U.S. patent application number 09/900849 was filed with the patent office on 2001-12-06 for integrated control system and method for controlling mode, synchronization, power factor, and utility outage ride-through for micropower generation systems.
Invention is credited to Hall, William B., Matty, Thomas C., Underwood, Thomas C..
Application Number | 20010048290 09/900849 |
Document ID | / |
Family ID | 22491027 |
Filed Date | 2001-12-06 |
United States Patent
Application |
20010048290 |
Kind Code |
A1 |
Underwood, Thomas C. ; et
al. |
December 6, 2001 |
Integrated control system and method for controlling mode,
synchronization, power factor, and utility outage ride-through for
micropower generation systems
Abstract
An integrated system for comprehensive control of an electric
power generation system utilizes state machine control having
particularly defined control states and permitted control state
transitions. In this way, accurate, dependable and safe control of
the electric power generation system is provided. Several of these
control states may be utilized in conjunction with a utility outage
ride-through technique that compensates for a utility outage by
predictably controlling the system to bring the system off-line and
to bring the system back on-line when the utility returns.
Furthermore, a line synchronization technique synchronizes the
generated power with the power on the grid when coming back
on-line. The line synchronization technique limits the rate of
synchronization to permit undesired transient voltages. The line
synchronization technique operates in either a stand-alone mode
wherein the line frequency is synthesized or in a connected mode
which sensed the grid frequency and synchronizes the generated
power to this senses grid frequency. The system also includes power
factor control via the line synchronization technique or via an
alternative power factor control technique. The result is an
integrated system providing a high degree of control for an
electric power generation system.
Inventors: |
Underwood, Thomas C.;
(Laurel, MD) ; Hall, William B.; (Annapolis,
MD) ; Matty, Thomas C.; (North Huntingdon,
PA) |
Correspondence
Address: |
Dike, Bronstein, Roberts & Cushman
Intellectual Property Practice Group of
Edwards & Angell, LLP
P.O. Box 9169
Boston
MA
02209
US
|
Family ID: |
22491027 |
Appl. No.: |
09/900849 |
Filed: |
July 3, 2001 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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09900849 |
Jul 3, 2001 |
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09535541 |
Mar 27, 2000 |
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09535541 |
Mar 27, 2000 |
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09140391 |
Aug 26, 1998 |
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6072302 |
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Current U.S.
Class: |
322/20 |
Current CPC
Class: |
H02J 3/40 20130101; H02J
3/38 20130101 |
Class at
Publication: |
322/20 |
International
Class: |
H02H 007/06; H02P
009/00; H02P 011/00 |
Claims
1. A state machine having a plurality of control states for
electric power transformation in a device having a full wave
rectifier connected to a generator, a DC bus connected to the
output of the full wave rectifier, an inverter connected to the DC
bus, an inductor unit connected to the output of the inverter, a
first contactor unit selectively connecting and disconnecting the
inductor unit to and from a grid, and a precharge circuit connected
to the DC bus; the state machine comprising: an initialization
state for initializing the state machine; a first neutral state for
idling the state machine while monitoring commands and system
parameters; a pre-charge state for enabling and monitoring the
precharge circuit to pre-charge the DC bus to a pre-charge DC
voltage; a second neutral state for disabling the pre-charge
circuit and closing the first contactor; an engine start state for
verifying DC link voltage, sending a speed command to the start
inverter unit, enabling the start inverter, updating the speed
command being sent to the start inverter unit, and determining
successful engine start; a power on-line state for enabling a
current mode in said inverter and controlling the inverter to
deliver power at a level determined by a power level command; a
power off-line state for opening the first contactor, switching the
inverter to a voltage mode, and setting the power level command to
a nominal power level; a shutdown state for disabling the inverter,
opening the first contactor after waiting for a cool-down time
period, and reinitializing the state machine, a state controller
for controlling the following permitted transitions between said
control states: said initialization state .fwdarw. said first
neutral state .rarw..fwdarw. said pre-charge state .fwdarw. said
second neutral state .rarw..fwdarw. said start engine state
.rarw..fwdarw. said power on-line state .fwdarw. said power
off-line state .fwdarw. said shutdown state.
2. The state machine according to claim 1, further comprising: a
third neutral state for receiving a command including the power
level command and a shutdown command; said state controller
permitting the following additional state transitions: said start
engine state .fwdarw. said third neutral state .rarw..fwdarw. said
power on-line state.
3. The state machine according to claim 1, said state controller
permitting the following additional state transitions: neutral
state .fwdarw. pre-charge state upon receiving a pre-charge start
command; precharge state .fwdarw. neutral state when a pre-charge
rate at which said pre-charge circuit charges the DC bus is not
within tolerance values or when the DC bus voltage does not achieve
the pre-charge DC voltage.
4. The state machine according to claim 1, said state controller
permitting the following additional state transitions: pre-charge
state .fwdarw. start engine state upon successfully achieving the
precharge DC voltage on the DC bus and receipt of a start engine
command.
5. The state machine according to claim 1, said state controller
permitting the following additional state transitions: start engine
state .fwdarw. third neutral state upon receiving a zero power
level command, third neutral state .fwdarw. power on-line state
upon successful engine start and receiving a nonzero power level
command, power on-line state .fwdarw. power off-line state upon
receipt of an off-line command or upon a failed diagnostic test or
a grid outage, power off-line .fwdarw. third neutral state upon
successful diagnostic tests for a predetermined time period, third
neutral state .fwdarw. shutdown upon receiving a shutdown command,
shutdown state .fwdarw. said first neutral state upon receiving
restart command, and said second neutral .fwdarw. shutdown state
upon a fault condition or shutdown command.
6. The state machine according to claim 1, the device further
including, an emergency stop input, said state machine controller
opening the first contactor unit and switching the control state to
said shutdown state upon receipt of an emergency stop signal from
the emergency stop input.
7. The state machine according to claim 1, said pre-charge state
and said start engine state respectively returning to said first
and second neutral states upon failure of a pre-charge cycle and a
start engine cycle.
8. The state machine according to claim 2, said power on-line state
returning to said third neutral step when the power level command
indicates zero requested power.
9. The state machine according to claim 1, wherein said
initialization, pre-charge, power on-line, power off-line, and/or
shutdown states perform diagnostic tests on the device, said state
controller controlling state transitions based on results of the
diagnostic tests.
10. The state machine according to claim 1, the device further
including an engine for driving said generator, an engine control
unit connected to said engine, and a start inverter connected to
the DC bus and to said generator, said engine control unit
controlling said engine ignition and fuel for the engine, said
engine start state controlling said start inverter to drive the
generator as a motor to thereby spin the engine and permit starting
thereof, said engine start state also sending an engine start
command to the engine control unit.
11. The state machine according to claim 10, wherein said
initialization, pre-charge, power on-line, power off-line, and/or
shutdown states monitor the engine, said state controller
controlling state transitions based on results of the diagnostic
tests.
12. The state machine according to claim 1, said pre-charge state
also diagnosing the inverter, said state controller controlling
state transitions based on results of the diagnostic tests.
13. The state machine according to claim 1, said engine start state
determining successful engine start by monitoring current drawn
from the DC bus by the start inverter and engine speed wherein if
the current drawn falls below a current limit value and an engine
speed exceeds a speed limit then engine start is successful.
14. A method of controlling real and reactive power developed by a
main inverter in an electrical power generation control device,
comprising the steps of: sampling the three-phase currents output
from said inverter, transforming the sampled three-phase current
data to two-phase current data, transforming the two-phase current
data to a rotating reference frame, controlling an output voltage
according to a comparison result between a DC reference signal
having a real and a reactive reference signal component,
transforming the output voltage to a stationary reference frame,
transforming the stationary reference frame output voltage to a
three-phase reference signal, and controlling said inverter based
on the three-phase reference signal, wherein the DC reference
signal designates the real and reactive power output by the
controlled inverter.
15. The method according to claim 14, further comprising the step
of: connecting the electrical power generation control device to a
grid, determining the value of the DC reference signal according to
utility power factor request data supplied by a utility feeding the
grid.
16. The method according to claim 14, further comprising the step
of: determining the value of the DC reference signal according to a
power factor command received from an operator interface.
17. The method according to claim 14, said output voltage
controlling step utilizing a proportional and integral control
method.
18. The method according to claim 14, said inverter control step
generating a PWM control signal based on the three-phase reference
signal to control the inverter output.
19. An apparatus for synchronizing a line frequency of power output
from an inverter with a grid frequency, comprising: a grid
frequency sensor connected to the grid and outputting a grid
frequency signal indicative of the grid frequency; an A/D converter
sampling the grid frequency signal from said grid frequency signal
generator; a signal processor controlling said A/D converter to
perform A/D conversion of the grid frequency signal at a reference
frequency; a clock connected to said digital signal processor for
establishing the reference frequency and sending the reference
frequency to said digital signal processor; a first counter for
storing a frequency count, said first counter updating the
frequency count value according to the reference frequency; an edge
detector for detecting a rising or falling edge of the digitally
converted grid frequency; a second counter for storing a
synchronization value, said second counter adding a count value to
the synchronization value according to the reference frequency; a
correct frequency range detector detecting whether the frequency
count is within a frequency range; a frequency range error
corrector for setting the count value to a predetermined count
value when said correct frequency range detector detects that the
frequency count is outside the frequency range; a count value
calculator for calculating the count value by dividing 360.degree.
by the frequency count when said edge detector detects the rising
or falling edge; a frequency count resetter for resetting the
frequency count value to zero when said edge detector detects the
rising or falling edge and said count value calculator completes
the calculation of the count value; a synchronization detector
detecting synchronization when the synchronization value is
substantially zero or 360.degree.; and a synchronization value
adjuster for adjusting the synchronization value by an error
value.
20. The apparatus according to claim 19, further comprising: an
iterator for iterating the functions performed by the apparatus
until said synchronization detector detects correct
synchronization.
21. The apparatus according to claim 19, said synchronization value
adjuster calculating the error value based on the synchronization
value, an error limiter limiting the error value to a predetermined
range of error values thereby preventing large phase shift
jumps.
22. The apparatus according to claim 20, further comprising: a
pulse width modulation signal generator for generating pulse width
modulation signals based on the synchronization value and sending
the pulse width modulation signals to the inverter, wherein the
output of the inverter is controlled by the pulse width modulation
signals.
23. The apparatus according to claim 22, further comprising; a
power factor adjuster for adding a power factor phase shift value
to the synchronization value.
24. The apparatus according to claim 23, said grid frequency sensor
including: a transformer connected to the grid, a low pass filter
connected to said transformer, and an optical isolator connected to
said low pass filter, said optical isolator outputting a uni-polar
square wave having a frequency equal to the grid frequency, said
A/D converter sampling the uni-polar square wave from said optical
isolator, and said digital signal processor controlling said A/D
converter to initiate A/D conversion of the uni-polar square wave
at a reference frequency.
25. A method for synchronizing a line frequency of power output
from an inverter with a grid frequency, comprising: detecting a
grid frequency signal; sampling the grid frequency signal;
controlling said sampling step to sample the grid frequency signal
at a reference frequency; establishing the reference frequency;
storing a frequency count value in a first counter, updating the
frequency count value stored in the first counter according to the
reference frequency; an edge detecting step for detecting a rising
or falling edge of the sampled grid frequency; storing a
synchronization value in a second counter, adding a count value to
the synchronization value according to the reference frequency;
detecting whether the frequency count is within a frequency range;
a frequency range error correcting step for setting the count value
to a predetermined count value when said detecting step detects
that the frequency count is outside the frequency range;
calculating the count value by dividing 360.degree. by the
frequency count when said edge detecting step detects the rising or
falling edge; resetting the frequency count value to zero when said
edge detecting step detects the rising or falling edge and said
calculating step completes the calculation of the count value;
detecting synchronization when the synchronization value is
substantially zero or 360.degree.; and adjusting the
synchronization value by an error value.
26. The method according to claim 25, further comprising the step
of: iterating the functions performed by the method steps until
said synchronization detecting step detects correct
synchronization.
27. The method according to claim 25, said adjusting step
calculating the error value based on the synchronization value, an
error limiting step limiting the error value to a predetermined
range of error values thereby preventing large phase shift
jumps.
28. The method according to claim 26, further comprising the step
of: generating pulse width modulation signals based on the
synchronization value, controlling the output of the inverter with
the pulse width modulation signals.
29. The method according to claim 26, further comprising the step
of: inputting a power factor phase shift value, and adding the
power factor phase shift value to the synchronization value.
30. A method of controlling a device having a full wave rectifier
connected to a generator, a DC bus connected to the output of the
full wave rectifier, an inverter connected to the DC bus, an
inductor unit connected to the output of the inverter, and a first
contactor unit selectively connecting and disconnecting the
inductor unit to and from a grid, the method comprising the steps
of: commanding the inverter to perform online voltage control;
detecting a fault condition indicating a fault in the device or the
grid opening the first contactor; clearing a time counter; setting
a mode to an offline mode; and commanding the inverter to perform
offline voltage control; said opening, clearing, setting and
commanding offline voltage control steps being performed when said
detecting step detects the fault condition or continues to detect
the fault condition.
31. The method according to claim 30, further comprising the steps
of: determining the mode when said detecting step detects no fault
condition; and incrementing the time counter when said mode
determining step determines that the mode is the offline mode.
32. The method according to claim 31, further comprising the steps
of: checking the time counter for expiration thereof; disabling the
inverter; closing the contactor; and setting the mode to the online
mode, wherein said disabling, closing and setting the online mode
steps are performed when said checking step determines that the
time counter has expired.
33. The method according to claim 32, further comprising the steps
of: determining the mode when said detecting step continues to
detect no fault condition; commanding the inverter to perform
online current control; and enabling the inverter, said commanding
online current control step and said enabling step being performed
when said mode determination step determines that the mode is the
online mode.
34. The method according to claim 33, further comprising the step
of: iterating the method.
35. The method according to claim 30, wherein the fault condition
includes a fault in the device, loss of phase in the grid, loss of
utility authorization, grid voltage out of range, or loss of
synchronization between the device and the grid.
36. The method according to claim 30, inputting an offline command,
wherein upon receipt of the offline command said detecting step
detects the fault condition.
37. The method according to claim 30, wherein the predetermined
time period is approximately 30 seconds.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Technical Field of the Invention
[0002] This invention relates to control systems and methods for
controlling inverter based electrical power generation and feeding
of generated power to a grid. This invention particularly relates
to an integrated control system and method that integrates a
variety of power control functions including state machine control
of distinct operational modes, synronization with the grid, power
factor control and utility outage ride-through.
[0003] 2. Description of Related Art
[0004] Various control devices for controlling inverter based
electrical power generation are known in the art. Typical
controllers utilize analog voltage or current reference signals,
synchronized with the grid to control the generated wave form being
fed to the grid. Such controllers, however, lack distinct control
states and the capability of controlling transitions between
specifically defined control states.
[0005] Various techniques for synchronizing the frequency of
generated power to the frequency of a grid-are also known in the
art. Such conventional line synchronizers typically sense the line
frequency of the grid and lock to the grid when the generated
frequency drifts into synchronization.
[0006] Such conventional line synchronizers, however, do not have
the ability to control the rate of phase shift of the generated
power or the ability to interface easily with both 50 Hz and 60 Hz
grids.
[0007] Various techniques for controlling the power factor are also
known in the art. In the context of electrical power generation,
for example, Erdman, U.S. Pat. No. 5,225,712, issued Jul. 6, 1993,
discloses a variable wind speed turbine electrical power generator
having power factor control. The inverter can control reactive
power output as a power factor angle or directly as a number of
VARs independent of the real power. To control the reactive power,
Erdman utilizes a voltage waveform as a reference to form a current
control waveform for each output phase. The current control
waveform for each phase is applied to a current regulator which
regulates the drive current that controls the currents for each
phase of the inverter.
[0008] Although the conventional art may individually provide some
of these features, the combination of these features particularly
when utilized in conjunction with an integrated system utilizing
state machine control is not found in the art.
[0009] Other applications distinct from electrical power generation
also utilize power factor control devices. For example, Hall, U.S.
Pat. No. 5,773,955 issued Jun. 30, 1998, discloses a battery
charger apparatus that controls the power factor by vector control
techniques. The control loop utilized by Hall controls power
delivery to the battery to obtain a desired charge profile by
individually controlling the real and reactive components of the AC
input current. The AC input current is forced to follow a reference
that is generated in response to information received by the
battery charge control circuit to supply the desired charging
current to and remove discharge current from a battery.
SUMMARY AND OBJECTS OF THE INVENTION
[0010] An object of the invention is to provide an integrated
system for controlling all aspects of inverter based electrical
power generation and feeding of generated power to a grid. Another
object of the invention is to provide a state machine having a
plurality of defined control states for electric power
transformation including a state controller that controls permitted
transitions between the defined control states.
[0011] Another object of the invention is to provide a line
synchronization technique that is highly flexible and permits
synchronization with either a 50 Hz or 60Hz grid as well as
providing smooth transitioning from a stand-alone mode to a
grid-connected mode.
[0012] A further object of the invention is to provide a line
synchronization technique that can either sense the grid frequency
or synthesize a frequency for electrical power generation.
[0013] Still another object of the invention is to control the
re-synchronization rate to provide the smooth transition from
stand-alone mode to a grid-connected mode.
[0014] A further object of the invention is to provide a method of
controlling an electrical power generator during a utility
outage.
[0015] Yet another object of the invention is to integrate the
inventive method of utility outage ride-through with various other
control techniques to provide an integrated system.
[0016] Still another object of the invention is to provide power
factor control over generated electrical power wherein a simple DC
control signal having two components commanding the real and
reactive components of the generated power may be utilized to
control the power factor.
[0017] The objects of the invention are achieved by providing a
state machine having a plurality of control states for electric
power transformation including an initialization state, a first
neutral state, a pre-charge state, a second neutral state, an
engine start state, a power on-line state, a power off-line state,
and a shut down state wherein the state controller controls state
transitions such that only permitted transitions between control
states are allowed to occur. In this way, a high degree of control
can be achieved for electrical power generating and feeding of
electrical power to a grid. In this way, the safety and reliability
of the system can be ensured.
[0018] The objects of the invention are further achieved by a
method of controlling real and reactive power developed by a main
inverter in an electrical power generation control device including
the steps of sampling the three-phase currents output from the
inverter, transforming the sampled three-phase current data to
two-phase current data, transforming the two-phase current data to
a rotating reference frame, controlling an output voltage according
to a comparison result between a DC reference signal having real
and reactive reference signal components, transforming the output
voltage to a stationary reference frame, transforming the
stationary reference frame output voltage to a three-phase
reference signal, and controlling the inverter based on the
three-phase reference signal. By utilizing such a control method,
the DC reference signal can be input by an operator or a utility
feeding the grid to thereby designate the real and reactive power
output by the controlled inverter.
[0019] The objects of the invention are further achieved by
providing a line frequency synchronization apparatus and method
that utilizes a frequency sensor that samples the frequency of the
grid or a synthesizer that synthesizes a grid frequency. In the
case of sampled grid frequency, the frequency sensor signal is
converted by an A/D converter that is controlled by initiating the
conversion and reading of the digital value at a fixed frequency.
This fixed frequency establishes the time base for which the
invention can compute the actual frequency of the signal. This is
further accomplished by determining when the falling or rising edge
of the signal occurs and counting the number of samples
therebetween.
[0020] In this way, a synchronization error signal is generated
that can be utilized to bring the generated power into
synchronization with a grid or the synthesized grid frequency.
Furthermore, the synchronization shift rate is preferably limited
in order to provide a smooth transition.
[0021] The objects of the invention are further achieved by
providing a utility outage ride-through method and apparatus that
detects a fault condition indicating that the electrical power
generation device should be disconnected from the grid, opens a
contactor that connects the device to the grid, clears a time
counter, sets a mode to an off-line mode, commands the inverter
within the device to perform off-line voltage control, and waits
for a predetermined time period after all fault conditions have
been cleared before setting the mode to an on-line current control
mode, enabling the inverter and thereafter closing the contactor to
reestablish the connection to the grid.
[0022] Further scope of applicability of the present invention will
become apparent from the detailed description given hereinafter.
However, it should be understood that the detailed description and
specific examples, while indicating preferred embodiments of the
invention, are given by way of illustration only, since various
changes and modifications within the spirit and scope of the
invention will become apparent to those skilled in the art from
this detailed description.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] The present invention will become more fully understood from
the detailed description given hereinbelow and the accompanying
drawings which are given by way of illustration only, and thus are
not limitative of the present invention, and wherein:
[0024] FIG. 1 is a high-level block diagram illustrating the major
components of a microturbine generator system that may be
controlled according to the invention;
[0025] FIG. 2 is a high-level block diagram of a small
grid-connected generation facility which is another example of a
generation facility that may be controlled according to the
invention;
[0026] FIG. 3 is a system block diagram of an electrical power
generator according to the invention illustrating major components,
data signals and control signals;
[0027] FIG. 4 is a detailed circuit diagram of a line power unit
that may be controlled according to the invention;
[0028] FIG. 5(a) is a state diagram according to a first embodiment
of the invention that illustrates the control states and permitted
control state transitions according to the invention;
[0029] FIG. 5(b) is another state diagram illustrating a second
embodiment according to the invention showing the control states
and permitted control state transitions according to the
invention;
[0030] FIG. 6(a) is a block diagram illustrating a line
synchronization apparatus according to the invention;
[0031] FIGS. 6(b)-(d) illustrate synchronization and phase-shift
angles in a coordinated diagram showing relative positions and
transitions of the signals according to the invention;
[0032] FIGS. 7(a)-(b) are flow charts illustrating the line
synchronization method according to the invention;
[0033] FIG. 8 is a flow chart illustrating the utility outage
ride-through method according to the invention; and
[0034] FIG. 9 is a control-loop block diagram illustrating the
power factor control method according to the invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0035] FIG. 1 illustrates the major components of a line-power unit
100 containing the inventive control devices and methods and the
overall relationship to a microturbine generator. As shown, the
microturbine generator system includes two major components: the
turbine unit 10 and the line-power unit 100 may be arranged as
shown in FIG. 1.
[0036] The turbine unit 10 includes a motor/generator 15 and an
engine control unit 12. The turbine unit 10 is supplied with fuel.
For example, the motor/generator 15 may be constructed with an
Allied Signal Turbo Generator.TM. which includes a turbine wheel,
compressor, impeller and permanent magnet generator which are all
mounted on a common shaft. This common shaft is supported by an air
bearing which has a relatively high initial drag until a cushion of
air is developed at which point the air bearing is nearly
frictionless.
[0037] The motor (engine) in the motor/generator 15 is controlled
by the engine control unit 12 which, for example, throttles the
engine according to the demand placed upon the generator.
Communication is provided between the turbine unit 10 and the line
power unit 100 as shown by the control/data line connecting these
units in FIG. 1. This data includes operating data such as turbine
speed, temperature etc. as well as faults, status and turbine
output.
[0038] The motor/generator 15 supplies three-phase (3.phi.)
electrical power to the line power unit 100 as further shown in
FIG. 1. The line power unit 100 also supplies three-phase auxiliary
power (3.phi. Aux) to the turbine unit 10.
[0039] The line power unit 100 contains three basic components. The
line power unit controller 200, starter 220 and utility interface
240 are all included within line power unit 100. Furthermore, an
operator interface that permits an operator to monitor and control
the line power unit is further provided. The operator interface may
include a front panel display for displaying critical operating
data as well as controls such as a shut down switch and power level
command input as further described below.
[0040] A DC bus supplies DC power to the line power unit 100 to
permit off-grid starting of the turbine unit. Furthermore, the
utility interface 240 supplies three-phase electrical power to the
utility grid 99 as well as an optional neutral line. The line power
unit 100 also receives utility authorization from a utility company
which authorizes connection to the grid 99.
[0041] FIG. 2 illustrates a small grid-connected generation
facility showing some of the details of the components controlled
by this invention. More particularly, a turbine generator 15
generates AC power that is supplied to rectifier 60. The AC power
is then converted into DC power by rectifier 60 and supplied to DC
link consisting of DC bus 61 and capacitor 62 connected across DC
bus 61.
[0042] An inverter 70 transforms the DC voltage on the DC link into
a three-phase AC waveform that is filtered by inductor 72 and then
supplied to the utility 99 via contactor K1.
[0043] As further discussed below in relation to FIG. 3, the
invention controls the inverter 70 and contactor K1 as well as
other components. FIG. 2 is actually a simplified diagram
illustrating the necessary components for utility outage
ride-through. Other components illustrated in FIGS. 3 and 4 are
necessary for other types of control exercised by the invention
such as power factor and synchronization.
[0044] FIG. 3 is a system block diagram illustrating a generation
facility that may be controlled according to the invention. The
generation facility includes a turbine generator 15 generating AC
power supplied to rectifier 60. This AC power is converted by
rectifier 60 into DC voltage supplied to the DC link. This DC link
may have the same construction as shown in FIG. 2. The inverter 70
transforms DC power from the DC link into three-phase AC power that
is fed to the grid 99 via inductor unit 72 and contactor K1. Power
may also be supplied directly to the internal loads via a
connection to the output of the inverter 70.
[0045] The controller 200 receives a sensed voltage from the DC
link as well as the output AC current from the inverter 70 as
inputs thereto. The controller 200 utilizes these inputs to
generate control signals for the inverter 70. More particularly,
the inverter 70 is controlled by pulse width modulated (PWM)
control signals generated by controller 200 to output the desired
AC waveform. When the generation facility is online, the controller
200 performs feedback current control by utilizing feedback current
supplied by a current sensor located at an output side the inverter
70. When the generation facility is offline, however, the control
exercised by the controller 200 changes. Specifically, the
controller 200 performs feedforward voltage control by utilizing
feedforward voltage supplied by a voltage sensor located at an
input side of the inverter 70. These current and voltage sensors
for feedback current control and feedforward voltage control,
respectively may be part of the inverter 70 or separate therefrom
as shown in FIG. 3.
[0046] The controller 200 also outputs a disconnect control signal
to contactor K1 to control the connection of the generation
facility to the utility grid 99. Further details of the control
method implemented by controller 200 are described below.
[0047] FIG. 4 illustrates the details of a line power unit 100
according to the invention. This line power unit (LPU) 100 includes
an LPU controller 200 that may be programmed according to the
techniques disclosed herein. FIG. 4 is a particularly advantageous
embodiment of a line power unit 100 that may be controlled
according to the invention.
[0048] FIG. 4 shows the details of the inventive line power unit
100 and its connections to the permanent magnet generator 15,
engine control unit 12 and utility grid 99. The starter unit 220 is
generally comprised of start inverter 80, precharge circuit 78,
transformer 76, and transformer 82. The utility interface generally
includes the main inverter 70, low pass filter 72, transformer 74,
voltage sensor 98, and contactor K1. The LPU controller 200
generally includes phase and sequence detector circuit 97,
transformer 82, full wave rectifier 83b, full wave rectifier 83a,
control power supply 84 and LPU controller 200. Correspondence
between the general construction shown in FIG. 1 and the detailed
embodiment shown in FIG. 4 is not important. This description is
merely for the purpose of orienting one of ordinary skill to the
inventive system.
[0049] Turning to the details of the line power unit 100
construction, the permanent magnet generator 15 has all three
phases connected to PMG rectifier 60. A DC bus 61 interconnects PMG
rectifier 60 and main inverter 70. A capacitor 62 is connected
across the DC bus 61.
[0050] The output of the main inverter 70 is connected to
transformer 74 via low pass LC filter 72. A voltage sense circuit
98 is connected to the output of the transformer 74 and supplies
sensed voltages to the LPU controller 200 utilizing the data line
shown. The voltage sense circuit 98 does not interrupt the power
lines as may be incorrectly implied in the drawings. Instead, the
voltage sense circuit is connected across the lines between
transformer 74 and contactor K1.
[0051] A contactor K1 is controlled by LPU controller 200 via a
control line as shown in FIG. 4 and provides a switchable
connection between transformer 75 and the utility grid 99. A
neutral line may be tapped from transformer 74 as further shown in
FIG. 2 and connected to the grid 99.
[0052] A separate start inverter 80 is connected to the DC bus 61
and the external DC voltage supply which may be constructed with a
battery. The start inverter 80 is also connected to the permanent
magnet generator 15.
[0053] A precharge circuit 78 is connected to the grid via
transformer 76 and transformer 82. Precharge circuit 78 is further
connected to the DC bus 61. The precharge circuit 78 has a control
input connected to a control data line that terminates at the LPU
controller 200 as shown.
[0054] The line power unit 100 also supplies power to a local grid
(e.g., 240 VAC three phase supplying auxiliary of local loads) via
transformer 74. This local grid feeds local loads and the turbine
unit including pumps and fans in the turbine unit.
[0055] An auxiliary transformer 77 is also connected to the output
of the transformer 74. The output of the auxiliary transformer 77
is fed to full wave rectifier 83 to supply full wave rectified
power to the control power supply 84. The control power supply 84
supplies power to the engine control unit 12 and the LPU controller
200 as well as the I/O controller 310.
[0056] The I/O controller 310 is connected via data lines to the
LPU controller 200. The I/O controller 310 is further connected to
the engine control unit 12, display unit 250, and LPU external
interface 320. The LPU external interface 320 has a connection for
communication and control via port 321.
[0057] The LPU controller 200 has control lines connected to the
start inverter 80, main inverter 70, precharge circuit 78,
transformer 82, and contactor K1. Furthermore, data is also
provided to the LPU controller 200 from control/data lines from
these same elements as well as the phase and sequence detector 97
that is connected at the output of contactor K1. The LPU controller
200 also communicates data and control signals to the engine
control unit 12.
[0058] The engine control unit is supplied power from the control
power supply 84 and communicates with engine sensors as shown.
[0059] State Machine Mode Control
[0060] FIG. 5(a) is a state diagram showing the control states and
permitted control state transitions. The state diagram shown in
FIG. 5(a) describes a state machine that may be implemented with
the LPU controller 200 to control the line power unit 100 with the
defined states and control state transitions. This state machine
provides mode control for the following modes of operation:
initialization, neutral, pre-charge, turbine start, power on-line,
power off-line, and shut down.
[0061] The state diagram shown in FIG. 5(a) assumes that the line
power unit 100 is mounted in an equipment cabinet having cooling
fans and pumps circulating cooling fluid through cold plates. A
cold plate is merely a device that includes a plenum through which
cooling fluid is circulated and to which various power conversion
devices such as the main inverter 70 and start inverter 80 are
mounted. The cold plate acts as a heat sink for these devices and
thereby prevents overheating. The alternative shown in FIG. 5(b)
assumes that no such cabinet or cooling system is present and
represents a simplified control state diagram for the
invention.
[0062] Before describing the state transitions, a description of
each control state will first be provided.
[0063] The power on/reset condition 500 is not really a control
state but, rather, an initial condition that triggers the state
machine. This initial condition includes power on of the line power
unit 100 or reset of the line power unit 100.
[0064] The initialization state 505 occurs after reset or power on
and initializes global variables, initializes the serial
communication ports including the I/O controller 310 and LPU
external interface 320 having serial ports contained therein,
executes a built-in-test (BIT), and initializes the real-time
interrupt facility and input capture interrupt within the LPU
controller 200.
[0065] The initialization state also starts the line
synchronization techniques of the invention which are further
described below as well as starting the power factor control method
of the invention.
[0066] The neutral state 510 monitors commands from the I/O
controller 310 and engine control unit 12 to determine the next
mode of operation as well as checking critical system
parameters.
[0067] The pre-charge state 515 enables the pre-charge unit 78 to
charge the DC link as well as checking on the rate of charging to
determine correct hardware function. The pre-charge state 515 also
performs diagnostic checks of the main inverter 70 to identify open
or short type failures.
[0068] The neutral with pre-charge complete state 520 closes
contactor K1 and performs diagnostic tests of the line power unit
100.
[0069] The purge cabinet state 525 purges the equipment cabinet in
which the line power unit 100 is mounted including turning on any
cooling fans and pumps and thereby bring the line power unit 100
into a purged and ready state.
[0070] The neutral with purge complete state 530 is an idle state
that waits for an engine start command from the operator that is
routed via port 321 to LPU external interface 320 to I/O controller
310 and thereby to LPU controller 200.
[0071] The start engine state 535 generally performs the function
of starting the engine that drives the permanent magnet generator
15.
[0072] The start engine state 535 resets the start inverter 80 and
performs basic diagnostic checks of the line power unit 100. The
start engine state 535 also verifies the DC link voltage and
thereafter sets the pulse width modulated control signal supplied
to the start inverter 80 to control the maximum speed that the
start inverter 80 will drive the permanent magnet generator 15 as a
motor to thereby permit the engine to start.
[0073] More particularly, the start engine state enables the start
inverter 80, receives updated speed commands from the engine
control unit 12, monitors fault signals from the start inverter 80,
and checks the speed of the engine and DC current drawn from the
start inverter 80 to determine a successful start.
[0074] Actual starting of the engine is under the control of the
engine control unit 12 which feeds fuel and any necessary ignition
signals to the engine that is being spun by the permanent magnet
generator 15. The start engine state 535 then waits for a signal
from the engine control unit 12 to terminate the start operation
which involves sending a stop signal to the start inverter 80.
[0075] Further details of engine starting can be found in related
application Attorney Docket #1215-380P which is hereby incorporated
by reference.
[0076] The neutral with start complete state 540 is an idle state
wherein the engine is started and the permanent magnet generator 15
is being driven by the engine thereby producing three-phase power
that is rectified by PMG rectifier 60 to supply DC bus 61 with DC
power. The neutral with start complete state essentially waits for
a power level command from the operator that is routed via port
321, LPU external interface 320, I/O controller 310 to the LPU
controller 200.
[0077] The power on-line state 545 enables the main inverter 70 in
a current mode and sends pulse width modulated control signals to
the main inverter 70 to output three-phase electrical power having
the commanded power level. The power on-line state also performs
various system checks to maintain safe operation such as verifying
the DC link voltage and cold plate temperatures.
[0078] The open contactor state 550 opens the main contactor
K1.
[0079] The power off-line state 555 switches the main inverter 70
to a voltage mode and sets the power level command to a nominal
level to power the local loads. The power off-line state may
perform various system checks to maintain safe operation.
[0080] The shut down state 560 disables the main inverter 70 and
reinitializes global variables that are utilized by the state
machine to control the line power unit 100.
[0081] The purge cabinet state 565 performs essentially the same
functions as the purge cabinet state 525 and ensures that the
equipment cabinet housing the line power unit 100 cools down.
[0082] The open contactor state 570 waits for a nominal cool down
period such as 5 minutes as well as controlling the contactor K1
such that it breaks the connection with the grid 99 thereby
ensuring disconnection from the grid 99.
[0083] The clear faults state 575 clears any fault codes that may
have triggered the shutdown.
[0084] The emergency stop indication 580 is not actually a control
state, but instead illustrates the receipt of an emergency stop
signal. The equipment cabinet housing the line power unit 100
preferably includes an emergency stop button that a user may
trigger to shut down the system in an emergency.
[0085] The open contactor state 585 is triggered by the receipt of
an emergency stop signal and opens main contactor K1 thereby
breaking the connection to the grid 99.
[0086] The state transitions are represented in the drawings with
arrows. These arrows convey important information. For example an
unidirectional arrow such as .fwdarw. indicates a one-direction
only permissible state transition. A bi-directional arrow, on the
other hand, such as .rarw..fwdarw. indicates bi-directional
permissible state transitions. This may also be expressed by using
the following bi-directional and unidirectional permissible state
transition symbologies: (1) neutral state .rarw..fwdarw. pre-charge
state and (2) power on-line state .fwdarw. power off-line
state.
[0087] The operation of the state machine illustrated in 5(a) will
now be described.
[0088] After receiving the power on or reset signal 500, the
initialization state 505 is triggered. After completion of the
initialization procedures and successful built-in tests, the state
machine permits the transition to neutral state 510.
[0089] The neutral state 510 monitors commands from the operator
and engine control unit 12. Upon receiving an appropriate command,
the state machine permits the transition to the pre-charge state
515 from the neutral state 510.
[0090] As described above, the pre-charge state 515 triggers the
pre-charge unit 78 to pre-charge the DC bus 61 to a desired
pre-charge voltage. The pre-charge state 515 determines successful
pre-charge by monitoring the pre-charge rate and determining
whether the pre-charge voltage is within acceptable limits at the
end of the pre-charge cycle.
[0091] If the pre-charge state 515 determines that the pre-charge
cycle is not successful, then the state machine transitions back to
the neutral state 510 as indicated by the fail path illustrated on
FIG. 5(a). Upon successful completion of the pre-charge cycle,
however, the state machine permits the transition from the
pre-charge state 515 to the neutral with pre-charge complete state
520.
[0092] The neutral with pre-charge complete state 520 closes the
main contactor K1 thereby connecting the line power unit 100 to the
grid 99. Thereafter, the state machine permits the transition to
the purge cabinet state 525.
[0093] Upon successful purging of the cabinet and passing of any
diagnostic tests such as checking the cold plate temperatures, the
state machine permits the transition from the purge cabinet state
525 to the neutral with purge complete state 530. Upon receipt of a
start engine command, the state machine permits the transition to
the start engine state 535.
[0094] As described above, the start engine state 535 control the
start inverter 80 to drive the permanent magnet generator 15 as a
motor to spin the engine at a speed to permit the engine to be
started. If the engine fails to start, then the state machine
transitions to the neutral with purge complete state 530. If the
engine successfully starts, then the state machine transitions to
the neutral with start complete state 540 which waits for the
receipt of a power level command from the operator or a remote
host.
[0095] Upon receipt of a non-zero power level command, the state
machine transitions from the neutral with start complete state 540
to the power on-line state 545.
[0096] If there is a utility outage, then the state machine
transitions to the open contactor state 550 as further described in
the utility outage ride-through section below.
[0097] On the other hand, receipt of a zero power level command
transitions the state machine from the power on-line state to the
neutral with start complete state 540.
[0098] After the open contactor state 550 completes the operation
of opening contactor K1, the power off-line state 555 is entered.
Upon completion of the power off-line procedures in power off-line
state 555, the state machine transitions to the neutral with start
complete state 540. If a shutdown command is received, the state
machine then transitions to the shutdown state 560. The shutdown
state 560 is followed by the purge cabinet state 565, open
contactor state 570 and clear faults state 575 and then the neutral
state 510 thereby bringing the line power unit 100 into a neutral
state.
[0099] Upon receipt of an emergency stop signal 580, the open
contactor state 585 is triggered. Thereafter, the shutdown state
560 is entered by the state machine and then the purge cabinet
state 565, open contactor state 570, clear faults state 575 and
neutral state 510 are sequentially entered by the state
machine.
[0100] FIG. 5(b) is a simplified state diagram that simplifies the
states and state transitions illustrated in FIG. 5(a). FIG. 5(b)
generally assumes that there is no cabinet that needs to be purged.
The state machine in FIG. 5(b) also consolidates some of the states
illustrated in FIG. 5(a). States having the same reference numerals
are identical to those shown in FIG. 5(a). The differences are
pointed out below.
[0101] The neutral with pre-charge complete state 527 shown in FIG.
5(b) differs from the neutral width pre-charge complete state 520
shown in FIG. 5(a) essentially because the purged cabinet state 525
has been eliminated in FIG. 5(b). The neutral with pre-charge
complete state 527 closes the main contactor K1 and awaits for
receipt of a start engine command from an operator or other device
such as a remote host.
[0102] Further details of such remote host that may be utilized
with this invention are provided by related application Attorney
Docket No. 1215-379P the contents of which are hereby incorporated
by reference.
[0103] The power off-line state 556 shown in FIG. 5(b) also differs
from the power off-line state 555 shown in FIG. 5(a). Essentially,
the power off-line state 556 combines the open contactor state 550
with the power off-line state 555 shown in FIG. 5(a). Thus, the
power off-line state 556 performs the functions of opening the
contactor K1, switching the main inverter 70 to a voltage mode and
setting the power level to a nominal level to power the local
loads. Furthermore, various system checks may be performed to
maintain safe operation.
[0104] The operation of the state machine shown in FIG. 5(b) is
essentially the same as that shown in FIG. 5(a) with differences
noted below.
[0105] The main difference is the consolidation of the neutral with
pre-charge complete state 520 and the neutral with purge complete
state 530 and the elimination of the purged cabinet state 525 from
FIG. 5(a). Thus, when the pre-charge state 515 successfully
completes the pre-charge cycle, the neutral with pre-charge state
527 is entered by the state machine.
[0106] Upon receipt of an engine start command, the start engine
state 535 is entered by the state machine. Furthermore, upon a
utility outage, the state machine transitions directly from the
power on-line state 545 to the power off-line state 556 as shown in
FIG. 5(b).
[0107] By utilizing the state machines of either FIGS. 5(a) or
5(b), the invention provides a real-time control method for
controlling the line power unit 100. This real-time control unit
includes specifically defined control states that ensure correct
and safe operation of the line power unit 100. Furthermore, various
system checks and diagnostics are performed throughout which
further ensure safe operation and which further affect state
transitions.
[0108] Line Synchronization
[0109] FIG. 6(a) illustrates the frequency sensing component of the
frequency synthesizing apparatus and method according to the
invention in relation to other components of the line power unit
100 and the utility grid 99.
[0110] The phase and sequence detecting circuit 97 shown in FIG. 4
may have the construction shown in FIG. 6(a). More particularly,
the sequence detector includes a transformer 605 connected to two
phases A, B of the utility grid 99. In this way, transformer 605
inputs the voltage and frequency of the utility grid 99.
[0111] This sensed voltage from transformer 605 is supplied to a
low pass filter 610 and then to an optical isolator 615. The output
of the optical isolator 615 is a uni-polar square wave as shown in
FIG. 6(a) that is supplied to the line power unit controller 200.
Specifically, the line power unit controller includes a vector
control board 210 having an A/D converter 215 that accepts the
uni-polar square wave from the optical isolator 615.
[0112] The A/D converter preferably converts this uni-polar square
wave into a 10-byte digital signal that is fed to the digital
signal processor (DSP) 220. The output of the DSP 220 is fed to a
pulse width modulation (PWM) signal generation device 225.
[0113] The pulse width modulation signals from PWM 225 are fed to
gate drive circuit 230 which drives the IGBT switches 71 located
within the main inverter 70. The main inverter 70 is fed a DC
voltage from DC bus 61 as shown in FIG. 4. For simplicity, this
connection is not shown in FIG. 6(a).
[0114] The-output of the main inverter 70 is filtered by inductor
72. Then, the voltage is stepped up by transformer 74 and supplied
to the utility grid via contactor K1. The output of the transformer
74 also supplies local loads as shown in FIG. 6a.
[0115] The frequency synchronization apparatus shown in FIG. 6(a)
operates in the following general manner. The output of the optical
isolator 615 is a uni-polar square wave with a voltage swing
preferably within the limits of the A/D converter 215. The DSP 220
controls the A/D converter 215 by initiating the conversion and
reading of the digital value at a fixed frequency. This fixed
frequency establishes the time base for which the inventive methods
can compute the actual frequency of the signal and thereby the
actual frequency of the utility grid 99. This is accomplished by
determining when the falling edge of the signal occurred and
counting the number of samples between successive falling
edges.
[0116] Alternatively, the invention could utilize the rising edge
of the signal, but for simplicity this explanation will focus on
the falling edge implementation.
[0117] FIGS. 6(b)-(d) illustrate various signals utilized by the
invention to perform synchronization. FIG. 6(b) illustrates the
SYNC signal that is the fixed frequency signal utilized by the DSP
220 to control the initiation and reading of the data from the A/D
converter 215. FIG. 6(c) illustrates the THETA signal which is a
variable in software that is utilized to represent the angle of the
utility sine wave and ranges from 0.degree. to 360.degree. in a
series of stepped ramps each of which runs from 0.degree. at the
falling edge of the SYNC pulse to 360.degree. at the next falling
edge of the SYNC pulse. FIG. 6(d) illustrates THETA.about.which is
the phase shift added to THETA for power factor control as further
described below.
[0118] The synchronization method is further illustrated in FIG.
7(a)-(b). As shown in FIG. 7(a), the synchronization function is
started or called every 64 microseconds at which time step 702
causes the digital signal processor 220 to read the A/D 215 input.
As further illustrated in FIG. 7(a), the input signal is a square
wave at the frequency of the grid.
[0119] Then, step 704 sets the minimum, maximum and typical
constants which are set according to the selected grid frequency.
The grid frequency is chosen between either 50 or 60 hertz which
thereby effects the values for the minimum, maximum and typical
constants in step 704.
[0120] Thereafter, step 706 increments the frequency counter which
is represented as FreqCount=FreqCount+1. The variable FreqCount is
the number of times this routine is called between falling edges of
the input signal.
[0121] After step 706, then step 708 checks whether the FreqCount
variable is out of range. If so, the Count variable is set to a
typical value in step 710 and the step 712 then clears the status
flag that would otherwise indicate that the line power unit 100 is
in synchronization with the grid 99. In other words, step 712
clears this status flag thereby indicating that the line power unit
is not in synchronization with the grid 99.
[0122] After step 712 or if decision step 708 determines that the
FreqCount is not out of range, then step 714 then determines
whether there is an input from the falling edge detector. Step 714
determines whether the falling edge of the synchronization pulse
has occurred. If yes, then the flow proceeds to jump point A which
is further illustrated in FIG. 7(b).
[0123] Step 708 essentially determines whether the grid 99 is
present or whether there is a utility outage. If there is utility
outage, then the FreqCount variable will exceed the maximum thereby
causing the system to set the count value to a typical value in
step 710.
[0124] FIG. 7(b) continues the frequency synchronization process
beginning with a determination of whether the frequency of the
incoming signal, input is within the correct range. Particularly,
step 716 determines whether the FreqCount variable is within the
minimum and maximum values. If not, then step 722 sets the count
variable to a typical value and then step 724 sets a status flag
indicating synchronization error.
[0125] On the other hand, if the FreqCount variable is within the
correct range as determined by step 716, then step 718 sets the
Count variable equal to 360.degree./FreqCount. Then step 720 clears
the status flag indicating no synchronization error.
[0126] After either steps 720 or 724, the method executes step 726
which resets the FreqCount variable to 0.
[0127] Thereafter, the method then determines whether THETA is in
synchronization with the incoming signal input. THETA should equal
0 at the same time the falling edge of the input signal is detected
if synchronization has occurred. This is determined by step 728
which checks whether THETA is substantially equal to 360.degree. or
0.degree.. If not, the status flag is cleared by step 732
indicating that the line power unit is not in synchronization. If
yes, then step 730 sets the status flag indicating that the LPU 100
is in synchronization with grid 99.
[0128] After setting the status flags in step 730 or step 732 then
the process adjusts THETA to maintain or achieve synchronization
with the input signal. Particularly, step 734 first determines if
THETA is less than 180.degree.. If yes, then the error variable is
set to minus THETA. If not, then step 738 sets the error variable
equal to 360.degree.-THETA.
[0129] After setting the error variable in step 736 or step 738,
then the method proceeds to limit the rate of change of the Error
variable. The preferred embodiment shown in FIG. 7b limits the
Error variable to +/-0.7.degree. in step 740. Thereafter, step 742
sets the THETA variable equal to THETA plus the Error variable.
[0130] After step 742, the flow returns via jump point B to the
flow shown in FIG. 7(a) beginning with step 744.
[0131] As further shown in FIG. 7(a), the process proceeds after
jump point B by generating THETA by incrementing THETA by the count
variable every 64 microseconds. This process generates the THETA
signal shown in FIG. 6(c). More particularly, step 744 sets
THETA=THETA+Count thereby incrementing THETA.
[0132] After step 744, decision step 746 determines whether THETA
is greater than 360.degree.. If yes, step 748 resets THETA to THETA
minus 360.degree. to bring THETA within range.
[0133] If not, then step 750 determines the phase shift variable
THETA.about.by setting THETA.about.equal to THETA plus any desired
phase shift.
[0134] THETA.about.is an optional variable as is step 750. This
optional step 750 permits an operator to adjust the power factor of
the three phase power delivered to the grid 99 by utilizing the
phase shift variable. In essence, the operator merely needs to
input data to set the phase shift variable to thereby adjust the
power factor. Step 750 can then adjust the power factor by setting
THETA.about.=THETA+phase shift.
[0135] After step 750, the synchronization function has completed
its operations as indicated by end of SYNC function step 752. This
routine is again called after 64 microseconds have elapsed since
the initiation of the SYNC function in step 700.
[0136] The inventive methodology illustrated in FIGS. 7(a) and 7(b)
outputs a THETA.about.that is utilized by a known vector algorithm
in the vector board 210 to generate pulse width modulation signals
from PWM 225 that are fed to gate drive 230 to thereby control the
main inverter 70. Such pulse width modulation control of the power
can then shift the phase of the power output from main inverter 70
and thereby bring the output power into synchronization with the
utility grid 99.
[0137] Instead of sampling the grid frequency, circuit 97 may also
synthesize a grid frequency. This is necessary when the line power
unit 100 is operating in a stand-alone mode or when the utility
grid 99 is not available. Thus, the system must synthesize a
frequency when the grid is temporarily disconnected so that the
output power frequency is self-regulating.
[0138] One of the advantages of the inventive line synchronization
technique is that it limits the resynchronization rate in step 740.
By limiting the resynchronization rate, the invention provides a
smooth transition from out-of-SYNC line power unit 100 to an
in-SYNC line power unit 100 that is in synchronization with the
utility grid 99. This reduces transient voltages, stress on the
components and increases safety.
[0139] As further described above, this line synchronization
technique also permits power factor control such that an operator
or remote host can input a phase shift data via port 321 and
thereby control the power factor of power supplied to the grid
99.
[0140] Utility Outage Ride-through
[0141] The state machines described in FIGS. 5(a)-(b) include
states that are involved in the utility outage ride-through
methodology. Specifically, the neutral with start complete state
540, power on-line state 545, open contactor state 550, and power
off-line state 555 shown in FIG. 5(a) are the control states
involved in the utility outage ride-through methodology.
[0142] Alternatively, the neutral with start complete state 540,
power on-line state 545 and power off-line state 556 shown in FIG.
5b are alternative control states that may also be utilized by the
utility outage ride-through methodology of this invention.
[0143] The utility outage ride-through methodology may be
implemented within a controller such as the controller 200 shown in
FIG. 3 or the LPU controller 200 shown in FIG. 4.
[0144] The utility outage ride-through method that may be
programmed into the LPU controller 200 is shown in FIG. 8.
Furthermore, the utility outage ride-through methodology shown in
FIG. 8 may be utilized by the state machine shown in FIGS. 5a-b to
control the state transitions mentioned above.
[0145] The utility outage ride-through method shown in FIG. 8
begins with step 800. Then, steps 805, 810, 815, 820, 825 determine
the existence of a fault condition. Upon the occurrence of any of
these fault conditions, then the flow proceeds to open main
contactor step 830.
[0146] More particularly, step 805 determines whether there is a
loss of utility authorization. In general, most electric utilities
send authorization data to each electrical power generator
supplying power to the grid 99. In this way, the utility can either
authorize or cancel authorization for connection to the grid 99.
Step 805 determines whether the utility authorization has been
cancelled.
[0147] Step 810 determines whether there is a loss of phase. This
may be performed by sampling the input from the phase and sequence
detector 97. If any of the phases have been lost, then step 810
directs the flow to open main contactor step 830.
[0148] Similarly, loss of synchronization step 810 determines
whether there is a loss of synchronization between the line power
unit 100 and the grid 99. This loss of synchronization may be
determined from the status flag "LPU in SYNC" set by the
synchronization method described above in relation to FIGS.
7(a)-(b).
[0149] Step 820 decides whether the industrial turbo generator
(ITG) host has sent an off-line command via port 321 to the LPU
controller. It is not essential that an ITG host be utilized, and
this step 820 may be simplified to receive any off-line command by
LPU controller 200.
[0150] Step 825 determines whether the AC voltage of the grid 99 is
out of range. The voltage sense circuit 98 senses this AC grid 99
voltage and sends a signal to the LPU controller 200 which can
thereby determine whether the VAC is out of range in step 825.
[0151] If any fault condition has occurred, then step 830 is
executed which opens the main contactor K1 and disconnects the line
power unit 100 from the grid 99.
[0152] Thereafter, step 835 resets or clears a time counter which
is preferably a 30 second time counter.
[0153] Then, step 840 sets the operational mode to offline which
causes the state machine of FIG. 5(a) to transition from the open
contactor state 550 to the power off-line state 555. The power
on-line state 545 to open contactor state 550 transition occurs in
step 830 and is triggered by any of the fault conditions described
above.
[0154] Thereafter, off-line voltage control is initiated by step
845 wherein the main inverter 70 is controlled by LPU controller
200 in a voltage control mode for stand-alone operation and feeding
of the local loads.
[0155] After setting the off-line voltage control in step 845, step
850 enables the main inverter 70 to thereby supply power to the
local loads. This ends the flow as indicated by step 895.
[0156] The system then continues checking the occurrence of fault
conditions as described above. Continued fault conditions have the
effect of clearing the 30 second counter each time.
[0157] When all of the faults have been cleared, then the flow
proceeds to step 855 which determines whether the on-line or
off-line mode (state) is being utilized by the line power unit 100.
Continuing with this example, the off-line mode is now utilized by
the state machine. Thus, the mode determination step 855 directs
the flow to step 860 which begins incrementing the 30 second
counter.
[0158] If the counter has not yet reached the 30 second time limit,
then step 865 directs the flow to off-line voltage control setting
step 845 and enable three phase inverter step 850 the effect of
which is to return or loop back to the increment 30 second counter
step 860.
[0159] This loop continues until the 30 second counter has elapsed
as determined by step 865. Thereafter, step 870 disables the main
inverter 70. After disabling the main inverter 70, step 875 closes
main contactor K1 thereby connecting the line power unit 100 to the
grid 99. Then, the mode is set to the online mode which transitions
the state machine from the neutral with start complete state 540 to
the power on-line state 545. This also causes the next loop to take
the left branch as determined by the mode determination step 855
which will now sense the online mode.
[0160] If the mode is on-line, the flow proceeds from step 855 to
on-line current control step 885 which controls the main inverter
70 in a current control mode. Thereafter, step 890 enables the
inverter 70 to thereby supply power to the grid 99 via closed
contactor K1. The process is then completed as indicated by end
step 895.
[0161] By utilizing the utility outage ride-through methodology
above, the invention has the capability of detecting a utility
outage or other fault condition thereby triggering disconnection
from the grid. The invention also provides a smooth transition from
a current mode (utility connected) to a voltage mode (utility
outage) for the main inverter 70.
[0162] The benefit is more stability and faster response to wide
swings in generator voltage. The invention also has the feature of
over-current limiting which is a self-protection function which
prevents voltage brown-out at excessive current levels. This method
also easily transitions from voltage mode to current mode when
reconnecting to the grid thereby minimizing transients on power
output to the grid 99.
[0163] When the line power unit 100 disconnects from the grid 99, a
typical system will vary greatly in speed and output voltage as it
is rapidly unloaded. To prevent such large voltage swings from
reaching the inverter 70 output, a feed forward technique is
utilized as described above to control the inverter 70 output
voltage.
[0164] Using such feed forward control, the generator voltage is
sampled and used to establish the modulation index of the
pulse-width modulated sinusoidal voltage produced by the inverter
70 keeping the sinusoidal output voltage nearly constant. This
control technique provides the high level of stability and fast
response needed for rapid changes of input voltage. Over-current
protection is provided by reducing the modulation index when the
maximum allowed output current is reached, producing a brown-out
effect.
[0165] When the grid power is restored, the line power unit 100
voltage is first synchronized with the grid voltage. After
synchronizing with the grid (as determined by step 815 and
implemented by the synchronization techniques described above),
normal current controlled power flow into the grid 99 can then
resume.
[0166] Power Factor Control
[0167] The system may be further enhanced by providing an apparatus
and method for controlling the power factor of power delivered to
the grid 99. Although the synchronization control described above
also provides power factor control, the invention also provides an
alternative control loop that controls the power factor.
[0168] The power factor control device and methods according to the
invention may be applied to a wide variety of grid-connected
generation facilities as graphically illustrated by FIG. 2. The
current controlled inverter 70 may be controlled with the device
shown in FIG. 9.
[0169] FIG. 9 illustrates a device for controlling power factor
that interfaces with a current controlled inverter 70 as shown in
FIG. 9 or, alternatively, the current controlled inverter 70 shown
in FIG. 2 or 4.
[0170] This power factor control device includes a sensor 98 that
senses the current supplied to the utility 99 from the inverter 70.
All three phases (I.sub.a, I.sub.b, I.sub.c) of the current
supplied to the utility 99 are sensed by sensor 98 and supplied to
three-phase to two-phase transformer 905 to output two-phase D-Q
coordinate signals I.sub.d, I.sub.q.
[0171] The two-phase signals I.sub.d, I.sub.q are then supplied to
a stationary-to-rotating reference frame transformation unit 910
that changes the two-phase AC signals (I.sub.d, I.sub.q) from the
stationary to a synchronously rotating reference frame which
converts the signals from AC to DC.
[0172] The DC signals are then compared against reference signals
I.sub.q Ref, I.sub.d Ref by comparators 920 and 925, respectively.
The comparators 920, 925 are preferably proportional-plus-integral
gain stages that perform proportional-plus-integral comparison
operations between the reference signals I.sub.q Ref, I.sub.d Ref
and the DC signals I.sub.d, I.sub.q.
[0173] The reference signals I.sub.q Ref, I.sub.d Ref may be
supplied by the LPU controller 200 which, in turn, may be supplied
these reference signals from an operator via port 321, LPU external
interface 320, I/O controller 310. In this way, either the LPU
controller 200 or the operator can command the power factor.
[0174] Furthermore, the utility may also request a certain power
factor to be supplied to the grid 99 by the line power unit 100.
Such a request can be fed to the system via the reference signals
I.sub.q Ref, I.sub.d Ref.
[0175] The proportional plus integral gain stages 920, 925 output
voltage signals V.sub.q, V.sub.d that are transformed back to a
stationary reference frame by rotating to stationary reference
frame transforming unit 930 to output AC voltages V.sub.q, V.sub.d.
These AC voltages are then subjected to a two-phase to three-phase
transform by unit 935 to thereby output three-phase voltages
V.sub.a, V.sub.b, V.sub.c which are then sent to a pulse width
modulator which controls the switches in a three-phase, full-wave
IGBT bridge within the inverter 70 to produce AC currents (I.sub.a,
I.sub.b, I.sub.c) with a vector that contains the real and reactive
components commanded by I.sub.d Ref and I.sub.q Ref. This power
factor control loop provides independent control of the real and
reactive components of the current output to utility 99. This
invention draws upon widely known vector control techniques
developed for induction motor drives. The desired amplitudes of
real and reactive current supplied to the utility 99 are commanded
by I.sub.q ref and I.sub.d ref, respectively. The control loop
described above drives the output current to the utility (I.sub.a,
I.sub.b, I.sub.c) so that the magnitude and phase contain the
commanded real and reactive current components.
[0176] This is often beneficial in improving the power factor in
the utility distribution system 99. Furthermore, the utility
interface 99 may also be a local grid. Such a local grid may also
require power factor correction due to large inductive or
capacitive loads on the local grid. The poor power factor that such
large inductive or capacitive loads cause may be corrected by
utilizing the power factor control method and apparatus disclosed
herein.
[0177] The invention being thus described, it will be obvious that
the same may be varied in many ways. Such variations are not to be
regarded as departure from the spirit and scope of the invention,
and all such modifications as would be obvious to one skilled in
the art are intended to be included within the scope of the
following claims.
* * * * *