U.S. patent application number 16/885435 was filed with the patent office on 2020-12-10 for method to detect utility disturbance and fault direction.
This patent application is currently assigned to S&C Electric Company. The applicant listed for this patent is S&C Electric Company. Invention is credited to David Glenn Porter, Stephen E. Williams.
Application Number | 20200389030 16/885435 |
Document ID | / |
Family ID | 1000005049941 |
Filed Date | 2020-12-10 |
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United States Patent
Application |
20200389030 |
Kind Code |
A1 |
Porter; David Glenn ; et
al. |
December 10, 2020 |
METHOD TO DETECT UTILITY DISTURBANCE AND FAULT DIRECTION
Abstract
A method for detecting a voltage disturbance in a utility having
a micro-grid. The method transforms current and voltage
measurements into first and second voltage values and first and
second current values in a stationary reference frame, and
transforms the first and second voltage values and the first and
second current values to third and fourth voltage values and third
and fourth current values in a rotating reference frame, where the
third voltage value defines an average magnitude of the three-phase
power signals. The method multiplies the third current value by the
third voltage value to obtain an instantaneous power value and
multiplies the fourth current value by the third voltage value to
obtain an instantaneous volt-ampere reactive (VAR) value. The
method opens the switch if the VAR value has a magnitude above a
predetermined value and a direction indicating the fault is outside
of the micro-grid in the network.
Inventors: |
Porter; David Glenn; (East
Troy, WI) ; Williams; Stephen E.; (Franklin,
WI) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
S&C Electric Company |
Chicago |
IL |
US |
|
|
Assignee: |
S&C Electric Company
Chicago
IL
|
Family ID: |
1000005049941 |
Appl. No.: |
16/885435 |
Filed: |
May 28, 2020 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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14374833 |
Jun 29, 2015 |
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PCT/US2012/023422 |
Feb 1, 2012 |
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16885435 |
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61438525 |
Feb 1, 2011 |
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61438507 |
Feb 1, 2011 |
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61438517 |
Feb 1, 2011 |
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61438534 |
Feb 1, 2011 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
Y02E 40/30 20130101;
G05B 15/02 20130101; H02J 3/1807 20130101; H02J 3/32 20130101 |
International
Class: |
H02J 3/32 20060101
H02J003/32; H02J 3/18 20060101 H02J003/18; G05B 15/02 20060101
G05B015/02 |
Claims
1. A method for detecting a voltage disturbance in an electrical
power distribution network that includes an electrical system
having one or more power sources that can be disconnected from the
network by a disconnect switch provided in an electrical line,
where the network provides three-phase electrical AC power signals
to the electrical system, said method opening the disconnect switch
in response to detecting the voltage disturbance only if the
voltage disturbance is in the network outside of the electrical
system, said method comprising: reading instantaneous voltage
measurements of each of the three-phase power signals on the
electrical line; reading instantaneous current measurements of each
of the three-phase power signals on the electrical line; detecting
whether a fault is occurring in the distribution network by using
the voltage measurements to detect a voltage disturbance on the
electrical line; transforming the voltage measurements into first
and second voltage values in a stationary reference frame;
transforming the first and second voltage values in the stationary
reference frame to third and fourth voltage values in a rotating
reference frame, where the third voltage value defines an average
magnitude of the three-phase power signals and the fourth voltage
value provides an indication of whether the third voltage value is
locked to a network voltage; correcting the fourth voltage value
over time to maintain the third voltage value locked to the network
voltage; transforming the current measurements into first and
second current values in the stationary reference frame;
transforming the first and second current values in the stationary
reference frame to third and fourth current values in a rotating
reference frame; multiplying the third current value by the third
voltage value to obtain an instantaneous power value; multiplying
the fourth current value by the third voltage value to obtain an
instantaneous volt-ampere reactive (VAR) value; and opening the
switch if the VAR value has a magnitude above a predetermined value
and a sign indicating the voltage disturbance is outside of the
electrical system in the network.
2. The method according to claim 1 wherein detecting a voltage
disturbance includes calculating a sliding window root mean squared
(RMS) voltage for each three-phase power signal over a first
predetermined sample period using the instantaneous voltage
measurements.
3. The method according to claim 1 wherein transforming the voltage
measurements into first and second voltage values and transforming
the current measurements into first and second current values
includes employing a Clarke transformation, and wherein
transforming the first and second voltage values into third and
fourth voltage values and transforming the first and second current
values includes into third and fourth current values includes
employing a Park transformation.
4. The method according to claim 3 wherein transforming the first
and second voltage values and transforming the first and second
current values includes using a sine and cosine of a frequency
correction angle.
5. The method according to claim 4 wherein employing the Park and
Clark transformations includes using the equations: V d s = 2 3 V a
- 1 3 ( V b + V c ) , V q s = 1 3 ( V b - V c ) , V dr = V d s cos
( .theta. ) + V q s sin ( .theta. ) , V qr = V q s cos ( .theta. )
- V d s sin ( .theta. ) , I d s = 2 3 I a - 1 3 ( I b + I c ) , I q
s = 1 3 ( I b - I c ) , I dr = I d s cos ( .theta. ) + I q s sin (
.theta. ) , I qr = I cos ( .theta. ) - I d s sin ( .theta. ) ,
##EQU00001## where V.sub.a, V.sub.b and V.sub.c are the
instantaneous voltage measurements of the three-phase power
signals, I.sub.a, I.sub.b and I.sub.c are the instantaneous current
measurements of the three-phase power signals, V.sub.ds is the
first voltage value, V.sub.qs is the second voltage value, V.sub.dr
is the third voltage value, V.sub.qr is the fourth voltage value,
I.sub.ds is the first current value, I.sub.qs is the second current
value, I.sub.dr is the third current value, I.sub.qr is the fourth
current value and .theta. is the frequency correction angle.
6. The method according to claim 4 wherein correcting the fourth
voltage value over time includes providing the fourth voltage value
to a proportional-integral (P-I) regulator that generates a
correction frequency that changes a base frequency of the network,
where the frequency correction angle is determined from the changed
base frequency.
7. The method according to claim 1 further comprising filtering the
power value and the VAR value to remove transients therefrom.
8. The method according to claim 1 wherein the electrical system is
a critical load or a micro-grid.
9. The method according to claim 1 wherein opening the switch
further includes looking at the current direction of the power
signal.
10. A method for detecting a voltage disturbance in an electrical
power distribution network that includes an electrical system
having one or more power sources that can be disconnected from the
network by a disconnect switch provided in an electrical line,
where the network provides three-phase electrical AC power signals
to the electrical system, said method opening the disconnect switch
in response to detecting the voltage disturbance only if the
voltage disturbance is in the network outside of the electrical
system, said method comprising: reading instantaneous voltage
measurements of each of the three-phase power signals on the
electrical line; reading instantaneous current measurements of each
of the three-phase power signals on the electrical line;
transforming the voltage measurements into first and second voltage
values in a stationary reference frame using a Clarke
transformation; transforming the first and second voltage values in
the stationary reference frame to third and fourth voltage values
in a rotating reference frame using a Park transformation, where
the third voltage value defines an average magnitude of the
three-phase power signals and the fourth voltage value provides an
indication of whether the third voltage value is locked to a
network voltage; transforming the current measurements into first
and second current values in the stationary reference frame using a
Clarke transformation; transforming the first and second current
values in the stationary reference frame to third and fourth
current values in a rotating reference frame using a Park
transformation; multiplying the third current value by the third
voltage value to obtain an instantaneous power value; multiplying
the fourth current value by the third voltage value to obtain an
instantaneous volt-ampere reactive (VAR) value; and opening the
switch if the VAR value has a magnitude above a predetermined value
and a sign indicating the voltage disturbance is outside of the
electrical system in the network.
11. The method according to claim 10 wherein transforming the first
and second voltage values and transforming the first and second
current values includes using a sine and cosine of a frequency
correction angle.
12. The method according to claim 11 further comprising correcting
the fourth voltage value over time to maintain the third voltage
value locked to the network voltage, wherein correcting the fourth
voltage value over time includes providing the fourth voltage value
to a proportional-integral (P-I) regulator that generates a
correction frequency that changes a base frequency of the network,
where the frequency correction angle is determined from the changed
base frequency.
13. The method according to claim 10 wherein the electrical system
is a critical load or a micro-grid.
14. A detection system for detecting a voltage disturbance in an
electrical power distribution network that includes an electrical
system having one or more power sources that can be disconnected
from the network by a disconnect switch provided in an electrical
line, where the network provides three-phase electrical AC power
signals to the electrical system, said method opening the
disconnect switch in response to detecting the voltage disturbance
only if the voltage disturbance is in the network outside of the
electrical system, said detection system comprising: means for
reading instantaneous voltage measurements of each of the
three-phase power signals on the electrical line; means for reading
instantaneous current measurements of each of the three-phase power
signals on the electrical line; means for detecting whether a fault
is occurring in the distribution network by using the voltage
measurements to detect a voltage disturbance on the electrical
line; means for transforming the voltage measurements into first
and second voltage values in a stationary reference frame; means
for transforming the first and second voltage values in the
stationary reference frame to third and fourth voltage values in a
rotating reference frame, where the third voltage value defines an
average magnitude of the three-phase power signals and the fourth
voltage value provides an indication of whether the third voltage
value is locked to a network voltage; means for correcting the
fourth voltage value over time to maintain the third voltage value
locked to the network voltage; means for transforming the current
measurements into first and second current values in the stationary
reference frame; means for transforming the first and second
current values in the stationary reference frame to third and
fourth current values in a rotating reference frame; means for
multiplying the third current value by the third voltage value to
obtain an instantaneous power value; means for multiplying the
fourth current value by the third voltage value to obtain an
instantaneous volt-ampere reactive (VAR) value; and means for
opening the switch if the VAR value has a magnitude above a
predetermined value and a sign indicating the voltage disturbance
is outside of the electrical system in the network.
15. The detection system according to claim 14 wherein the means
for detecting a voltage disturbance calculates a sliding window
root mean squared (RMS) voltage for each three-phase power signal
over a first predetermined sample period using the instantaneous
voltage measurements.
16. The detection system according to claim 14 wherein the means
for transforming the voltage measurements into first and second
voltage values and the means for transforming the current
measurements into first and second current values employ a Clarke
transformation, and wherein the means for transforming the first
and second voltage values into third and fourth voltage values and
the means for transforming the first and second current values
includes into third and fourth current values employ a Park
transformation.
17. The detection system according to claim 14 wherein the means
for transforming the first and second voltage values and the means
for transforming the first and second current values use a sine and
cosine of a frequency correction angle.
18. The detection system according to claim 17 wherein the means
for correcting the fourth voltage value over time provides the
fourth voltage value to a proportional-integral (P-I) regulator
that generates a correction frequency that changes a base frequency
of the network, where the frequency correction angle is determined
from the changed base frequency.
19. The detection system according to claim 14 wherein the
electrical system is a critical load or a micro-grid.
Description
CROSS-REFERENCE TO A RELATED APPLICATIONS
[0001] This application is continuation of prior U.S. application
Ser. No. 14/399,534, filed Jun. 29, 2015, which is a U.S. national
stage entry of International Application Number PCT/US2012/023422,
filed Feb. 1, 2012, which claims priority of U.S. Patent
Application Nos. 61/438,507, 61/438,517, 61/438,525 and 61/438,534
filed Feb. 1, 2011, which are all hereby incorporated herein by
reference in their entirety.
TECHNICAL FIELD
[0002] This patent provides apparatus and methods to control and
coordinate a multiplicity of electric distribution grid-connected,
energy storage units deployed over a geographically-dispersed
area.
INTRODUCTION
[0003] This patent describes embodiments of systems, apparatus and
methods to provide improved control and coordination of a
multiplicity of electric distribution grid-connected, energy
storage units deployed over a geographically-dispersed area. The
units may be very similar to those described in U.S. Pat. No.
6,900,556 and commonly referred-to under names such as Distributed
Energy Storage (DES). An alternative design of units that may be
adapted, used, deployed or controlled in accordance with the
embodiments herein described is described in U.S. Pat. No.
7,050,311 and referred-to as an "Intelligent Transformer". In
summary, these units are self-contained energy storage systems
consisting typically of a storage battery capable of holding 25 kWH
of energy or more, an inverter, and a local control system with a
communication interface to an external control system responsible
for coordinating their function within the distribution grid. Under
sponsorship of the Electric Power Research Institute (EPRI), the
functional requirements for a very simple control system for
coordinating the operation of these units have been cooperatively
developed and placed in the public domain.
[0004] The primary function of the DES unit is to assist the
utility in reducing peak demand (referred to commonly as "peak
shaving" or "load following") to defer or eliminate a regional need
for additional generating capacity, although the DES unit has many
other valuable features. These include the ability to provide
reactive power compensation, to provide backup power for stranded
customers when the main source of supply is temporarily
unavailable, and to provide frequency support (ancillary services).
An extensive description of the requirements of the basic DES unit,
from the customer (electric distribution utility) point of view is
contained in the EPRI DES Hub and Unit Functional Requirements
Specifications. Other functions allow the DES unit to facilitate
the connection of various renewable energy sources into the grid.
This includes providing energy storage or buffering during periods
of weak demand, and conversion from DC to AC and AC to DC.
[0005] The development of these units has been prompted by the very
recent emergence of low cost, highly-functional battery storage
systems capable of many hundreds of charge/discharge cycles, superb
charge density characteristics and temperature performance. A
second enabling technology has been the availability and low cost
of highly-reliable solid-state inverter systems, and a third
technology is that of modern, high-bandwidth communications. It
should be noted that although the enabling technologies have
involved battery based storage systems, future energy storage could
be in fuel cells or any other means for storing and retrieving
electric energy and may also include distributed generation
technologies in combination with or in lieu of storage. The nature
of these alternative storage and generation technologies would have
little bearing on most of the challenges or solutions mentioned in
this disclosure.
[0006] As a result of the rapid emergence and convergence of these
new technologies and others, little attention has been placed on
how DES could be leveraged to meet other important capacity
constraints in the distribution grid. That is, not all capacity
constraints are related to peak demand for generation capacity. For
example, the distribution system is fed from distribution
substations, and the transformers in these substations are
extremely costly and difficult to replace. These transformers
convert power provided at transmission or sub-transmission voltages
of (typically) 69 kV and above to the voltages required for
economic distribution of electricity to the utilities end
customers. Capacity constraints in these transformers, or loss of
capacity due to end of life or other operational issues, can create
overheating (hot spots), leading to unexpected failure and
concomitant risk of service interruption.
[0007] Another capacity constraint is the distribution feeder
itself, particularly in the most-heavily utilized sections near the
substation. In metropolitan areas in particular, feeders typically
exit the substation underground and continue underground, in
cableways or ductwork, for distances of hundreds of feet to several
miles. Underground, high-voltage cable is very expensive, heat
sensitive and replacement is even more problematic than substation
transformers.
[0008] As mentioned above, a historical purpose of DES is peak
flattening or shaving to serve the needs of generation (regional
needs). In that sense, DES, when deployed as large numbers of
units, is often referred-to as a "Virtual Power Plant". Although
DES could also be used to reduce transformer or feeder peak
loading, the strategies and methods for controlling loading at
these three points, using DES are different. For example, a
regional need to reduce load is considered a three-phase total
energy target. There are no phase-specific requirements, and within
reason, individual differences or imbalances from phase-to-phase
are not considered a concern. On the other hand, a substation
transformer capacity limitation is inherently phase-specific. For
example, using DES units, a capacity limitation on Phase A, being
specific to Phase A, can only be addressed by reducing loading on
Phase A. However, a DES unit downstream from the transformer on any
feeder could discharge energy to reduce load as long as it was on
Phase A. In contrast, a capacity limitation sensed at the head of a
single phase of a feeder can only be addressed by shifting load to
DES units on that phase and on that feeder.
[0009] There are several other complications to DES energy
dispatch. It's possible that multiple capacity constraints,
particularly at times of near brownout or blackout conditions, may
exist simultaneously. Under this scenario, complex decision-making
may be necessary to prioritize and mediate the various constraints.
Energy storage management is also a concern. Since these units are
geographically dispersed there is a need to level out the usage of
the units to prevent over-utilizing or exclusively-utilizing
specific units, requiring premature battery replacement in those
units, while failing to gain benefit from the investment in other
units.
[0010] The deployment of new energy sources near the energy
consumer, under direct control of the utility, presents other
opportunities for improvement in power distribution capacity
management as well. Historically, capacity management has been
primarily based upon static, worst-case estimates of circuit
loading applied to models of electrical characteristics of the
distribution system. The fundamental goal of this analysis is to
protect the electrical components from damage due to overheating.
However, once the capacity, measured in amperes or watts, has been
established, the primary monitoring, if any, is based on real-time
measurements of current or power rather than on heat. In overhead
distribution, where the load is carried on individual conductors
consisting of bare wire, the analysis is relatively accurate and
foolproof.
[0011] The analysis of capacity based on component overheating is
much more complicated when the components are packaged or in some
way thermally constrained. For example, the thermal analysis of
power flow and capacity of a substation transformer is extremely
complex. The individual windings of the transformer are typically
immersed in oil, adjacent to, and influenced by the other windings,
and affected by very complex electrical phenomenon such as the
internal absorption of power flow harmonics, circuit imbalance,
power factor and aging of components. As a result, capacity
estimates of the transformer must be de-rated to account for these
various influences. Because of the substantial expense and customer
service impacts of a transformer failure, these derating factors
tend to be very conservative. Due to the inherent variability of
the above factors, even with the best design tools, the true,
real-time capacity of the distribution system can only be guessed.
In the case of the substation transformer, "hot spot" temperature
monitoring (see, for example U.S. Pat. Nos. 4,362,057 and
6,727,821) can be applied to determine exactly when the transformer
is being pushed to its true limit. However, without the ability to
immediately reduce load when this point is reached, the
distribution system operator must either allow the transformer to
be damaged and risk catastrophic failure, or temporarily disconnect
customers from service. Strategic application of load-side energy
from the substation or distributed storage can reduce or prevent
such dire circumstances from occurring.
[0012] The challenge of estimating and monitoring the capacity of
underground feeder is even more complex than of the substation
transformer. Dense runs of insulated conductor in conduit, in
confined air spaces, adjacent to other potentially heat-generating
cable, surrounded by thermally insulating earth, can create
unpredictable and unexpectedly-high operating temperatures. As a
result, special thermo-electric simulation programs have been
developed such as the Cyme Corporation's CYMCAP.TM., to assist
distribution capacity planning engineers with the task of
establishing more accurate cable capacity limits. Even with
sophisticated programs such as CYMCAP.TM., precise cable capacity
estimation is difficult for a variety of reasons such as variations
in the thermal insulating properties of the earth along the
feeder.
[0013] For underground feeders, a relatively new technology called
Distributed Temperature Sensing (DTS), based on fiber optic cable
embedded in or placed adjacent to the underground cable, enables
the real time feeder temperature to be measured every few feet
along the underground cable (see for example U.S. Pat. Nos.
4,362,057 and 4,576,485). With DTS and its associated substation
instrumentation, real-time thermal monitoring of the entire
underground feeder section can be accomplished. Processing
capabilities of the instrumentation include capabilities similar to
CYMCAP.TM., allowing the thermal data to be converted internally
into much more-precise real time estimates of cable capacity. As
with the capabilities of transformer hot spot monitoring, lacking
the ability to immediately reduce load when the real-time thermal
capacity is reached, the distribution system operator must either
allow the cable to be damaged and risk catastrophic failure, or
temporarily disconnect customers from service. However, unlike
transformer overloading that could be mitigated with substation
energy storage, feeder overloading can only be mitigated by
reduction of load (such techniques are usually referred to as
"demand reduction" or DR) or generation of energy on the feeder
using a system such as distributed storage.
[0014] The combination of a new means to selectively reduce
distribution system loading, combined with the technologies of
thermal sensing systems could allow for new, "semi-closed loop"
control of the electrical distribution supply system based upon
control of energy to meet thermal loading requirements. Such a
control system should respond to capacity constraints at all three
levels (regional, substation transformer and feeder capacity), even
if present simultaneously, should be capable of optionally using
the new temperature sensing technologies, and should attempt to
even the wear due to repeated discharge/charge cycles over all
storage units in the system.
[0015] Yet another area where DES can be of value is in the area of
reactive power compensation (RPC), more broadly referred-to as
Volt/VAR control. Many systems have been disclosed for providing
improved voltage and reactive power control on the distribution
feeder. The components distributed along the feeder for RPC consist
entirely of fixed and switched capacitor banks, providing large,
single blocks of three-phase RPC. The nominal sizes of these banks
range from 600 to 1,800 kVAR, with the most typical size being
1,200 kVAR. DES units, with their embedded inverters and
sophisticated internal control systems, are capable of providing
RPC as well as real power output. This is referred-to as "four
quadrant control" since any combination real and/or reactive power
can be transferred to/or from the connected distribution system.
Mathematically, real and reactive power both can be generated or
consumed, with the practical restriction that the magnitude of the
vector sum of the two cannot exceed the nameplate output rating of
the DES unit. However, due to the small size of the DES units, even
with only RPC active, the total compensation on a feeder is only
slightly larger than a single 1,800 kVAR switched capacitor bank.
During peak loading, when DES is needed for real power peak
shaving, very little residual RPC is available. However, at all
other times, the full power rating of each DES unit can be applied
to RPC at a very low cost. Furthermore, unlike traditional switched
capacitor banks, DES units that are deployed on individual phases,
can be dispatched to balance the RPC across phases. Control systems
attempting to leverage the ability of DES to provide RPC must
carefully prioritize demand such that RPC only utilizes the
residual RPC after real power output has been dispatched.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] FIG. 1a illustrates an embodiment of a distributed energy
storage (DES) system.
[0017] FIG. 1b is a graphic illustration of a distribution system
with DES units.
[0018] FIG. 2 is a graphic illustration of a DES unit and
illustrating power flow.
[0019] FIG. 3 is a graphic illustration of individual states and
functions of each state of the control loop.
[0020] FIGS. 4a-e illustrate variations of scheduled fixed
discharge of DES units in a DES system.
[0021] FIG. 5 illustrates a DES unit discharge process.
[0022] FIG. 6 illustrates a process for distribution of demand to
the various DES units.
[0023] FIG. 7 illustrates a process to determine dispatchable
demand, per-phase and per-Unit.
[0024] FIG. 8 illustrates a process to determine reactive power
dispatch.
[0025] FIG. 9a illustrates a process for base loading of a phase on
four feeders.
[0026] FIG. 9b illustrates a process to allocate reactive power to
meet an external request.
[0027] FIG. 10 illustrates a typical demand curve.
[0028] FIG. 11 illustrates a process of transformer thermal
modeling dynamic demand adjustment.
[0029] FIG. 12 illustrates an example of a pair of duct banks, one
carrying two, three-phase circuits, and a second bank on top
carrying a single circuit.
[0030] FIG. 13 is a one line diagram of a microgrid or offline UPS
system.
[0031] FIG. 14 illustrates and algorithm for Power and VAR flow
direction determination.
[0032] FIG. 15 illustrates a process for opening and closing the
disconnect switch of the system depicted in FIG. 13.
[0033] FIG. 16 illustrates a process for autonomous mode operation
of a DES unit.
DETAILED DESCRIPTION
[0034] An embodiment of a DES system is shown in FIG. 1a.
Connectors depicted in the drawings indicate information exchange
between components. The DES units (1) are assembled or prepackaged
components or boxes including energy storage modules (batteries in
the present system). The system could use virtually any form of
energy storage, including kinetic, capacitive, chemical, etc., as
long as it is locally-convertible by the unit to electrical energy
on demand. The DES units also include a four-quadrant inverter and
digital computer-based control with the ability to communicate to
the outside world. The present units utilize the open standard DNP3
communication protocol to communicate to the Hub Controller ("Hub")
(2) although modern computer technology provides a wide variety of
application protocols that could be used. Since the DES units are
dispersed over a wide geographic area, a radio communication system
(3) is preferentially utilized to facilitate the information
exchange with the Hub (2). S&C Electric Company's SpeedNet.TM.
radio system can be used for this purpose, as can a wide variety of
other communication products using radio or any other suitable
media.
[0035] The Hub (2) executes the energy dispatch and coordination
functions that are the subject of this patent. In an embodiment,
the Hub is provided as a pre-packaged, self-contained, rack
mountable, PC-based server appliance, with internal software
components organized using a service-oriented architecture (SOA).
The software may be built around the Microsoft.TM. Corporation's
Windows Server 2008 operating system, although any other suitable
technology, multi-tasking PC operating system could be used. The
Hub (2) is primarily self-contained in that it is able to operate
and dispatch energy-related operating commands and data without
external components other than the DES units (and the intervening
wide area communication system), plus a local communication
interface (4) to the substation's feeder and transformer breakers
which have their own, internal capability to sense current, voltage
and other power-related data at the respective breaker. These
breakers are commonly available from a wide variety of sources and
are typically outfitted with prepackaged breaker controls. The
breaker controls include instrumentation and metering functions
that allow feeder power/metering data (voltage, current and other
derived power properties) to be accessed. The data is then made
available to other substation applications such as the Hub, using
DNP3. DNP3 can run over local communication media such as Ethernet
or RS232 serial lines, both used widely in the substation
environment. The data is provided to the Hub as pre-conditioned,
averages over a few seconds of time to reduce the inaccuracy due to
brief fluctuations. An example breaker control is the Schweitzer
Engineering Laboratories (SEL) 351S. Although the Hub controller
has been implemented with the above components, there are many
possible ways to implement the system architecture, the goal being
to bring information from the DES units, from other instrumentation
such as substation feeder breakers, transformers, and from a system
configuration database into an intelligent device that can allocate
energy flows in and out of the DES units based on diverse potential
needs and requirements.
[0036] Another interface to the outside world is an optional
interface to the customer's SCADA system (5) to allow the
distribution operators to monitor and manage the Hub system in a
limited sense. The interface also provides the capability for the
utility's distribution operators to select the Regional Demand
Limit, which is one of the Hub's system settings. This value is
accessible over DNP3 as an analog output to an external
application. The utility could therefore provide the means for an
external automation system such as the utility's Energy Management
System or Distribution Management System to automatically set the
value using DNP3 and the same communication interface used by the
SCADA system (5).
[0037] A more fully-functioned interface, relative to the
distribution operator's SCADA system is a local Human Machine
Interface (HMI) (14) that can be directly accessed in the
substation via a local keyboard and display interface/web browser
(7) or remotely accessed using a variety of methods supported under
the Windows Server operating environment. The local HMI provides
full control over the operation of the system and provides an
alternate means for the distribution operator to set the regional
demand limit (External Three-Phase Demand Trigger).
[0038] Internal to the Hub are several additional/optional
individual software components. The Device Application Server
(DAS), (6), provides a DNP3 protocol-compatible interface to
external devices including substation equipment (4) mentioned above
and the DES units themselves via the wide area network
communication system (3). The DAS (6) provides a service-oriented
architecture for exchanging data and control functions between
applications internal to the Hub and the DAS. It also provides
translation between application-oriented, named data values and the
numeric identification of DNP3 points. A convenience provided by
the DAS is to act as one or more DNP3 "virtual" devices. This
feature configures the DAS to act as a server to external DNP3
applications such as substation SCADA and DMS systems via (5). The
DAS receives DNP3 poll requests and responds using its own cached
data. Hub applications can populate the cache with the appropriate
data. The DNP device description for these "virtual" devices is
configured into the DAS and the API to the DAS allows the DAS to
either respond to external requests for data from the data stored
in its cache, or to transmit the request to the Hub application.
Control commands from external applications are transmitted
directly through the virtual device and the DAS to the Hub dispatch
engine (see below). The DNP protocol implementation in the Hub
Controller is described above for completion. A perfectly-suitable
alternative design would incorporate the DNP protocol directly in
the Hub application or could use an entirely different
communication protocol to exchange data with other applications and
devices or could use any possible combination thereof.
[0039] Another component of the Hub Controller, also mentioned for
completion, is an Oracle Database and database server application.
All system settings (8), real-time data (9) and historical results
(10) is stored in the database which offers convenient and reliable
non-volatile data storage and retrieval as well as advanced
security features. The database can also be replicated to an
external database server for backup. Another feature of the Oracle
database is its ability to be loaded with a copy of the
distribution operator's geospatial (15) and electrical connectivity
(12) system data. This data is used by the Hub to determine exactly
where the DES units are, relative to the feeders and other
electrical components. Once again, the use of an Oracle database is
a convenience and all of the data could be configured and accessed
from alternative database structures, traditional files and/or all
possible combinations of Oracle database, alternative database and
traditional file storage.
[0040] The heart of the energy dispatch function provided by the
Hub is the Hub Dispatch Engine (HDE), (13), which is a focus of the
present disclosure. Utilizing most of the other interfaces and
databases, the HDE provides coordination and control of both real
and reactive power flow going into and out of the individual DES
units.
[0041] FIG. 1b provides a rough sketch of a distribution system
with DES units. Power to the distribution substation, or "station"
(1), is fed by a transmission line (4) that enters the station and
goes directly into the station transformer (2). At the entry to the
transformer, current and voltage sensing elements (not depicted)
provide inputs to a relay providing protection for the transformer
as well as power flow metering elements used by the HDE's dispatch
logic. This described embodiment illustrates a single transformer
supplying all of the feeder circuit breakers (3) for simplicity,
although alternatively it is possible to have multiple transformers
supplying the feeders. The transformer (2) typically feeds multiple
feeder circuits, each with its own circuit breaker (3). The number
of feeders is arbitrary. It should be noted that the individual
circuits are shown each as a single line, although power is
actually supplied as three separate phases. Sensing is provided
individually on each phase. DES units (5), identified for
simplicity, are scattered throughout the distribution system,
outside the station. Although not shown on the diagram, each DES
unit is connected to a single phase of the feeder, on a secondary
circuit, isolated from the feeder by a distribution customer
transformer not shown. The DES units are distributed across
multiple phases and multiple feeders. A potential implementation
will see as many as a hundred or more DES units connected to the
various phases on any one feeder. In the illustrated embodiment,
the customer transformers are assumed to be connected phase-ground,
although with minor transformations the system could easily work
with phase-phase connected transformers. It should also be noted
that a three-phase DES unit could be built, consistent with the
principles disclosed herein. Such a unit would typically serve a
three-phase load such as a commercial or industrial customer, and
would have the added benefit of being capable of improved feeder
balancing since power could be shifted back and forth between
phases.
Terminology, Variables, and Conventions
[0042] See Table 1 (attached at the end of the this text) for a
list of terms used in this disclosure.
[0043] Tables 2a-d (attached at the end of this text) list settings
(or setpoints) used by the HDE (13). In one possible implementation
all of these reside permanently in a non-volatile,
centrally-sharable database, although other data structures may be
employed. In the attached settings/database tables, the term "(list
of)" indicates that the items below are part of a repeating group
of data elements of a record type described by the following text.
Each of these repeating groups or records is uniquely identified by
a text string, referred to as "ID". Internally, there may be an
additional numeric index value for efficient.
[0044] Table 2a lists HDE (13) global settings. The settings in
this category are unique to the station and used throughout the
disclosure. Table 2b lists the HDE's settings unique to each feeder
leading out of the substation. Table 2c lists the HDE's settings
unique to each DES Group in the Hub. Of note is that there are
multiple algorithms that can be selected-from for charging, and
multiple algorithms that can be selected-from for discharging each
group. The data structures provide selections of schedules and
additional parameters for the desired charge and discharge
algorithms, and also selections and additional parameters for all
of the alternative algorithms. By doing so, the user can change the
selection of the desired algorithm, without losing the values of
the associated parameters should he/she decide to change back to a
previously-configured algorithm.
[0045] Schedules for the various charge and discharge algorithms
have similar data, but must be kept carefully separated to avoid
misuse. For example, if a fixed charge schedule was inadvertently
assigned to a Group for fixed discharge scheduling, the Group might
operate at a completely erroneous time period. Additional, subtle
differences are also of concern. For example, a fixed discharge
schedule will likely be used to discharge the Group at a certain,
very limited time of the day, perhaps no more that 3-6 hours, while
a demand-limited discharge schedule would attempt to span the
entire possible period of high demand during the day--this could be
8-12 hours or more. So schedules that are presented to the user
should come from a list consistent with the type of algorithm the
customer has selected. To accomplish this separation, a separate
table in the database is constructed to relate the Group to its
schedule, and to the type of schedule (algorithm) used for
discharge and the type of schedule (algorithm) used for
charging.
[0046] Table 2d describes Unit-specific settings used by the HDE.
Some of the settings in this Table are configured in the Hub, and
some are configured individually in the DES units. Any time a
setting changes in the DES Unit, it will notify the Hub that it
needs to refresh its copy of the Unit's settings. For clarity, the
table indicates which settings are configured in the DES unit
versus the Hub.
[0047] Tables 3a-d (attached at the end of this text) list
programming variables that are referred to in this patent. Table 3a
lists variables that are calculated and used system-wide. Table 3b
lists variables that are unique to each feeder. That is, a unique
set of variables are maintained for each feeder configured into the
system. Table 3c lists variables unique to each DES group. Table 3d
lists variables unique to each DES unit.
[0048] Power Sign Conventions
[0049] An important convention in the disclosure relates to
direction of real and reactive power flow. Referring to FIG. 2, DES
units and the DES system as a whole can be looked upon as a
distributed power source with the unique characteristic of being
able to consume power (act as a load) or produce power (act as a
source). The DES units can operate in any of four quadrants;
producing or consuming real or reactive power. The following
conventions have been adopted to reduce the ambiguity of settings
and reported power quantities. These conventions are consistent
with IEEE 1547 and IEC 61850.
[0050] The DES unit along with associated downstream loads
constitutes a Local Electric Power System (LEPS) and as such can be
viewed as a load connected to the Distribution System. The DES
breaker is the "Island Interconnection Device (IID) as it is termed
in IEEE 1547.4. The connection of the inverter leads to the DES
termination bus is the "Point of Distributed Resource Connection."
The inverter and battery in combination constitute a Distributed
Resource and, as such, are considered a source. FIG. 2 illustrates
the corresponding power flow conventions.
[0051] Some examples are elaborated below: [0052] 1) When the DES
unit is in Standby Mode (neither charging or discharging Watts or
VARS) and there is some customer consumption of both Watts and
VARS, there is a net power flow into the DES unit expressed at
Point A as positive Watts and positive VARS. The power flow at
point B is also expressed as positive Watts and VARS. The power
flow at point C is zero. [0053] 2) When the DES unit is discharging
real and reactive power at levels exceeding local customer
consumption of real and reactive power there is a net power flow
out of the DES unit expressed at Point A as negative Watts and
negative VARS. The power flow at point B is expressed as positive
Watts and VARS. The power flow at point C is expressed as positive
Watts and positive VARS. [0054] 3) When the DES unit is charging
real power continuing to discharge reactive power at levels
exceeding local customer consumption of real and reactive power
there is a net real power flow into and a net reactive flow out of
the DES unit expressed at Point A as positive Watts and negative
VARS. The power flow at point B is expressed as positive Watts and
VARS. The power flow at point C is expressed as negative Watts and
positive VARS. [0055] 4) When the DES unit and its associated
customers are islanded, there is no power flow into the DES unit
and power flow expressed at Point A is zero. The power flows at
points B and C are matched, presumably both positive Watts and
positive VARS.
[0056] Tables 4a-d (attached at the end of this text) describe the
data elements that are used for information exchange between each
of the DES units and the Hub. As mentioned previously, the DNP3
communication protocol is used as a standardized vehicle for
exchanging this information although a nearly unlimited number of
different communication protocols could be used. Table 4a lists DNP
analog input points that are read from each unit at the start of
each execution of the control loop. Table 4b lists DNP analog
output points that are selectively written-to when the control loop
has recalculated energy settings or at any other appropriate time.
Table 4c lists DNP digital status points also read from the unit at
the start of each execution of the control loop. Many of these
points are provided for information purposes but are not
significant to the energy dispatch functions. For example, specific
alarm points are provided to support detailed troubleshooting data.
Table 4d lists DNP digital outputs that allow the Hub to control
the operation of the DES units. These outputs are written
selectively to control the basic functioning of the DES units.
[0057] In summary, the Hub provides its own DNP polling engine and
internal cache via the APS. Timing of polling is determined by
whether or not the destination device is a station device or a
field device as discussed below. All communication parameters are
configured in the system database. During normal operation, DNP
standard objects are used to exchange status, analog and control
information between the DES units and the APS.
HDE Dispatch Control Loop
[0058] The Hub's energy dispatch function, executed by the HDE
(13), is implemented in a fairly simple control loop. The
individual states and functions of each state of the control loop
are shown in FIG. 3 and described below:
Initialization (1, 1a)
[0059] The HDE accesses its master database and reads its
configuration and last known operating state to determine, for
example, if its dispatch functions are supposed to be enabled or
disabled. See the next section for details on the initialization of
the Hub's control sequence.
Request Station Data (2)
[0060] The HDE requests the APS, to perform a Class 0 DNP poll to
determine current real and reactive power demand, voltage, and
related data from the substation relays sensing power at the
substation transformer breaker and at each feeder breaker. Table 5
(attached at the end of this text) lists the analog points read
from the transformer and Table 6 (attached at the end of this text)
lists the points from each of the feeder breakers.
Request Unit Data (3)
[0061] The HDE requests through the APS a similar sequence as used
for Station Data, to request a Class 0 Poll of all DES units.
[0062] States 2 and 3 are executed as quickly as possible, sending
requests in parallel to all devices without waiting for responses,
subject to the specific communication requirements of each of the
channels and devices. For example, substation equipment on serial
lines must be polled one at a time, with responses processed for
each poll request before the next device on that channel can be
polled. However, for devices such as DES units that are deployed in
an IP-based, wide area network, requests for all units can be sent
as quickly as the requests can be accepted over the Ethernet
interface, and responses are then processed as they arrive.
Responses are cached by the APS for retrieval by the HDE. The APS
provides timeouts and automatic retries to compensate for the
possibility of lost poll requests or responses. The HDE then waits
either for all responses to be received or for a predetermined
time, gathers all expected responses from the APS and advances to
the next state (4).
Evaluate Changes to Energy Dispatch (4)
[0063] On entry to this state, the HDE has received updated energy
and performance data from all required sensing points. Responses
from the APS that indicate that the cached data has not been
refreshed are handled as off-normal conditions. These conditions
prevent energy dispatch functions that require data from the
affected poll response. For example, if the station transformer
breaker cannot be read, the HDE ceases to attempt to satisfy
capacity limitations associated with the transformer or
regional/external capacity limits. If a feeder breaker cannot be
read, the HDE ceases to attempt to satisfy feeder capacity
limitations specifically associated with that feeder. If a DES unit
cannot be read, it is treated as if it's completely out of service.
If the overall communication status has deteriorated to the point
where no DES units can be dispatched to meet any requirement, such
as would be caused by a catastrophic failure of all communication
associated with the HDS, then the Error state (7) is entered.
[0064] The logic in State 4 allocates both real and reactive power
to/from the DES units. This allocation is discussed in detail in
the next section.
Send Updated Operating Data (5)
[0065] The HDE transmits the updated real and reactive power
requirements and operating information to each Unit, one-by-one,
and then waits a predetermined time for a DNP confirmation. Analog
and state data is sent as DNP analog and control outputs. Along
with this data is sent the current time from the Hub for
synchronization. Communication retry logic is handled by the APS
and individual units that fail to respond after a predetermined
number of retries are reported to the HDE as being out of
service.
Processing Incoming Command (6)
[0066] The HDE responds to a variety of commands from the SCADA
master station and a local HMI. These commands are processed
immediately and perform a variety of management functions such as
allowing the real and reactive power dispatch functions to be
individually enabled and disabled, and allowing system settings to
be changed. In the simplest implementation of the HDE, upon
successful processing of any command the HDE is reinitialized.
Energy Dispatch Operating Mode
[0067] The HDE dispatches real and reactive power to DES units in
aggregations called "Groups". See Table 1 for a definition of the
Group construct adopted for convenience in the present
implementation. Group aggregations allow the system operator to
assign specific energy functions in a more systematic way. For
example, an operator could assign all DES units near the end of the
feeder to a specific group, and then schedule that group to
discharge real power at a specific time of day known to cause low
voltage or other power quality problems. It should be noted that in
the herein described implementation, all operating DES units must
be configured into at least one Group. Alternate implementations
may not have this requirement.
[0068] Group configuration includes a combination of charge,
discharge and reactive power compensation (RPC) parameters. In this
system configuration all groups are configured to be consistent in
terms of scheduled times of activity. Not all groups need to be
scheduled to be charging at the same time, but some cannot be
scheduled to charge while others are scheduled to discharge. For
example, it would be a configuration error to have Group 3
scheduled for executing its charging algorithm while Group 4 was
scheduled for discharging. However, since the sign of the charge or
discharge rate could be negative, it is possible to use a unit to
mitigate an emergency overvoltage situation by effectively charging
the unit as part of its discharge cycle. RPC does not consume
energy from the battery and can therefore be scheduled to operate
during any time of the day or night, without regard to real power
scheduling.
[0069] The system as a whole is in discharge mode when any Group is
scheduled to be discharging, and is in charge mode when any Group
is scheduled to be charging. This assumption simplifies the
programming in the present implementation, although the principles
can be applied equally-well in the more complex case.
[0070] Each Group has its own operating mode and schedule for
charging and discharging real and reactive power configured into
its settings database. These operating modes specify the actual
charge or discharge energy allocation algorithm used by the DES
units in the Group. The algorithms are listed below and further
described in the next section.
Standby
[0071] If specified for the Group, or if the HDE's automatic
operation mode is disabled (STANDBY mode), then all DES units in
the Group are told to neither charge nor discharge, without regard
to settings for the Group that the units are associated with.
STANDBY affects both VAR and real power operating modes.
AUTOMATIC Operation (Real Power Discharge)
[0072] In AUTOMATIC operating mode, the HDE reads the definition of
each of its Groups from the master database and then determines,
for all units in the Group how the unit should be told to operate,
as specified in the subsections below. FIG. 6 discussed below
provides a graphic description of how the DES real power is
automatically allocated to different needs.
Scheduled Fixed Discharge
[0073] This mode provides simplified operation of DES units based
upon very predictable requirements for demand reduction. In this
mode, each DES unit in the Group is commanded to discharge based
upon a predetermined discharge schedule, unique to each day of the
week.
[0074] Since the amount of energy stored in each unit is variable
based upon various operating circumstances, at the time of
discharge it is possible that there will not be enough charge
stored in the group as a whole to meet the discharge requirements.
As a result, two variations of discharge logic are supported.
SCHEDULED FIXED DISCHARGE POWER PRIORITY allows the requested
discharge rate to be unaffected but to be terminated early if the
required energy is not available. SCHEDULED FIXED DISCHARGE
DURATION PRIORITY allows the discharge rate to be reduced,
proportionate to available energy in each unit, with the discharge
time remaining unchanged. Variations of SCHEDULED FIXED DISCHARGE
are shown graphically in FIGS. 4a-e.
[0075] The schedule configuration for each Group consists of the
following information, repeated for each day of the week,
Sunday-Saturday, plus an additional schedule entry for operation on
holidays that occur during the week: [0076] 1) Fixed Discharge
Start Time when discharge should begin (Hour, Minute) [0077] 2)
Fixed Discharge Ramp Up Time (minutes). [0078] 3) Fixed Discharge
Duration (minutes) [0079] 4) Fixed Discharge Ramp Down Time
(minutes) [0080] 5) Fixed Discharge Rate summed over entire Group
(KW)
[0081] Since the Fixed Discharge Rate is over the entire Group, the
HDE must first determine what the Group is capable of (available
discharge rate) at the time of evaluation: [0082] 1) For a unit
that has a manual local override in effect, and which is
discharging, it will be assumed to continue to discharge at the
same rate that will be included in the calculation. The rate used
is the rate read from the DES unit on the last poll. [0083] 2) For
a unit that's offline or otherwise incapable of discharging, its
contribution will be zero. [0084] 3) For any unit whose percent
dispatchable capacity is zero, the unit's contribution will be
zero. [0085] 4) For all other units, the unit's contribution will
be [0086] a. Zero if not operating within a scheduled period.
[0087] b. Proportionately between zero and its maximum rating if
the evaluation time occurs during ramping. [0088] c. Its maximum
rating for real power discharge, Maximum Rated Discharge in
kW.sup.1, if operating during a scheduled time period outside of
the unit's ramping on or off .sup.1 Maximum Rated Discharge in kW
is the same as the nameplate rating in kVA, since reactive power
output (at maximum real power discharge rate) is zero.
[0089] If the available discharge rate is less than the Group's
configured Discharge Rate requirement: [0090] a. (SCHEDULED FIXED
DISCHARGE POWER PRIORITY) the discharge rates for each unit (fixed
discharge rate) are unchanged, but the length of time is reduced
without sacrificing ramp-down time (FIG. 4d). [0091] b. (SCHEDULED
FIXED DISCHARGE DURATION PRIORITY) the discharge rate assigned to
the group is reduced to allow the discharge time to remain as
configured (FIG. 4c).
[0092] If the available discharge rate is greater than the Group's
Discharge Rate requirement as specified above, the fixed discharge
rate, for each unit is reduced in proportion to the unit's
scheduled maximum contribution. FIGS. 4a-e illustrate various
possible scheduled discharge algorithms.
Scheduled Demand-Limited Discharge
[0093] This mode provides automatic control of demand to a maximum
KW limit, within a scheduled period of the day. The limiting is
prioritized, to three levels. The first level of limiting is to
feeders as specified by the setpoint Feeder Three-Phase Demand
Trigger (which is divided by three before use, and then used as
feeder per-phase demand trigger), and if additional demand-carrying
capacity is available, it is used to reduce demand at the
station-level. At the station, a second, demand limitation is
specified for the station's transformer (Transformer Three-Phase
Demand Trigger Minimum) with an additional, third,
externally-specified demand limitation due to transmission or
generation restrictions (External Three-Phase Demand Trigger). The
Station's external limit is typically controlled by the energy
management system (EMS) and may be adjusted daily or as often as
necessary. A manual setting is also supported to allow daily
adjustment when EMS control is unavailable.
[0094] Peak shaving and load leveling may be planned and scheduled
at the Feeder level to make use of the storage resources on one or
more Feeders before the Transformer schedule requires additional
discharge. Conversely, the Transformer schedule may require
discharge before any of the associated Feeder schedules require
discharge. This algorithm supports both scenarios.
[0095] This algorithm attempts to limit capacity utilization based
upon a predetermined demand limit. The assumption in the basic
algorithm is that the DES system as a whole contains enough energy
to maintain the demand within the specified limit for the duration
of the peak utilization. Further modifications on this algorithm
are discussed in subsequent sections of this disclosure.
[0096] In the following discussion the term "overloaded" is used to
indicate that there is a need for discharge to satisfy the settings
of the applicable Transformer or Feeder.
Basic Demand Distribution Rules
[0097] The Transformer limit (Transformer Three-Phase Demand
Trigger Minimum) is specified as a three-phase value but is applied
per-phase by dividing the three phase value by three. The Station
External limit (External Three-Phase Demand Trigger), however, is
specified as a three-phase value and any DES unit on any phase is
eligible to provide demand reduction against this limit. However,
discharge is preferentially-applied to preserve or improve phase
balancing at the feeder level.
[0098] The DES units each have the capability to automatically go
into an "islanded mode" where they disconnect the source of supply
and carry the entire customer load from their internal energy
storage system. When the storage is depleted, the system is shut
down. The "islanding" state of the units is a status point (Running
in Islanded Mode) that is read over communications and monitored by
the HDE during processing of all poll responses. If a unit is in an
Islanded operating mode, it is not called on to participate in any
charging or discharging or reactive power dispatch functions, and
its stored energy is not counted in the total energy available from
the system.
[0099] Only DES units on an overloaded feeder phase can be used to
reduce its demand as measured at the head of the feeder. Likewise,
only DES units on the overloaded phase of a transformer can be used
to reduce the overload at the transformer. Based on the way the
algorithm works, the reduction of overload on a transformer is
distributed proportionately and preferentially to DES units on the
same phase of under-loaded feeders. Note that this could result in
increased phase imbalance on those feeders. Only if the transformer
overload cannot be supplied from under-loaded feeders will the
overloaded feeders be tapped for demand reduction. Finally, all
feeder and transformer overload conditions must be satisfied as
best as possible before external demand reduction will be
considered. This assures the best use of resources to satisfy all
levels simultaneously.
[0100] The schedule information for each Group consists of the
following information, repeated for each day of the week,
Sunday-Saturday, plus an additional schedule entry for operation on
holidays that occur during the week: [0101] 1) Demand Limiting
Start Time Time during the day, after which discharge may begin if
demand needs to be mitigated (Hour, Minute) [0102] 2) Demand
Limiting Duration (minutes) The length of time during which demand
limiting is in effect once the start time has been reached.
[0103] Note that there are no demand triggers for the DES units,
for the Feeder, or the station Transformer specified for the Group.
These parameters are independent of individual Group
characteristics.
[0104] Since the demand limiting is over the entire Feeder, the HDE
must first determine at the time of evaluation, what the demand is,
per phase, at the head of the Feeder (e.g., Table 6:
RealPowerPhaseA), and at the station transformer (e.g., Table5:
RealPowerPhaseA), and must correct for (add) to the feeder's
demand, the energy contribution of all, presently discharging DES
units (Table 4a: DES Storage Power) in all Groups on the load side
of the affected phase at the sensing point. These corrected values
are referred-to below as the corrected feeder per-phase demand and
corrected transformer per-phase demand. The latter values are
summed to yield the corrected external three-phase demand, which
may also require demand limiting through dispatch (discharge) of
DES units.
[0105] The HDE must also determine how much DES stored energy
(translated to an available discharge rate in KW) is available to
selectively dispatch. This requires summing the available
(dispatchable) storage capacity per phase, per feeder, excluding
units in a manual overridden or offline state, and excluding units
on a fixed schedule. DES units on a manual discharge or fixed
schedule are not further adjusted by the logic above to satisfy
feeder, station, or external needs, however, their discharge is
included as a contribution to demand limiting.
[0106] The DES unit provides some local control over the rate of
power flow in and out of the unit. The control includes limiting
the vector sum of real and reactive power to the unit's nameplate
rating. It also includes limited control of power in relation to
voltage support on the distribution line. That is, low or high
voltage may limit or suppress charge or discharge of the unit,
respectively. Since these are local conditions that can change
rapidly in real time, the HDE does not attempt to take them into
account. Therefore, the HDE's dispatch of energy is effectively a
maximum discharge or charge rate that may be locally limited by the
unit during operation.
Demand Distribution Algorithm
[0107] DES unit discharge is dispatched as a maximum possible
demand reduction, per unit (Table 4b: RealPowerSetpoint) and is
calculated using the algorithm described below and illustrated in
FIG. 5. Beginning at (1) in the FIG. 5, the algorithm assigns the
demand reduction to all of the units, one by one, based upon the
total, prioritized requirements of the system, sending the assigned
discharge rates to the units during the HDE's main control loop:
[0108] 1) At (2) in the Figure, for a unit in a Group configured
for Scheduled Fixed Discharge, the Unit's total contribution will
be its calculated fixed discharge rate (3). [0109] 2) At (4) in the
Figure, for a unit that has a manual override (invoked locally or
remotely) in effect, and which is discharging, it will be assumed
to continue to discharge at the same rate which will be included in
the calculation (5) (as manual contribution). [0110] 3) At (6) in
the Figure, for a unit that's offline or otherwise incapable of
discharging, its contribution will be zero (7). [0111] 4) At (8) in
the Figure, for a unit whose percent dispatchable capacity is zero,
the unit's contribution will be zero (9). [0112] 5) At (10) in the
Figure, for all other units in Groups selected for Scheduled
Demand-Limiting Discharge, the unit's scheduled maximum
contribution will be: [0113] a. Zero if not operating within a
scheduled period for the Group that unit is in (11) [0114] 6) At
(12) the DES unit's contribution will be zero (13) if: [0115] a.
the corrected feeder per-phase demand is less than its triggering
threshold (feeder per-phase demand trigger), and [0116] b. the
corrected transformer per-phase demand is less than it triggering
threshold (transformer per-phase demand trigger), and [0117] c. the
total of the three corrected transformer per-phase demands is less
than the External Three-Phase Demand Trigger [0118] 7) At (14) in
the Figure, the DES unit's contribution is initialized to its
Maximum Rated Discharge in kW, that is, its Nameplate rating for
maximum real power output which is equal to its kVA rating when
reactive power output is zero, if we're otherwise operating during
a scheduled time period. Note that this is an initial value that
may be reduced if not all of the discharge capacity is needed.
[0119] 8) At (15) in the Figure, the calculations above (item (5))
are carried out for all DES units in all Groups with the results
(each unit's scheduled maximum contribution) saved for further
adjustments in subsequent calculations. The scheduled maximum
contribution is also summed over all units, per phase, on each
feeder (per-phase scheduled maximum contribution), and over all
units on all phases in the station (station scheduled maximum
contribution). Additionally, the manual contributions and fixed
discharge rates are summed similarly (per-phase manual
contribution, external manual contribution, per-phase fixed
discharge rate, external fixed discharge rate) for inclusion in
demand calculations. When initial values of the discharge rates
have been calculated for all units as per the above sequence, at
(16) the algorithm moves to the next phase of calculation. [0120]
9) Beginning at (17), the algorithm seeks to prioritize the
allocation of demand to DES units based on the relative importance
of individual capacity constraints, giving priority first to feeder
capacity limitations, then to transformer capacity limitations, and
finally to requests for external or regional needs to reduce
demand. Note in the logic below that DES units being discharged to
meet feeder constraints will not be used to further meet
transformer constraints unless these cannot be met by units on the
appropriate phase of other feeders. It would be possible to
prioritize these requirements differently based upon the relative
cost or other impacts of overcapacity situations. [0121] Another
point relates to the predetermined selection of the absolute value
of demand that establishes the capacity of the feeder (feeder
per-phase demand trigger), transformer (transformer per-phase
demand trigger), or external capacity (External Three-Phase Demand
Trigger) restraint. See the section titled "Other Capacity
Management Features" for enhancements that can further improve
overcapacity mitigation. [0122] To determine the final discharge
rate of all DES units, the following additional variables are
calculated for each DES unit (each variable is zero if scheduled
maximum contribution for the DES unit is zero): [0123] a. (feeder
is overloaded). Referring now to FIG. 5 at (18), if the corrected
feeder per-phase demand is greater than feeder per-phase demand
trigger, and the difference is greater than the sum of the fixed
and manual contributions for all DES units on that phase (fixed
discharge rate, manual contribution), then at (19) allocate as much
demand as necessary to bring the load down to the capacity limit:
[0124] i. Divide the difference above, minus the sum of the fixed
and manual contributions on the feeder phase, by the sum of the
scheduled maximum contribution over all units on the feeder phase
[0125] ii. Then subtract the proportion above of scheduled maximum
contribution (yielding the variable: allocation to feeder overload)
from scheduled maximum contribution for all units on that feeder
phase. [0126] iii. Note that the maximum proportion should
obviously be limited to 100% (if this limit must be applied, a
warning condition should be raised since the system is unable to
adequately mitigate the overcapacity condition) [0127] iv.
(proportion based upon relative size and charge state of all units
on the phase) For all units with a non-zero allocation to feeder
overload, multiply the value by (itself times the unit's state of
charge times the unit's capacity in kWH), divided by the sum of
(itself times the unit's state of charge times the unit's capacity
in kWH) for all units on that phase of the feeder with a non-zero
allocation to feeder overload. This will proportion the discharge
on the phase relative to both the capacity and the discharge state
of all units being discharged.sup.2. .sup.2 Note that this step in
the logic allocates demand on a single phase of the feeder
proportionate to a combination (multiple) of the Unit's nameplate
size in kVA (Table 2d: Maximum Rated Discharge) and available
energy in kWH (Table 4b: Available Energy). The same proportioning
should be performed at every step that allocates demand to the
feeder. In all cases, the balancing is over a single phase of a
single feeder. The processing is mentioned only once in the text to
reduce the volume of redundant specification. [0128] b.
(transformer is overloaded). At (20), if the corrected transformer
per-phase demand is greater than transformer per-phase demand
trigger, and the difference is greater than the sum of the fixed,
manual and allocation to feeder overload contributions for all DES
units (fixed discharge rate, manual contribution, allocation to
feeder overload) on that phase throughout the station, at (21):
[0129] i. Divide the difference above, minus the sum of the fixed
and manual contributions on the phase, by the sum of the
contributions over all units on the phase (excluding units on
feeders with any phase overloaded from the sum). [0130] ii. Then
subtract the proportion above, of scheduled maximum contribution
(yielding the variable: allocation to transformer overload) from
scheduled maximum contribution for all units on that phase,
excluding units on feeders with any phase overloaded from the sum.
Note that this proportion must be limited to 100%. If it is greater
than 100%, the remaining demand overload should be remembered and
may be reduced in the next step, and otherwise, the next step
should be skipped. [0131] iii. At (22) divide the uncompensated
demand overload above by the remaining scheduled maximum
contribution summed over DES units on the same phase but on any
OVERLOADED feeder. [0132] iv. Then subtract the proportion above,
of scheduled maximum contribution, yielding the variable:
allocation to transformer overload from overloaded feeders, from
scheduled maximum contribution for all units on that phase. Note
that this proportion must be limited to 100%. If it is greater than
100%, the remaining demand overload, summed over all DES units on
the phase (unsatisfied transformer overload) should be remembered
and reduced in the next step, and otherwise, the next two steps
should be skipped. [0133] v. Divide the difference between
unsatisfied transformer overload and scheduled maximum
contribution, by the sum of scheduled maximum contribution for each
remaining overloaded transformer phase. [0134] vi. Then subtract
the proportion above, from scheduled maximum contribution for all
units on that phase. Note that this proportion must be limited to
100%. If it is greater than 100%, the remaining demand overload
should generate a warning since the system is unable to fully
mitigate a transformer overload condition. [0135] Note that in the
allocation sequence above, when mitigating transformer overload,
the HDE prioritizes DES unit discharge first to feeders that, on a
three-phase basis, are relatively lightly-loaded, then to feeders
that have a phase that's overcapacity even if it's a different
phase than the transformer phase that is overloaded, and finally,
as a last-resort, to phases of a feeder that are overcapacity but
have some remaining unallocated demand. This prioritization
attempts to minimize excess heating of underground feeders from
adjacent phases that are already over or near-capacity. [0136] c.
(externally-requested demand reduction). At (23) if the External
Three-Phase Demand Trigger is non-zero, and the sum over all DES
units on all phases of scheduled maximum contribution is non-zero,
and at (24) the sum over all phases of corrected transformer
per-phase demand minus the sum of all demand contributions from
discharging DES units is greater than External Three-Phase Demand
Trigger, then we have a remaining, unsatisfied need for additional
demand reduction. Divide the difference by the sum over all DES
units on all phases of the scheduled maximum contribution, and
then: [0137] i. At (25) calculate the proportion above, of
scheduled maximum contribution, yielding the variable: allocation
to external station demand reduction, for all units on all phases.
Note that this proportion must be limited to 100%. If it is greater
than 100%, an event notification should be generated since the
system is not capable of maintaining the desired external demand
limit. [0138] Note that the algorithm for satisfying the external
demand uses proportionately more energy from DES units that are
otherwise under-allocated relative to their nameplate rating. It
would be possible to allocate as much demand as was available,
first from units on feeders that were not overcapacity on any phase
and that were also not on phases that were overcapacity at the
substation transformer. [0139] At (26) the discharge allocation
algorithm is repeated for all DES units in the Fleet. [0140] 7) At
(27) the final discharge rates for all units are determined and
then sent to the DES units. For all units configured for Scheduled
Demand-Limiting Discharge, and not in a fixed schedule or manual
override operating mode, the final discharge rate sent to each DES
unit in each Group is the sum of the individual contributions:
[0141] a. allocation to feeder overload, which reduces demand on
feeders from load-side DES units [0142] b. allocation to
transformer overload, which reduces demand on the station
transformer from DES units on the same phase but on feeders that
are not overloaded [0143] c. allocation to transformer overload
from overloaded feeders, which reduces demand on the station
transformer from DES units on the same phase but on feeders that
are overloaded [0144] d. allocation to external station demand
reduction, which reduces demand when there is available, remaining
DES capacity to reduce demand seen by an external source of supply,
proportionate to DES unit remaining capacity.
[0145] The above distribution of demand to the various DES units is
shown graphically in FIG. 6. The first column (variable scheduled
maximum contribution) shows the entries for each DES unit that
contain the amount of available power in each DES unit that can be
used to reduce overload in the system via one of the Group
allocations. It is initialized to the rated capacity of the unit,
with some derating for the state of each individual unit. DES units
that are either out of service, in a manual mode, or scheduled for
a fixed amount of discharge are not included in the data. The
second through sixth columns are individual components of discharge
that get dispatched to reducing the respective overloads. As the
logic proceeds, these columns are filled in, one by one, with each
allocation causing a comparable reduction in the demand shown in
the first column. After all six columns are filled in, the sum is
stored in the seventh column. This last column if summed, will
yield the total demand reduction in real time from the system,
which would be seen at the station source.
[0146] The second column (Fixed & Manual Contribution,
variables fixed discharge rate and manual contribution) is the
amount of discharge that should be included in the total system
output, but is otherwise not available to be dispatched to meet the
various demand limits of the system. The third column (Allocation
to Feeder Overload, variable allocation to feeder overload), is the
amount of demand that is dispatched to reduce feeder overload
conditions. The fourth column (Allocation to Transformer Overload,
variable allocation to transformer overload) is the amount of
demand allocated from DES units on un-overloaded feeders that is
dispatched to reduce demand from the same phase of an overloaded
station transformer. Note that the capacity from these units is
used preferentially to reduce an transformer overload condition.
The fifth column (Allocation to Transformer Overload from
Overloaded Feeders, variable allocation to transformer overload
from overloaded feeders) is the amount of demand allocated from DES
units on overloaded feeders that is dispatched to reduce demand
from the same phase of an overloaded station transformer. Note that
the capacity from these units is used if there is insufficient
capacity of the DES units on the more lightly-loaded feeders to
eliminate an transformer overload condition. The sixth column
(Allocation to Station Overload, variable allocation to station
overload) is the amount of demand allocated proportionately from
DES units with remaining capacity after all other requirements are
satisfied, to reduce demand for constraints external to the
station. Note that this demand is not phase-dependent--available
capacity in DES units on any phase of any feeder can be used to
reduce the external demand.
[0147] The last column is the sum of the individual contributions
of the previous six columns. This value is written individually to
each unit (Table 4b: RealPowerSetpoint) during the evaluation
interval.
Other Capacity Management Features
[0148] The logic of the previous section utilizes fixed demand
thresholds to control the level at which the HDE should limit
demand. Note that the amount of aggregated energy storage in the
DES system is limited. It is possible that the integrated energy
demand of the customers served by the system over the length of the
peak operating period could exceed the available DES storage. If
other measures were not taken to mitigate this possibility, demand
could spike to undesirable or even damaging levels as the DES
system runs out of stored energy. FIG. 10 shows a typical demand
curve (2) that could be equally valid to demand on a single phase
of a feeder, or on a transformer/station. In order to maintain
demand at or below the fixed capacity limit (1), the HDE will
dispatch discharge requests to the DES units on the affected phase
for the entire period of time (3) that demand (2) is above the
limit (1). The amount of energy in the DES units necessary to meet
this requirement is the area under the curve (energy) shown as
demand to be shaved (4).
[0149] Since the amount of DES energy storage is fixed, and since
the amount of customer load can never be predicted to 100%
accuracy, no system can provide perfect assurance that an
overcapacity situation can be prevented. However, three generalized
mechanisms are provided in this invention to further mitigate both
the risk of overcapacity and its corresponding potential
damage.
Emergency Reduction in Backup Reserve
[0150] In normal operation, the HDE attempts to perform all of its
overcapacity mitigation/peak shaving without impacting the ability
of the DES units to automatically "Island" with a pre-determined
amount of backup power (see the Unit's DNP point: BackupReserve).
This backup power allows electrical service customers to be
supplied entirely from the DES storage system and remain unaffected
by temporary interruptions in their source of supply. Commercially,
the Islanding feature is something that the distribution operator
may charge for, and therefore be committed to provide. At the same
time, the commitment may have an exclusion for use in emergencies
when failure to reduce load could cause damage to a portion of the
distribution system or could cause the distribution system to
collapse, in turn contributing to a regional blackout. On the other
hand, when overcapacity mitigation, particularly to meet an
external/regional requirement, is provided simply to reduce the
cost of purchasing power on the costly "spot market", reductions in
the backup reserve may be undesirable. For these reasons the HDE is
designed to allow the backup reserve to be selectively and
proportionately reduced. These decisions will more likely occur
near the end of a discharge cycle, when the peak demand is
declining, distribution cable and equipment is reaching its highest
temperatures after extended peak use, and energy storage is at its
minimum. The ability to tap into the system's backup reserve can
reduce or eliminate corresponding overcapacity issues such as
described below.
[0151] Each DES unit individually reserves its own, predetermined
value for BackupReserve. The HDE's setting: Reserve Power
Proportional Reduction can be used to globally and proportionately
reduce this value if necessary to mitigate overcapacity issues at
the external/regional level or at the station transformer. It would
do so by sending an adjusted value (see the Unit's DNP point:
BackupReserveScaleFactor) to the affected unit during the main
control loop. Correspondingly, this value could be proportionately
and selectively reduced on affected feeders to mitigate emergency
overcapacity issues.
[0152] Referring once again to FIG. 5, operation (8), based upon
the distribution operator's requirements, the following additional
logic would be performed: [0153] If the battery is not
fully-depleted, that is, if the battery state of charge (see the
Unit's DNP Point: BatteryStateofCharge) is greater than the Unit's
DNP Point: DepletedChargeReserve, set the Unit's DNP point:
BackupReserveScaleFactor to 0% and continue to (10) in the
flowchart of FIG. 5.
[0154] The logic above would allow the backup reserve to be applied
unselectively to all overcapacity constraints. Similar logic could
be used to selectively apply the backup reserve only to
overcapacity on the feeder the DES unit is connected-to, or to
apply it only for a transformer overcapacity issue versus an
external overcapacity issue.
Dynamic Modification of Fixed Overcapacity Trigger Thresholds
[0155] Mitigation of overcapacity conditions can be further
improved by modification of fixed overcapacity thresholds in real
time during system operation. For example, in the case of the
external or regional capacity limit, this limit may be set, as
mentioned above, to minimize the cost of purchasing or generating
power during a peak operating period. In this case, the desired
threshold is preferentially adjusted up or down to insure that the
energy storage is fully-utilized, and that that utilization is
distributed as uniformly as possible toward leveling instantaneous
energy demand. Since the customer energy demand is variable, a
precise trigger level cannot be predicted. However, sophisticated
modeling tools allow an initial trigger level to be predicted, and
then modified in real time using, for example, using the following
inputs: [0156] Measurements of historical energy demand as a
function of time, for example, on 15 minute intervals. [0157]
Correlations with chronological properties such as time of day, day
of the week, holiday status, month of the year. [0158] Temperature,
humidity and other environmental data from the surrounding area,
measured on as frequent a basis as possible, preferably by hour.
[0159] Special local circumstances such as major sporting events or
other entertainment, election days, etc.
[0160] In the above example, another problem that can arise is that
the energy in the DES units may be called upon to meet feeder or
transformer capacity constraints. In this case, the available
energy may be less than required, but this might not be known until
the peak period had been reached. The algorithm below provides the
means to optimize the dispatch of energy to meet a regional or
external requirement. A similar approach can be used to optimize
dispatch to meet feeder or transformer capacity constraints.
[0161] Referring to FIG. 5 at item (23) and beyond in the
flowchart, the term "External request to reduce demand", which
actually refers to the predetermined value: External Three Phase
Demand Trigger may be replaced with a value calculated using the
procedure below: [0162] 1) At the scheduled start time of the
discharge period, determine an initial value for the External Three
Phase Demand Trigger which, based upon the aggregated total amount
of storage available in the DES system, would exactly equal the
predicted demand above the Trigger during the scheduled discharge
time period, when integrated over time: [0163] a. Determine the
available storage in the DES system in kWH. To do this, sum the
storage in all of the DES units in the Fleet (AvailableEnergy in
Table 4b). [0164] b. Predict the demand curve for the day. There
are many possible ways to do this based upon a myriad of
sophisticated modeling tools beyond the scope of this invention.
However, for simplicity, the following approach is used in the
present invention: [0165] i. Establish the demand curve by
averaging 5 minute sampling interval, three-phase total demand
measurements for the same weekday day and time for the last four
weeks, approximating the curve by joining the adjacent points with
straight lines. Save this averaged demand curve for use in
subsequent steps. [0166] ii. Beginning with a proposed demand level
trigger 1% below the peak value of the demand curve, calculate the
energy, in kWH, required to reduce demand to that level. This
corresponds to the integrated area between the curve and the demand
level for the entire scheduled discharge period. [0167] iii.
Compare the calculated energy with the available storage calculated
in 1a above. If the difference is greater than a predetermined
level of accuracy, for example, 1%, continue to reduce/adjust the
demand level until the two values are within the desired level of
accuracy. This value becomes the initial value for the External
Three Phase Demand Trigger. [0168] 2) Referring now to FIG. 3,
State 4, once the scheduled start time has passed, update the
External Three Phase Demand Trigger using a process similar to the
process of steps 1a-b above, as follows: [0169] a. Determine the
remaining dispatchable energy stored in the DES system as was done
in 1) a above. [0170] b. Starting with the present time of day,
adjust the saved demand curve from 1) b (i) by multiplying each of
its points by the percentage difference of the demand read in FIG.
3, State 3, at the station transformer, for the most-recent demand
summed over all three phases. For example, if the demand today at
the present time is 110% of the average demand at this same time of
day for the last four weeks, establish a new revised demand curve
for today with each sample 110% of the average for the same time of
day. [0171] c. As was done in 1) b (ii) and (iii) above, but
starting from the present time rather than the beginning of the
day, calculate a new value for the External Three Phase Demand
Trigger.
[0172] With minor modifications, the above procedure can also be
applied to dynamically adjust both feeder and transformer
overcapacity triggers. The only significant differences would be
that the initial trigger would be a predetermined value established
to protect equipment from damage, and the dynamic trigger would be
raised if necessary but never lowered below the initial trigger
value.
Capacity Management Based Upon Thermal Monitoring
[0173] The capacity management thresholds, Transformer Three Phase
Demand Trigger Minimum, and Feeder Three Phase Demand Trigger
Minimum provide a conventional means for the HDE to manage loading
and mitigate overcapacity situations on the substation's
transformer and feeders respectively. These settings are explicitly
intended to limit damage to equipment from overheating which in
turn is caused by excessive power flow for some period of time.
However, there may not necessarily be a direct correlation between
power flow and the internal temperature of electrical components.
For example, a substation transformer with an internal temperature
of 100 deg. C. will incur much more damage from a 20% overload than
a transformer with a 60 deg. C. temperature. And the rate at which
the heat can be dissipated is highly dependent on ambient air
temperatures. For these and other reasons, the relationship between
temperature and transformer loading (or overloading) is extremely
complex. Therefore, the most precise way to monitor or actively
manage transformer loading is to actually monitor temperature.
[0174] The means for measuring temperatures inside the most
critical areas of substation transformers, particularly core
windings (hot spots) and oil (often measured near the top of the
tank and referred to as top oil temperature) are well known.
Typical methods involve the use of fiber optic cables and sensors
which can be connected to transducer elements that yield
temperature measurements, usually in deg. C., which in turn can be
monitored in real-time by the substation SCADA system.
[0175] Even greater challenges to accurate capacity management are
encountered on the feeders leaving the substation, and particularly
on underground feeders. Typical underground cables are designed to
withstand continuous temperatures of no greater than 90 degrees C.
In urban or semi-urban areas, underground cables are generally
carried in multi-feeder, concrete-lined duct banks, surrounded by
soil and backfill of various types. FIG. 12 shows an example of a
pair of duct banks, one (1) carrying two, three-phase circuits, and
a second bank (2) on top carrying a single circuit. Over the top of
this ductwork lies a paved road (3), shown as a black horizontal
layer. When these cables carry currents approaching the circuit
capacity, they generate heat, which must be somehow conducted to
the earth or surrounding materials (4) and through the materials to
the outside air. As with transformers, the correlation between
power flow and the internal temperature of these cables is
extremely complex. Factors affecting the heating, unrelated to
power flow in the cable include effects due to heat generated by
adjacent cables, variations in the thermal conductivity of the
earth surrounding the duct, duct air circulation and temperature
buildup from long periods of operation at peak or near-peak
capacity. In the example figure, significant additional heating
could be caused by sunlight on long stretches of black pavement.
Because the underground cable is very costly to replace,
sophisticated electrical and thermodynamic modeling programs such
as the Cyme Corporation's CYMCAP.TM. program have been developed to
calculate underground cable capacity. These programs help to reduce
the uncertainty of estimating the true cable capacity.
Unfortunately, thermal analysis in the underground system is
greatly-complicated by the linear variations in both current flow
and thermal conductivity that can exist over miles of underground
infrastructure. For example, a section of duct that happens to run
under pavement as shown in the Figure, where the pavement happens
to receive lengthy periods of sunlight, could get significantly
hotter than a segment that remains continuously in the shade.
[0176] As with substation thermal monitoring, the means for
measuring underground cable temperature are well-known to those
skilled in the art. A technology known as Distributed Temperature
Sensing (DTS), using fiber-optic cable and highly specialized
transducer boxes is capable of very accurately measuring
temperature of the cable every few feet along its length.
[0177] Going beyond the challenges of transformer overload analysis
based on temperature, feeder cable overload analysis requires
additional provisions taking into account: [0178] Feeder current at
the location(s) of the limiting temperature(s). Since the feeder
may have customer loads connected at various points along its
length, current flow will vary accordingly. [0179] Temperatures of
adjacent cables, which may make it more difficult (or easier) to
reduce temperature by reducing loading of the affected cable.
[0180] Differences in loading patterns of adjacent cables which can
affect the rate of change of temperature in an overloaded section,
making it more difficult to relate current temperature to the
amount of load reduction necessary to stay within thermal
constraints.
[0181] Fortunately, very sophisticated real-time analysis tools
have been developed to reduce all of these considerations into a
single, real-time output for each conductor providing its real-time
(or dynamic) ampacity. An excellent example of this technology is
the LIOS Technology Gmbh, RTTS real-time thermal rating system.
[0182] Thermal monitoring systems for transformers and underground
cable such as the ones mentioned above have been available for some
time. However, their use has been greatly limited by their very
substantial cost, combined with the difficulties in quickly and
effectively responding to thermal overload. Ideally, the response
would be to reduce loading. However, the distribution operator has
limited, and in many cases no available means to reduce customer
load. A widespread deployment of DES units, combined with HDE
management of capacity based on thermal monitoring provides a new,
novel means to reduce premature aging and failure of distribution
system components. The algorithms below provide the preferred means
to implement this control, although many options exist for
refinement based on these principles.
Transformer Capacity Management Based Upon Hot Spot Temperature
Monitoring
[0183] Substation transformer overloads producing hot spot
temperatures marginally above the continuous nameplate rating are
known by those skilled in the art to cause very small, incremental
amounts of wear or premature aging. Higher overloads cause
exponentially greater wear. Based on the distribution operator's
economic analysis of wear versus replacement cost, emergency or
temporary overload is usually allowable based upon the amount of
overload required and the length of time the overload will be
required. The algorithm of the preferred embodiment allows the
operator to configure the amount of overload to be tolerated in
terms of hot spot temperature, as well as the length of time the
overload may be present before load is reduced using DES real power
dispatch. Multiple levels of overload can be specified, each with
its own allowable duration. The algorithm measures hot spot
temperature and load on the transformer during operation and uses
the real-time correlation between the two to determine the amount
of load reduction necessary to achieve the required hot spot
temperature reduction. This eliminates the complexity of attempting
to calculate the relationship based upon myriad other factors.
[0184] Referring now to FIG. 11 and Table 7, the algorithm operates
as follows. The settings applicable to the adjustment are shown in
the first two columns of Table 7. These settings apply equally to
each of the three phases of the transformer. However, the
calculations of FIG. 11 are performed independently on each phase
and result in a unique, dynamically calculated demand target
(dynamic transformer per-phase demand threshold) for each phase.
The table provides allowable levels of thermal overload
(Transformer Hot Spot Temperature) with varying durations (Length
of Allowable Overload) before load reduction is initiated via DES
discharge. At (1), initialization of the dynamic adjustment of
allowable transformer load begins. The initialization occurs at HDE
startup and then the loop repeats forever, on a nominal 30 second
basis which can easily be modified if desired. The variable last
transformer per-phase hot spot temperature (see below) is
initialized to zero and other variables are initialized
appropriately. For example, dynamic transformer per-phase demand
threshold is initialized to an infinite value for each of the three
phases so the initial starting conditions defeat the possibility of
discharging the DES units until it is determined that the
transformer has been overloaded for a sufficient period of time. At
(2), transformer per-phase hot spot temperature is read via SCADA
communications and via the Hub's DAS from the transformer's breaker
where the three, hot spot temperature monitoring points are read,
one-by-one, as each of the three phases is processed in the 30
second loop. At (3) per-phase demand at threshold is saved if the
logic detects that there has been a rise in transformer temperature
across the associated temperature threshold in the table. Since
these transformers are very large, their temperature changes
relatively slowly, and by capturing the demand at the approximate
moment that the temperature crosses the threshold, a demand
approximating the load necessary to exceed that temperature can be
approximated. At (4) if the demand is above any threshold, the
amount of time that demand is continuously over the threshold is
incremented. Excursions of temperature over the threshold are
correspondingly filtered by this logic which is looking for lengthy
periods of time when the temperature in the transformer is
exceeding damaging levels. At (5) the logic is looking for the
lowest table entry which has accumulated enough time to justify
reducing demand. By looking for the lowest entry, the logic
correspondingly retrieves an upper bound on the demand level that
needs to be maintained (dynamic transformer per-phase demand
threshold) to prevent the associated overload temperature from
being exceeded. At (6) if the temperature is below the
second-lowest entry, then the transformer is considered to be
operating within its normal range and the dynamic transformer
per-phase demand threshold can be set to an infinite value (or
largest valid value) to prevent load reduction via HDE power
discharge. At (7) the logic sets the dynamic threshold to a
slightly lower setting than that corresponding to the upper bound
above to keep the temperature just under the overload that has been
exceeded. At (8) the logic saves the most-recent transformer hot
spot temperature which is used in detecting the temperature
transition at (3), and then continues around the loop to process
the other of the three phases.
[0185] Referring now to the Section titled "Demand Distribution
Algorithm", and the associated FIG. 5, the static transformer
per-phase demand trigger used in Step (5) and Step (7b) (boxes (12)
and (20) in FIG. 5) is replaced by the dynamic transformer
per-phase demand trigger calculated in the present section.
Feeder Capacity Management Based on DTS
[0186] As mentioned above, real-time modules such as the LIOS RTTS
system are capable of providing real-time ampacity data for
individual conductors in the underground feeder system. This
greatly simplifies the logic required in the HDE to manage feeder
loading.
[0187] Referring now to the Section titled "Demand Distribution
Algorithm", and the associated FIG. 5, the static feeder per-phase
demand trigger used in Step (5) and Step (7a) (boxes (12) and (18)
in FIG. 5) is replaced by a new value, unique to each phase, called
dynamic feeder per-phase demand trigger which would be read using
DNP from the above-mentioned DTS system.
AUTOMATIC Operation (Real Power Charge Mode)
[0188] In AUTOMATIC operating mode for charging energy storage, the
HDE reads the definition of each of its Groups from the master
database and then determines, for all units in the Group how the
unit should be told to operate, as specified in the subsections
below.
[0189] Note that a basic, distinguishing feature of Charge Mode is
that if there is any feeder-level limit encountered on the amount
of charging that can be accommodated at any point in real-time,
then the charging-driven demand is distributed over all DES units
attempting to charge, in inverse proportion to each Unit's state of
available, dispatchable energy. This differs from discharge mode
where the energy is proportioned only within the DES units of any
given Group.
[0190] "Charge Mode" is entered when one or more Groups have
schedules that call for charging at that point in time. It is
assumed that none of the schedules for the fleet have overlap
between charge and discharge schedules. Such an overlap would be
considered a setup error. If its necessary to charge a unit during
system-level discharge (or discharge during system-level charging),
use Manual operation of the individual Unit(s).
Scheduled Fixed Charge Mode
[0191] This mode provides simplified operation of DES units based
upon very predictable requirements for demand management. In this
mode, each DES unit in the Group is commanded to charge based upon
a predetermined charge schedule, unique to each day of the week.
The schedule configuration for each Group consists of the following
information, repeated for each day of the week, Sunday-Saturday,
plus an additional schedule entry for operation on holidays that
occur during the week: [0192] 1) Fixed Charge Start Time when
charge should begin (Hour, Minute) [0193] 2) Fixed Charge Ramp Up
Time (minutes). [0194] 3) Fixed Charge Duration (minutes) [0195] 4)
Fixed Charge Ramp Down Time (minutes) [0196] 5) Fixed Charge Rate
summed over entire Group (KW)
[0197] Since the Fixed Charge Rate is over the entire Group, the
HDE must first determine what the Group is capable of drawing from
the grid, worst-case (available charge rate) at the time of
evaluation: [0198] 1) For a unit that has a manual local override
in effect, and which is charging, it will be assumed to continue to
charge at the same rate which will be included in the calculation.
The rate used is the rate read from the DES unit on the last poll.
[0199] 2) For a unit that's offline or otherwise incapable of
charging, its contribution will be zero. [0200] 3) For a unit whose
percent dispatchable capacity is equal to or greater than 100%, the
unit's contribution will be zero. [0201] 4) For all other units,
the unit's contribution will be [0202] d. Zero if we're not
operating within a scheduled period. [0203] e. Proportionately
between zero and its maximum rating if the evaluation time occurs
during ramping. [0204] f. Its Maximum Rated Charge in KW, if we're
operating during a scheduled time period outside of the Unit's
ramping on or off.
[0205] If the available charge rate is less than the Group's
configured Charge Rate requirement, the charge rates for each unit
(fixed charge rate) are as specified above.
[0206] If the available charge rate is greater than the Group's
Charge Rate requirement as specified above, the fixed charge rate,
for each unit is reduced proportionately.
Scheduled Demand-Limited Charging Mode
[0207] This mode provides automatic control of demand to a maximum
KW limit, during charging within a scheduled period of the day. The
algorithm below distributes the charging demand, per phase, per
feeder, proportionate to the energy discharge level of each Unit.
That is, the least-charged DES units are charged up faster.
[0208] Handling of holidays is TBD. The schedule information for
each Group consists of the following information, repeated for each
day of the week, Sunday-Saturday, plus an additional schedule entry
for operation on holidays that occur during the week: [0209] 1)
Demand Limiting Charge Start Time Time during the day, after which
charging may begin. (Hour, Minute) [0210] 2) Demand Limiting Charge
Duration (minutes) The maximum length of time during which charging
is in effect once the start time has been reached.
[0211] Note that there are no demand triggers for the DES units,
for the feeder, or the station transformer specified for the Group.
There is only one demand trigger (feeder per-phase charge trigger)
and it is set at the feeder-level and applies to cumulative demand
over all DES units on a given phase without regard to Group
membership.
[0212] During the scheduled period, units will continue to charge
whenever demand is under the feeder per-phase charge trigger. The
allocation of charging demand must insure that the feeder per-phase
charge trigger is never exceeded due to charging.
[0213] Since the demand limiting is over the entire feeder, the HDE
must first determine at the time of evaluation, what the demand is,
per phase, at the head of the feeder (eg Table 6: RealPowerPhaseA),
and must correct for the effect of the demand from each charging
DES unit (Table 4a: DES Storage Power) on the feeder's demand. This
correction is the energy contribution of the charging demand in
all, presently charging DES units in all Groups on the load side of
the affected phase as sensed at the feeder breaker. These corrected
values at the head of the feeder are referred-to below as the
corrected feeder per-phase demand. Once the present charging demand
has been subtracted, the HDE can reallocate charging demand to DES
units based in part upon discharge state.
[0214] The HDE must estimate on each feeder phase, how much
dispatchable charging demand can be accommodated, and in the
worst-case, how much dispatchable demand would be drawn if it was
available. The first value, per-phase dispatchable charging demand,
is obtained by subtracting the corrected feeder per-phase demand
from feeder per-phase charge trigger. The dispatchable charging
demand is determined by subtracting any contributions to demand
from any units on the respective feeder phase that are in a manual
operation mode or configured for "Scheduled Fixed Charge".
[0215] The dispatchable demand, per-phase and per-DES unit (Table
4b: RealPowerSetpoint) may be calculated as shown referring to FIG.
7 at (1), for each DES Unit, the dispatchable charging demand (CR)
is calculated as follows: [0216] 1) In FIG. 7, at (2) for a unit in
a Group configured for Scheduled Fixed Charge, the Unit's
contribution to feeder demand (CR) will be set at (3) to its fixed
charge rate. [0217] 2) At (4), for a unit that has a manual
override (invoked locally or remotely) in effect, and which is
charging, it will be assumed to continue to charge at the same rate
which will be included in the calculation (as manual contribution
at (5)). [0218] 3) At (6), for a unit that's offline or otherwise
incapable of charging, its contribution will be set to zero at (7).
[0219] 4) At (8), if the DES unit is in a group configured for
Scheduled Demand-Limited Charging but the DES unit is
fully-charged, the Unit's CR will be set to zero at 9. [0220] 5) At
(12), for a unit in a group configured for Scheduled Demand-Limited
Charging, whose percent dispatchable capacity is less than 100%,
the unit's CR (at this step of evaluation) will be its nameplate
rating discharge rate (Maximum Rated Discharge) at maximum real
power output which is the same as its kVA nameplate rating. This
demand value, each unit's scheduled maximum contribution, is then
saved for further adjustments in subsequent calculations. The
scheduled maximum contribution is also summed over all units, per
phase, on each feeder (per-phase scheduled maximum contribution).
Note that this value is demand going INTO the storage system, as
opposed to output during peak shaving. [0221] 6) At (13) the
calculations above are repeated for all DES units, aggregated over
all groups scheduled for charging on each phase of each feeder,
with the results saved for further analysis. [0222] 7) To determine
the final charge rate of all DES units, the following additional
calculations and variables are calculated beginning at (14): [0223]
i. At (15), the corrected feeder per-phase demand (feeder per-phase
demand corrected for the effects of units presently charging), is
subtracted from the feeder per-phase charge trigger, yielding
per-phase dispatchable charging demand. [0224] ii. At (16) the
percentage discharge (100-percentage charged) of each unit with a
dispatchable charging rate is summed up over all units under the
HDE's control, yielding per-phase aggregated discharge level for
use in further calculations. [0225] iii. At (17) each Unit's
dispatchable charging demand is adjusted. [0226] iv. (feeder is
heavily loaded). At (18) if the per-phase dispatchable charging
demand is negative or zero the final charge rate for all
dispatchable units on the feeder phase is set to zero at (19).
[0227] v. (feeder is lightly loaded) At (20) if the per-phase
dispatchable charging demand is greater than the per-phase
scheduled maximum contribution, the final charge rate for all
dispatchable units on the feeder phase is set to their scheduled
maximum contribution at (21). [0228] vi. (feeder is moderately
loaded) If neither of the above conditions are true, then the
charging demand exceeds the available charging power. The charging
demand per-phase, per feeder, is reduced in each unit, first in
proportion to their relative maximum demand (Maximum Rated
Discharge), then inversely proportional to their state of charge in
percent (percent dispatchable capacity). The logic below is applied
for each DES unit with a dispatchable charging rate: [0229] 1.
(charging proportionate to feeder capacity) At (22), for each unit
the scheduled maximum contribution is multiplied by per-phase
dispatchable charging demand and divided by the per-phase scheduled
maximum contribution. [0230] 2. At (23) the results of the step
above are multiplied by the unit's percentage discharge
(100-percent dispatchable capacity) and divided by per-phase
aggregated discharge level to yield the final charge rate in kW.
[0231] 3. At (24) the logic repeats the sequence of calculations
for all DES units on all feeders.
AUTOMATIC Operation (Reactive Power Compensation Mode)
[0232] DES units are capable of performing reactive power
compensation (RPC) with minimal losses. For this reason, reactive
power compensation, when enabled, is scheduled, typically,
around-the-clock. However, to provide more flexibility for
customers wishing to reduce DES run time, a single, master
operating schedule is automatically associated with RPC. That is, a
single schedule applies to all units dispatched by the HDE. RPC can
be enabled or disabled independently of the other, real
power-related automatic operating modes.
Interaction of DES RPC with Other Systems
[0233] In rough terms, DES reactive power compensation, per feeder,
will typically provide no more than about one third of the reactive
power required to achieve unity power factor, and even less when
DES is actively peak shaving real power. However, DES RPC provides
the equivalent of a "fine tuning knob" on other RPC control systems
and should be dispatched accordingly. These other control systems
generally include fixed and switched capacitor banks on the feeder,
plus other fixed and switched substation capacitor banks. Where
capacitor banks are present on the feeder, unless the feeder is
operating near its voltage extremes, the operation of the capacitor
bank will generally not be influenced significantly by DES.
Reactive Power Dispatch Fundamentals
[0234] The following general comments apply to the treatment of RPC
by the HDE and DES units: [0235] 1. DES units produce power in any
of the four quadrants. During the HDE's communication and control
loop, it always sets both real (Table 4b: DES Storage Power) and
reactive power (Table 4b: DES Storage Vars) setpoints when sending
its power dispatch requests to the DES units. RPC dispatch
calculations are performed after all real power charge/discharge
dispatch requirements are determined, during the HDE's main
communication and control loop. [0236] 2. DES units operating in
manual control mode will generate reactive power output at their
specified output level, with real power output taking precedence
over reactive power (in order to stay within the Unit's rated
voltage and power constraints--see below). [0237] 3. DES units
respond locally to overvoltage or under-voltage conditions. That
is, if a serious over or under-voltage condition develops, the
Unit's internal logic will automatically force the unit into an
islanded configuration to protect customer loads. The preferred
embodiment of the HDE does not attempt to modulate VAR output to
manage over or under-voltage conditions. [0238] 4. If RPC is not
enabled or not scheduled to be active, and the unit is not in
Manual operating mode, the HDE commands the DES unit to charge and
discharge at unity power factor. The following additional rules
apply only when RPC is enabled and scheduled to be active. [0239]
5. The HDE will establish the ability of each DES unit to provide
RPC (maximum VAR output) according to the following formula:
[0239] reactive power maximum output= ((unit KVA
Rating).sup.2-(unit real power output).sup.2) [0240] The DES unit
KVA Rating is a nameplate rating fixed at manufacturing time and
configured into the HDE's unit-specific database (Table 2d: Maximum
Rated Discharge). Typical values are 25, 50 and 75 KVA. The "unit
real power output" is the actual real power output being dispatched
to the Unit. The net effect of the formula above is to prioritize
real power output preferentially over reactive power output in all
dispatch calculations, and to limit reactive power to the nameplate
rating of the Unit. Note that the reactive power maximum output
from the formula would be a positive number. Since the unit is
capable of producing both reactive and capacitive power (or
actually, power in any of the four possible quadrants), the actual
maximum reactive power output can be positive or negative but will
have the same magnitude in both cases. [0241] 6. As with real power
dispatch, when dispatching the aggregated output of multiple DES
units, if the total RPC required is less than the aggregated
maximum output, the required reactive power output will be
proportioned to the DES units relative to their maximum output.
[0242] 7. The HDE maintains tables of information for the entire
fleet, per unit, containing the following data: [0243] a.
Most-recent real power (KW) output. [0244] b. Most-recent reactive
power (VAR) output. [0245] c. Unit's available reactive power
maximum output (using formula above). [0246] 8. Reactive power
compensation, if enabled and scheduled to be active, is dispatched
first to satisfy an external demand setting, and second, to produce
unity power factor on each phase of each feeder. [0247] 9. An
external RPC setting is provided as a three-phase unsigned value,
summed over all phases, representing the amount of RPC to be
applied, in units of KVARs. However, all compensation is applied
independently, per phase. That is, unlike real power dispatch to
satisfy external demand, excess reactive power compensation on one
phase, cannot mitigate a shortage of reactive power compensation on
another. That is, the external RPC setting is divided by three and
the result applied individually to each phase. [0248] 10. Unlike
real power discharge, external demand for RPC is specified relative
to the most-recent, reactive power demand of the distribution
system that would be seen if there was no DES system. This creates
some additional complexity since the most-recent measured or
predetermined RPC output of the distribution system already
includes DES RPC for feeder-level as well as external RPC requests.
The above fundamentals are assumed in the RPC dispatch algorithm
described in the algorithm below.
Reactive Power Dispatch Algorithm
[0249] In the algorithm below, the term "inductive" refers to a
flow of uncompensated reactive power such as that produced by
electric motors, while the term "capacitive" refers to compensated
reactive power such as that produced by shunt capacitors. The term
"unity power factor" refers to the situation in which there is no
reactive power present, either inductive or capacitive. Referring
to FIG. 8, the algorithm begins at (1): [0250] 1. At (2), the HDE
calculates the maximum VAR (RPC) output of each DES unit based on
the most recent real power charge/discharge requests as calculated
by the real power dispatch algorithms. It also retrieves the
present RPC being applied from the last dispatch cycle, per phase.
[0251] 2. At (3), the HDE calculates the maximum cumulative
available RPC output for each phase, per feeder. It also calculates
the total per phase over all phases for the entire DES Fleet. The
calculations include contributions from all configured,
dispatchable units. [0252] 3. At (4) if the total available RPC
over the Fleet is less than the external RPC request, when viewed
per phase, then at (5) all DES units on the affected phases, are
dispatched at their maximum output. [0253] 4. Otherwise, at (6),
for any phase that is not dispatched at its maximum output as
above, the HDE examines the power factor on each feeder for that
phase, selecting feeder phases that have an inductive power factor.
In (7) it allocates the amount of RPC it would take, per phase, to
provide unity power factor on each feeder on that phase, first
subtracting the present output of the DES units from the
most-recent readings at the feeder breakers. DES units on any
feeder phase that is already capacitive are not allocated any RPC
at this step. On any given feeder, if the available RPC from the
DES units is not enough to provide unity power factor, the Unit's
maximum RPC output is dispatched. Alternatively, if the required
allocation is less than the maximum available RPC, each unit's
allocation is reduced proportionately. [0254] 5. At (8) the logic
for RPC in (6) and (7) is repeated for all feeders on the same
phase that have inductive power factor. This attempts to serve the
external RPC request preferentially by adjusting the power factor
on all affected feeders and phases to unity power factor without
over compensating (producing a capacitive power factor) on any of
them. [0255] 6. Alternatively, if the RPC requirement cannot be
fully satisfied from the above logic, at (9), the algorithm checks
to see if there remains a partially unsatisfied RPC request. Then
at (10) if the total allocation above over all feeders on the
affected phase is less than the external RPC request, per phase,
the difference is distributed proportionately to the RPC available
from DES units on feeder phases already dispatched to unity power
factor. This allows the power factor on any given phase of a feeder
to become capacitive to serve an external, otherwise unsatisfied
requirement for RPC. [0256] 7. At (11) the logic is repeated for
each of the other two phases in the station. [0257] 8. At (12),
only if there is no external RPC request, the HDE dispatches the
DES units, per phase, per feeder, to achieve unity power factor at
each phase of each substation feeder breaker. Contrary to external
RPC requests, DES units can be dispatched to either generate or
compensate for reactive power. On any feeder phase, if DES capacity
to provide RPC is greater than demand, the output of all units is
reduced proportionate to their reactive power maximum output.
Reactive Power Dispatch Examples
[0258] The following examples illustrate graphically the way the
algorithm of the previous Section is applied. In the graphics, the
shaded areas show reactive power on the given feeder phase. Green
shaded areas show a feeder phase with an over-compensated, net
negative (or capacitive) power factor, and a gold shaded areas show
a feeder phase with an under-compensated, net positive (or
inductive) power factor.
[0259] Referring to FIG. 9a, in this first example on the left side
of the graphic, the base loading of phase A on four feeders, before
application of DES RPC is shown. Feeder number 1 has the most
uncompensated inductive loads, while feeder 4 has overcompensated
load, presumably caused by over-application of switched capacitor
banks on the feeder. The example shows the allocation of reactive
power to meet an external request, when the external request is for
slightly more compensation than that necessary to produce unity
power factor on Feeder 3, phase A. Feeder 3 is brought to neutral
power factor, and feeders 1 and 2 are reduced proportionately to
their respective available RPC. Feeder 4 is unaffected since its
reactive power was already over-compensated.
[0260] Referring to FIG. 9b, this second example shows the
allocation of reactive power to meet an external request, when the
external request is for more compensation than would be needed to
bring the specified phase (Phase A in the example) on all of the
under-compensated feeders (F1-F3) to unity power factor. The
additional required compensation is allocated proportionately,
relative to remaining RPC capacity, among all DES units on the same
phase on all feeders.
Distributed Temperature Sensing Control
[0261] Using DES in conjunction with distributed temperature
sensing it is possible to control feeder loading. DTS includes an
add-on module, hardware, software or combinations thereof that
calculates real-time feeder maximum loading in amps. It is possible
to use a relatively simple algorithm that substitutes DTS-based
real-time feeder capacity value, per-phase, for the DES's feeder
capacity setting. It also allows for distribution of the DES
discharge as described above.
[0262] It is also possible to predict feeder loading using
virtually any load prediction algorithm and if over capacity of the
feeder is anticipated for some time period, day, hour, etc., to
optionally reserve all DES capacity to reduce feeder conductor
loading when needed. This also allows for the release of the
reserved capacity when the loading peak has been reached.
[0263] From the DTS data, it is possible to extrapolate thermal
rise and feed this predicted expected maximum cable temperature
parameter into the DTS model and to control DES discharge to limit
to the worst-case thermal capacity calculated.
[0264] Auto sectionalizing, auto reconfiguration technology, such
as the IntelliTEAM distribution automation system allows for
management of cable loading based on shifting normally open point.
Using auto reconfiguration technology, it is possible to move the
normally open point to reduce load based upon DTS-calculated
capacity or to alleviate cable loading based upon DTS data or
predicted cable maximum temperature. In similar manner, it is
possible to rotate the normally-open point to distribute thermal
overload to other cables.
Fault Direction Determination
[0265] In an offline UPS or a disconnect switch for a microgrid,
measurement of voltage sags are a primary method of determining
when the utility has a disturbance. FIG. 13 shows a one line
diagram of a Microgrid or offline UPS system. A method for
determining utility disturbances that is very rapid and robust is
to do a sliding 1/2 cycle RMS voltage measurement (as described in
the UDM patent). This works well for voltage sags caused by
electrical faults in the utility. However, if the voltage sag is
caused by an electrical fault in the load, the ideal solution is to
continue to supply the load with the utility. This is because the
UPS or Microgrid will have a larger voltage sag when supplying
fault current than the utility. On the other hand, faults in the
utility are best isolated from the microgrid or UPS load allowing
the UPS or microgrid generation to carry the load. The
determination of where the fault is in relation to the disconnect
switch allows for ideal decision making. Additionally, this
determination must be made very quickly (sub cycle) so the sagged
voltage is quickly removed from the load when the fault is not in
the load.
[0266] Using current magnitude through the disconnect switch will
often work, but it has the problem that if there is generation or
motor loads in the load when the fault occurs, high magnitude
currents will flow from the load to the utility. In the case where
the load is back feeding a fault in the utility, current magnitude
alone can lead to an incorrect decision. To eliminate this problem,
a means is needed to look at the change in power and VARs including
the direction to determine if the fault is in the utility or in the
load. In addition, this must be done at the same time the voltage
is sagging so when the decision is made to disconnect due to a
voltage disturbance, the location of the fault can be determined.
This requires that the magnitude and direction of the current be
determined in 1 to 10 ms.
[0267] Power and VAR flow direction is needed to determine the
direction of the fault. This can be accomplished by three phase to
two phase calculations that allow instant calculation of power and
VARs. These are shown in FIG. 14. Line to neutral instantaneous
voltages are converted to Vds and Vqs using a Clarke transform.
These are then used to calculate Vdr and Vqr in a Park transform.
The angle used in the Park transform is developed by adjusting
.theta. to keep Vqr near 0 using a PI regulator. When this is done,
Vdr is the magnitude and Vqr can be assumed to be zero. This
simplifies the calculations. Normally Power=Vdr*Idr+Vqr*Iqr and
VARs=Vdr*Iqr-Vqr*Idr. However, if Vqr is held near 0, the
calculation of Power and VARs is simplified as shown in FIG.
14.
[0268] .theta. is then used in the current three phase to rotating
two phase conversion as well. When this is done, power (instant)
can be calculated as Vdr.times.Idr. VARs (instant) can be
calculated as Vdr times Iqr. These values are instantly correct
allowing their use as the voltage is sagging. Because of the
transient nature of the disturbance, a filter may be needed.
[0269] To decide if the voltage disturbance is in the utility
source or the load, the following logic can be used. This logic
looks at the magnitude of the voltage sag, and compares it with the
magnitude predicted if the sag was caused by the load. If the
magnitude of the predicted voltage sag is at least half of the
magnitude predicted by the change in current, the fault is in the
load and the disconnect switch is left closed. If the fault is
determined to not be in the load, the disconnect switch is
opened.
[0270] Below is code that could be used to make this decision:
TABLE-US-00001 // This is pseudo code for detecting a downstream
fault // A one line diagram is included in the disclosure //
Positive Idr is current in the direction to supply the load
resistor // Negative Iqr is current in the direction to supply the
load inductor // Theta is the angle that is in phase with the A
phase voltage such that // Vqr is zero. These calculations are not
shown, but the algorithm is shown // in the block diagram. //
Calculations assume counter clockwise rotation, a rinsing, b
rising, // then c rising voltages. LineImpedanceX = 0.06; // set
the line impedance due to inductance to 6% on a 1 PU current basis
LineImpedanceR = 0.02; // set the line impedance due to resistance
to 2% LineImpedance = (LineImpedanceX.sup. 2 + LineImpedanceR.sup.
2).sup. 0.5; // complex sum of the impedances // Put in the
overload capability at the moment. This can be a calculated //
value, or may be a fixed value. OverLoadX = 1.0; // shown as a
fixed value for simplicity OverLoadR = 0.1; // shown as a fixed
value for simplicity // start with the voltage Clarke transform
using the measured // instant line to neutral voltages Va, Vb, and
Vc // Scaled with Vdr = 1 at 100% voltage Vds = (2/3 * Va) - (1/3 *
(Vb + Vc)); Vqs = 1/3.sup. .5 * (Vb - Vc); // Now do the Park
transform using Theta of the PI regulator shown in the diagram Vdr
= (Vds * Cos(Theta)) + (Vqs * Sin(Theta)); Vqr = (Vqs * Cos(Theta))
- (Vds * Sin(Theta)); // Current Clarke transform using the
measured // instant line currents Ia, Ib, and Ic // scaled so an
output of 1 is 1 PU current as used to calculate impedance Ids =
(2/3 * Ia) - (1/3 * (Ib + Ic)); Iqs = 1/3.sup. .5 * (Ib - Ic); //
Now do the Park transform using Theta Idr = (Ids * Cos(Theta)) +
(Iqs * Sin(Theta)); Iqr = (Iqs * Cos(Theta)) - (Ids * Sin(Theta));
FilteredVdr = Lowpass(Vdr); // Lowpass filter of 1 to 100 seconds
typical FilteredIdr = Lowpass(Idr); // Lowpass filter with same
time constant as Vdr FilteredIqr = Lowpass(Iqr); // Lowpass filter
with same time constant as Vdr DeltaVdr = FilteredVdr - Vdr; //
this is the change in Vdr DeltaIdr = FilteredIdr - Idr; // this is
the change in Idr DeltaIqr = FilteredIqr - Iqr; // this is the
change in Iqr DvFromIdr = DeltaIdr * LineImpedanceR; // expected
voltage drop from real power increase in load DvFromIqr = -DeltaIqr
* LineImpedanceS; // expected voltage drop from reactive power
increase in load DvTotal = DvFromIdr + DvFromIqr; // total expected
voltage drop // here is the logic to determine if a fault is
downstream. // VaRms is a half cycle sliding window RMS calculation
FaultIsDownstream = False; // if any phase is below 90% of nominal
votlage and // the Microgrid or UPS can not supply the increased
Power or VAR load if(((VaRms < 0.9) || (VbRms < 0.9) ||
(VcRms < 0.9)) && ((DeltaIdr > OverLoadR) ||
(-DeltaIqr > OverLoadX))) { if(DvTotal > (0.5 * DeltaVdr)) //
if the voltage sag can be attributed at least 50% // to increase in
power or Vars in the load { FaultIsDownstream = True; // Do not
open the switch between the utility and the load } }
[0271] The last part of the logic looks at the increased current to
see if the UPS or Microgrid can supply the current with its
remaining capability including its overload capability. If the
increase in current is less than what the Microgrid or UPS can
supply, then it is OK to disconnect from the utility because the
increased current is available. In fact, often an inverter based
supply can hold its output voltage constant in the face of changing
loads including overloads. This can result in correcting the
voltage even with a low level downstream fault.
[0272] FIG. 15 shows a process for opening and closing the utility
disconnect switch.
Autonomous Operating Mode
[0273] Substation loads for residential customers are somewhat
predictable. These loads are affected by the time of day, day of
week, and temperature. If a distributed energy storage (DES) system
is used to reduce peak loads, the amount of storage required at any
given time should be predictable based on these factors. Weekdays
tend to be very similar to each other. Weekends and Holidays are
likewise similar, but different from weekdays. If the desired
discharge and charge profiles are known for past weekdays at a
given temperature, the desired discharge for a weekday could follow
that profile and be relatively close to the optimal discharge
profile, even without a higher system knowledge.
[0274] This suggests a way to `learn` what the optimal discharge
and charge profiles would be based on temperature and either
weekday or weekend/holiday. It assumes that there is a controller
that knows much more about the load on the distribution system than
simply the time of day and temperature, and it dispatches the
storage in an optimal way based on this much greater level of
knowledge.
[0275] A DES that is controlled by a central controller such as the
HUB may have several arrays of recorded charge and discharge data.
These arrays may be two-dimensional but could be further
multi-dimensional. For example, they may have the half hour of the
day (48) and the ambient temperature in 5.degree. C. increments
from -40.degree. C. to 50.degree. C. (18). There may be an array
for weekdays and an array for weekends/holidays, or there may be an
array for each day of the week and one for holidays.
[0276] The array may contain a filtered power level from -1 to 1
per unit (PU) with a typical resolution of 1%. This data can be
then stored in less than 1K bytes of data per array. Alternately
higher resolution data could be stored, this could double the
storage requirements, but would achieve much greater accuracy. For
the simplest system with weekdays and weekends/holidays this
results in the need for less than 2K bytes of data.
[0277] The storage may work as depicted in FIG. 13.
[0278] When first deployed, each hour would have a fixed value that
is outside the range of -1 to 1 PU. As an example, a value of 1.27
PU might be used as the default for un-modified data.
[0279] When the DES is placed in service, the system would start
recording data. So if the weekday time was between 0100 and 0130
and the DSS was charging at an average of 25% power for the half
hour, while the outside temperature averaged 16.degree. C. for the
half hour, the weekday array data for this time and temperature
would be changed from 1.27 PU to -0.25 PU. In the next half hour if
the system stopped charging, the data for the next half hour and
the average temperature during that time would be changed from 1.27
PU to 0.0 PU.
[0280] After a few days, there will be some additional data at the
same time and temperature. This would be used to modify the
existing data in a filtered way. For example, if the filter
constant is 0.25 and the new data for the 0100 to 0130 time at
15.degree. C. to 20.degree. C. was charging at 37%, the new array
value would be calculated as
NewValue=OldValue+(TodaysValue-OldValue)*FilterValue. For the
example given, OldValue is -0.25, TodaysValue is -0.37 and
FilterValue is 0.25, then NewValue=-0.25+(-0.37-(-0.25))*0.25. This
gives a new value of -0.28, or 25% of the way between the old and
new values. Over time the array will fill up and will represent the
usage of the DSS system.
[0281] When communication is lost, the DES will revert to this
stored usage value. For example if it is a weekday between 0100 and
0130 and the temperature is between 15.degree. C. and 20.degree.
C., the DES will look up its operating point and see that it is
-0.28 PU. If the battery can charge, the battery will charge at
-0.28 PU until communication is restored. When communication is
restored, the DES will follow the commands sent by the
controller.
[0282] If the data for the time and temperature is 1.27 PU
indicating that there is no data for that particular time and
temperature, the DES will first look up one temperature step to see
if there is data at that temperature. If there is, it will use that
data, if not it will look down one temperature step. If there is
valid data it will use that data, if not it will look up two
temperature steps and so on. If there is no valid data, the system
will turn off. Of course, the system could look down temperature
data first or it could find the closest temperature to the ambient
temperature that has data and use that data. Additional factors
could also be used to determine this data like wind speed.
Special Circumstances Operating Modes
[0283] The above documented features of DES unit control via a Hub
control device describe various, generally regular scenarios for
scheduled discharge and charge based upon peak loading and capacity
mitigation. For example, the system may be designed to charge the
batteries at night when demand is low, and discharge during peak
loading, typically during the day. The system is intended to
support thousands of DES units managed in dozens to perhaps
hundreds of individually-scheduled Groups.
[0284] The problem with this approach is that special operating
circumstances may arise, e.g, if a storm rolls in, suddenly
changing the priority of the system operator. For example,
anticipating a storm the system operator may want all DES units
charged to their maximum to be ready to back up customers for as
long as possible and to be able to reduce load for circuits
suddenly reconfigured. An already over-taxed operator may spend
significant time reconfiguring for this unexpected event.
[0285] Special operating circumstances allow the system to be
instantly reconfigured, allowing units to be charged at the maximum
rate but subject to all the capacity constraints programmed-in.
Since storms can be unpredictable, a quick, reliable
reconfiguration feature would reduce the amount of time that the
system was off-normal, and increase the comfort level of the
operator in switching the system to this off-normal state and then
back again.
[0286] The Hub therefore may be configured with one or more special
circumstances override functions, e.g., a storm anticipation
function. Upon activating the "storm anticipation" function, by
pressing perhaps a single storm anticipation button, the system
operating mode, exclusive of DES units with a local or remote,
manual override present, and exclusive of units on feeders or
transformers with any, load-side units discharging to address a
programmed capacity constraint, will switch to demand-limited
charge mode. They will remain in this mode until the system
operator switches the special circumstances mode to disabled.
Options can be created to easily override specific (feeder,
transformer) capacity constraints. Another option will allow the
charging to either override or maintain an external demand
limits.
TABLES
TABLE-US-00002 [0287] TABLE 1 Terminology Term Definition
Transformer Specifically, this refers to the station (or
substation) transformer supplying the DES fleet. For simplicity it
is assumed that one transformer supplies all feeders controlled by
the Hub, however those skilled in the art will recognize that more
complex arrangements such as parallel-connected transformers can be
easily accomodated. Each transformer is outfitted with current and
voltage sensing and monitoring, such that the voltage, current, and
V-I phase angle/VAR circuit parameters can be accessed by the Hub.
This same sensing point provides the measurements of station demand
for system-wide energy management. Feeder The three-phase circuit
leading out of the station, and on which the DES Units are
deployed. Similar to the Transformer, the feeder has sensing at the
station to provide the necessary information on power and VARs.
Station Short for distribution substation-where all of the Hub's
feeders typically connect to the transmission source through a
step-down transformer, with dedicated circuit breakers at the
transformer supply and at the head of each feeder. Fleet A term for
all DES Units controlled by the Hub. For simplicity, it is assumed
that one Hub controls all the DES units connected to load served by
the substation. Group A customer-specified means to organize the
DES fleet into a collection of Units running the same algorithm
with the same settings. Units within a group share settings and to
some extent, as a result, are discharged and charged in unison,
with proportional variation based upon individual differences in
things such as state of charge/discharge, reserve power, unit size,
etc. An instance of a group consists of units that are all on the
same phase. A group is configured with properties that are
identical from phase to phase, but is managed as three, independent
instances of the group. In other words, the settings for the group
apply uniformly to each of three individual phases, but the
dispatching of the units on each phase is independent of
dispatching units on either of the other phases. A group must be
completely-contained within a zone (see below). Zone A section of
three-phase feeder bounded by electrically-controllable
sectionalizing switches. A group must be completely contained in a
zone. Demand The real component of power flow, as measured in watts
or multiples thereof. Energy Power flow integrated over time, as
measured in watt-hours or multiples thereof.
Table 2: Settings and Configuration Variables Used by the HDE
TABLE-US-00003 [0288] TABLE 2a Hub Global Settings Variable
Description Real Power Dispatch Enable True (non-zero) if AUTOMATIC
control of real power dispatch is enabled. This is a master control
enable/disable for the Hub's real power dispatch engine. External
Three-Phase Demand Trigger A setpoint indicating, the maximum
amount of demand that this station should attempt to limit itself
to. Although this is a setpoint, it is expected to be modified
frequently to support the needs of the EMS system. The value is
specified and applied as a three phase total. Reactive Power
Dispatch Enable True (non-zero) if AUTOMATIC control of reactive
power compensation (RPC) dispatch is enabled. This is a master
control enable/disable for the Hub's reactive power dispatch
engine. (reference to) Schedule ID for reactive The master schedule
to use if reactive power power dispatch compensation (RPC) dispatch
is enabled. During an scheduled active period, the RPC dispatch
engine responds to external requests for RPC, and if an external
request is not active, then DES RPC dispatch controls each feeder
to unity power factor at each feeder breaker. External Three-Phase
Reactive Power A setpoint indicating an amount of reactive
Compensation power compensation, in units of KVAR, that should be
dispatched from the entire fleet. The value is specified as a
three-phase total, but is divided by three before being dispatched
in three equal amounts to the DES fleet. Reserve Power Proportional
Reduction A dynamically-adjustable setpoint in the hub that allows
for a system-wide proportional decrease in the Reserve Capacity for
Islanded Operation. This parameter allows additional energy to be
used to relieve an overload situation. The parameter ranges in
value from 0 to 1.0, with a default of 1.0 (no reduction). Station
Name A unique identifier of the station in which the Hub operates.
Text string. Hub ID A unique identifier of the Hub Controller. Text
string, length TBD. Hub IP Address The address of the Hub when
accessed from the SCADA system. This would be the address of a DNP
Device Server providing the interface to the SCADA or DMS system on
behalf of the Hub. Hub DNP Address 16-bit DNP address unique to the
Hub within the DNP Device Server Hub DNP Definition The
fully-qualified name of the file containing the XML definition of
the DNP implementation for the Hub as seen by the SCADA system. The
XML definition is a convenient way to define the DNP points as
named variables and to associate the actual DNP point numbers and
related information for each named variable. Transformer
Three-Phase Demand A setpoint defining the minimum transformer
Trigger Minimum demand for scheduled demand limiting discharge. The
equivalent single phase value is determined by dividing by three
and the discharge is managed on a per phase basis. During
operation, the minimum may be raised if it is determined that there
is not enough stored energy to meet the desired transformer loading
requirements.
TABLE-US-00004 Table 2b Feeder-Specific Settings Variable
Description (list of) Feeders A repeating group of information
associated with each feeder. Feeder Three-Phase Feeder equivalent
of Transformer Demand Trigger Three-Phase Demand Trigger Minimum
Minimum Feeder Three-Phase A setpoint indicating the maximum
desired Charge Trigger three-phase demand of the feeder. Note that
at the feeder level, maximum demand is specified as a three-phase
setpoint but is managed as three, independent per-phase settings on
a phase-by-phase basis. Feeder ID A text string uniquely
identifying the feeder, 16 bytes. Feeder Breaker IP Required for
data acquisition of feeder Address demand, voltage, and power
factor information. Feeder Breaker Required for data acquisition of
feeder DNP Address demand, voltage, and power factor information.
Feeder Breaker The fully-qualified name of the file DNP Definition
containing the XML definition of the DNP implementation for the
breaker, including version information and point list with assigned
names for use by the application.
TABLE-US-00005 TABLE 2c Group settings Variable Description (list
of) Groups A repeating group of information about a Group. Group ID
A text string uniquely identifying the Group, 16 bytes. Hub ID A
text string identifying the Hub to which this group is associated.
Group Discharge Algorithm An enumerated value-One of: STANDBY.
Units in the group are not in service for discharge. MANUAL
DISCHARGE (Discharge rate is user-specified subject only to voltage
and other high-priority overrides). SCHEDULED FIXED DISCHARGE POWER
PRIORITY (discharge according to the ''Fixed Discharge Schedule and
settings'', limiting time if energy is low). SCHEDULED FIXED
DISCHARGE DURATION PRIORITY (discharge according to the ''Fixed
Discharge Schedule and settings'', limiting discharge rate if
energy is low). DEMAND LIMITING SCHEDULE (see algorithm in text).
(reference to) Schedule ID for fixed This points to the relevant
schedule for discharge discharge of the Group if it is scheduled
for fixed discharge. Fixed Discharge Rate If this group is using
fixed discharge scheduling, this is the total desired discharge
rate in KW for the group. Note that this may be reduced during
operation due to capacity limitations within the group (see
available discharge rate below). (reference to) Schedule ID for
demand If the group is being scheduled using Demand limited
discharge Limiting discharge, this points to the relevant schedule.
Group Charge Algorithm An enumerated value-One of: STANDBY. Units
in the group are not in service for charging. SCHEDULED FIXED
CHARGE (charge according to the ''Fixed charge schedule and
settings'', DEMAND LIMITING SCHEDULE (see algorithm in text).
(reference to) Schedule ID for fixed If the group is being
scheduled using the Fixed charging charge algorithms, this points
to the relevant schedule. Fixed Charge Rate If the group is
configured to charge with a fixed charge rate, this is the total
desired charge rate in KW for the group. Note that this may be
reduced during operation due to capacity limitations within the
group (see available charge rate below). (reference to) Schedule ID
for Demand If the group is being scheduled using Demand Limiting
Charge Limiting charge, this points to the relevant schedule. (list
of) Schedules This is a repeating group specifying the time period
during which the scheduled algorithm can be active. Note: The
schedule structure is shared by all of the charge and discharge
algorithms including reactive power compensation. Therefore not all
parameters are used by all scheduling algorithms. Each table row
contains separate columns to support unique time periods on each
day of the week, plus an additional holiday/weekend entry. Each DES
Group's fixed discharge schedule, for example, a single row of the
repeating group, contains all of the data elements relevant to each
calendar day of the week, plus one additional entry for holidays,
total of 8 entries. Any scheduled active period that spans midnight
can continue into the following calendar day. Schedule ID A unique
string identifying the schedule. Schedules may be re-used for
different groups, and a schedule can contain configured parameters
for differing algorithms, but only one set of parameters for a
charge algorithm, or one set of parameters for a discharge
algorithm, can be actively in use at one time. Algorithm Type
Category of algorithm this schedule is to be used for. Either
''Charge'', ''Discharge'', or ''RPC'' should be specified.
Algorithm For charging algorithms, this is either ''Fixed Charge''
or ''Demand Limited''. For discharge algorithms, this is either
Fixed Discharge'' or ''Demand Limited Discharge''. This field is
ignored for RPC. Start Time In schedules, the time within a single
day when the scheduled algorithm becomes active, specified in hours
(0-23) and minutes (0-59) past midnight. Ramp Up Time (Applicable
to fixed discharge/charge schedules only) the amount of time (in
minutes) during which charge/discharge power should be ramped,
linearly, between zero and the predetermined output level
(Discharge/Charge Rate). Note that if the output level is reduced
due to capacity limitations in the Units, the effective ramping
rate will be reduced but the time should remain as specified. This
also applies to ramping down. Duration The amount of time (in
minutes) during which charge/discharge is to remain at the
predetermined Charge/Discharge Rate. Excludes ramp up and ramp down
times. For demand limited charge/discharge, and for RPC, this is
the total amount of time the algorithm is to be applied. Ramp Down
Time (Applicable to fixed discharge/charge schedules only) The
amount of time (in minutes) during which power should be ramped
down, linearly, from the predetermined output level to zero. Note
that if the output level is reduced due to capacity limitations in
the Units, the effective ramping rate will be reduced but the time
should remain as specified.
TABLE-US-00006 TABLE 2d DES Unit-specific settings Stored in Unit =
Yes, = RO from Variable Hub.sup.1 Description Unit ID A 16,
alphanumeric character name to identify the unit to the system. DNP
Address The DNP address of the DES Unit IP Address IPv4 address of
the DES Unit. Unit DNP Definition The fully-qualified name of the
file containing the XML definition of the DNP implementation for
the DES Unit, including version information and point list with
assigned names for use by the application. Note: This file could be
stored in the DES Unit and made available on demand. Maximum Rated
Discharge The nameplate rating value for the maximum discharge
rate, in kVA, that the Unit is engineered to produce. Note that
when maximum real power output is required, reactive power output
is zero, and the nameplate kVA rating of the unit is also equal to
its maximum real power output as measured in kW. Group Assignment
The number of the Group (8-bit unsigned integer) this unit is
assigned to. Phase An enumeration of the identification of which
feeder phase a DES Unit is connected-to. Reserve Capacity for
Islanded The amount of capacity, in percent, that is reserved for
Operation operation in Islanded mode. This capacity does not
include a second, smaller percentage of capacity reserved for
Depleted Battery Reserve (see below). Depleted Battery Reserve A
percentage of energy storage capacity (kWH), that is not to be used
for either Islanded Operation or any overload reduction. This
energy is left in the battery to insure that the unit can withstand
long periods of outage without completely draining the battery and
risking possible damage. Reliability Reserve A percentage of energy
storage capacity (kWH), that is not to be stored for either
Islanded Operation or any demand reduction. When charging, this
amount of energy is left out of the battery to insure that the unit
can act to reduce voltage when necessary. For example, during
periods of peak demand, it is possible, for a Unit near a source of
supply to find its line voltage excessively-high. In this
circumstance the unit should use that excess to charge its
batteries to reduce voltage. .sup.1RO from Hub means that the value
may not be sent from the Hub to the DES Unit. The data may be
entered in the database, but may be superseded (replaced) when the
Hub updates its information about the unit.
TABLE-US-00007 TABLE 3a HDE-calculated global variables used in the
disclosure Variable Description transformer per-phase This is the
demand limit for load following and demand trigger is equal to 1/3
of the actual measured three phase transformer demand at the start
time (Demand Limiting Start Time) unless the demand at that time is
less than the Transformer Three-Phase Demand Trigger Minimum. Each
phase will be managed independently with the intent to maintain
this demand. corrected transformer This is the measured demand, in
KW, per per-phase demand phase, at the station transformer, with
the present amount of DES discharge on the same phase having been
added. The corrected value should closely represent the demand that
would be present without DES units in service. corrected external
This is the sum of corrected transformer per- three-phase demand
phase demand over all phases. unsatisfied transformer A sum over
all Units on a given phase in a overload station, of transformer
demand that cannot be satisfied by discharging Units on feeders
that are under capacity.
TABLE-US-00008 TABLE 3b Hub Feeder-Specific Calculated Variables
Variable Description feeder per-phase Feeder Equivalent of
transformer per-phase demand trigger demand trigger. feeder
per-phase This is the measured demand, in KW, per demand phase, at
the head of the feeder. corrected feeder This is the measured
demand, in KW, per per-phase demand phase, at the head of the
feeder, with the present amount of DES discharge having been added.
The corrected value should closely represent the demand that would
be present without DES units in service. feeder per-phase Feeder
Three-Phase Charge Trigger setpoint charge trigger divided by
three. per-phase aggregated This variable holds a simple sum of the
discharge level aggregated percentage discharge of all DES Units.
This is calculated during charging and is used to establish the
proportionate discharge which is applied to requests for demand, in
kW, for charging Units.
TABLE-US-00009 TABLE 3c Hub Group-Specific Calculated Variables
Variable Description available discharge rate For a Group
configured for fixed, scheduled discharge, the actual, amount of
real power, in KW, that can be cumulatively-supplied by the group
in real-time.
TABLE-US-00010 TABLE 3d Hub Unit-Specific Calculated Values
Variable Description fixed discharge For a member of a Group
configured for fixed, rate*** scheduled discharge, this is the
discharge rate, in KW, assigned to this member in real-time. manual
For DES units that are in a manual override contribution*** state,
this is their actual discharge rate in KW. This value is read from
each DES Unit. scheduled maximum During evaluation of energy
discharge or contribution charging requirements, this variable
contains each unit's maximum, dispatchable output in KW limited by
such factors as whether or not its group is scheduled to be
available for discharging, whether the feeder, transformer or
station is above its capacity limitations, and other similar
factors. As discussed in the text, this value is based on unit
energy and power ratings, state of charge, reliability reserve,
depleted battery reserve, and reserve scaling factors. This value
does not reflect voltage or power constraints which may also affect
the maximum contribution that an individual unit may make. final
discharge During an evaluation interval, this is the rate***
discharge rate, in kW that will be sent to the Unit from the Hub.
final charge rate*** During an evaluation interval, this is the
charge rate, in kW that will be sent to the Unit from the Hub. The
actual amount of energy stored in the battery, based on this level
of power draw will vary based on the battery's ability to store
charge. allocation to feeder For any phase on any feeder that is
operating overload in an overloaded condition, this is the
scheduled, available capacity that is allocated to reducing the
demand. It is proportioned equally based upon Unit size, in KW,
over all Units on the feeder phase. allocation to For any phase on
the transformer that is transformer operating in an overloaded
condition, this is overload the scheduled, available capacity that
is allocated to reducing the demand from feeders that are not
overloaded. It is proportioned equally based upon Unit size, in KW.
allocation to For any phase on the transformer that is transformer
overload operating in an overloaded condition, this is from
overloaded the scheduled, available capacity that is feeders
allocated to reducing the demand from feeders that are overloaded.
It is proportioned equally based upon Unit size, in KW, over all
Units on the appropriate phase and feeder. allocation to The amount
of demand to be discharged from external station each DES Unit to
satisfy demand reduction demand reduction requested from an
external source. The demand is satisfied by each unit in proportion
to its ability to satisfy the requirement, after all other demand
requirements have been satisfied. dispatchable The amount, in kWH,
of available capacity of capacity the unit which can be dispatched
to meet peak shaving requirements or utilized for reactive power
management. This value excludes the reserve for islanding, depleted
battery reserve, or reliability reserve. per-phase scheduled For a
given feeder phase, this variable holds maximum each unit's
nameplate-rated maximum contribution contribution to demand
reduction or to charge restoration (energy storage). per-phase For
a given feeder phase, this variable holds dispatchable the amount
of demand, in kW, that is available charging demand to be allocated
for dispatchable (neither fixed or manually-controlled) charging of
Units. ***These variables contain the Hub' s allocation of the DES
energy discharge, in KW, to each individual DES Unit.
TABLE-US-00011 TABLE 4a DNP Communication Interface: DES Unit
Analog Input Points Point # Description Access Units Type Comments
0 Line1Volts Read Volts * 100 INT16 VAC RMS as measured from L1-N 1
Line2Volts Read Volts * 100 INT16 VAC RMS as measured from L2-N 2
XfmrPrimaryVoltageEst Read Volts * 100 INT16 Transformer
Primary-Side Voltage Estimate, based on secondary side voltage +/-
the drop/rise due to current through the impedance of the
transformer, reported on a 120VAC nominal scale basis. 3 Line Power
Read kWatts * INT16 With the scale factor in the MCU set as
positive the following 10 sign convention applies + for Watts from
grid to load/battery (charging/consuming) - for Watts from
generation/battery to grid (discharging/producing) 4 Line Vars Read
kVARs * INT16 With the scale factor in the MCU set as positive the
following 10 sign convention applies + for capactive VARs - for
inductive VARs 5 DES Storage Power Read kWatts * INT16 With the
scale factor in the MCU set as positive the following 10 sign
convention applies + for Watts from battery to grid/load
(discharging) - for Watts from grid to battery (charging) 6 DES
Storage Vars Read kVARs * INT16 With the scale factor in the MCU
set as positive the following 10 sign convention applies + for
producing/capacitive VARs from DES Storage - for
consuming/inductive VARs from DES Storage 7 Battery State Of Charge
Read % * 10 UINT16 Battery State Of Charge 8 Islanded Duration Read
minutes UINT16 Duration of presently Active Islanding operation (0
if Islanding is Inactive) 9 AvailableEnergy Read kWH * 100 UINT16
The amount of stored energy in kilo-watt-hours available for
dispatchable discharge. This is exclusive of charge reserved for
backup/islanding. Range is 0-2500 for 25 kWH battery, 0- 10,000 for
a 100 kWH battery, 10 PercentAvailableEnergy Read % * 10 UINT16 The
amount of stored energy as a percentage of the unit rating
available for dispatchable discharge. This is exclusive of charge
reserved for backup/islanding.
TABLE-US-00012 TABLE 4b DNP Communication Interface: DES Unit
Analog Output Points point description access type format Comments
Limits 0 RealPowerSetpoint R/W kWatts .times. 100 INT16 With the
scale factor in the MCU set as Active over the range of positive
the following sign convention -25 kW to +25 kW, A applies setting
of 2500 will set + for Watts from battery to grid/load the output
to 25kW (discharging) - for Watts from grid to battery (charging) 1
ReactivePowerSetpoint R/W kVAR .times. 100 INT16 With the scale
factor in the MCU set as Active over the range of positive the
following sign convention -25 kVAR to 25 kVAR, A applies setting of
2500 will set + for producing/capacitive VARs from DES the output
to 25kVAr STORAGE - for consuming/inductive VARs from DES STORAGE 2
MaxSOC R/W % * 10 INT16 The maximum state of charge for protection
of the battery during peak-shaving / dispatched-power operation.
0-100.0, default = 100.0% 3 DepletedChargeReserve R/W % * 10 INT16
The minimum state of charge for self 0-100.0, default = 1.0%
(a.k.a. MinSOC) protection and extended outage recovery. 4
BackupReserve (a.k.a. R/W % * 10 INT16 Charge reserved for
providing backup 0-100.0, default = 20.0% MinSOC-CS) power. This is
the lowest the SOC will be allowed to go when discharging in non-
islanded current-source operation. 5 BackupReserveScaleFactor R/W %
* 10 INT16 This is a scale factor applied to point #4 0-100.0,
default = 100.0% (BackupReserve) to reduce the BackupReserve. A
value of 100.0 indicates no reduction in the BackupReserve, a value
of 0 would indicate reduction of the BackupReserve to 0%
TABLE-US-00013 TABLE 4c DNP Communication Interface: DES Unit
Digital Input Points point # description access format Comments 0
Enabled Read Bit Set if the system is presently enabled 1 LocalMode
Read Bit Set if the system is presently switched to local control
mode (versus remote/SCADA control mode) 2 Running in Islanded Mode
Read Bit Turned on when the Unit has moved to islanded mode because
of a loss of synchronism, voltage disturbance, or manual request 3
LocalSettingChange Read Bit Set if a setting change has been
entered and activated locally. The purpose is to inform the Hub
that it's unit settings database must be updated. 4
LocalUserLoggedIn Read Bit Set if a local user has logged in to the
DES unit, Cleared on logout and/or timeout. 5 RemoteUserLoggedIn
Read Bit Set if a remote user has logged in via the SCADA/DNP
interface, Cleared on logout and/or timeout 6 DSP Comms Error Read
Bit Set on communications Timeout from DSP to MCU (MCU watches for
change in UnixTime value from DSP and set/clears based on
difference between present value and MCU UnixTime, using a
threshold). 7 AcBreakerState Read Bit 0-indicates open 1-indicates
closed 8 DcBreakerState Read Bit 0-indicates open 1-indicates
closed 9 SetpointNotAccepted Read Bit 0-Setpoint good 1-Setpoint
not good 10 Spare Spare 11 Spare Spare 12 Spare Spare 13 Spare
Spare 14 Spare Spare 15 Spare Spare 16 Information Alarm Read Bit
Set if there are any informational alarms active in the system 17
Warning Alarm Read Bit Set if there are any warning alarms active
in the system 18 Inhibit Alarm Read Bit Set if there are any
inhibit alarms active in the system 19 Isolate Alarm Read Bit Set
if there are any isolate alarms active in the system 20 Trip
Offline Alarm Read Bit Set if there are any hip offline alarms
active in the system 21 Self Reset Alarm Read Bit Set if there are
any self reset alarms active in the system 22 Auto Reset Alarm Read
Bit Set if there are any auto reset alarms active in the system 23
Manual Reset Alarm Read Bit Set if there are any manual reset
alarms active in the system 24 ParameterCalibrationChange- Read Bit
Set if this alarm is active Activation 25 ExecutionTimeOverrun Read
Bit Set if this alarm is active 26 ParameterCalibrationNvError Read
Bit Set if this alarm is active 27 AnyAppBrdPwrSupplyUV Read Bit
Set if this alarm is active 28 McuCommsError Read Bit Set if this
alarm is active 29 ManualReset Read Bit Set if this alarm is active
30 AutoReset Read Bit Set if this alarm is active 31 Emergency Stop
Read Bit Set if this alarm is active 32 AllPhaseLegsTripped Read
Bit Set if this alarm is active 33 UdmOverVoltage Read Bit Set if
this alarm is active 34 UdmUnderVoltage Read Bit Set if this alarm
is active 35 SystemDisable Read Bit Set if this alarm is active 36
AutoResetLockout Read Bit Set if this alarm is active 37
ScadaCommError Read Bit Set if this alarm is active 38
DcLinkDissipatorinstalled Read Bit Set if this alarm is active 39
Spare15 Read Bit Set if this alarm is active 40
IgbtGateDriveUVLine1 Read Bit Set if this alarm is active 41
InverterCurrentLimitLine1 Read Bit Set if this alarm is active 42
InverterOCLine1 Read Bit Set if this alarm is active 43
IgbtOvertemperatureWarnLine1 Read Bit Set if this alarm is active
44 IgbtOvertemperatureTripLine1 Read Bit Set if this alarm is
active 45 Spare21 Read Bit Set if this alarm is active 46 Spare22
Read Bit Set if this alarm is active 47 Spare23 Read Bit Set if
this alarm is active 48 IgbtGateDriveUVLine2 Read Bit Set if this
alarm is active 49 InverterCurrentLimitLine2 Read Bit Set if this
alarm is active 50 InverterOCLine2 Read Bit Set if this alarm is
active 51 IgbtOvertemperatureWarnLine2 Read Bit Set if this alarm
is active 52 IgbtOvertemperatureTripLine2 Read Bit Set if this
alarm is active 53 Spare29 Read Bit Set if this alarm is active 54
Spare30 Read Bit Set if this alarm is active 55 Spare31 Read Bit
Set if this alarm is active 56 AcBreakerUnsuccessfulClose- Read Bit
Set if this alarm is active Attempt 57 AcBreakerUnsuccessfulOpen-
Read Bit Set if this alarm is active Attempt 58
DcBreakerUnsuccessfulClose- Read Bit Set if this alarm is active
Attempt 59 DcBreakerUnsuccessfulOpen- Read Bit Set if this alarm is
active Attempt 60 VeryOverVoltage Read Bit Set if this alarm is
active 61 OverVoltage Read Bit Set if this alarm is active 62
UnderVoltage Read Bit Set if this alarm is active 63
VeryUnderVoltage Read Bit Set if this alarm is active 64
OverFrequency Read Bit Set if this alarm is active 65
UnderFrequency Read Bit Set if this alarm is active 66
VeryUnderFrequency Read Bit Set if this alarm is active 67 DcLinkOV
Read Bit Set if this alarm is active 68 DcLinkUV Read Bit Set if
this alarm is active 69 DcLinkMidpointUnbalanced Read Bit Set if
this alarm is active 70 IgbtThermistorShorted Read Bit Set if this
alarm is active 71 IgbtThermistorBroken Read Bit Set if this alarm
is active 72 DspFpgaHeartbeatLost Read Bit Set if this alarm is
active 73 AnyBatteryAlarm Read Bit Set if this alarm is active 74
BatteryOverTemperature Read Bit Set if this alarm is active 75
BatteryOverVoltage Read Bit Set if this alarm is active 76
BatteryUnderVoltage Read Bit Set if this alarm is active 77
BatteryOverCurrent Read Bit Set if this alarm is active 78
BatteryModuleComms Read Bit Set if this alarm is active 79
BatteryOilLevelProblem Read Bit Set if this alarm is active 80
BatteryInterlockStatus Read Bit Set if this alarm is active 81
BatteryHeaterStatus Read Bit Set if this alarm is active 82
BatteryBmsComms Read Bit Set if this alarm is active 83
VsReturnDelayActive Read Bit Set if this alarm is active 84
DischargeLimitinVsExceeded Read Bit Set if this alarm is active 85
InverterOutputLimited Read Bit Set if this alarm is active 86
WaterInUnit Read Bit Set if this alarm is active 87 Spare63 Read
Bit Set if this alarm is active
TABLE-US-00014 TABLE 4d DNP Communication Interface: DES Unit
Digital Output Points point # description access format Comments 0
EnableRequest W Bit LatchOn to remotely request automatic operation
be enabled LatchOff to remotely request automatic operation be
disabled (this request may be overridden locally via a
Remote/LocalEnable/LocalDisable selector switch) 1 ResetAlarms W
Bit PulseOn to reset ''Manual Reset'' alarms (Ignored when the
local/remote selector switch is in a local position) 2
RealPowerClamp W Bit LatchOn to clamp the Real Power setpoint value
to a locally defined parameter value LatchOff to follow the
RealPowerSetpoint received via SCADA (The locally defined parameter
value will typically be zero to effectively disable real power
compensation) 3 ReactivePowerClamp W Bit LatchOn to clamp the
ReactivePowerSetpoint value to a locally defined parameter value
LatchOff to follow the ReactivePowerSetpoint value received via
SCADA (The locally defined parameter value will typically be zero
to effectively disable reactive power compensation) 4
InhibitIslanding W Bit LatchOn to Inhibit both Automatically and
Manually Initiated Islanding LatchOff to allow either Automatic or
Manual initiation of Islanding 5 RequestIslanding W Bit LatchOn to
Manually Initiated Islanding LatchOff to allow Islanding Return to
occur (Upon Battery depletion, return to line if possible) 6
LocalSettingsChangeAck W Bit PulseOn to Acknowledge (and clear) the
LocalSettingChange point, StatusPoint #3
TABLE-US-00015 TABLE 5 Substation Transformer DNP Point List Point
# Description Units Type Comments 0 CurrentPhaseA Amps INT16 1
CurrentPhaseB Amps INT16 2 CurrentPhaseC Amps INT16 3 VoltagePhaseA
Volts INT32 Line to ground 4 VoltagePhaseB Volts INT32 5
VoltagePhaseC Volts INT32 6 RealPowerPhaseA Watts INT32 7
RealPowerPhaseB Watts INT32 8 RealPowerPhaseC Watts INT32 9
ReactivePowerPhaseA VARs INT32 10 ReactivePowerPhaseB VARs INT32 11
ReactivePowerPhaseC VARs INT32 12 TemperaturePhaseA Deg. C. INT16
Transformer Hot Spot Temperature 13 TemperaturePhaseB Deg. C. INT16
14 TemperaturePhaseC Deg. C. INT16 Note: All points below are
analog points measured on the low voltage output side of the
substation transformer
TABLE-US-00016 TABLE 6 Feeder Breaker DNP Point List Point #
Description Units Type Comments 0 CurrentPhaseA Amps INT16 1
CurrentPhaseB Amps INT16 2 CurrentPhaseC Amps INT16 3 VoltagePhaseA
Volts INT32 Line to ground 4 VoltagePhaseB Volts INT32 5
VoltagePhaseC Volts INT32 6 RealPowerPhaseA Watts INT32 7
RealPowerPhaseB Watts INT32 8 RealPowerPhaseC Watts INT32 9
ReactivePowerPhaseA VARs INT32 10 ReactivePowerPhaseB VARs INT32 11
ReactivePowerPhaseC VARs INT32 12 RealPowerCapacityPhaseA Watts
INT32 From DTS System if available 13 RealPowerCapacityPhaseB Watts
INT32 14 RealPowerCapacityPhaseC Watts INT32 15
CableTemperaturePhaseA Deg. C. INT16 From DTS System if
available-highest temp along length 16 CableTemperaturePhaseB Deg.
C. INT16 17 CableTemperaturePhaseC Deg. C. INT16 Note: All points
below are analog points measured on the input side of the each
substation feeder breaker unless otherwise noted
TABLE-US-00017 TABLE 7 Example Transformer Emergency Overload Table
per-phase per-phase Transformer Length of demand at time above Hot
Spot allowable threshold threshold Temperature Overload (kW),
(hours), (Deg. C.) (Hours) (3 values) (3 values) Comment 105
(infinite) Highest desired temperature within normal range 110 24.0
Triggering temperature for overload mitigation 115 24.0 120 12.0
125 10.0 130 8.0 135 6.0 140 3.0 150 1.0
* * * * *