in a 3-dimensional (3D) graphical image format.
[00236] Figure 27 is an example process for automatically generating a
schematic user
interface for visualizing the health, reliability, and performance of an
electrical system, in
accordance with one embodiment. In one embodiment, the operational steps that
comprise the
process are implemented through a schematic user interface creator engine
(application/software
tool) that runs on the power analytics server. In another embodiment, the
operational steps that
comprise the process are implemented through a schematic interface creator
engine that runs on
a separate (network application) server that is communicatively connected to
the power analytics
server. In still another embodiment, the operational steps that comprise the
process are
implemented through a plurality of discrete applications that are distributed
amongst one or more
(network application) servers that are communicatively connected with the
power analytics
server. It should be understood, however, that the application(s) can be
distributed in any
configuration as long as the application(s) can communicatively access the
power analytics
server to implement the process.
[00237] The process begins with step 2702, where system configuration data can
be extracted
from a virtual system model of the electrical system. The virtual system model
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one or more virtual system model database(s) that are communicatively
connected to the power
analytics server. The configuration data can be stored in the memory of the
power analytics
server (or a network application server) and can include the unique
identifiers (i.e., node IDs) of
each of the components (i.e., piece of electrical equipment) that comprise the
virtual system
model, connectivity information (i.e., the electrical connectivity between the
various virtual
system model components and/or the data connectivity with the sensors
monitoring those
components) and/or equipment specific information such as node or branch
specific equipment
type (e.g., generator, circuit breaker, transformer, motor, fuse, static load,
etc.).
[00238] In step 2704, a logical construct of the virtual system model can be
constructed from
the system configuration data. In one embodiment, the logical construct can be
created in an
Extensible Markup Language (XML) format. In another embodiment, the logical
construct can
be created in an Extensible HyperText Markup Language (XHTML) format. It
should be
appreciated that the logical construct can be created using any mark-up
language as long as it can
be utilized to convey system configuration information about the components
(i.e., electrical
equipment) that make up the virtual system model.
[00239] In step 2706, one or more graphical objects can be generated to
represent one or more
pieces of electrical equipment included in the logical construct. This can be
accomplished
through the schematic user interface creator engine or equivalent
application(s) parsing the
system configuration data stored in the logical construct and generating
appropriate symbol
block(s) and/or graphical object(s) for each piece of electrical equipment
that comprise the
electrical system. The symbol block(s) or graphical object(s) that are
generated can then be
individually organized as buses, nodes and/or branches.
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[00240] In step 2708, the one or more graphical objects can be organized to
generate a
schematic user interface layout of the electrical system. This can be
accomplished using a self-
executing algorithm that can be either an integrated component of the
schematic user interface
creator engine or a separate discrete application that is configured to work
in conjunction with
the schematic user interface creator engine. In one embodiment, the self-
executing algorithm is
a.NET based application. In another embodiment, the self-executing algorithm
is an ACTIVE X
based application. In still another embodiment, the self-executing algorithm
is a JAVA based
application. It should be understood, however, that the self-executing
algorithm can be created
using any type of programming language as long as the resulting algorithm can
function either as
a component of the schematic user interface creator engine or in conjunction
with the same.
[00241] In one embodiment, the self-executing algorithm is in a force directed
layout format.
In another embodiment, the self-executing algorithm is in a tree layout
format. In still another
embodiment, the self-executing algorithm is in a layered diagraph layout
format. It should be
appreciated that the self-executing algorithm can follow any format as long as
each of the one
ore more graphical objects/symbol blocks in the resulting schematic user
interface layout can
later be linked to a corresponding piece of electrical equipment that comprise
the electrical
system.
[00242] After the schematic user interface layout of the electrical system is
generated, it can
be further optimized using the schematic interface creator engine (or
equivalent application) to
scan the schematic user interface layout and re-align the graphical object(s)
based on one or
more user selected optimization criteria. The optimization criteria can direct
the visual
representation(s) of the schematic user interface using various visualization
algorithms that can
manage the look of the graphical elements of the interface. That is, the
optimization criteria can
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be a set of positioning and general layout rules used to draw the network or
diagram in the most
optimal way (which can be different each time depending on the data set and
complexity of the
network). Examples of the optimization criteria (or rules) that can be applied
to a dataset for
layout purposes include, but are not limited to:
= Circular layout
= Hierarchical layout
= Orthogonal layout
= Symmetric layout
= Tree layout
= Force Directed
[00243] In step 2710, each of the one or more graphical objects in the
schematic user interface
layout can be communicatively linked to sensors configured to monitor the real-
time operational
status of the one or more pieces of electrical equipment represented by the
one or more graphical
objects. This can be accomplished by intelligently linking the unique
identifiers (e.g., equipment
IDs) associated with each of the graphical objects/symbol blocks to their
corresponding database
files and creating a tag or communication channel with the same unique
identifier to allow the
files to be populated with data from the electrical equipment associated with
each unique
identifier. For example, a Graphical Object A with a unique identifier of
"001" can be linked to
the database file "A" which is associated with the "001" identifier. A
communication channel
"001" can then be opened to allow data, acquired from a piece of electrical
equipment associated
with the "001" identifier, to populate database file "A."
[00244] The communication linkage between the graphical objects in the
schematic user
interface layout and the database(s) that store real-time data acquired from
the operation of the
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electrical equipment allow the schematic user interface to dynamically
represent fluctuations in
the real-time health, performance, reliability and availability of the
electrical system. For
example, the nodes, buses and branches in the schematic user interface layout
can be configured
so that they change colors and/or become animated in response to the monitored
real-time data of
and/or predicted values for the electrical system during operation.
[00245] The embodiments described herein, can be practiced with other computer
system
configurations including hand-held devices, microprocessor systems,
microprocessor-based or
programmable consumer electronics, minicomputers, mainframe computers and the
like. The
embodiments can also be practiced in distributing computing environments where
tasks are
performed by remote processing devices that are linked through a network.
[00246] It should also be understood that the embodiments described herein can
employ
various computer-implemented operations involving data stored in computer
systems. These
operations are those requiring physical manipulation of physical quantities.
Usually, though not
necessarily, these quantities take the form of electrical or magnetic signals
capable of being
stored, transferred, combined, compared, and otherwise manipulated. Further,
the manipulations
performed are often referred to in terms, such as producing, identifying,
determining, or
comparing.
[00247] Any of the operations that form part of the embodiments described
herein are useful
machine operations. The invention also relates to a device or an apparatus for
performing these
operations. The systems and methods described herein can be specially
constructed for the
required purposes, such as the carrier network discussed above, or it may be a
general purpose
computer selectively activated or configured by a computer program stored in
the computer. In
particular, various general purpose machines may be used with computer
programs written in
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accordance with the teachings herein, or it may be more convenient to
construct a more
specialized apparatus to perform the required operations.
[00248] Certain embodiments can also be embodied as computer readable code on
a computer
readable medium. The computer readable medium is any data storage device that
can store data,
which can thereafter be read by a computer system. Examples of the computer
readable medium
include hard drives, network attached storage (NAS), read-only memory, random-
access
memory, CD-ROMs, CD-Rs, CD-RWs, magnetic tapes, and other optical and non-
optical data
storage devices. The computer readable medium can also be distributed over a
network coupled
computer systems so that the computer readable code is stored and executed in
a distributed
fashion.
[00249] Although a few embodiments of the present invention have been
described in detail
herein, it should be understood, by those of ordinary skill, that the present
invention may be
embodied in many other specific forms without departing from the spirit or
scope of the
invention. Therefore, the present examples and embodiments are to be
considered as illustrative
and not restrictive, and the invention is not to be limited to the details
provided therein, but may
be modified and practiced within the scope of the appended claims.

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