Note: Descriptions are shown in the official language in which they were submitted.
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SYSTEMS AND METHODS FOR BLACKOUT PROTECTION
TECHNICAL FIELD
[0001] This disclosure relates to systems and methods for controlling
and protecting
an electric power delivery system and, more particularly, to systems and
methods for
wide-area under-frequency blackout protection in an electric power delivery
system.
BRIEF DESCRIPTION OF THE DRAWINGS
[0002] Non-limiting and non-exhaustive embodiments of the disclosure are
described, including various embodiments of the disclosure, with reference to
the
figures, in which:
[0003] Figure 1 illustrates a simplified diagram of one embodiment of an
electric
power delivery system that includes intelligent electronic devices.
[0004] Figure 2 illustrates a block diagram of one embodiment of an
intelligent
electronic device for protection and control of an electric power delivery
system
[0005] Figure 3 illustrates another block diagram of one embodiment of
an
intelligent electronic device for protection and control of an electric power
delivery
system.
[0006] Figure 4 illustrates one embodiment of a method for protection
and control of
an electric power delivery system.
[0007] Figure 5 illustrates another embodiment of a method for
protection and
control of an electric power delivery system that utilizes rotating inertia
information from
the system.
DETAILED DESCRIPTION
[0008] The embodiments of the disclosure will be best understood by
reference to
the drawings. It will be readily understood that the components of the
disclosed
embodiments, as generally described and illustrated in the figures herein,
could be
arranged and designed in a wide variety of different configurations. Thus, the
following
detailed description of the embodiments of the systems and methods of the
disclosure
is not intended to limit the scope of the disclosure, as claimed, but is
merely
representative of possible embodiments of the disclosure. In addition, the
steps of a
method do not necessarily need to be executed in any specific order, or even
sequentially, nor do the steps need be executed only once, unless otherwise
specified.
[0009] In some cases, well-known features, structures, or operations are
not shown
or described in detail. Furthermore, the described features, structures, or
operations
may be combined in any suitable manner in one or more embodiments. It will
also be
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readily understood that the components of the embodiments, as generally
described
and illustrated in the figures herein, could be arranged and designed in a
wide variety of
different configurations. For example, throughout this specification, any
reference to
"one embodiment," "an embodiment," or "the embodiment" means that a particular
feature, structure, or characteristic described in connection with that
embodiment is
included in at least one embodiment. Thus, the quoted phrases, or variations
thereof,
as recited throughout this specification are not necessarily all referring to
the same
embodiment.
[0010] Several aspects of the embodiments described are illustrated as
software
modules or components. As used herein, a software module or component may
include any type of computer instruction or computer executable code located
within a
memory device that is operable in conjunction with appropriate hardware to
implement
the programmed instructions. A software module or component may, for instance,
comprise one or more physical or logical blocks of computer instructions,
which may be
organized as a routine, program, object, component, data structure, etc., that
performs
one or more tasks or implements particular abstract data types.
[0011] In certain embodiments, a particular software module or component
may
comprise disparate instructions stored in different locations of a memory
device, which
together implement the described functionality of the module. Indeed, a module
or
component may comprise a single instruction or many instructions, and may be
distributed over several different code segments, among different programs,
and across
several memory devices. Some embodiments may be practiced in a distributed
computing environment where tasks are performed by a remote processing device
linked through a communications network. In a distributed computing
environment,
software modules or components may be located in local and/or remote memory
storage devices. In addition, data being tied or rendered together in a
database record
may be resident in the same memory device, or across several memory devices,
and
may be linked together in fields of a record in a database across a network.
[0012] Embodiments may be provided as a computer program product
including a
non-transitory machine-readable medium having stored thereon instructions that
may
be used to program a computer or other electronic device to perform processes
described herein. The non-transitory machine-readable medium may include, but
is not
limited to, hard drives, floppy diskettes, optical disks, CD-ROMs, DVD-ROMs,
ROMs,
RAMs, EPROMs, EEPROMs, magnetic or optical cards, solid-state memory devices,
or
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other types of media/machine-readable medium suitable for storing electronic
instructions. In some embodiments, the computer or other electronic device may
include a processing device such as a microprocessor, microcontroller, logic
circuitry,
or the like. The processing device may further include one or more special
purpose
processing devices such as an application specific interface circuit (ASIC),
PAL, PLA,
PLD, field programmable gate array (FPGA), or any other customizable or
programmable device.
[0013] Electrical power generation and delivery systems are designed to
generate,
transmit, and distribute electrical energy to loads. Electrical power
generation and
delivery systems may include equipment, such as electrical generators,
electrical
motors, power transformers, power transmission and distribution lines, circuit
breakers,
switches, buses, transmission lines, voltage regulators, capacitor banks, and
the like.
Such equipment may be monitored, controlled, automated, and/or protected using
intelligent electronic devices (IEDs) that receive electric power system
information from
the equipment, make decisions based on the information, and provide
monitoring,
control, protection, and/or automation outputs to the equipment.
[0014] In some embodiments, an IED may include, for example, remote
terminal
units, differential relays, distance relays, directional relays, feeder
relays, overcurrent
relays, voltage regulator controls, voltage relays, breaker failure relays,
generator
relays, motor relays, automation controllers, bay controllers, meters,
recloser controls,
communication processors, computing platforms, programmable logic controllers
(PLCs), programmable automation controllers, input and output modules,
governors,
exciters, statcom controllers, SVC controllers, OLTC controllers, and the
like. Further,
in some embodiments, IEDs may be communicatively connected via a network that
includes, for example, multiplexers, routers, hubs, gateways, firewalls,
and/or switches
to facilitate communications on the networks, each of which may also function
as an
IED. Networking and communication devices may also be integrated into an IED
and/or be in communication with an IED. As used herein, an IED may include a
single
discrete IED or a system of multiple IEDs operating together.
[0015] Electrical power generation and delivery system equipment may be
monitored and protected from various malfunctions and/or conditions using one
or more
IEDs. For example, an IED may be configured to protect the electrical power
system
equipment from abnormal conditions, such as when the power generation
capabilities
of the electrical power system cannot adequately supply system loads. Under
this
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unbalanced system condition, power loss or blackouts may occur that negatively
affect
both providers of electric power and their customers. Consistent with
embodiments
disclosed herein, an IED may utilize techniques to minimize blackout
conditions on a
larger portion of the electric power delivery system such as under-frequency
(UF) load
shedding techniques and over-frequency (OF) generation shedding or run-back
techniques.
[0016] Power imbalances in an electrical power delivery system may be
associated
with a fall (or rise) in the frequency of the electrical power system
fundamental voltage.
Consistent with embodiments disclosed herein, when a threshold UF (or OF)
level is
crossed, loads may be disconnected (e.g., shed) from the electrical power
system or
generators or other active power producing components on the electric power
system
may be shed or run-back to rebalance the system. By shedding selective loads,
shedding generators, or running back generators or other active power
producing
power system components and rebalancing the system, the negative effects of
unbalanced system conditions may be mitigated.
[0017] Figure 1 illustrates a simplified diagram of an electric power
generation and
delivery system 100 that includes IEDs 102-108 consistent with embodiments
disclosed
herein. Although illustrated as a one-line diagram for purposes of simplicity,
electrical
power generation and delivery system 100 may also be configured as a three
phase
power system. Moreover, embodiments disclosed herein may be utilized by any
electric power generation and delivery system and is therefore not limited to
the specific
system 100 illustrated in Figure 1. Accordingly, embodiments may be
integrated, for
example, in industrial plant power generation and delivery systems, deep-water
vessel
power generation and delivery systems, ship power generation and delivery
systems,
distributed generation power generation and delivery systems, and utility
electric power
generation and delivery systems.
[0018] The electric power generation and delivery system 100 may include
generation, transmission, distribution, and power consumption equipment. For
example, the system 100 may include one or more generators 110 -116 that, in
some
embodiments, may be operated by a utility provider for generation of
electrical power
for the system 100. Generators 110 and 112 may be coupled to a first
transmission
bus 118 via step up transformers 120 and 122, which are respectively
configured to
step up the voltages provided to first transmission bus 118. A transmission
line 124
may be coupled between the first transmission bus 118 and a second
transmission bus
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126. Another generator 114 may be coupled to the second transmission bus 126
via
step up transformer 128 which is configured to step up the voltage provided to
the
second transmission bus 126. Generators, as used herein may refer to any
equipment
capable of supplying electric power on an electric power delivery system, and
may
include, for example, rotating synchronous or induction machines or other
electronic
power producing equipment with an inverter capable of supplying electric power
(photovoltaic, wind power, battery, and the like).
[0019] A step down transformer 130 may be coupled between the second
transmission bus 126 and a distribution bus 132 configured to step down the
voltage
provided by the second transmission bus 126 at transmission levels to lower
distribution
levels at the distribution bus 132. One or more feeders 134, 136 may draw
power from
the distribution bus 132. The feeders 134, 136 may distribute electric power
to one or
more loads 138, 140. In some embodiments, the electric power delivered to the
loads
138, 140 may be further stepped down from distribution levels to load levels
via step
down transformers 142 and 144, respectively.
[0020] Feeder 134 may feed electric power from the distribution bus 132
to a
distributed site 146 (e.g., a refinery, smelter, paper production mill, or the
like). Feeder
134 may be coupled to a distribution site bus 148. The distribution site 146
may also
include a distributed generator 116 configured to provide power to the
distribution site
bus 148 at an appropriate level via transformer 150. In some embodiments, the
distributed generator 116 may comprise a turbine configured to produce
electric power
from the burning of waste, the use of waste heat, or the like. The
distribution site 146
may further include one or more loads 138. In some embodiments, the power
provided
to the loads 138 from the distribution site bus 148 may be stepped up or
stepped down
to an appropriate level via transformer 142. In certain embodiments, the
distribution
site 146 may be capable of providing sufficient power to loads 138
independently by the
distributed generator 116, may utilize power from generators 110-114, or may
utilize
both the distributed generator 116 and one or more of generators 110-114 to
provide
electric power to the loads.
[0021] IEDs 102-108 may be configured to control, monitor, protect, and/or
automate the electric power system 100. As used herein, an IED may refer to
any
microprocessor-based device that monitors, controls, automates, and/or
protects
monitored equipment within an electric power system. An IED may include, for
example, remote terminal units, differential relays, distance relays,
directional relays,
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feeder relays, overcurrent relays, voltage regulator controls, voltage relays,
breaker
failure relays, generator relays, motor relays, automation controllers, bay
controllers,
meters, recloser controls, communications processors, computing platforms,
programmable logic controllers (PLCs), programmable automation controllers,
input
and output modules, motor drives, and the like. In some embodiments, IEDs 102-
108
may gather status information from one or more pieces of monitored equipment.
Further, IEDs 102-108 may receive information concerning monitored equipment
using
sensors, transducers, actuators, and the like. Although Figure 1 illustrates
separate
IEDs monitoring a signal (e.g., IED 104) and controlling a breaker (e.g., IED
108), these
capabilities may be combined into a single IED.
[0022] Figure 1 illustrates various IEDs 102-108 performing various
functions for
illustrative purposes and does not imply any specific arrangements or
functions
required of any particular IED. In some embodiments, IEDs 102-108 may be
configured to monitor and communicate information, such as voltages, currents,
equipment status, temperature, frequency, pressure, density, infrared
absorption, radio-
frequency information, partial pressures, viscosity, speed, rotational
velocity, mass,
switch status, valve status, valve position, exciter status, magnetic flux
conditions,
circuit breaker status, tap status, meter readings, and the like. Further,
IEDs 102-108
may be configured to communicate calculations, such as phasors (which may or
may
not be synchronized as synchrophasors), events, fault distances,
differentials,
impedances, reactances, frequency, and the like. IEDs 102-108 may also
communicate settings information, IED identification information,
communications
information, status information, alarm information, and the like. Information
of the types
listed above, or more generally, information about the status of monitored
equipment,
may be generally referred to herein as monitored system data.
[0023] In certain embodiments, IEDs 102-108 may issue control
instructions to the
monitored equipment in order to control various aspects relating to the
monitored
equipment. For example, an IED (e.g., IED 106) may be in communication with a
circuit breaker (e.g., breaker 152), and may be capable of sending an
instruction to
open and/or close the circuit breaker, thus connecting or disconnecting a
portion of a
power system. In another example, an IED may be in communication with a
recloser
and capable of controlling reclosing operations. In another example, an IED
may be in
communication with a voltage regulator and capable of instructing the voltage
regulator
to tap up and/or down. In another example, an IED may be in communication with
a
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synchronous generator exciter to raise or lower field current, voltage, and/or
flux conditions. In
another example, an IED may be in communication with a generator speed
governor or other
electronic devices to modify the position of fuel valves, air louvers,
condensing or extraction
valves, steam bypass valves, compressor speeds, hydraulic pilot valves..
Information of the
types listed above, or more generally, information or instructions directing
an IED or other
device to perform a certain action, may be generally referred to as control
instructions.
[0024] The distribution site 146 may include an IED 108 for monitoring,
controlling, and
protecting the equipment of the distributed site 146 (e.g., generator 116,
transformer 142, etc.).
IED 108 may receive monitored system data, including current signals via
current transformer
(CT) 154 and voltage signals via potential transformer (PT 156) from one or
more locations
(e.g., line 158) in the distribution site 146. The IED 108 may further be in
communication with a
breaker 160 coupled between the feeder 134 and the distribution site bus 148.
In certain
embodiments, the IED 108 may be configurable to cause the breaker 160 to
disconnect the
distribution site bus 148 from the distribution bus 132, based on monitored
system data received
via CT 154 and PT 156.
[0025] Feeder 136 may be communicatively coupled with an IED 106 configured to
control a
breaker 152 between the loads 140 and the distribution bus 132 based on
monitored system
data. In some embodiments, the power provided to the loads 140 from the
distribution bus 132
may be stepped up or stepped down to an appropriate level via transformer 144.
Like the IED
108 of the distribution site 146, monitored system data may be obtained by IED
106 using CTs
and/or PTs (not shown).
[0026] Other IEDs (e.g., IED 104) may be configured to monitor, control,
and/or protect the
electric power generation and delivery system 100. For example IED 104 may
provide
transformer and generator protection to the step-up transformer 120 and
generator 110. In
some embodiments, IEDs 104-108 may be in communication with another IED 102,
which may
be a central controller, synchrophasor vector processor, automation
controller, programmable
logic controller (PLC), real-time automation controller, Supervisory Control
and Data Acquisition
(SCADA) system, or the like. For example, in some embodiments, IED 102 may be
a
synchrophasor vector processor, as described in U.S. Patent Application
Publication No.
2009/0088990. In other embodiments, IED 102 may be a real-time automation
controller, such
as is described in U.S. Patent Application Publication No. 2009/0254655. IED
102 may also be
a PLC or any similar device capable of receiving communications from other
IEDs and
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processing the communications therefrom. In certain embodiments, IEDs 104-108
may
communicate with IED 102 directly or via a communications network (e.g.,
network 162).
[0027] The central IED 102 may communicate with other IEDs 104-108 to provide
control and
monitoring of the other IEDs 104-108 and the power generation and delivery
system 100 as a
whole. In some embodiments, IEDs 104-108 may be configured to generate
monitored system
data in the form of time-synchronized phasors (i.e., synchrophasors) of
monitored currents
and/or voltages. IEDs 104-108 may calculate synchrophasor data using a variety
of methods
including, for example, the methods described in U.S. Patent No. 6,662,124,
U.S. Patent No.
6,845,333, and U.S. Patent No. 7,480,580. In some embodiments, synchrophasor
measurements and communications may comply with the IEC C37.118 protocol. In
certain
embodiments, IEDs 102-108 may receive common time signals for synchronizing
collected data
(e.g., by applying time stamps for the like). Accordingly, IEDs 102-108 may
receive common
time signals from time references 164-170 respectively. In some embodiments,
the common
time signals may be provided using a GPS satellite (e.g., IRIG), a common
radio signal such as
VVWV or WVVVB, a network time signal such as IEEE 1588, or the like.
[0028] Consistent with embodiments disclosed herein, IEDs 102-108 may be
configured to
determine a power system operating frequency from monitored system data. The
operating
frequency of the power system may be determined using many methods including,
for example,
measuring time between zero-crossings of voltage and/or current, measuring
positive-sequence
phasor rotations, measuring time between period voltage and/or current peaks,
and/or the like.
IEDs 102-108 may be further configured to indicate when an operating frequency
falls below a
predetermined level. In certain embodiments, an IED may have a number of
different UF levels
and may indicate when an operating frequency falls below one or more of the UF
levels.
[0029] Figure 2 illustrates a block diagram of an IED 200 for protection and
control of an electric
power delivery system (e.g., system 100 illustrated in Figure 1). IED 200 may
communicate with
one or more IEDs 222 configured to provide indications of UF events (e.g.,
when system
operating frequencies fall below one or more UF levels) to IED 200. In some
embodiments,
IEDs 222 may receive monitored system data and,
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based on the monitored system data, provide indications of UF events such as
when
measured operating frequencies fall below one or more UF levels to the IED
200.
[0030] In some embodiments, IEDs 222 may be programmed with a
predetermined
UF set point (e.g., level) and be configured to provide time synchronized
indications of
UF events to the IED 200. In some embodiments, IEDs 222 may include one or
more
set points (e.g., levels) and be configured to provide time synchronized
indications of
UF events (e.g., when one or more of the set points are crossed) to the IED
200.
Further, in certain embodiments, IEDs 222 may indicate the UF set point (e.g.,
level)
breached, a time indication of the UF event, the power consumed by a load
associated
with the IED, and/or synchrophasor data which may include a load angle.
[0031] Based on the UF event indications received from IEDs 222, IED 200
may
determine whether specific loads are exhibiting UF events and whether such
loads can
be disconnected (e.g., shed) to limit and/or avoid UF events and systems
disturbances.
This functionality may be achieved using one or more functional modules 202-
220
included in the IED 200. For example, indications of UF events (e.g., breached
UF set
points, time indications of UF events, power consumed by loads associated with
the
IEDs 222, and/or synchrophasor data) detected by IEDs 222 may be provided to a
UF
level array calculation module included in the IED 200. In certain
embodiments, UF
level array calculation module 208 may be configured to order UF events and
their
associated information based on time stamps indicating when the UF events were
received by their associated IEDs 222 (e.g., UF events may be ordered based on
their
time of occurrence). Information from the UF level array calculation module
208,
including one or more ordered UF events may be provided to a coinciding UF
level
event calculation module 206. The UF level event calculation module 206 may be
configured to determine whether the one or more UF events ordered by the UF
level
array calculation module 208 are associated with a larger system UF event
based on
the time stamps associated with the one or more UF events. For example, the UF
level
event calculation module 206 may determine that a particular set of UF events
ordered
by the UF level array calculation module 208 are associated with a larger
system UF
event based on their occurrence within a particular time period (e. .g, a 10
ms period).
Based on the UF events occurring within a particular time period, the UF level
array
calculation module 208 may determine that the loads associated with the UF
events are
associated with a power sub-grid experiencing a UF condition and provide this
information to a load reduction calculation module 204.
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[0032] The IED 200 may also include a user adjustable parameter module
202 that,
in some embodiments, includes parameters defining an amount of load to be shed
for a
particular UF-level. In some embodiments, the amount of load to be shed may be
in
the form of a power/frequency value (e.g., MW/Hz). Information regarding the
amount
of load to be shed for a particular UF-level may be provided to the load
reduction
calculation module 204. The load reduction calculation module 204 may also
utilize
information regarding the UF events provided by the UF level array calculation
module
208 and UF level event calculation module 206, including time indications of
UF events
and indications of UF set points breached. Based on the information received
by the
load reduction calculation module 204, the load reduction calculation module
204 may
determine an amount of load to shed (e.g., the amount of load to shed from the
system
measured in MW) based on the defined user parameters and the other received UF
event information.
[0033] IEDs 222 may be further configured to monitor the power consumed
by the
loads they are associated with. Information regarding the power consumed by
loads
associated with the IEDs 222 may be monitored in terms of power (e.g., MW) or
other
coupled parameters such as current. For example, in reference to Figure 1, IED
106
may be capable of monitoring the power consumed by loads 140, and IED 108 may
be
capable of indicating the power presented consumed by the distributed site
146.
[0034] Consistent with some embodiments, information regarding the power
consumed by loads may be provided to a power array calculation module 212
included
in the IED 200. In some embodiments, the power array calculation module 212
may
calculate a power consumption value for each load (e.g., by using parameters
coupled
to power consumption such as current). Further, the power array calculation
module
212 may sort and/or order specific loads based on their associated power
consumption.
[0035] The user adjustable parameter module 202 may include a parameter
that
includes a priority indication for loads associated with the IEDs 222. For
example, the
priority indication may include a priority queue indicating the order in which
loads
should be shed from the system in the event of an UF condition. Accordingly,
the
priority indication may indicate certain loads (e.g., a hospital) that should
stay
connected to the system in the event of an UF condition.
[0036] The information generated by the power array calculation module
212 may
be provided to a load shedding selection module 210 included in the IED 200
along with
the priority indication provided by the user adjustable parameter module 202.
The load
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shedding selection module 210 may further receive information related to an
amount of
load to shed from the load reduction calculation module 204. Based on the
received
information (e.g., the amount of load to shed, the priority of the loads, and
the amount
of power consumed by the loads), the load shedding selection module 210 may
determine which loads should be shed to reduce the effects of the detected UF
event in
the system. That is, the load shedding selection module 210 may match the
amount of
power to shed with the power used by each of the loads, prioritized by the
priority
information, and determine which loads to shed.
[0037] In some embodiments, the IED 200 may include a load shedding
control
module 214 configured to receive an indication from the load shedding
selection
module 210 of which loads should be shed and provide a control signal to the
IEDs 222
associated with the loads that should be shed directing the IEDs 222 to shed
(e.g.,
disconnect) the relevant loads from the system. For example, in reference to
Figure 1,
the load shedding selection module 210 may determine that loads 140 should be
shed,
and the load shedding control module 214 may direct the IED 106 associated
with the
loads 140 to trip breaker 152, thereby disconnecting the loads from the system
100.
[0038] Information regarding power sub-grids within a greater grid
topology of an
electric power delivery system may also be used by the IED 200 to calculate
which
loads should be shed in view of UF conditions. In this context, IEDs 222 may
provide
load angle information (e.g., synchrophasor information) to a phase angle
array
calculation module 220 included in the IED 200. In an electric power
generation and
delivery system, equipment (e.g., loads) associated with a certain power sub-
grid of the
electric power generation and delivery system may experience similar frequency
decay
rates when the system experiences an UF condition. Similarly, equipment
associated
with different power sub-grids may experience different frequency decay rates
when the
system experiences an UF.
[0039] For example, in a system having two sub-grids within a greater
grid topology
of an electric power delivery system, the probability of both sub-grids
experiencing the
same frequency decay rate in a system UF condition is low. In certain
conditions, the
frequency in one sub-grid may increase while the frequency in the other sub-
grid may
decrease. Moreover, even in conditions where both sub-grids exhibit a decay in
frequency, the frequency decays will likely reach set UF threshold levels at
differing
times. Based on the above, by analyzing the decay rates and times of loads
within a
system, the IED 200 may determine which loads are associated with a particular
power
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sub-grid. For example, if certain loads exhibit similar frequency decay rates
occurring at
similar times (e.g., within a 2 ms period), the IED 200 may determine that the
loads are
associated with a particular power sub-grid. In some embodiments, IED 200 and
its
associated modules 202-220 may determine which loads are associated with a
particular
power sub-grid based on the methods described in U.S. Patent Application
Publication No.
2009/0089608.
[0040] To enable the IED 200 to determine which loads are associated with a
particular
power sub-grid, IEDs 222 may communicate time-synchronized load phase
measurements
to IED 200 using, for example, the IEC 038.118 protocol. Load angles measured
by the
IEDs 222 may be provided to the phase angle array calculation module 220 that,
in some
embodiments, may store such information. The phase angle array calculation
module 220
may provide the measured load angles to a sub-grid detection module 218. Based
on the
measured load angles, the sub-grid detection module 218 may determine whether
loads
associated with the IEDs 222 are associated with particular sub-grids.
[0041] Information regarding which loads are associated with particular sub-
grids may be
provided to a sub-grid and priority based load selection module 216. The sub-
grid and
priority based load selection module 216 may also receive the parameter that
includes a
priority indication for loads associated with the IEDs 222 from the user
adjustable parameter
module 202. Additionally, the sub-grid and priority based load selection
module 216 may
receive an indication of the amount of load to be shed from the load reduction
calculation
module 204.
[0042] Based on the information related to which loads are associated with
particular sub-
grids, the priority information for the loads, and/or the amount of load to be
shed, the sub-
grid and priority based load selection module 216 may determine which loads
should be
shed by the system to reduce the effects of UF conditions. This information
may be provided
by the sub-grid and priority based load selection module 216 to the load
shedding control
module 214. The load shedding control module 214 may then use this information
in
conjunction with the information received from the load shedding selection
module 210 to
determine which loads should be shed and direct the appropriate IEDs 222 to
shed the loads
from the system.
[0043] In some embodiments, the modules 202-220 included in IED 200 may be
implemented in a programmable IED system. For example, the functionality of
IED 200 may
be achieved using a synchrophasor vector process (e.g., the SEL-3378 available
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from Schweitzer Engineering Laboratories, Inc.) or a real-time automation
controller
(e.g., the SEL-3530 available from Schweitzer Engineering Laboratories, Inc.).
[0044] Figure 3 illustrates another block diagram of an IED 300 for
protection and
control of an electric power delivery system. As illustrated, IED 300 may
include a
processor 302, a random access memory (RAM) 304, a communications interface
306,
a user interface 308, and a non-transitory computer-readable storage medium
310.
The processor 302, RAM 304, communications interface 306, user interface 308,
and
computer-readable storage medium 310 may be communicatively coupled to each
other via a common data bus 312. In some embodiments, the various components
of
IED 300 may be implemented using hardware, software, firmware, and/or any
combination thereof.
[0045] The user interface 308 may be used by a user to enter user
defined settings
such as, for example, an amount of load to shed for each event level, load
priority
information, and the like (e.g., the parameters included in the user
adjustable parameter
module 202 of Figure 2). The user interface 308 may be integrated in the IED
300 or,
alternatively, may be a user interface for a laptop or other similar device
communicatively coupled with the IED 300. Communications interface 306 may be
any
interface capable of communicating with IEDs and/or other electric power
system
equipment communicatively coupled to IED 300. For example, communications
interface 306 may be a network interface capable of receiving communications
from
other IEDs over a protocol such as the IEC 61850 or the like. In some
embodiments,
communications interface 306 may include a fiber-optic or electrical
communications
interface for communicating with other IEDs.
[0046] The processor 302 may include one or more general purpose
processors,
application specific processors, microcontrollers, digital signal processors,
FPGAs, or
any other customizable or programmable processing device. The processor 302
may
be configured to execute computer-readable instructions stored on the computer-
readable storage medium 310. In some embodiments, the computer-readable
instructions may be computer executable functional modules configured to
implement
certain systems and methods disclosed herein when executed by the processor.
For
example, the computer-readable instructions may include an UF load shedding
module
314 configured to cause the processor to perform the UF load shedding
operations and
a time alignment module 316 used time-aligning and coordinating various
communications to and from IEDs connected to the IED, as described in
reference to
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Figure 2. The computer-readable instructions may also include any of the
functional
modules described in reference to Figure 2 to implement the functionality of
the IED
300 described therein.
[0047] Figure 4 illustrates one embodiment of a method 400 for
protection and
control of an electric power delivery system. At 402, a central IED may
receive system
information from a remote IEDs each associated with a load. In certain
embodiments,
the system information may include information relating to the operating
frequencies of
the loads, the power consumption of the loads, synch rophasor information, an
indication that an operating frequency of a load has reached a predetermined
level, and
the like. Based on this system information, at 404, the central IED may
determine
which loads are associated with a particular sub-grid of the electric power
delivery
system experiencing an UF condition. In certain embodiments, determining which
loads are associated with a particular sub-grid of the electric power delivery
system is
based on the decay rates and/or decay times of operating frequencies of the
loads. At
step 406, the central IED may determine whether to disconnect one or more
loads
associated with the sub-grid from the electric power delivery system to
mitigate the UF
condition, sending a signal to IEDs associated with the one or more loads
directing the
IEDs to disconnect the loads. As discussed above, in some embodiments,
determining
which loads to disconnect from the electric power delivery system may be based
on
priority information associated with the loads.
[0048] In certain implementations of embodiments disclosed herein, each
load in a
system may have an associated IED that may be similar or identical IEDs. IEDs
associated with a load may be configured to monitor a machine rotor angle of a
load, an
operating frequency, a rate of change of the operating system frequency,
and/or power
consumption of the load. Each generator in the system may also have an
associated
IED that may be similar or identical IEDs. IEDs associated with a generator
may be
configured to monitor a machine rotor angle, an operational frequency, a rate
of change
of operation frequency, and power production of the generator.
[0049] Consistent with embodiments disclosed herein, island formation
may be
detected by time-correlation of frequency deviations in operating system
frequency
information received from IEDs associated with generators and/or loads.
Frequency
deviations may be detected by comparing received operating system frequency
information with one or more under frequency and/or over frequency (OF)
thresholds.
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In certain embodiments, these thresholds may be the same for IEDs associated
with
both loads and generators.
[0050] Figure 5 illustrates another embodiment of a method 500 for
protection and
control of an electric power delivery system that utilizes rotating inertia
information from
the system. Particularly, the illustrated method 500 may be utilized to
determine an
amount of load and/or power generator to shed to mitigate a UF or OF
condition.
Rotating inertia information may be expressed in terms of kg m2 or any other
suitable
convention including seconds x MVA rating. In certain embodiments, rotating
inertia
information for one or more loads of the system may be entered by a user into
one or
more associated IEDs. Similarly, rotating inertia information for one or more
generators
of the system may be entered by the user into one or more associated IEDs.
[0051] At 502, a total spinning inertia associated with one or more
detected islands
(e.g., a particular sub-grid of the electric power delivery system determined
using
embodiments disclosed herein) may be calculated. The total spinning inertia of
a
detected island may be denoted as "1-1". In certain embodiments, the total
spinning
inertia of a detected island may be calculated by summing together the
rotating inertia
information for loads and/or generators associated with the detected island.
[0052] At 504, a determination may be made whether detected operating
frequency
deviations of detected islands are above or below certain thresholds. If
frequency
deviations are below set thresholds (e.g., in an UF condition), at 506, an
amount of
additional mechanical power contribution required from generators associated
with the
island may be predicted according to a formula utilizing an operating
frequency, a rate
of change of the operating frequency, and a total spinning inertia of the
detected island
(i.e., "I-f'). In certain embodiments, the additional mechanical power may be
denoted as
"Pace and may be measured in Watts. An amount of load to be shed in the
detected
island may be calculated based on the predicted additional mechanical power
contribution, a load priority list, and a measured power consumption of each
load in the
detected island. In embodiments where system generators include fast feed-
forward
increase capability (e.g., generator "run-up" capabilities), in lieu of
shedding loads, the
additional mechanical power required by the Pacc term can be accomplished by
quickly
increasing the power output of generators. For example, power electronic based
generation such as photovoltaic, battery, or other similar power electronic
inverter style
generation may use such run-up to quickly increase the power output of the
generators.
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[0053] If frequency deviations are above set thresholds (e.g., in an OF
condition), at
508, an amount of mechanical power reduction required from the generators
associated
with the island may be predicted according to a formula utilizing the
operating
frequency, the rate of change of the operating frequency, and the total
spinning inertia
of the detected island (i.e., "I-f'). In certain embodiments, the amount of
mechanical
power reduction may be measured in Watts. An amount of power generation to be
shed in the detected island may be calculated based on the predicted amount of
mechanical power reduction, a generator priority list, and a measured power
production
of each generator in the detected island. In embodiments where system
generators
include fast feed-forward reduction capability (e.g., generator "run-back" or
"load
rejection" capabilities), the amount of generator Watts to be reduced may
instead be
achieved by running back generation instead of tripping generators offline
with circuit
breakers.
[0054] Certain embodiments of the systems and methods disclosed herein
may be
implemented using various suitable approaches. For example, in some
embodiments,
methods utilizing time-synchronized phasors (synchrophasors) may be utilized.
Machine rotor angle information, operating frequency information, a rate of
change of
the operating frequency, and power consumption values of generators and/or
loads in a
detected island may be sent from remote IEDs associated with the generators
and/or
loads to one or more centralized IEDs operating as central controller(s).
Utilizing this
information, the one or more centralized IEDs may perform the aforementioned
methods to determine which loads and/or generators should be sent trip signals
and/or
run-back or reject signals.
[0055] In certain embodiments, determining an amount of load to shed,
which may
be expressed in terms of Pacc, may be calculated according to the following:
Isystem = Jgeneratorl + generator_2 + === generator_n +JloacLl +.1load_2 +
===fload_n (1)
H
2mcsyAsrtaemting
system ¨
(2)
Pacc = 2Hsystemf RoCoF
(3)
where J
SyStem is the rotating inertia of the system, .1
-generator n is the rotating inertia of a
particular generator included in the system, J
-load n is the rotating inertia of a particular
load included in the system, Hsystem is the total spinning inertia of the
system,
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Pacc is the amount of additional mechanical power contribution required or
amount of
load to be shed, f is the operating frequency, and RoCoF is the rate of change
of the
operating frequency.
[0056] In certain embodiments, the one or more centralized IEDs may be
an SEL-
1102 controller (available from Schweitzer Engineering Laboratories, Inc.)
that
communicates to one or more remote IEDs such as SEL-751 relays (available from
Schweitzer Engineering Laboratories, Inc.) via one or more channels (e.g., one
or more
037.118 channels). For example, an illustrative system may include three
generators
and twelve sheddable loads. Five SEL-751 relays may be associated with the
three
generators, each having an H of 4 seconds and a 100 MVA rating. Ten SEL-751's
may
be associated with the twelve sheddable loads, each having an H of 0.5 seconds
and a
30 MVA rating. Each of the generators may produce 100 MW and each of the loads
may consume 25 MW.
[0057] An UF event having a 59 Hz UF level and a RoCoF of 2 Hz/sec may occur
with two generators and eight loads experiencing UF events within 6
milliseconds of
each other. Utilizing Equations 1-3, a solution for preventing a blackout
condition
caused by an underfrequency event may be determined. For example, based on the
above described illustrative system parameters, Jgenerator for each generator
is 800 kg-
m2, Litoed for each load is 30 kg-m2, Jsystem of the island experiencing the
UF event is
1,840 kg-m2, Hsystem of the island is 9.2 seconds, and Pacc power deficiency
is
therefore 60 MW. Three of the 25 MW loads may be selected for shedding (i.e.,
totally
75 MW collectively), ensuring that the island does not experience a blackout
condition.
[0058] Utilizing Equations 1-3, a solution for preventing a blackout
condition caused
by an OF event may also be determined. For example, based on the above
described
illustrated system parameters, J
- system of the island experiencing an OF event is 2,460
Mkg-m2, Hsystem of the island experiencing the OF event 12.3 seconds, and Pacc
power
excess is therefore 187 MW. To ensure the island does not experience a
blackout
condition, one of the 100 MW generators may be shed, while another may be run-
back
to 87 MW output to account for the 187 MW of excess power.
[0059] Certain embodiments of the systems and methods disclosed herein may
also
utilize a binary method to prevent a blackout condition. For example, in some
embodiments, one or more remote IEDs associated with loads and/or generators
in a
system may store operating frequencies and one or more RoCoF thresholds. The
one
or more remote IEDs may generate quantized and/or binary representations of
the
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operating frequencies and a RoCoF based on a comparison with the one or more
RoCoF thresholds and transmit this information to one or more centralized IEDs
operating as a centralized controller. The one or more remote IEDs may further
transmit power consumption and generation information from associated loads
and/or
generators. Based on the information received from the one or more remote
IEDs, the
one or more centralized IEDs may determine an estimated H and Pacc for the
system
utilizing, at least in part, Equations 1-3. Utilizing the estimated H and
Pacc, the one or
more centralized IEDs may determine which loads and/or generators of the
system
should be sent trip signals and/or run-back or reject signals.
[0060] An illustrative system implementing embodiments disclosed herein may
comprise one or more centralized IEDs that may be an SEL-1102 controller
(available
from Schweitzer Engineering Laboratories, Inc.), communicating with one or
more
remote IEDs such as SEL-751 relays (available from Schweitzer Engineering
Laboratories, Inc.) via one or more binary communication channels (e.g., one
or more
MirorredBits ). For example, an illustrative system may include three
generators and
twelve sheddable loads. Five SEL-751 relays may be associated with the three
generators, each having an H of 4 seconds and a 100 MVA rating. Ten SEL-751's
may
be associated with the twelve sheddable loads, each having an H of 0.5 seconds
and a
30 MVA rating. Each of the generators may produce 100 MW and each of the loads
may consume 25 MW.
[0061] An UF event having a 59 Hz UF level and a RoCoF of < 5 Hz/sec may occur
with two generators and eight loads experiencing UF events within 6
milliseconds of
each other. Utilizing Equations 1-3, a solution for preventing a blackout
condition
caused by the underfrequency event may be determined. For example, based on
the
above described illustrative system parameters and binary representations of
the
system information, Jgenerator for each generator is 800 kg-m2, Lhoad for each
load is 30
kg-m2, Jsystem of the island experiencing the UF event is 1,840 kg-m2, Hsystem
of the
island is 9.2 seconds, and Pacc power deficiency may be calculated as 75 MW.
Three
of the 25 MW loads may be selected for shedding (i.e., totally 75 MW
collectively),
ensuring that the island does not experience a blackout condition.
[0062] Utilizing Equations 1-3, a solution for preventing a blackout
condition caused
by an OF event in the aforementioned system may also be determined. For
example,
an OF event having a 61 Hz UF level and a RoCoF of < 5 Hz/sec may occur with
three
generators and two loads experiencing OF events within 3.5 milliseconds of
each other.
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Based on the above described illustrated system parameters, J
- system of the island
experiencing the OF event is 2,460 kg-m2, Hsystem of the island experiencing
the OF
event 12.3 seconds, and Pacc power excess is therefore 104 MW. To ensure the
island does not experience a blackout condition, one of the 100 MW generators
may be
shed, while another may be run-back to 96 MW output to account for the 104 MW
of
excess power.
[0063] The quantized and/or binary representations of the operating
frequencies
and/or RoCoF may introduce certain errors associated with the binary
simplification.
For example, in the above-detailed exemplary OF event, the binary
simplification may
introduce an 83 MW error into the calculated excess power Pacc. The island may
survive (i.e., not experience a blackout condition) if the generator can
sufficiently cover
the 83 MW error introduced by the simplification. If the generator cannot
sufficiently
cover the error, the OF in the island will accelerate to another OF threshold
level. In the
above-detailed example, if the generator cannot sufficiently cover the 83 MW,
the OF
event may rise to an operating frequency of 62 Hz and a RoCoF of <5 Hz/sec.
Based
on the above described illustrated system parameters, J
- system of the island experiencing
the OF event is 1,660 kg-m2, Hsystem of the island experiencing the OF event
8.3
seconds, and Pacc power excess is therefore 71 MW. To ensure the island does
not
experience a blackout condition, the generator may be run-back to 71 MW,
reducing
the error introduced by the binary simplification to 12 MW, thereby preventing
a
blackout condition.
[0064] In some embodiments, load composition factors of each sheddable
load may
be entered into the one or more remote IEDs associated with system loads
and/or the
one or more centralized IEDs. This information may be aggregated from loads
associated with a detected island to determine a total load composition factor
for the
island. Load compensation factors may be entered based on voltage dependency
or
frequency dependency or based on standard load categories including, for
example,
various P/Q modeled loads, P/V modeled loads, P/f modeled loads or the like.
Load
compensation factors may also be entered as a relative factor of direct
connected
induction motors, synchronous motors, electronic loads, resistive loads, or
the like.
Loads may be further categorized by load characteristics of direct connected
induction
motors and synchronous motors. Loads may then calculated by the one or more
remote and/or centralized IEDs to determine the totalized load characteristic
of each
detected island, which may be referred to as "RL." The total RL of a detected
island
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may be calculated by summing together the RL of all loads which are associated
to the
detected island.
[0065]
Interconnected grids such as those associated with large utilities may be
associated with boundaries imposed by utility company ownership of
transmission and
distribution capabilities. Islands may form that include interconnected areas
of multiple
utility companies, each of the areas being independently operated and having
localized
blackout prevention technologies. To utilize the aforementioned systems and
methods
to prevent blackout conditions in islands spanning across interconnected grids
associated with multiple utilities, generator and load information may be
provided on
one or more centralized IEDs. The one or more centralized IEDs may then share
total
inertia information, load compensation information, and Pacc calculations with
one or
more IEDs associated with particular portions of the grid. Localized blackout
prevention
technologies may use this system-wide information to take localized blackout
prevention measures.
[0066] While specific embodiments and applications of the disclosure have
been
illustrated and described, it is to be understood that the disclosure is not
limited to the
singular configurations and components disclosed herein. For example, the
systems
and methods described herein may be applied to an industrial electric power
delivery
system or an electric power delivery system implemented in a boat or oil
platform that
may not include long-distance transmission of high-voltage power. Moreover,
principles
described herein may also be utilized for protecting an electrical system from
OF
conditions, wherein power generation would be shed rather than load to reduce
effects
on the system. Accordingly, many changes may be made to the details of the
above-
described embodiments without departing from the underlying principles of this
disclosure. The scope of the present disclosure should, therefore, be
determined only
by the following claims.
