Few products are more critical to a complex modern society than electrical energy. Wide-area blackouts can create catastrophe,
but the proper means to pacify or calm the system grid could reduce such incidents to minor inconvenience.
Disturbances on a large power grid propagate through the system in milliseconds to fractions of a second. Major blackouts
occur when an unconfined system disturbance cascades throughout the power grid. Precise measurements of the voltages and currents
in the grid, including both the magnitudes and the phase angles between voltages and currents, can initiate the process of
preventing or at least minimizing such events.
The phase angle between voltages and currents is very important as it relates to the power factor. If this angle is zero degrees,
the load is purely resistive; if the angle is not zero, there is some reactive loading, or additional storage in the system.
Also when voltage angles between regions change rapidly, something can be wrong.
With that data, pacifying the grid requires that the disturbance be diagnosed, and counteractive actions taken. One of the
most promising ways to stabilize the grid is to selectively shed load (or trip generators) and/or selectively switch reactive
power compensation devices (capacitor/reactor banks). Operating and stabilizing such a system over a wide area requires an
infrastructure in place to take these voltage and current measurements at selected generation and transmission sites and time-tag
them to within microseconds, using GPS equipment. The transmission or latency times from these measurement sources to the control facility must also be deterministic (time-stable
and predictable) and as short as possible, to ensure that measurements are made and analyzed quickly to enable a timely response
to the problem. Finally, this requires installation of suitable reactive power compensation equipment; Bonneville Power Administration
(BPA) has such an infrastructure in place.
Figure 1 Partial map of the principal transmission lines in the Western Electricity Coordinating Council (WECC), showing
locations of the phasor measurement units (PMUs), the phasor data concentrator (PDC) and the Wide Area stability and voltage
Control System (WACS) control processor
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The Wide Area stability and voltage Control System ( WACS), a BPA demonstration project, with assistance from Ciber, Inc and
Washington State University, uses phase angle data to provide grid pacification. This system is designed to prevent or minimize
outages, and also to increase power delivery capability. Once testing is complete, BPA plans to implement it over a wide-area
grid such as the western United States and Canada interconnected high voltage transmission system (Figure 1).
Pacifying Large-Area Grids Ordinarily, slight variations can occur between phase angles in wide areas, but when one or more regions swing suddenly and
dramatically one way or the other, this indicates a possible disturbance. Dealing with local disturbances traditionally involves
relaying out faulty equipment and isolating the problem before it cascades. With the complexity of high-voltage transmission
networks, however, failures or very severe disturbances may cause other sections to overreact, creating instability. The most
promising solution treats the problem as a whole and regulates the grid's frequency and voltages within manageable limits,
by generator or load shedding, and/or inserting reactive compensation devices. These tactics can modify the magnitude and
phase relationship between voltages and currents in the power system network.
The overall WACS system consists of several key components:
- A variety of GPS Universal Coordinated Time (UTC)-synchronized phasor measurement units (PMUs) read the voltage and current at selected sites within the interconnected transmission
grid and convert these quantities into phasors (see later discussion), using a local GPS-synchronized time and frequency source
as a reference. This records not only the local phase relationship between the voltage and current (to obtain watt and var
readings) but also the absolute phase and time relationship with other stations in the system.
- An extensive fiberoptic network ensures that transmission latency times remain very low, on the order of 1-3 electrical cycles,or
17 to 50 milliseconds (ms), a critical factor, and this ensures that transmission will be as deterministic as possible.
- A phasor data concentrator (PDC) at the central command site collects all the data packets from the PMUs, time correlates
them, and forms a message packet used by the WACS controller. BPA developed and implemented a system currently operating at
30 packets per second, that could be upgraded to 60 packets per second.
- A real-time process controller receives and analyzes the message packets and produces the control action. Selected for its
robustness, it uses the Peripheral Component Interconnect eXtensions for Instrumentation (PXI) form factor, has industry-wide
use, and is highly adaptable. We selected the same company's software for the development language, as a direct link can exist
between code development and the real-time operating system target.
- An extensive and secure communications network operated by BPA uses fiber optic, microwave, and other media to disseminate
the control actions throughout the grid to those substations and generating plants involved in the calming process.
- Generator tripping must be technically and contractually feasible, and the reactive power devices must be in place. BPA has
a sizable array of series and shunt capacitor banks as well as inductors within its area for use in this project. In the Pacific
Northwest, hydroelectric generators can be tripped at low cost and with fast reconnection.
Figure 2 The major components in the WACS system
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Figure 2 shows the overall block diagram of the project.
While inputs are actually connected to the PDC at present, the control outputs are not yet connected to the power system.
This will be done when sufficient monitoring of system response shows that it will be absolutely safe to do so. Several years
of testing and monitoring have shown no false operations, nor has it missed an opportunity to respond correctly.
Figure 3 The concept of a phasor. Note that the conversion contains both the magnitude and the phase angle.
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Remote Measurements As noted earlier, both the voltage and current, and the phase relationship between them and a reference must be monitored
at many sites within the BPA system. The most obvious way to measure the phase relationship is to timetag the zero crossings
once or twice per cycle (16 to 8 ms), but distortion and noise make this very difficult and impractical. Digitizing the raw
waveforms at high sample rates (for example, 16k samples/second or so) and transmitting them to the control station using
deterministic communications is possible and could provide information for other applications; this is perhaps the best and
most desirable, but the mechanism for this with the available fiber optic system is not yet planned. 
Figure 4 The process of computing the phasors from 3-phase voltages and currents. Note that the Watt (VI cosf) and Var (VI
sinf) equations assume a phase to ground voltage measurement.
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The current method we use converts the three phase voltage and current quantities into phasors, or more specifically synchronized
phasors. A phasor is simply the complex representation of the rms magnitude X and the time difference φ (expressed in radians) as depicted in Figure 3. This is done for all three phases (each 120 degrees apart) on both the voltages and the currents and then combined into
one voltage and current phasor. Figure 4 shows the computational process.
A synchronized phasor provides that the measurement is relative to some common wide-area time reference, in most cases using
GPS transmissions. Measurements taken at one substation are synchronized with those taken at all other substations. As a rule,
these phasors should be calculated at a rate of one per electrical cycle, but averaging over more cycles achieves higher accuracy.
