IEEE Electrification - March 2021 - 16

fewer transmission lines carrying the
load, but this was the first measurement showing the change. Hence, this
demonstrated that phasors offered
another way that we could monitor
system reliability. Phasors also displayed the oscillatory responses much
more clearly than SCADA measurements. As a result of observing these
benefits, BPA decided to build out the
phasor measurement system beyond
the original scope of the EPRI test.

Planning the BPA Phasor
Measurement System

This precipitated a
major investigation of
the system planning
and operation as well
as a flurry of interest
in systems that could
provide better
information about the
state of the system.

Given the mandate and backing, we
had the freedom to create a measurement system that could support multiple applications.
The clear and obvious use was the analysis of system
dynamics. We had already used PMUs for special tests and
found that they provided accurate measurement with
excellent dynamic response. BPA ran system tests on a
regular basis, so phasor measurements could provide
good support for this work. This work requires measurement at key points across the system as well as good data
collection and storage.
We also saw the benefit of using phasors for operation
and control applications. These both require real-time
data gathering and communication. Allowable delay in
receiving data for operations is in the 1-2 s time frame
and not difficult to achieve. Automatic controls, like RASs,
may require delays of fewer than 0.1 s, so the design and
implementation of measurement systems can be very
exacting. Reliability is paramount for critical controls;
such systems require careful design and self-monitoring
capability. Consequently, the system design required the
capability of very low latency operation and incorporating
redundancy features.
With the existing EPRI project, we had a broad coverage of BPA but with little detail. Power system dynamics
are largely controlled by the generator responses, so the
best coverage will include the main generator sites, key
transmission connections, and sites of other significant
power flow controls, such as static var compensator
(SVC) or thyristor-controlled series capacitor (TCSC) locations. The system planners designated sites that would
give the best coverage. We also considered the accessibility of potential transformer/current transformer signals
and communication back to the control center.
BPA had a microwave system that covered all of the
main grid substations. The modems then in use would
not handle data transmission at the rate we wanted to
use with the new PMUs. The PMUs could report at
30 measurements/s, and we wanted to establish this
rate for the new system. We had to buy and test a number of modems to find one that would work with the

I E E E E l e c t r i f i cati o n M agaz ine / MARCH 2021

binary data format and BPA communication at this rate. As with most
utilities, the communication system
was a star architecture, with the
substations connecting directly back
to the control center. We used that
same architecture, sending phasor
measurements directly to a concentrator at the control center. The concentrator had to collect the data and
then send them on the applications
that would use the data. The field
connections were all serial, but by
the time they were collected from a
number of PMUs, the data rate
would be too high for serial communication. Hence, we decided that the
concentrator output would be Ethernet, using the highest speed commonly available at the time, 10 Mb/s. Ethernet would also allow for easy data distribution as
local area networks (LANs) were becoming common
within the company.
For operation and control applications, real-time data
delivery to applications on the LAN would work fine. The
analysis needed a system for data storage and retrieval.
With that plan, we could write an application for a PC
that would store the data from the stream in files that
could then be accessed by other computers for analysis.
The important thing was making the data readily accessible to the users.
An important aspect of any operational system is troubleshooting and maintenance. Since a phasor measurement system is spread out over the grid, has components
in substations, goes over communication systems, and
uses applications in the control center, it can be difficult to
locate or resolve problems. To deal with this, we planned a
monitor application that would display visually in real
time the status of each PMU and its data as well as keep a
record of the performance. With this, we could observe at
any time if there was a problem-and the likely cause. We
could also look at the ongoing performance to see if there
were intermittent problems and how severe they might be.
The historical record aids in tracking down the source of
each problem.

Implementing the System
The first requirement was a better method of collecting the
data. The data concentrator we had was not very reliable,
did not align the data by time stamp, and did not keep a full
record. A PMU measures phase angle using a Coordinated
Universal Time (UTC) time reference, so angles between
phasors can be calculated only when they represent the
same measurement time. Consequently, the data from
PMUs need to be aligned by time tag before they are sent to
applications and storage. Time tag alignment requires some
complicated processing algorithms to handle data delays,

IEEE Electrification - March 2021

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