Note: Descriptions are shown in the official language in which they were submitted.
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TITLE
DISTRIBUTED CONTROL OF DYNAMIC REACTIVE POWER
This application is being filed on 09 March 2012, as a PCT
International Patent application in the name of Petra Solar, Inc., a U.S.
national
corporation, applicant for the designation of all countries except the U.S.,
and, Johan
H.R. Enslin, a citizen of the Netherlands, Ruba Akram Amarin, a citizen of
Jordan,
Adje F. Mensah, a citizen of Togo, and Ehab H. Shoubaki, a citizen of Jordan,
applicants for the designation of the U.S. only, and claims priority to U.S.
Patent
Application Serial No. 61/450,742 filed on 09 March 2011, the disclosure of
which
is incorporated herein by reference in its entirety.
BACKGROUND
[001] A large amount of today's electric power is generated.by large-
scale, centralized power plants using fossil fuels, hydropower or nuclear
power, and
is transported over long distances to end-users. Power flows from the
centralized
power plants through distribution networks to consumers. The electric power
from
the centralized power plants to end-users is generally delivered in form of
alternating current (AC), where both current and voltages are sinusoidal, also
referred to as AC systems. In AC systems, power is measured as the rate of
flow of
energy past a given point. If the end-user's load is purely resistive, only
real power
is transferred, as both the voltage and the current are in phase. If the end-
user's load
is purely reactive (capacitor and inductor), the voltage and the current are
90 degrees
out of phase and there is no net transfer of energy to the load.
[002] Typical end-user loads have resistance, inductance, and capacitance,
so both real and reactive power flow to the end-user loads. The inductive and
capacitive properties of the end-user loads cause the currents to change phase
with
respect to voltage: capacitance tending the current to lead the voltage in
phase, and
inductance to lag it. For transmitting the same amount of real power, the AC
system
with higher phase difference between the current and the voltage will have
higher
circulating currents, hence higher loses. Moreover, the higher circulating
currents
require higher rated equipment (conductors, transformers, etc.) or can cause
damage
to the equipment due to overcurrent.
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[003] Hence in AC systems, to transfer maximum amount of energy, and
to increase the efficiency and stability, the phase difference between the
current and
the voltage should be minimal. The phase difference between the current and
the
voltage is controlled by absorbing or delivering reactive power in the
electric power
systems. The control of reactive power in the electric power system is
referred to as
VAR support. The VAR support in the electric power system is provided using
VAR compensators. These VAR compensators are generally located in a
distribution substation or on feeders closer to the distribution substation.
These
VAR compensators offer minimal or no protection to transformers or other
equipment's located near the loads. Moreover, the present day VAR compensators
are stand-alone.
SUMMARY
[004] Consistent with embodiments of the present invention, systems and
methods are disclosed for a topology and control for fast dynamic distributed
reactive power in an electric power system. The systems may include a voltage
sensor for sensing an instantaneous value of the grid voltage. The systems may
further include a reactive power compensator and a controller to operate the
reactive
power compensator. The controller may be configured to determine an amount of
reactive power to be provided to the electric system based on the sensed grid
voltage
and a droop profile. The controller may further be configured to operate
switches of
the reactive power compensator to add/remove capacitors to the electric power
system and/or set firing angle of one or more inductors.
[005] It is to be understood that both the foregoing general description and
the following detailed description are examples and explanatory only, and
should
not be considered to restrict the invention's scope, as described and claimed.
Further, features and/or variations may be provided in addition to those set
forth
herein. For example, embodiments of the invention may be directed to various
feature combinations and sub-combinations described in the detailed
description.
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BRIEF DESCRIPTION OF THE DRAWINGS
[006] The accompanying drawings, which are incorporated in and
constitute a part of this disclosure, illustrate various embodiments of the
present
invention. In the drawings:
[007] FIG. 1 shows an environment in which various embodiments of the
present invention can be practiced;
[008] FIG. 2 shows a power distribution system with fast dynamic
distributed VAR compensators, in accordance with an embodiment of the present
invention;
[009] FIG. 3 shows the dynamic distributed VAR compensator of FIG. 2,
in accordance with an embodiment of the present invention;
[010] FIG. 4 is a block diagram of elements of a controller for the VAR
compensator of FIG. 3, in accordance with an embodiment of the present
invention;
[011] FIG. 5 is a droop profile for a distributed VAR compensator, in
accordance with an embodiment of the present invention;
[012] FIG. 6 is an architecture for data acquisition, monitoring, and
control, of fast dynamic distributed VAR compensators, in accordance with an
embodiment of the present invention; and
[013] FIG. 7 is a diagram depicting modes of operation for a VAR
compensator, in accordance with an embodiment of the present invention.
DETAILED DESCRIPTION
[014] The following detailed description refers to the accompanying
drawings. Wherever possible, the sane reference numbers are used in the
drawings
and the following description to refer to the same or similar elements. While
embodiments of the invention may be described, modifications, adaptations, and
other implementations are possible. For example, substitutions, additions, or
modifications may be made to the elements illustrated in the drawings, and the
methods described herein may be modified by substituting, rendering, or adding
stages to the disclosed methods. Accordingly, the following detailed
description
does not limit the invention. Instead, the proper scope of the invention is
defined by
the appended claims.
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[015] Embodiments of the present invention may provide systems and
methods for controlling reactive power in an electric power distribution
system by
providing a fast dynamic distributed VAR compensator. The reactive power may
be
controlled by absorbing or delivering reactive power in the power distribution
system through the distributed VAR compensator. The systems may include a
voltage sensor for sensing an instantaneous value of the grid voltage. The
systems
may further include a reactive power compensator and a controller to operate
the
reactive power compensator. The controller may be configured to determine an
amount of reactive power to be provided to the electric system based on the
sensed
grid voltage and a droop profile. The controller may further be configured to
operate switches of the reactive power compensator to add/remove capacitors to
the
electric power system and/or set firing angle of one or more inductors, based
on the
determined amount of reactive power.
[016] Consistent with embodiments of the present invention, FIG. 1 is an
environment in which various embodiments of the present invention can be
practiced. FIG. 1 is shown to include a generation station 102, one or more
transmission units 104a, 104b, and 104c (collectively referred to as
transmission
units 104), one or more distribution units 106a and 106b (collectively
referred to as
distribution units 106), a micro grid 108, one or more loads 110a and 110b
(collectively referred to as loads 110), and a power distribution system 112.
Additionally, micro grid 108 further includes one or more Power Electronic
Interfaces (PEIs) 114a, 114b, and 114c (collectively referred to as PE1s 314),
one or
more DG resources 116a, 116b, and 116c (collectively referred to as DG
resources
116), and one or more DG units 118a, 118b, and 118c (collectively referred to
as
DG units 118).
[017] As described above, the generation station 102 may depend on
traditional and renewable sources that may include, but are not limited to,
fossil
fuels, nuclear, hydro, wind, photovoltaic, and geo-thermal. In addition to the
above,
the generation station 102 may generate a large-scale power to be distributed
to the
loads 110 via the power distribution system 112. The distribution network is
described in more details with respect to FIG. 2.
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[018] Consistent with embodiments of the present invention, the power
generated by the generation station 102 may be provided to the transmission
units
104 to further transmit the power to the distribution units 106. The power
generated
from the generation station 102 is feed into transmission units 104. Since the
generation units 102 are generally located far away from the distribution
units 106,
the transmission units 104 may use high voltage (110KV or above) to reduce the
energy loss in transmission. The distribution units 106 may be the final stage
in the
delivery of power to the end-users and may use step down transformers to
reduce
voltages from the high values. The end-users are also referred to as customer
premise in this disclosure.
[019] FIG. 2 is a diagram of a power distribution system 200 with fast
dynamic distributed VAR compensator. As shown in FIG. 2, the power
distribution
system 200 may include a distribution substation 202, one or more distribution
feeders 204a and 204b (collectively referred to as feeders 204), one or more
secondary distribution transformers 206a and 206b (collectively referred to as
secondary distribution transformers 206), one or more customer premises 208a
and
208b (collectively referred to as customer premises 208), one or more
capacitor
banks 210, one or more fast dynamic distributed VAR compensators 212a and 212b
(collectively referred to as VAR compensators 212). The power distribution
system
200 of FIG.2 may further include a communication system 214 and a data center
216.
[020] The distribution substation 202 may transfer power received from a
transmission system to the feeders 204. The substation 202 may include one or
more primary transformers 218 to change voltage levels between high
transmission
voltages (110KV or above) and lower distribution voltages (2.3KV to 35KV). The
substation 202 may further include switching, protection, and control
equipment
220. The primary transformers 218 may have a primary winding and a secondary
winding (not shown the FIG. 2). The transmission system may be connected to
the
primary windings and the feeders 204 may be connected to the secondary
windings
of the primary transformers 218.
[021] The output of the distribution substation 202 may be feeders 204.
The feeders 204 may run along streets overhead (or underground, in some
cases).
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The feeders 204 may be used to deliver power from the distribution substation
202
to the customer premises 208. Only large customer premises may be fed directly
from the distribution voltages. Most customer premises may be fed via
secondary
distribution transformers 206. The secondary distribution transformers 206 may
be
configured to change the voltage level from the feeders 204 to a voltage level
(relatively low level) requested by the customer premises 208. The secondary
distribution transformers 206 may be pole mounted or set on the ground and may
be
located near customer premises 208. Although only one customer premise is
shown
to be connected to a secondary distribution transformer in FG. 2, more than
one
customer premises may be connected to a single secondary distribution
transformer.
In one example embodiment, part of the power distribution system 200 beyond
the
secondary distribution transformer 206 may also be referred to as secondary
voltage
network.
[022] The secondary voltage network may be provided with one more
VAR compensators 212. As an example, the VAR compensators 212 may be
connected between the secondary distribution transformers 206 and the customer
premises 208, preferably nearer to the secondary distribution transformers
206. The
VAR compensators 212 may be configured to provide fast dynamic distributed
reactive power compensation on the secondary voltage network. The VAR
compensators 212 are described in more detail with respect to FIG. 3 in this
disclosure.
[023] Consistent with embodiments of the present invention, one or more
capacitor banks 222 may be connected to the feeders 204 to provide voltage
control
on the feeders 204. The capacitor banks 222 may also include a capacitor
controller
224 to connect/disconnect one or more capacitors to the feeders 204.
[024] Consistent with embodiments of the invention, the capacitor
controller 224, the VAR compensator 212, and the control equipment 220 may be
connected to the data center 216 through the communication system 214. The
communication system 214 may be a ZigBee protocol based communication system,
a wide area network (WAN), a mesh network, the internet or another standard
communication system. The capacitor controller 224, the VAR compensator 212,
and the control equipment 220 may also communicate with each other using the
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communication system 214. In one example embodiment, the data center 216 may
be located at a central monitoring system.
[025] Consistent with embodiments of the invention, the power
distribution system 200 may include a central monitoring system (not shown in
FIG.
2). The central monitoring system may be configured to communicate with
elements of the power distribution system 200 using the communication system
214
or a separate communication system. The central monitoring system may be
configured to communicate with the elements of the power distribution system
200
using two way communication systems. The two way communication may include,
receiving data from the elements regarding status of the power distribution
system,
and in response to the received status data, sending commands to configurable
elements. The commands may include set of action to be performed by the
element
receiving the command. The data center 214 may be located at the central
monitoring system and is used to store the received data from the elements of
the
power distribution system.
[026] Consistent with embodiments of the invention, the central
monitoring system may include standard power distribution system management
tools like Distribution Management System (DMS), Supervisory Control and Data
Acquisition (SCADA) system, Outage Management System (OMS), Fault Detection
Isolation and Restoration (FDIR) system, Crew Management System (CMS),
Metrology Data Management System (MDMS), and inventory management system.
[027] Although only two VAR compensators have been shown in FIG. 2,
a typical power distribution system may include more than two VAR compensators
distributed over a large geographical area. The number of VAR compensators may
be based on number of customer premises, types of customer loads, amount of
customer loads, and distance of the customer premise from the distribution
substation. As an example, one VAR compensator per secondary distribution
transformer may be provided to control reactive power in the power
distribution
system. An example specification of a VAR compensator is provided in Appendix
1
of this specification.
[028] FIG. 3 shows elements of the VAR compensator 212, in accordance
with an embodiment of the present invention. The VAR compensator 212 may
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include a voltage sensor 302, a controller 304, a reactive power compensator
306, a
fuse 308, an electromagnetic interference (EMI) reactor 310, and a
communication
module 312.
[029] The voltage sensor 302 may be connected to the feeders 204. The
voltage sensor 302 may be configured to sense an instantaneous value of the
feeder
voltage, also referred to as grid voltage (Vgrid). The sensed instantaneous
value of
the feeder voltage may be sent to the controller 304. The controller 304 may
be
configured to operate switches in the reactive power compensator 306 to
provide
VAR support to the feeders 204 based on the sensed grid voltage. The
controller
304 and its functioning are described in more detail with respect to FIG. 4 of
this
disclosure.
[030] In one embodiment, the reactive power compensator 306 may be
connected to the feeders 204 through the fuse 308 and the EMI reactor 310. The
fuse 308 may be configured to interrupt excessive current to prevent
overheating or
damage of the reactive power compensator 306. The EMI reactor 308 may be
configured to attenuate conducted radio frequencies disturbances between the
feeders 204 and the reactive power compensator 306.
[031] In one embodiment, the reactive power compensator 306 may
include a lead VAR unit 314 and one or more VAR units 316a, 316b, and 316c
(collectively referred to as VAR units 316). The lead VAR unit 314 and the VAR
unites 316 are connected to the feeders 204 in parallel. The reactive power
compensator 306 may further include a Metal Oxide Varistor (MOV) 318. The
Metal Oxide Varistor (MOV) 318 may be connected in parallel to the lead VAR
unit
314 and the VAR units 316.
[032] In one embodiment, the MOV 318 may be configured to protect
sensitive components of the reactive power compensator 306 against excessive
transient voltages. The MOV 318 may conduct significantly increased current
when
voltage across the lead VAR unit 314 and the VAR units 316 is high. The MOV
318 may remain non-conductive as a shunt-mode device during normal operations
when the voltage across the VAR units remains below a clamping voltage. When
the voltage across the VAR units crosses the clamping voltage, the MOV 318 may
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be triggered, and may shunt the current created by the increased voltage away
from
the VAR units. The clamping voltage may be determined by the utilities.
[033] In one embodiment, the lead VAR unit 314 may include a reactor
320, a Triode for Alternating Current (TRIAC) or solid-state AC switch 322,
and a
driver 324. The reactor 320 may be connected to the feeders 204 through the
TRIAC 322. The driver 324 may be configured to operate the TRIAC 322.
[034] In one embodiment, the VAR unit 316a may include a TRIAC 324a,
a driver 326a, a reactor 328a and one or more capacitors 330a and 330b
(collectively
referred to as capacitors 330). The one or more capacitors 330 may be
connected to
the reactor 328 in series. The one or more capacitors 330a and 330b may be
connected together either in series or in parallel or in combination of series
and
parallel. The reactor 328 may be connected to the feeders 204 through the
TRIAC
324. As depicted in FIG. 3 the VAR units 316b and 316c may also include
components similar to the VAR unit 316a. The components of the VAR units 316b
and 316c may be connected in similar fashion to those of the VAR unit 316a. As
an
example, the VAR units 316b may include a TRIAC 324b, a driver 326b, a reactor
328b and one or more capacitors 330c and 330d. As another example, the VAR
unit
316c may include TRIAC 324c, a driver 326c, a reactor 328c and one or more
capacitors 330e and 330f.
[035] In one embodiment the TRIACs 322 and 324 may be electronic
components that can conduct current in either direction when switched ON. The
TRIACs 322 and 324 may be switched ON by applying either a positive or a
negative current to its gate electrodes. The gate current, also referred to as
gating
signal may be provided by the drivers 324 and 326. Once switched ON, the
TRIACs 322 and 324 may continue to conduct until the current flowing through
it
drops below a predetermined threshold value. The predetermined threshold value
may also be referred to as holding current. In one embodiment, the drivers 324
and
326 may be operated by the controller 304.
[036] FIG. 4 is block diagram of the controller 304 of FIG. 3, in
accordance with an embodiment of the present invention. The controller 304 may
include an Analog-to-Digital converter (ADC) 402, a Phase Locked Loop (PLL)
404, a Root Mean Square (RMS) estimator 406, an error estimator 408, a droop
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profile 410, and a modulator 412. The controller 304 may further include a
supervisory state machine 414, a digital communication bus 416 and a timer
418.
[037] In one embodiment, the ADC 402 may be configured to receive the
sensed instantaneous value of the grid voltage from the voltage sensor 302.
The
ADC 402 may provide digital versions of physical signals representing the grid
voltage and each individual capacitor banks. The output from the ADC 402 may
be
sent to PLL 404 and the RMS estimator 406.
[038] In one embodiment, the PLL 404 may generate an output signal
related to the phase of the input signal. The PLL 404 may provide a reference
in
phase with the grid voltage. The PLL 404 may also provide an estimated
frequency
of the grid voltage to the RMS estimator 406 as a corrective factor.
[039] In one embodiment, the RMS estimator 406 may use the output
from the ADC 402, to compute a RMS value of the grid voltage (vg,,d). The RMS
value is a statistical measure of magnitude of varying quantity, e.g.
sinusoids. In
one example, the RMS value of the grid voltage can be computed as:
IT
vfins Pea =
wherein Vpeak is peak value of the grid voltage (Vgrid).
[040] In one embodiment, the output from the RMS estimator 406 may be
used as input for the error estimator 408. The error estimator 408 may compare
the
RMS value of the grid voltage (Vgr,d) received from the RMS estimator 406 with
a
reference RMS voltage. The error estimator 408 may further estimate a
difference
between the RMS value of the grid voltage computed by the RMS estimator 406
and
the reference RMS voltage.
[041] In one embodiment, the reference RMS voltage may be provided by
the central monitoring system and stored locally in the RMS estimator 406. In
one
example embodiment, the reference RMS voltage may be dynamically modified
based on an operating condition of the power distribution system 200.
[042] In one embodiment, the estimated difference between the RMS
value of the grid voltage computed by the RMS estimator 406 and the reference
RMS voltage may be used as input for the droop profile module 410. The droop
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profile module 410 may include a droop profile as depicted in FIG. 5. The
droop
profile is discussed in more detail with respect to FIG.5 of this disclosure.
[043] In one embodiment, the droop profile module 410 may estimate a
desired amount of reactive power to be absorbed/delivered in the feeders 204
based
on the estimated difference. The droop profile module may estimate the desired
amount by either using a locally stored droop profile or using a droop profile
located
at a central monitoring system.
[044] In one embodiment, the output from the droop profile module 410
may be used as an input for the modulator 412. The modulator 412 may translate
the output from the droop profile module 410 into a control signal that
connects/disconnects capacitors from the feeders 404, and set a firing angle
for the
variable inductor in the reactive power compensator 306. The output from the
modulator 410 may be used as inputs for the drivers 324 and 326.
[045] In one embodiment, the supervisory state machine 414 may be
configured to coordinate interaction between closed loop droop control and
external
command interface exposed through a communication conduit. The supervisory
state machine 414 may also carry configuration parameters such as various
operating
schedules and relative to voltage, or any other quantities described above.
[046] In one embodiment, the timer 418 may provide a reference timing
signals to all other components within the controller. The reference timing
signals
may be used by the components to synchronize internal clock or time stamp the
data
sensed from the utility grid. The digital communication bus 416 is configured
to
establish communication between the controller 304 and communication system
214.
[047] In one embodiment, by means of phase angle modulation switched
by the TRIAC 322, the reactor 324 may be variably switched into the circuit
and so
provide a continuously variable reactive power injection (or absorption) to
the power
distribution system 200. In this configuration, coarse voltage control is
provided by
the capacitors 330; the TRIAC controlled reactor is to provide smooth control.
Smoother control and more flexibility can be provided with the TRIAC
controlled
capacitor switching.
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[048] FIG. 5 depicts an example of a droop profile, in accordance with an
embodiment of the present invention. In one embodiment, the droop profile may
include a one to one mapping between an estimated error in RMS value of the
grid
voltage and a desired amount of reactive power to be absorbed or delivered in
the
feeders 204. Whenever, the estimated error in RMS value of the grid voltage
falls
between two consecutive values provided in the mapping, the desired reactive
power
may be calculated by performing an interpolation using the points below and
above
of the estimated error in RMS value of the grid voltage.
[049] In one embodiment, although the mapping between the estimated
error in RMS value of the grid voltage and the desired amount of reactive
power is
depicted in form of a graph in FIG. 5, the mapping may be depicted in form of
a
table or any other mapping technique.
[050] In one embodiment, the mapping between the estimated error in
RMS value of the grid voltage and the desired amount of reactive power may be
stored on the droop profile and updated dynamically. The mapping may be
updated
by a central monitoring system or an administrator. The updated mapping may be
sent over the communication system 214. Furthermore the mapping between the
estimated error in RMS value of the grid voltage and the desired amount of
reactive
power may be updated locally based on operating conditions of the feeders 204.
[051] FIG. 6 is architecture
for data acquisition, monitoring, and control
for fast dynamic distributed VAR compensator, in accordance with yet another
embodiment of the present invention. As depicted in FIG. 6, the VAR
compensators
may be connected to the secondary voltage network of the power distribution
system.
[052] In one embodiment, the VAR compensator may be provided with a
power generation source connected to the power distribution system. As an
example, the VAR compensator may be provided along with a solar Photovoltaic
(PV) system. In another embodiment, the VAR compensator may be provided as a
standalone element connected to the power distribution system.
[053] As depicted in FIG. 6, the VAR compensator may be configured to
communicate over a communication system to a central monitoring system. The
communication system may be a wireless communication system or a wired
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communication system. The communication system may enable the VAR
compensator to interact with other VAR compensators or another power
conditioning devices in the power distribution system. The central monitoring
system may use the communication system to monitor and control each individual
VAR compensators. Moreover the communication system may allow management
of a VAR compensators geographically dispersed over a large area from a
centralized location.
[054] In one embodiment, the communication system may be a smart grid
communication system which is employed by utilities to manage the power
distribution system. The integration of the VAR compensators with the smart
grid
system will enable monitoring and reporting of operation and health of the VAR
compensator to the central monitoring system. The monitoring and reporting may
include recording reactive power generated by the VAR compensator. The
monitoring and reporting may further include sending a maintenance and repair
alerts to a utility control center.
[055] In one embodiment, the integration of VAR compensator with smart
grid, may enable the VAR compensators to be controlled remotely. In one
example,
the VAR compensator can be remotely configured by command over the
communication system. The resulting state of the VAR compensator may be viewed
in the central monitoring system.
[056] In one example embodiment, the integration of VAR compensator
with smart grid, may provide utilities with grid reliability tools, in which
the central
monitoring system constantly monitor and provide real time status updates on
critical parameters such as voltage and VAR thereby enabling automatic power
outage detection and faster repair response time.
[057] FIG. 7 depicts voltage different mode of operation of the VAR
compensator, in accordance with an embodiment of the present invention. As
depicted in FIG.7 the VAR compensator may be operated in two different modes.
In
a first mode of operation, the VAR compensator may work based on a droop
profile
stored locally. The VAR compensator based on a grid voltage and the droop
profile
can absorb/deliver reactive power in the power distribution system. In a
second
mode of operation, the VAR compensator operations are controlled by a central
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monitoring system. The central monitoring system may send commands over the
communication system.
[058] In one embodiment, the fast dynamic distributed VAR compensator
may regulate voltage on secondary service taps on distribution feeders to
within
required limits. The voltage regulation may allow the utilities to extend
operation
lifetime of secondary distribution transformer by compensating for emergent
and
growing load profiles along the feeder. Moreover, the distributed VAR
compensator
may minimize loses in secondary distribution transformers by improving power
factor along the feeder. Furthermore, the distributed VAR compensator may
curtail
voltage rise due to increasing number of distributed generation such as
photovoltaic
(PV) cells. The ability to curtail voltage rise may allow for additional PV
cells on
feeders.
[059] In one embodiment, the fast dynamic distributed VAR compensator
may be capable of delivering both leading and lagging reactive power to the
power
distribution system. The reactive power generation in the VAR compensator, may
provide smooth and continuous voltage output when operating (e.g. supporting
minimum voltage or correcting power factor) on the power distribution system.
The
VAR compensator may be designed to minimize harmonics and noise generated on
the line due to component selection and controlled switching.
[060] Controlling reactive power in a power distribution system may
reduce loses in the power distribution system and transmission system.
Moreover,
controlling reactive power allows reduction of transformer loses, capacity
relieve
and peak saving through volt/VAR optimization. Controlling reactive power may
allow defer transformer upgrade and replacement, thereby increasing
efficiency.
Moreover controlling reactive power increases the power factor on the feeder
thereby mitigating power quality impacts of other photovoltaic (PV) generation
or
non-linear loads. The distribution helps in avoiding reliance on a centralized
VAR
compensation that requires big reactive elements, and generates line frequency
harmonics. Further, avoiding reliance on the centralized VAR support
eliminates
the possibility of a single point of failure. The fast dynamic distributed VAR
compensators, using separate VAR units, by providing VAR support at the point
of
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load increases the overall performance of the utility grid, and decreases the
loses and
voltage fluctuations for the customers.
[061] Embodiments of the invention may be practiced in an electrical
circuit comprising discrete electronic elements, packaged or integrated
electronic
chips containing logic gates, a circuit utilizing a microprocessor, or on a
single chip
containing electronic elements or microprocessors. Embodiments of the
invention
may also be practiced using other technologies capable of performing logical
operations such as, for example, AND, OR, and NOT, including but not limited
to
mechanical, optical, fluidic, and quantum technologies. In addition,
embodiments of
the invention may be practiced within a general purpose computer or in any
other
circuits or systems.
[062] Embodiments of the invention, for example, may be implemented as
a computer process (method), a computing system, or as an article of
manufacture,
such as a computer program product or computer readable media. The computer
program product may be a computer storage media readable by a computer system
and encoding a computer program of instructions for executing a computer
process.
The computer program product may also be a propagated signal on a carrier
readable
by a computing system and encoding a computer program of instructions for
executing a computer process. Accordingly, the present invention may be
embodied
in hardware and/or in software (including firmware, resident software, micro-
code,
etc.). In other words, embodiments of the present invention may take the form
of a
computer program product on a computer-usable or computer-readable storage
medium having computer-usable or computer-readable program code embodied in
the medium for use by or in connection with an instruction execution system. A
computer-usable or computer-readable medium may be any medium that can
contain, store, communicate, propagate, or transport the program for use by or
in
connection with the instruction execution system, apparatus, or device.
[063] The computer-usable or computer-readable medium may be, for
example but not limited to, an electronic, magnetic, optical, electromagnetic,
infrared, or semiconductor system, apparatus, device, or propagation medium.
More
specific computer-readable medium examples (a non-exhaustive list), the
computer-
readable medium may include the following: an electrical connection having one
or
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more wires, a portable computer diskette, a random access memory (RAM), a read-
only memory (ROM), an erasable programmable read-only memory (EPROM or
Flash memory), an optical fiber, and a portable compact disc read-only memory
(CD-ROM). Note that the computer-usable or computer-readable medium could
even be paper or another suitable medium upon which the program is printed, as
the
program can be electronically captured, via, for instance, optical scanning of
the
paper or other medium, then compiled, interpreted, or otherwise processed in a
suitable manner, if necessary, and then stored in a computer memory.
[064] Embodiments of the present invention, for example, are described
above with reference to block diagrams and/or operational illustrations of
methods,
systems, and computer program products according to embodiments of the
invention. The functions/acts noted in the blocks may occur out of the order
as
shown in any flowchart. For example, two blocks shown in succession may in
fact
be executed substantially concurrently or the blocks may sometimes be executed
in
the reverse order, depending upon the functionality/acts involved.
[065] While the specification includes examples, the invention's scope is
indicated by the following claims. Furthermore, while the specification has
been
described in language specific to structural features and/or methodological
acts, the
claims are not limited to the features or acts described above. Rather, the
specific
features and acts described above are disclosed as example for embodiments of
the
invention.
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APPENDIX 1
Specifications
No. of - - 1 per Distribution Transformer
Operating Voltage 240 Volts AC
Reactive Power 20-50 KVAr
Operating Temperature -40 ¨ 85 deg C
Box - Enclosure, Nema4
Key Features - Dynamic VAR control through solid-state-switches
- Low-voltage ride through
- Communication
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