Public Manual
PMU Installation and Configuration Requirements
Version No. 1.0, 08/09/2012
PMU Installation and
Configuration
Requirements
MISO
P.O. Box 4202
Carmel, IN 46082-4202
Tel.: 317-249-5400 Fax: 317-249-5703
http://www.misoenergy.org
Contents
Document Change History................................................................................................................... 3
Forward ................................................................................................................................................ 4
1.
Introduction ..................................................................................................................... 5
2.
Document Organization .................................................................................................. 7
3.
PMU Compliance with C37.118 and Calibration............................................................ 8
4.
Substation Installation Requirements........................................................................... 10
5.
Control Center Installation Requirements .................................................................... 17
6.
Checklists and Documentation ..................................................................................... 25
Appendix A: Pre-installation Preparation........................................................................................... 26
Appendix B: Equipment Installation................................................................................................... 32
Appendix C: Installation Checkout at the Measurement Site (Substation) ....................................... 33
Appendix D: Installation Checkout at the Control Center ................................................................. 40
i
ii
Appendix A: Pre-installation Preparation
DOCUMENT CHANGE HISTORY
Version
Reason for Issue
Date
Author
0.1
Draft
3/7/2012
Ken Martin (EPG)
0.5
Reorganize as requirements document
4/12/2012
Ken Martin (EPG)
0.6
0.7
Emphasize the calibration aspect
Initial Draft
4/13/2012
4/20/2012
Ken Martin (EPG)
Anna Zwergel
1.0
Installation Guide
7/24/2012
David Kapostasy
Appendix A: Pre-installation Preparation
FORWARD
This document is intended to provide PMU installation guidance to the transmission
owners (TOs) that are part of the electric network administered by Midwest Independent
System Operator (MISO). This document provides requirements for phasor measurement
system installation at the TO facilities. The Appendix provides detailed background
information for understanding the measurement issues and guidance for their assessment.
Appendix A: Pre-installation Preparation
1. INTRODUCTION
Synchrophasors are a measurement of the electric power system. More precisely, they are
an estimate of the phasor equivalent of the power system AC characteristics for a
particular bus or line at a given instant in time. To make this measurement, the Phasor
Measurement Unit (PMU) will estimate (“measure”) the phasor equivalent and send that
value to a given destination. Details about how fast the measurements are made, the
measurement characteristics, how they are transmitted, and so on are part of the system
design and detailed in the implementation considerations. These issues are summarized in
the appendix.
The PMU is the heart of the installation. The PMU creates phasor estimates from AC
voltage and current inputs. The key is to recognize that a phasor is a representation of AC
waveform parameters for a particular instant in time. The phasor is not a value that can be
directly measured from an electromagnetic signal in terms of voltage or current. This is
due to the fact that it is an AC quantity. Instead, the phasor must be estimated from
observations (samples) taken over an interval of time. The consequence of this is that
phasor estimation (measurement) is a very complex process with a large number of
parameters. These parameters include the sampling process (bits of resolution and analog
filtering), period of observation (window length), conversion algorithm (usually a Fourier
method), timetag application, frequency estimation method, and output filtering (out-ofband filtering). The PMU vendor will choose values and methods for these parameters
and processes which best fit their technology and their interpretation of the best way to
gain valid results. The consequence is that the phasor value will vary somewhat from
vendor to vendor for the same input waveforms. In addition to the implementation
differences, errors in implementation create measurement differences; these need to be
discovered and resolved as well.
The IEEE Synchrophasor standard C37.118 sets minimum requirements that should be
achieved by all PMUs. These requirements are intended to assure that the measurements
from all PMUs will be comparable under a variety of typical power system operations.
Appendix A: Pre-installation Preparation
The measured values will not be identical due to different measuring methods, so the
standard tries to assure that the measurements are the same (comparable) to a level of
analysis or observation that would typically be used by a power utility. Requirements
were tested against field experience and laboratory tests to assure that they were
reasonable and achievable. However, for extreme measurement situations or specific
applications, differences in processing will give differences in the phasor values. Rather
than tie measurements to a fixed method, the IEEE working group felt it more important
to allow and encourage technology development by only specifying result requirements,
even though this approach results in some difference in measurement.
Appendix A: Pre-installation Preparation
2. DOCUMENT ORGANIZATION
This document provides the requirements for validation and documentation of phasor
system installation. It is broken into chapters for each level of installation. Chapter 3
describes PMU certification and calibration requirements. Chapter 4 focuses on the PMU
installation in the substation. Chapter 5 examines the data being reported to the control
center. In both cases, the validation requirements are detailed and a method for obtaining
the validation is given. The details to be reported are listed. The appendix is similarly
organized and provides an in depth reference for the validations and methods by which
the data can be assessed.
Appendix A: Pre-installation Preparation
3. PMU COMPLIANCE WITH C37.118 AND
CALIBRATION
When available, compliance with C37.118.1 must be shown. The utility, vendor, or a 3rd
party can perform the required tests. The requirements in the standard cover both overall
performance and calibration. Compliance needs to be shown for the particular PMU
model with the specific settings that will be used, since differences in settings can
significantly change performance. A complete set of tests should only be needed on a
single unit, since most of the processing is a software function and these will not change
from unit to unit (unless the actual design is faulty). Differences between units of the
same type and the same settings should only be input scaling and phase angle. These
differences are determined by calibration testing.
The measurement accuracy capability of a typical PMU is in the 0.5% range. Calibration
requires signals and measurement devices that have resolution and accuracy in the 0.1 to
0.05% range. It is difficult to do this in a substation setting, so this type of testing should
be performed in a laboratory. The basic C37.118.1 performance requirements require
accuracy in the 1% range, but the test results can be used to as high accuracy as the test
equipment will allow. The C37.118 steady state magnitude and angle tests can be used
for calibration.
For best operational accuracy, every PMU should be calibrated in the lab before
deployment in the field. The scale factors should be adjusted based on these calibration
results to give the best accuracy possible. A test record needs to be kept, and periodic
recalibration is required.
Since that may not practical, a generally acceptable approach is to test a sample of a
batch of PMUs. If these meet requirements consistently, testing of a subset of those
deployed should be sufficient. Examination of the results may show there is a systematic
error in the measurement that can be improved by adjustment of the default scaling.
However in general calibration adjustments for individual units cannot be made from a
sample test.
Appendix A: Pre-installation Preparation
A third alternative is to require manufacturer certification and calibration. This can
include calibration with adjusted scale factors. The utility can then spot test a few units
to be sure calibration is good.
Appendix A: Pre-installation Preparation
4. SUBSTATION INSTALLATION
REQUIREMENTS
The substation installation consists primarily of the Phasor Measurement Unit (PMU). It
will have voltage (V) and current (I) inputs for measurement, a time input for
synchronization, and a data output. The validation of this installation consists of ensuring
that the outputs are correctly connected, quantities are correctly identified (labelled), the
scaling is correct, and the data I/O is operational.
1. Check that the clock used for synchronization to UTC is on time and locked on
GPS time. Check that the PMU correctly indicates when time is locked and that the
lock is steady.
Method
The clock may be a GPS receiver internal to the PMU or may be a substation clock that
supplies time using IRIG-B or another format. The PMU may provide a display to show
the clock time as received by the PMU or allow using a program to look at the data.
MISO is currently investigating solutions that will allow for easy local validations to be
performed. UTC time does not change for daylight seasons. It has a constant offset from
local standard times. The offset from Eastern Standard Time (EST) is +5 hours (add 5
hours to EST time to get UTC).
Lock should be indicated by the receiver, whether internal or external to the PMU. It is
required to be indicated by the output data. If there is no user indication on the substation
equipment, start output data and observe the indication there using a local device as
indicated above.
To determine that the lock indication reports correctly, remove the time synchronization
source form the clock. The PMU should report sync is lost within 1 minute. It should
likewise report sync is regained when the time is reacquired (the receiver may take a few
minutes to re-lock after the antenna is reattached). Note that if GPS is used as the prime
source, this exercise will involve disconnecting the GPS input from the clock. If the
Appendix A: Pre-installation Preparation
clock is internal to the PMU, disconnect the GPS input. If the clock is external to the
PMU, the GPS must be removed from the clock, not just the time signal (ie, IRIG-B)
from the PMU. The PMU must determine that the time signal is synchronized, not
simply that it is receiving a time signal (the PMU may have a valid time signal but the
signal may not be synchronized to UTC).
The lock to GPS must be continuous. In reality the receiver may have short unlocks
while switching satellites, but the receiver should ride through those with its internal
oscillator. If there are any significant reception difficulties, they should show up within a
day. Monitor the lock signal for a 24 hour period to be sure that there are no dropouts.
Any dropouts require investigation, remediation, and retest. The clock or PMU may have
a built in monitor which can be used to confirm lock. Alternatively collect output data
using Connection Tester or a PDC to analyze for dropouts. A PDC should provide
performance statistics that will show the sync performance.
Documentation
Documentation in the form of notes and test results needs to be provided to show this test
was successfully completed. It should include a description of the PMU timing system,
the method for performing these tests, a list of the equipment used, and the actual results.
2. Confirm that the phasor measurement magnitudes are within 1% of input levels.
Also confirm voltages are within 1% + 1kV and currents within 1% (Above 50
Amps) of comparable substation measurements.
Traditional substation measurements are bus voltage and power flow in lines. Some
substations will provide metering or other indications of line currents. PMUs measure V
& I. The challenges in measurement comparison are that the values vary constantly, so
the user has to estimate a moment and variation that is the same.
Substation values can be read from test equipment, substation meters, or local SCADA
systems. PMU values are often provided by a PMU display. MISO is currently
investigating solutions that will allow for easy local validations to be performed.
Appendix A: Pre-installation Preparation
Comparison of phasors with actual inputs
Connect test equipment to the PMU input voltage and current. The test equipment should
be within its certification period and have and accuracy rating of 0.1% or better.
Compare the input values with the values provided from the PMU. Make the readings for
comparison at as close time wise as possible to eliminate variations. Make the
comparisons by phase, ie, Va input to Va phasor, etc. Be sure to apply sqrt(3) corrections
where needed. Note that generally PMU voltage inputs are phase-neutral and current
inputs are phase, so Y-D scaling is probably not needed. The comparisons should be
within 1%, the minimum C37.118 requirement. If the error is larger, investigate as there
is probably a connection or setup error. If PMU also reports positive sequence, it is
worth checking by averaging three single phase readings for comparison (the phase
angles should be close enough). Positive sequence tested should be within 1%. This
additional comparison assures that the phasing is properly connected.
Comparison of phasors with substation instrumentation
This will be less accurate than the first step since installed substation instrumentation is
usually less accurate than portable test equipment and it often will be connected to
different PT and CT signals. It does provide local validation that the PMU is correctly
connected to the indicated PT and CT signals as designed. There will usually be voltage
measurements in the substation and sometimes current measurement. Compare
individual voltage and current phases as above. Try to choose voltage readings from the
same PT for comparison. If there are only single readings, just compare the appropriate
phase.
If there are only power measurements on feeders, compare with power computed from V
& I phasor values. A tool that will provide these readings on line is the best approach. If
no such tool is available, power can be computed manually 𝑃 = 𝐼𝑋 𝑉𝑋 + 𝐼𝑌 𝑉𝑌 using
rectangular components or 𝑃 = 𝐼𝑀 𝑉𝑀 ∗ cos(𝜑𝑣 − 𝜑𝑖) using polar components.
The point to these comparisons is to spot wiring or naming errors. For example, if the
wrong current is wired into the PMU, the computed value will probably differ
considerably. The comparison needs to only be to an accuracy that will reveal errors
Appendix A: Pre-installation Preparation
since the accuracy is checked directly in the test above. A comparison of 4% is probably
sufficient, allowing for 1% in the PMU and 3% for the local measurement.
Documentation
Documentation in the form of notes and test results needs to be provided to show this test
was successfully completed. It should include a description of the instrumentation used
to confirm the measurements and the method of validation used. It should show the
actual values, calculations where needed, and the results.
3. Confirm that the phasor measurement angle differences are within 1 degree of
corresponding input signal angle differences. Also confirm the angles with
comparable measurements in the substation.
Phasor angle measurements are made relative to UTC time and there is no direct way to
make validate these values short of using another PMU. However the phase angle
between signals can be readily determined by a number of methods. As above, portable
instrumentation is prescribed here for calibration and using installed substation
equipment for signal validation.
Comparison of phasors with actual inputs
Choose a reference signal (e.g., the bus voltage) against which all other angles will be
measured. Connect phase angle measurement equipment to the reference signal and
another input signal (voltage or current). Compare the angle between the same signals
measured by the PMU. Make the readings for comparison at as close time wise as
possible to eliminate variations. This comparison is easiest with a phasor reading device
that allows setting a reference that will be subtracted from the other signals to directly
display the angle difference. Alternatively the process can be done manually. Choose a
time when the system frequency is very close to 60 Hz as the phase angles will vary more
slowly. Compare measurements of the same signal and phase. The input and PMU
measurement should be within 1 degree of each other. Differences larger than this need
to be investigated and resolved. The PMU TVE (Total Vector Error) calibration requires
phase angle accuracy 0.57 degrees or better. Testing has shown most PMUs measure
phase angle to accuracy near .02 degrees. Test equipment should be capable of 0.1
Appendix A: Pre-installation Preparation
degree accuracy, but check the specifications. If the current is low (under 20% of rated
current) the measurement may be less accurate.
Comparison of phasors with substation instrumentation
Compare PMU measurements with local installed instrumentation. Traditional
measurement equipment does not measure phase angle. Angle between V & I can be
𝑄
determined from real and reactive power measurement. Phase angle 𝜑 = tan−1 (𝑃 )
where Q and P are reactive and real power respectively. The phase angle for each current
relative to the related voltage can be determined this way. These standard instruments
will not give the angle between different bus voltages or currents for which there is no
corresponding voltage. As with the specialized instrumentation, when the current is low,
the watt, var, and phasor measurement will be less accurate. Allow larger errors for
currents less than 20% of rated current, and do not expect to make comparisons with
currents less than 10%.
This step is only for the purpose of confirming signal designation, so compare
measurements with this in mind. The level of comparison should be enough to confirm
the correct signal with the correct phasing has been selected.
Documentation
Documentation in the form of notes and test results needs to be provided to show this test
was successfully completed. It should include a description of the instrumentation used
to confirm the measurements and the method of validation used. It should show the
actual values, calculations where needed, and the results.
4. Confirm that analog measurements are within 5% of other measuring devices in
the substation.
Synchrophasor data communication can include samples of analog signals that are not
phasors. The C37.118 protocol includes this data type as “analog” data. It can be
represented in integer or floating point values. The standard does not specify what these
analog signals are, so they can be any continuously varying signal such as power (watt
and var), control signals, local readings (pressure, temperature) or any other continuously
Appendix A: Pre-installation Preparation
varying signal. The standard also does not specify how the measurement is to be made,
scaled, or any other parameter. The data type was added so the user can include
measurements in the synchronously sampled data set that are important to using phasor
system data and adding understanding of power system operation. Some of these values
may have local reporting in the substation and some may not. Since there is no standard
specification for making these measurements and what they represent, this confirmation
is simply a best effort to be sure that the reported data reasonably represents the signal it
is supposed to.
Method
Find a suitable means to read the values as sent from the PMU. These values are often
provided by a PMU display. MISO is currently investigating solutions that will allow for
easy local validations to be performed. Locate a measurement display for the quantity in
the substation. In some cases portable test instrumentation may be required. In cases
where there is no means to locally observe the measured quantity, this test can be
ignored. Compare the two values. The values generally should be within 5% of each
other, however, in some cases it should be much closer and others not as close. It is left
to the user’s discretion to determine an appropriate level of correspondence and validate
the measurement to this level.
Documentation
Documentation in the form of notes and test results needs to be provided to show this test
was successfully completed. It should detail if the test was not completed and why, such
as for lack of instrumentation. It should explain any deviation of accuracy acceptance
from the given 5% minimum. It should include a description of the instrumentation used
to confirm the measurements and the method of validation used. It should show the
actual values, calculations where needed, and the results.
5. Confirm that digital status measurements report the correct Boolean state.
Synchrophasor data communication can include digital status indications. The C37.118
protocol includes this data type as “digital” data. Digital status is represented as a
Boolean 0 or 1 binary value. The standard carries Boolean values in blocks of 16 as 16-
Appendix A: Pre-installation Preparation
bit words. The standard includes the ability to specify which bits in each word are valid
representations (that is, in use) and what is the normal state (as opposed to an alarm
state). These status can be used for any binary signal (ie, on or off) such as alarms,
switch position, position, etc. The user must assign suitable identification and determine
how the indication will be used. The data type is included so the user can include
indications in the synchronously sampled data set that are important to using phasor
system data and adding understanding of power system operation. Some of these values
may have local reporting in the substation and some may not, however it should be
possible to determine the local state of all such indications.
Method
Find a suitable means to read the values as sent from the PMU. These values are often
provided by a PMU display. MISO is currently investigating solutions that will allow for
easy local validations to be performed. Locate the source of the signal and if possible a
display or indicator in the substation. Determine that the normal state is correctly
indicated by the (phasor) data. In cases where the indication can be changed by changing
the state of the source, to that and observe that the indication changes. In cases where the
source cannot be changed, such as breaker position on a critical line (that cannot be taken
out of service), operate the input in a test mode to be sure the indication changes. It is
important to actually change the input state (ie, voltage into the PMU) to be sure all input
thresholds are satisfied and the input is operable and correctly mapped to the data. Do
this for all digital inputs that are sent as digital status.
Documentation
Documentation in the form of notes and test results needs to be provided to show this test
was successfully completed. It should detail if the test was not completed and why, such
as for lack of access. It should include a description of the instrumentation used to
confirm the measurements and the method of validation used. It should show the actual
values, calculations where needed, and the results.
Appendix A: Pre-installation Preparation
5. CONTROL CENTER INSTALLATION
REQUIREMENTS
The control center installation includes the PDC, communication systems, and various
applications. This checkout is primarily to assure that the communication to the PMUs is
operating correctly, the data is correctly identified and scaled, and interstation phasing is
correct. It also provides an initial comparison with state estimation to confirm if the
overall measurement schemes compare.
1. Confirm that received data matches the setup and the time stamps are within 2
seconds of the local time.
There will generally be a number of remote devices (PMUs and PDCs) reporting to the
control center. The data received from each device needs to be validated that it matches
the data description. At this stage only the message reports need to be validated; data
content will be validated in step 3. If the time stamps do not match the actual time, the
data will not match and cannot be combined. These issues need to be resolved before the
data itself can be validated.
Method
Data is mapped as binary values into a frame (message) that is sent from the PMU to the
control center. These frames will vary in size and content from station to station. The
receiving device, usually a PDC, will make the connection to the remote and request a
configuration message. This message will provide the data description including names,
scale factors, data type, and the location in the data frame. The PDC uses this
information to decode and scale the data to usable values. The contents of this message
need to be examined and compared with a listing of data items listed in the design
documents. The names should match, all data items should be accounted, and scale
factors should seem reasonable. Data values will be more closely examined in step 3, but
a review at this stage can reveal problems that are more difficult to diagnose later.
Appendix A: Pre-installation Preparation
A timestamp is included with all data frames. It indicates the time of measurement. Data
frames should be sent with minimal delay, so they should be received with a time stamp
that is no more than a few seconds earlier than the current time. The data time stamp is in
UTC time which will be offset from the local time and does not change for daylight
seasons. Determine what the current offset from local to UTC time is. The offset from
Eastern Standard Time (EST) is +5 hours (add 5 hours to EST time to get UTC) and
Eastern Daylight Time during the summer season +4 hours. Use an accurate local time
reference and visually compare the received data time with the local time. This can be
done with some PDCs or alternatively a data viewing program for a PC, or Connection
Tester. A visual comparison can determine if the times are within one second of each
other. If the received data time appears to be more than one second ahead or more than 3
seconds behind local time, there is like a clock error at the PMU or some other setting
problem that needs to be resolved.
Documentation
Documentation in the form of notes and test results need to be provided to show this test
was successfully completed. It should include a listing of the data that is being sent from
each substation and the scale factors provided by the PMU. It should also give an
approximate time comparison between the received data and local time (document the
observed + or – difference of seconds between the local and received data times).
Describe the method for performing these tests and list of the equipment used.
2. Catalog communication errors and show that the overall data loss is less than
0.1% over a 24 hour period.
Each remote device reporting to the control center has a communication channel which
may include a number of links, translations, carrier systems, and so on. Each element of
the communication chain can cause impairments of one type or another. This test simply
observes and documents these impairments over a 24-hour period as well as assures that
the overall data loss is less than 0.1%. Phasor data systems can be operated at loss rates
much less than 0.1% (which is approximately 2 data samples/min at 30/s data rate), but
this rate will generally provide usable data for most applications. A well designed and
Appendix A: Pre-installation Preparation
implemented system can be expected to have a loss rate <0.001% (1 frame/hour) during
normal operation.
Method
For each remote measurement input to the control center, monitor the reception of data
over a 24-hour period and record all data loss. The inputs will usually be from a single
PMU at a substation, but can be from a substation PDC or possibly from another PDC
that collects data from other PMUs. The record of data loss should include separate
tallies of data that is received but corrupted, data that is not received but expected, and
any unexpected changes in data format. The receiving device needs to have a long
enough wait that it includes all data received up to a reasonable delay of at least 10
seconds (ie, it should count data that is up to 10 seconds delayed as successfully
received). Data that is received with a time stamp more than 10 seconds from the current
time should be counted as lost with a time error. The tally should also include data
received but flagged as in error. These flags are data invalid, PMU error, PMU sync lost,
or sort-by-arrival. For data loss that is significant (> 0.001%), the record should include
sufficient information to determine the pattern of data loss, such as all loss in one
dropout, 1-2 frames at a time spread over the time period, a regular repetition for dropped
frames, etc. For this requirement, the received data itself should be saved so this more
detailed analysis can be performed.
Documentation
Documentation in the form of notes and test results need to be provided to show this test
was successfully completed. It should demonstrate that the data loss for each input
channel is < 0.1% over the 24 hour test period. It should include a list showing the
number of times and overall percent of each category of data loss including:
1. Data not received
2. Data received but corrupted (CRC error or similar)
3. Data received with time stamp error
4. Data received with error flag set
Appendix A: Pre-installation Preparation
a. Data invalid
b. PMU error
c. Sync lost
d. Sort-by-arrival
In cases where data loss is significant (> 0.001%), the store of data captured during the
test should be further examined for the pattern of loss; this will be included in the report.
Describe the method for performing these tests and list of the equipment used.
3. Compare received signals with SCADA measurements and confirm that they
report the same values within the following limits:
•
Voltages – 1% + 1kV magnitude
•
Currents – 3% Above 50 Amps magnitude & same direction
•
MW/MVAR – 5% magnitude & same direction
•
Frequency – 0.003 Hz
SCADA provides fairly complete power system measurement capability for most
utilities. This step confirms that the phasor system reporting is consistent with that
provided by SCADA. Since SCADA is the established system, the accepted position is
that it is correct. The comparison will first help to locate measurement quantities that are
mislabeled or otherwise incorrectly identified. Second it will enable finding scaling or
wiring errors. Last, it may result in correction of SCADA measurements. Some
measurements from phasors will not have a SCADA equivalent, so can be skipped in this
procedure. These measurement comparisons are intended to be taken once and reported;
if taken several times over different operating conditions, the results will be more
accurate and useful, but this is not required..
Method
Comparisons can be done with live displays side by side, or snapshot data samples. The
important point is that data from each will need to be compared at the same time.
Appendix A: Pre-installation Preparation
Both systems provide voltage measurements. As long as the comparisons are from line
or busses that are connected, the voltages will be essentially the same. In many cases the
SCADA measurement is a single phase. If the phasor single phase measurements are
provided, the same phase can be used for comparison. The positive sequence is generally
close enough. Phasors generally report line-neutral, so use appropriate conversions.
SCADA systems often do not report currents. If they are available, make phase by phase
comparison where possible. MISO’s system designates the current as out of the bus
when in phase with the voltage. For consistency, it is recommended the current direction
be designated the same as in the SCADA system.
SCADA systems usually do report MW and MVAR. Phasor systems usually do not,
however they are easily calculated from the V & I measurements. An additional
application may be required to make these conversions, or the V & I values including
angle can be obtained and the user can manually calculate them. Once calculated the
comparisons are easy to make. The direction indications follow the current direction
choices. If the directions do not match, the problem is probably the current direction
designation.
An important note for current, MW, & MVAR calculations are the reduced precision at
low current levels. If current is less than 20% of the indicated full scale, the
measurement is likely to be less than the rated accuracy and the resulting comparisons
will be worse. The error is usually worse for the angle, so computing MW or MVAR is
likely to have high error. For example, a line scaled for 2000 amps but with only 100
amps (5% rated) might show a var reading of 20 MVAR when it really only has 3
MVAR. The point here is do not expect to get good comparisons with this kind of
reading. Wait for higher flows, or simply note the result and the conditions as observed.
Frequency varies constantly but generally in a limited range during normal steady-state
operation. Choose a quiet time in the system to make the measurements. It is best to
compare the phase measurements against each other to spot any that are in error. If the
many phasor measured frequencies are close to each other, then the SCADA
measurement is probably in error. Keep in mind that the SCADA measurement probably
Appendix A: Pre-installation Preparation
averages frequency over a second or more, while phasor measurement is over a few
cycles at most.
Documentation
Documentation in the form of notes and test results need to be provided to show this test
was successfully completed. It should list all the signals from each that were compared
and show the results. The comparison methods need to be described and the equipment
used listed.
4. Validate data status indications.
Every frame of data includes a 4-bit data quality status indication. These 4 bits are data
valid, PMU error, sync valid, and sort by arrival. The “good” or normal state is cleared
to 0; when set to 1 the bit indicates the alarm or abnormal state. These bits are set by the
measurement device (PMU) or other processing devices (PDC) based on measurement
conditions or errors detected in further data processing. The annex describes these bits
and their use. This step is to validate that these quality indications are being properly
received and handled by the control center equipment.
Method
For each incoming data stream, observe the status indications with a device that receives
the incoming data. Confirm that all bits are cleared (to a 0) indicating that all incoming
status indications are good. If any are set to 1 indicating a trouble condition, confirm that
the impaired state is actually valid. No further testing is required for this requirement.
While not required, further testing of system operation is recommended. First set up a
data output from the control center PDC. Observe that the input under test is included in
the output. Disconnect or disable that input only. Observe that the output data for that
input is marked as invalid data. Second, if the PDC allows manually setting the input to
sort by arrival, set it that way. Observe that the output data stream indicates the data is
Appendix A: Pre-installation Preparation
timed using sort by arrival. Third, if assistance is available at the substation, have the
timing synchronization removed from the clock (remove GPS antenna) so the clock will
go to an unsynchronized status. Observe that the sync bit is set in both the input and the
output data.
Documentation
Documentation in the form of notes and test results need to be provided to show this test
was successfully completed. It should list what testing was done and the results. The
documentation for the 24-hour test in step 2 also supports this validation. List the
equipment used.
5. Compare received signals with EMS State Estimation results and confirm that the
phasor system reports the same values within the following limits:
•
Voltages – 2% magnitude, 1 degree phase angle
•
MW & MVAR – 5% magnitude & same direction
State Estimation (SE) uses primarily watt and var measurements along with bus voltages
to estimate the complex system voltages (magnitude and phase angle) across the grid. By
using over-determined equations and complex processes to reduce systematic errors, the
techniques can provide highly accurate results, including location and reduction of actual
measurement errors. SE solutions are used to operation guidelines as well as system
security assessment, so they become a critical element in system operation. Since they
are taken as the basis for operation, phasor system measurement should compare
accurately with SE, and differences need to be resolved. SE is also the only method other
than phasor measurement that can provide system phase angle, which is the basis for all
power flow.
Method
SE is usually executed automatically on a scheduled basis, with repetition ranging from
one to many minutes. Comparison will be done using a snapshot of captured phasor data
corresponding to the same time as the SE. Data for the SE will usually span several
seconds to several minutes. The best approach is to use phasor data with a time stamp
Appendix A: Pre-installation Preparation
close to the middle of the SE time. It is also important to use a time when the system is
as quiescent as possible. If one can observe the frequency signals, choose a time when all
the phasor frequency signals are changing very little. At these times the phase angles and
consequently power flows are undergoing minimum change.
Use a single phasor data snapshot for the comparison, using only valid, synchronized
data. Use the positive sequence voltages and currents for the calculations and
comparisons. Use the voltage phase angle to calculate phase angle between busses.
Compare the SE solution at as many points as possible, making at least one magnitude
and angle comparison at every station where there are phasor voltage measurements.
This process is an important step in the validation of phase angle measurement in each
station.
The MW and MVAR comparisons are not as important at this step since they are
probably also covered in step 3. If the SE does not provide MW and MVAR estimates
corrected from those supplied by SCADA, these comparisons are already covered in step
3 and do not need to be done here. The same observations provided in step 3 about
limited accuracy due to low currents apply here as well.
Problems in SE solutions are well documented. The phasor solutions are likely to be
better than those from the SE in boundary areas and where there are limited
measurements. This step has also proven to locate errors in SE configuration.
Differences in excess of the given comparison limits should be investigated to determine
the cause, which could be in either measurement system.
Documentation
Documentation in the form of notes and test results need to be provided to show this test
was successfully completed. It should list all the signals from each that were compared
and show the results. The comparison methods need to be described and the equipment
used listed.
Appendix A: Pre-installation Preparation
6. CHECKLISTS AND DOCUMENTATION
Appendix A: Pre-installation Preparation
APPENDIX A: PRE-INSTALLATION
PREPARATION
System Design
Phasor measurement system installation starts with the system design. System design
should start with the applications that will use the data and the requirements for that that
serves these applications. These considerations include but are not limited to:
1. Locations from where measurements are required (PMU location)
2. Signals to be measured at those locations (including phasors, analog quantities,
Boolean indications, frequency)
3. Data rate (rate at which measurements are sent from site)
4. Maximum reporting latency (delay in sending data from site)
5. Reporting reliability (allowable data loss)
6. Measurement characteristics (accuracy, resolution, bandwidth, filtering)
It is often the case that the applications that will use the data are not specifically defined
or fully characterized. Since the technology is relatively immature, even currently
defined applications are likely to develop and incorporate new requirements. In absence
of well-defined requirements, system design can use general requirements that have been
found to serve existing and expected applications. MISO has provided a set of basic
requirements for this phasor measurement system.
The next step in the system design is designation of methods and equipment to
accomplish these design requirements. These considerations include:
1. Communication capability to the designated locations
2. Selection of communication equipment to meet the bandwidth and latency
requirements
Appendix A: Pre-installation Preparation
3. Selection of PMUs to make the required measurements
4. Selection of ancillary equipment to suit the PMU (timing input, interposing
transformers & relays, etc.)
5. Actual installation design
Careful design at the initial stage will save a lot of time later. In some cases information
may be difficult to find, such as PMU capability, reliability, and installation details. The
terminology is also new to most design groups, so it may be difficult to understand the
specifications. It may be advisable to engage a consult to help with the design and
specification process to avoid problems later on.
Design considerations are detailed in C37.242 sections 6.3 through 6.6 with a summary in
6.7. This document focuses on the installation and checkout, so will not delve further
into the design stage here.
Equipment Selection
Phasor Measurement Unit (PMU)
There is a wide variety of PMU equipment available. These range from specialized
PMUs that have only a single voltage and current input to DFR type equipment that will
handle a dozen or more V and I signals distributed throughout a substation. The main
PMU differences that are considered here are:
1. Number of V & I inputs
2. Distributable input interface units
3. Auxiliary inputs for analog or Boolean (status) inputs
4. Timing input
5. Communication interface
6. Algorithm selections
7. Accuracy & performance
Appendix A: Pre-installation Preparation
8. Multi-function devices vs. single function PMUs
9. Cost
All V & I inputs should be 3-phase and the PMU should offer positive sequence as one of
the output options. The number of inputs and how many of each of V & I will vary by
the installation and the requirements. Generally the principal bus voltage and major line
currents should be included in the measurement set. Since the incremental expense to
include most line currents is small, most utilities will try to do a complete station
measurement. It may be necessary to include several PMUs to cover a large station.
Another issue is access to the V & I signals. In some substations, the currents are only
available at distributed relay houses, or even in bay controller boxes. When choosing a
PMU, it is necessary to determine how the signals are distributed for access. It may
require using a PMU that has distributable input modules that can be located where the
input signals are available or use smaller size PMUs that can be locally installed. The
issue is a little more complicated than just the number of inputs.
The focus is usually on the V&I inputs for phasor calculation, but in many cases, the user
needs auxiliary information like breaker or switch status, or perhaps the exciter value.
Having all this information in a coherent measurement set can be the key to a forensic
analysis or essential to a wide area control system. Analog and Boolean data is included
in the C37.118 measurement set and is supported by some PMU vendors. If these data
types are required for the phasor data system, the designer must select units that support
them and with input characteristics that match the installation.
All PMUs require a precise time input. Most will either use a direct GPS input (from an
antenna) or an IRIG-B time code. For the former, it means the PMU must be located
within allowable cable length distances from an antenna mounting point (including
routing into the building). For substations, this is usually not too difficult is well planned.
Fortunately the signal is fairly resistant to interference from substation equipment. IRIGB must be likewise provided from a high accuracy source, usually GPS. The IRIG signal
type needs to match that expected by the PMU which should be high accuracy (level shift
or Modified Manchester). Modulated signals are really not accurate enough. The second
Appendix A: Pre-installation Preparation
thing is the 37.118 (also called 1344) time information profile should be used so the PMU
can determine when a timing error occurs.
Most PMU devices will use an Ethernet interface and be included on an IP network.
Some models only have RS-232 serial. It is certainly easier to use network
communications from end to end, but serial-Ethernet translators are available and work
well. In some cases, serial may be preferred due to cyber security concerns. Serial or
network will handle all communications from a single PMU up to 60/s data rates. The
designer needs to determine the necessary bandwidth and allowable delays and designe
the system accordingly.
PMU algorithms and performance are difficult to assess without testing and a thorough
study of the technology. Generally, a PMU with M-class performance will have more
accuracy but more delay in reporting. A PMU using P-class will be faster reporting but
will suffer loss of precision in some situations. These performances will vary somewhat
between devices. Most PMUs will offer both classes of performance. It is recommended
that the designer evaluate the intent of the system and design accordingly. Choose a few
PMUs that meet the expected use, and have them tested. Choose PMUs that pass
C37.118.1 requirements and other particular tests that are specified, and have the best
measurement accuracy. It may be advisable to consult with others through involved
technical organizations for more insights.
Two commonly cited differences are units that are built into equipment with other
functions such as a relay (multi- function) or are stand-alone for PMU function only.
While dual-function characteristics are a valid concern, they really are not much different
that a dedicated unit. A single function units needs to be tested under realistic operating
conditions to be sure that some housekeeping tasks will not interfere with the critical
PMU functions. A multi-function unit needs more careful consideration of what the
alternate function may be doing, but otherwise is the same. The PMU functions needs to
be tested for proper operation while the alternate function is occupied in its reasonable
operating scenario. In all cases, realistic assessment of operational tasks is required.
Appendix A: Pre-installation Preparation
Cost is always a consideration, sometimes the most important. Generally the overall cost
of installing a PMU with its communication component is 3-10 times that of the PMU
itself. Based on this, it makes sense to choose a PMU that fits into the situation the best
with the least amount of auxiliary equipment. That will often be the cheapest alternative
overall.
Communication equipment
Phasor measurement data is usually sent as packets with phasor, frequency, and other
measurements all corresponding to the time stamp that is included in the packet. This is
referred to as a data frame since the measurements are more complex than a sampled
waveform. The rate is usually 10/s or greater and the data is pushed from the PMU at the
periodic rate rather than polled by command. Data rates are generally pre-planned, so it
is easy to calculate the required bandwidth. The actual equipment will depend on the
communication facilities in the substation and the communication system that connects to
other locations. Detailed scenarios are not presented here since there will be a wide
variety of actual equipment needs as well as company procedures and regulatory policies
to follow. The basic requirements of data rate (bandwidth), latency, and reliability should
be presented to communication specialists to design the system and specify the
equipment.
Timing source
Presently (in 2012) the only source of time that is reliable and accurate enough for phasor
measurements is GPS. The Global Position System (GPS) uses satellites that transmit
precisely timed signals that a receiver correlates to triangulate position. The satellite time
codes are stable and synchronized to universal time (UTC), so the signals can be used to
provide a precise time as well as position. A PMU may have a GPS receiver installed
internally inside or may require a timing signal from an external GPS receiver. The basic
GPS signal is 1575 MHz so it will travel only a limited distance from the antenna. The
designer must consider the PMU location relative to potential antenna locations if the
PMU uses an internal GPS. Note also that a single antenna can supply several receivers
by using amplifiers and splitters. It the PMU is supplied by an external GPS clock, it will
Appendix A: Pre-installation Preparation
receive timing by local time code. The most common local time code is IRIG-B. The
level shift and modified Manchester versions have sufficient precision for
synchrophasors. There may be some issues with amplitude and impedance matching, but
these are readily solved. The IRIG codes were designed for timing on military test
ranges, so they do not have built-in continuous timekeeping capability. In particular, they
do not inherently provide indication of synchronization to a universal time source. These
added features can be provided in the indication or control codes. The C37.118 standards
provide a recommended set of codes tor continuous timekeeping. If the GPS clock can
add this code set and the PMU can read it, the PMU can provide the synchronization time
and status required by the standards which are necessary for reliable measurement system
operation. If the GPS receiver is internal to the PMU, the required time and status can be
derived directly. Details for GPS installation and time distribution are left to specific
manufacturer instructions.
Appendix B: Equipment Installation
APPENDIX B: EQUIPMENT INSTALLATION
Communication equipment
Utility and equipment procedures need to be followed. Most PMUs now use network
communications, so the system will require network implementation at the installation site as well
as the control center or wherever the data is being sent. Recommendations on communication
equipment installation are out of scope of this document. See C37.242 section 6.6 for more
details.
Timing equipment
Some PMUs incorpate an internal GPS receiver while others receive time from an external unit.
The key issues here is that the PMU requires a very precise time reference which can generally
only be supplied by a satellite based timing system. GPS is the only widely available system that
is fully operational. The GPS receiver must have access to an antenna that can receive the 1.5
GHz signal. The antenna requires good sky view as the satellites track in a semi-polar orbit. In
most cases the distance to the antenna is limited, so placement of the receiver is tied to the
placement of the antenna. Installation needs to consider these limitations.
If the PMU uses an external timing source, a local time code is required. IRIG-B is the usual
choice, though other codes are used in some cases. In all cases, the clock needs to be able to
convey to the PMU the synchronization status with respect to UTC standard time. C37.118 has a
profile for IRIG-B that will convey this status. This or other means must be used as the PMU
needs to report sync status as well as data. This is critical where applications rely on phase angle
measurement for decision making. See C37.242 section 6.3.2.
PMU equipment
The manufacturer instructions need to be followed for this installation.
MAYBE add some DETAIL from the other paper including signal access, signal scaling, MORE?
See C37.242 sections 6.3.3, 6.4, and 6.5.
Appendix C: Installation Checkout at the Measurement Site (Substation)
APPENDIX C: INSTALLATION CHECKOUT AT THE
MEASUREMENT SITE (SUBSTATION)
The basic goal of equipment checkout is to confirm the signals being measured, the
interaction among the equipment components, and data reporting. In some cases
calibration can be achieved. It is anticipated that the equipment has been calibrated and
tested for standard operations before installation. It is often difficult to do more extensive
testing in the field, so it is better done in the laboratory.
Communication equipment
The communication system needs to be first checked using standard communication test
equipment. Data transfer should be confirmed from the PMU to the receiving device,
usually a PDC, independently from the phasor data system. Then once the phasor data
system is established, it needs to be continuously monitored for problems with
appropriate alarming for prompt resolution. See C37.242 section 6.14 for more details.
End-to-end connectivity
Devices on each end should be able to contact each other and establish connection where
that is required. This test assures that there is a complete path and required signaling is
installed. For networks, it assures that routing and firewall settings are correct. The
connection test needs to use the actual methods that the phasor equipment will use, such
as TCP to a certain port or multi-cast UDP. If it is not possible to reasonably simulate
these paths, the actual systems can be used. Sometimes this is very difficult to do with
phasor equipment as it may have not diagnostic tools. The use of a sniffer like Wireshark
may be very helpful.
Reliable operation
Connectivity confirms the path exists and works. Path problems can create reliability
issues. The system needs to be monitored for data loss that indicates path problems. If
the path involves a connected state of operation (e.g. TCP), then monitor to be sure the
connection is not dropped an excessive number of times. Monitor the data for loss or
Appendix C: Installation Checkout at the Measurement Site (Substation)
data errors (CRC errors). Look for patterns in each kind of errors. Insufficient
bandwidth, communication mismatch, a noisy link, and excessive latency can lead to data
loss. Each of these will have a different pattern which may not be consistent, so it is best
to analyze the problem based on the results rather than a fixed criterion. This analysis
should be ongoing because problems may crop up any time.
Timing equipment
GPS timing equipment is generally self-contained with few user accessible diagnostics.
The signal from the satellite is spread-spectrum so is not visible on a signal analyzer.
Once installed and powered up, a receiver should detect satellites within a few minutes
and lock onto the minimum 4 satellites required to achieve synchronization within a few
minutes. Most receivers will display a dilution of precision (DOP) value (PDOP, TDOP,
etc.) which indicates how good the time and position solution is. This value should be
low, maybe 1-5. If the receive signals are weak or blocked, the DOP will be high. Since
the satellite positions change constantly, it is necessary to monitor the performance over a
period of time, preferably at least a week initially, to be sure there is not blockage or
interfering signals that will cause a problem.
If the receiver is external to the PMU, it will have a time code that is sent to the PMU.
IRIG-B is the most common. This code needs to include an indication of lock to the
UTC time provided by the GPS system. Without this the PMU can only determine that it
is locked to UTC or not. The timing profile in C37.118.1 has complete information that
can be imbedded in the IRIG-B code, including the new continuous time quality
indication. The PMU should be capable of reading this timing profile.
The basic test is to be sure the PMU reads the time code and indicates that it is locked to
it. The phase angle determined by the PMU should match other measurements as
detailed in the next section. To test the loss-of-sync detection, remove the antenna cable
from the receiver or PMU. The GPS receiver should indicate loss of lock to GPS and
within one minute the PMU should set the loss of sync bit. If this does not happen, the
system needs to be corrected. (Note that there could be induced voltages on the antenna
which are effectively grounded through the antenna cable shield. When the cable is
Appendix C: Installation Checkout at the Measurement Site (Substation)
removed, the sheath may disconnect before the signal conductors. This can result in
excessive voltage on the antenna or receiver amplifier components resulting in unit
failure.)
There are no quantitative tests recommended for timing installations since the receiver is
generally much more accurate than any other source at a substation. If more
characterization is required, a separate reference clock device will need to be provided
along with equipment that can compare the signals very precisely. GPS receivers
generally accomplish self-monitoring very well. Further information can be found in
C37.242 section 4 and section 6.3.2.
PMU equipment
Introduction
The PMU is the heart of the installation. It makes the measurement using the AC signals
and timing, makes any required adjustments, and sends measurements to applications. It
needs to meet standard requirements for input and electromagnetic interference
protection. It must tolerate input overloads such as fault currents. It will often have
several 3-phase signal inputs. It requires a timing input, either directly from an antenna
or from another local time source. It will usually need to handle communication directly
to the control center or other external application. This part covers the checkout of these
factors.
The installation checkout confirms that the PMU is making the planned measurements,
the timing inputs are working correctly, and the data output is operating as expected.
This is not intended as a calibration procedure.
The first test after physically installing the device and its inputs is to apply power. Most
PMUs have some kind of front panel indications to confirm that the unit is operating and
if there are any error alarms. Confirm that the unit is operating normally before moving
on to the rest of the process. Use vendor provided information to resolve initial
problems. Further information can be found in C37.242 sections 6.9 - 6.13.
Appendix C: Installation Checkout at the Measurement Site (Substation)
Voltage and current inputs
Essentially the process is to confirm the inputs are correctly identified, calibrated, and
phased. Checkout in the substation requires a display or tool or software application that
allows looking at the phasor output. It works best having this on-site, but it can be done
by having someone read values sent to the control center. Methods to look at, evaluate,
and compare these phasor values are assumed in the following discussion. The phasor
outputs may include single phase phasors, sequence phasors (positive, negative, zero), or
both. Positive sequence is most often reported, so it is also assumed it will be available
for comparisons. If it is not present, single phase phasors can be used instead with some
adjustments in analysis.
Magnitude
The magnitude of voltage and current signals is determined from the signal itself; the
time reference does not affect the measurement. The value should be the RMS value for
the signal. All three phases of a three phase signal and positive sequence should be about
the same magnitude. Phasing can affect positive sequence, so if it is significantly
different, check Phasing below.
Values can be checked using panel meters in the station or direct measurements on the V
& I inputs. Measurement of direct inputs with standard test instruments will produce a
much more accurate comparison, but will not reveal any high-side scaling errors. Since
these signals vary constantly, an exact comparison is not possible. In most cases
comparison within 2% should be achievable. If there are significant discrepancies (5%
and greater), wiring and scaling should be checked. This can also be a flag that the
wrong currents or voltages have been wired in. Note that most voltage phasors are l-n, so
multiple by Sqrt(3) to get l-l values.
Phasing
The PMU may require the phases for a specific 3-phase input to attach to specific
terminals or may allow the user to select the phases in software. Errors in phasing can be
determined and corrected as follows:
Appendix C: Installation Checkout at the Measurement Site (Substation)
1. Phase order - If A-B-C phases are not in the correct order, the positive sequence
will be small, close to zero. Swapping any two phases will correct the order. Aphase should be the about same phase angle as positive sequence which can give a
guideline for the overall designation.
2. Missing phase - If there is a missing phase, the positive sequence will be 2/3 its
normal value. Single phase phasors should tell which phasor input is missing.
Note that a missing input can be from a connection problem or a failed input
channel.
3. Reversed phases – Most PMUs use Y connected voltages so the connection is
unlikely to be reversed. With current, the CTs are line current which can be
connected with either polarity. While there is no absolute designation, the most
common orientation is positive power (V x I*) is power flowing out of the bus.
Thus if using the convention of positive power is power flowing out of the bus,
the current will be approximately in phase with the voltage. Conversely if power
is flowing into the bus, the current angle will be approximately 180 degrees from
the voltage. All currents on lines with the same power flow should have similar
phase angles.
4. Designated A-phase – Since measurements cover a wide area, it is necessary to
have the same A-phase designation for all substations over the area where the
measurements will be compared. Since the phase angle is determined by both the
time reference and the waveform, this both a good time sync and the proper
phase. The measured phase angle will deviate over time based on the difference
between actual system frequency and absolute frequency, whose phase is fixed in
time. Consequently there is no fixed reference that can be used at a single
substation for checking the system phasing. This check will be covered in the
next section for checking at the control center.
Phasing comparison is more difficult to achieve. If measuring the actual V & I input with
test instruments, the V-I relation can be measured directly. Choose a particular V phasor
and measure everything with that reference. Check the phase angles as shown by the
phasor values. The angles should compare within 3-5 degrees except for very low
currents which may be 10-25 degrees off.
Appendix C: Installation Checkout at the Measurement Site (Substation)
The most common substation metering is power. The relative V-I phase angle can be
determined from these values by φ = tan-1 (Q/P). This method is a little less accurate but
should be within 5-7 degrees. As stated above, determining the accuracy of absolute
phase relative to other measurements requires system comparison or laboratory type
testing, so is not included here.
Frequency
Frequency is generally derived from rate of change of phase angle. It can, however, be
derived in a more traditional way, such as the period between zero crossings. It can be
derived from any AC signal, but a voltage signal, either one of the phases or the positive
sequence, is usually used. The particular source signal is usually assigned by the PMU
vendor. Some PMUs allow the user to select the signal. There may or may not be a fail
over signal designation. If the signal fails, the frequency measurement will be lost.
Some PMUs lock the frequency output to a nominal value if the source is too low; others
will continue to estimate frequency from whatever signal is present, which usually
presents a rather poor measurement.
Frequency can be compared with any local measurement device. The PMU measurement
is generally very precise and will probably be better than any comparable measurement.
In any case, the measurements should be within 0.005 Hz. Frequency is generally very
close to nominal (within .025 Hz), so there is little variation over which to make
comparisons.
Rate of change of frequency (ROCOF)
ROCOF tends to be a very noisy measurement since it is the second derivative of the
phase angle, the measurable quantity. It is generally derived as the derivative of
frequency. Currently the only use is as an indicator of a sudden change in frequency due
to some kind of an event. In that case it may spike to 20 Hz/s or more, which raises
measurement significantly above the normal noise floor.
There is no other measurement that is normally comparable. Testing consists of
observing that the ROCOF remains less than 0.5 Hz/s during a few minutes of steady-
Appendix C: Installation Checkout at the Measurement Site (Substation)
state operation. If possible to introduce a sudden change, ROCOF should provide a spike
much higher than nominal. Realistic numbers are left to the observer.
Other analog signals
The synchrophasor standard, C37.118.2, includes an analog signal type which is not
phasors. This is intended to cover scalar measurements such as exciter values, controller
settings, or air pressure. By sampling these values and including them in the data stream,
auxiliary equipment operation can be analyzed right with the power system. Since these
values can be sampled by an A/D, input digitally by other controllers, or provided other
ways, these measurement details are not provided by the standard. It is left to the user to
provide and define scaling, operation, and meaning for these signals.
Since the signals and their meaning are user defined, the user will have to determine how
to validate their operation. The PMU in this case only provides the channel for reporting
data.
Digital indications
The C37.118.2 synchrophasor standard also includes a digital data type which is a
Boolean value. These values normally represent switch, alarm, or other indications than
are represented as a 0 or 1. They are packed into 16-bit digital words for transmission to
the control center. In most cases, the PMU samples the digital input when it sends a
report. Since reporting is generally very fast, 12/sec or faster, this is unlikely to miss any
changes. If the input changes state twice (e.g., 0 to 1 and back to 0) in the same sampling
interval the change will be missed since the value is reported at the sampling time. In
some cases, the PMU may latch the change so it will catch momentary transitions. That
leads to another problem where the reported value is not the current state. These details
of performance and operation need to be examined by the user so that measurement
reports can be correctly understood.
Testing digital indications consists of setting the input to one state or another and
confirming the correct indication is reported.
Appendix D: Installation Checkout at the Control Center
APPENDIX D: INSTALLATION CHECKOUT AT THE
CONTROL CENTER
It is assumed that system is first checked out at the substation. If this is not the case,
some of the initial procedures for measurement validation will need to be done at the
control center. When measurements are sent to a control center, they are already in
digital form and the values will not change unless corrupted in transmission. This is
detectable by virtue of the CRC and error detection imbedded in the underlying
communication protocol. So the accuracy at the control center is the same as at the
substation. The issues between substation and control center are:
1. Signal identification and naming
2. Data timing and grouping
3. Data loss
4. Data errors
5. Data quality indications
6. Wide area angle and frequency comparisons
7. More?
Signal identification and naming
Signals are identified in relation to the power system by a name that may incorporate
some key words or use a standardized abbreviation convention. At the substation level,
names can be localized and assigned with little confusion. However when combined with
data from a large geographic area, a local name can be confusing. For example, “North
345 kV Bus” may be very precise at the substation but very ambiguous at the system
level. The first challenge is making sure the naming as reported from the PMU can be
related to the power system. The C37.118 format provides both signal naming and
station naming. These can be combined for a system recognizable name. Or the signals
themselves can have a system name or code. In any case, the name should uniquely
define the signal so the measurement can be reliably the compared with other
measurements.
Appendix D: Installation Checkout at the Control Center
Data sent from a PMU is in a certain order in a message. The configuration provides a
“blueprint” associating a name and scaling with each data item. The receiving systems
must decode the messages correctly and must detect any changes in the messages to keep
the decoding consistent with the data actually being sent.
Data should be compared with other data systems to assure the signal identification is
correct. This comparison will usually be done with the EMS/SCADA system. Since
phasor measurements report V, I, and F while most SCADA measurements are MW,
MVAR, and V, some conversions will be required.
The simplest comparisons are power and magnitude:
V = |V|
I = |I|
(MW) + (MVAR) i = VI*
where bold indicates a complex number and i = √-1 is the imaginary number.
Comparisons of voltage and current magnitude should be accurate, within the accuracy
limits of each measurement. However SCADA measurements are often done on a single
phase which can differ from positive sequence according to the system imbalance. To
get the closest comparisons, the comparisons should match phase and type if that is
possible. Otherwise, use the positive sequence phasors and allow for some differences.
Comparisons of MW and MVAR will likely be a little less precise. While the SCADA
should be full 3-phase, the phasor will use positive sequence and it will not necessarily
average out between current and voltage imbalance. There can also be some power flow
contribution from harmonics which are removed from the phasor values. The other issue
in these calculations is using small values. Small values limit numerical resolution and
also introduce noise when the phasor is calculated. If the current is very small, say less
that 20% rated, the A/D may be using only a few bits of resolution so the measurement
will be noisy, particularly angle measurement. Noise and accuracy in calculated values
will be similarly affected. Likewise when the phase angle between V and I is small, the
Appendix D: Installation Checkout at the Control Center
MVAR will be small is likely to be inaccurate due to limited resolution. Similarly if the
phase angle between V and I is near 90 degrees, the MW measurement will be affected.
For the purposes of confirming signal identification, comparisons within 2-5% are
sufficient, particularly for MW and MVAR. Voltage and current measurements should
be within 3%. However, confirming calibration calls for comparison to the required
accuracy of each signal. Thus if the SCADA and phasor measurements are each required
to be 1%, the comparison should be no worse than 2% (=1% + 1%). The user needs to
decide how these comparisons will be used.
Data timing and grouping
Data is sent in packets or “frames” as described in the C37.118 standard. A frame is
block of measurements with status indications and a time stamp for the time that the
measurements were taken. A data frame may be broken up and may be delayed in the
communication process. C37.118 frames have a CRC that can be used to assure the
contents are intact and not mixed up with other frames. Since frames may be carried over
other protocols, the receiving device needs to be able to reassemble frames reliably and
check the CRC. The user should confirm that the device they are using will reliably
perform these functions.
Delays will usually be small, but can be up to several seconds. This is highly dependent
on the communication system. Since data is sent on a continuous and timed basis, it is
possible to confirm the output delay from the PMU itself. If the PMU meets C37.118.1
requirements, it is required to output data within a few reporting periods (see standard).
Using that as a baseline, a receiving device can be used to timetag when the data is
received at the control center, thereby testing the communication delays. While an
accurate measurement is not necessarily easy to perform, and approximate value that
compares delay with other data inputs is quite achievable. The important part of this
procedure is to assure that delays from all remote units are similar. It is best to do this
test in over a 24 hour (or longer) interval to be sure that there are not some periodic
events that adversely affect one or more inputs. If this or other continuous monitoring is
not feasible, 1-5 minute snapshots throughout a 24 hour period are advisable.
Appendix D: Installation Checkout at the Control Center
Differences in delay between signals should be less than 100 ms unless very special
circumstances apply, such as separate back-to-back connected communication systems or
very big distance variations. Differences over the 24 hour period should show smaller
changes, perhaps 50 ms or less. In either case, results that are significantly different than
these general figures should be investigated. There could be perfectly acceptable reasons
for different numbers, but generally larger deviations are because of a problem in the
configuration.
Data loss
Data loss is the most common problem in data transmission from the PMU to the control
center. The cause can range from faulty equipment to overloaded communication
channels. Some data loss is acceptable as there will always be random error effects.
Generally the data loss should be less than .1% in all cases. Loss < .001% is very
achievable. This author has observed data transfer with no loss for more than 2 weeks at
a time.
At system checkout, first confirm if there is loss. The system should be observed for at
least a 24 hour period. If there is no loss, consider it done. If there is loss, look for a
pattern. Is it a single sample at random intervals, blocks of samples randomly spaced, or
something periodic? Random single samples at rates < .01% (1 sample/10,000
equivalent to 1/6 min at 30/sec) is not worth pursuing. 0.1% (2 samples/min at 30/sec)
may be acceptable in overall performance, but it shows communication problems if it
occurs continuously. At this rate of loss, overloaded network segments or faulty
equipment are likely to be the problem. If it happens on a regular interval, look for a
correlation between the time and the data loss. Greater amounts of data loss are likely to
be communication overload or even network mismatches (such as half vs full duplex). It
is often easier to diagnose problems with larger amounts of data loss. In all cases, look
for regular patterns of loss and correlation between time and operation of other systems.
The problem could be at (or in) the PMU, so it may be necessary to intercept and check
the data loss at the PMU output as well as at points in the data transmission system.
Data errors
Appendix D: Installation Checkout at the Control Center
Errors in data transmission will usually be masked by the receiving systems as data loss.
Most phasor systems now use a network communication system which protects data
integrity at the data link layer with a CRC or other means. When that layer receives data
with an error, it discards the packet and the user only observes a missing packet.
Systems that still use serial have direct access to the RS232 interface and will detect
errors through the packet CRC. These can be observed by the users. Generally such
errors will only be caused by data collisions or interrupted channels. If data errors of this
nature happen more than a few times/day, the complete communication channel needs
end to end testing to find the problem. Alternatively there could be a modem problem. It
is possible that there is a problem in the PMU or receiving device itself, and this will
require more thorough testing to determine.
Data quality indications
Every frame of C37.118 data contains four basic quality indications. These are data
valid, PMU error, sync valid, and sort-by-arrival. The data user has to check the quality
to know if the data item is indeed valid data and if there are restrictions for its use. Since
data is generally sent as a stream of measurements from a PMU to a PDC, then to an
application or another PDC, and so on, quality needs to be passed on and changed
according to errors or problems in the communication.
The context of data quality indications is as follows: Each PMU will include a single
quality flag that covers the status of all the data in the frame. The quality applies to one
frame at a time (it can change from frame to frame) and while it may affect each
measurement differently, it applies to all measurements in the frame. A PDC receives
data from one or more PMUs. It collects all the frames corresponding to a particular time
stamp and puts the data into a single frame with that time stamp. The data from each
PMU remains in its own block that includes its quality indications. Those indications
may be updated by the PDC as described in the following paragraphs. The output data
frame is always the same size (for a particular data stream) and always has blocks of data
from the same PMUs in the same locations. This ordering of the data is described by the
configuration and is necessary for the receiving device to decode the data. Quality
Appendix D: Installation Checkout at the Control Center
indications for each PMU must always be included to identify the state of the data
contained in the block, since the block is always included. Thus the quality indications
are an integral part of the data.
The data valid bit indicates if the data in the given PMU block is valid or invalid. If the
bit is set to invalid, the user should not use the data for anything. At best, the user may
user the data but only with a prior knowledge of why the bit is set to invalid. The bit is
usually set to invalid by a PDC to indicate that no data was received from the data source
for this particular data frame. In that case, the data that is in the PMU block is random
values used as a placeholder. Other reasons for setting the bit to invalid are a PMU in
test mode, receipt of a CRC error, and PMU transmission problem. There is proposal to
set the data to a NaN (not a number) to differentiate non-data from errored data, but that
is at present not an established standard.
The PMU error bit is reserved for the PMU to indicate there is a measurement or
operation problem. The exact meaning of this bit is left to the particular vendor since
there are many problems it could be used to indicate. These can include but not be
limited to A/D problem, computation overflow, memory failure, input failure,
configuration error, etc. The PMU error may be fatal and invalidate some measurements
or may be an advisory. In any case, when this error is detected, the user should
investigate and determine the cause of the indication before using the data. Note that
some vendors have used this flag for other things relating to data processing as well. The
user needs to follow the data chain to find the source of the flag and take action
accordingly.
The sync valid bit indicates whether the measurement is accurately synchronized to UTC
time. The PMU needs to have an indication from the time source, whether internal GPS
decoding or and external input as using IRIG-B, that the signal is synchronized to UTC;
otherwise the PMU should set this bit to 1 to indicate not in sync. Once the bit is set to 1
(not in sync), it should never be set to 0 by other processing in the chain since no device
can re-synchronize it. If the PMU reports the measurement is in sync (bit cleared to 0),
succeeding devices will normally pass on the flag without changes. However, it is
possible that the PMU does not correctly determine sync; if a succeeding PDC
Appendix D: Installation Checkout at the Control Center
determines the measurement is not in sync, it may set the bit to indicate not in sync. Note
that if the measurement is not is sync, the phase angle will not be dependable, but the
magnitude measurements should be intact. Generally the frequency and rate of change of
frequency will be within usable limits as well. Also note that in most cases, all
measurements from a single PMU use the same internal time reference, so the angles
between phasors from the same PMU are accurate even though the external sync is bad
and the angles with phasors from other PMUs are invalid.
The sort-by-arrival bit indicates the data has been assigned a local timetag by the
receiving device. In the case of data that is received with a time stamp that is not
reasonably close to the current time, the PDC can be equipped to detect this as a timetag
failure and assign a time stamp locally. So this will not be misinterpreted by subsequent
systems, the sort-by-arrival bit must be set to indicate the timetag is artificial. It is also
recommended the sync valid bit should be set to indicate the synchronization is invalid,
since the phase angles will not be reliable with any timetag change. The rationale and
process for sort-by-arrival is as follows: Phasor data systems send data in real-time with
minimal delays. Generally the latency in reporting (time delay from measurement to
receiving by subsequent systems) is a fraction of a second, at least in the first link from
the PMU to the first PDC. Even if it is longer than this, the delay will be less than a
significant timetag error that is detectable by a PDC. If data is received by a PDC with a
timetag that is clearly incorrect, the time that the data is received at the PDC is closer to
the actual measurement time than that assigned to the data frame. The PDC can assign a
timetag that is approximately the current real time and the data will thus have a
measurement timetag that is closer to the actual measurement time than what was
received with the data frame. This process is executed by placing the data in a frame
with other data corresponding to the most current time.
A few of the details above need a little more explanation. First, the PDC cannot detect
time errors anywhere near the accuracy required for phasors. Small timetag errors will
not be detected and this process will not be used in those cases. Time errors in the range
that will be detected and corrected in this process will be in the range of 1 minute or
greater. Consistent delays in data transmission will be much less than this, so the
Appendix D: Installation Checkout at the Control Center
difference is clearly differentiable. The mechanism by which the PDC detects a timetag
error and the length of time it requires to change to or from a sort-by-arrival status is left
to the PDC vendor. The actual timetag assigned should be consistent with other received
data so it is as close to the time of measurement as possible. Again, the mechanism for
doing this is left to the PDC vendor.
Checkout of data quality requires affirming that the control center PDC or any
intermediate PDC passes on the quality bits as received and manipulates them as
described. It should also be confirmed that all applications that use phasor data read and
interpret the quality bits. For example, any application which uses phase angles should
read and take appropriate action based on the sync error and sort-by-arrival bits, either of
which indicates that the phase angle measurement is not reliable.
Wide area angle and frequency comparisons
The control center is likely the first place where voltage phase angles from different
PMUs can be compared. Voltage phase angle directly relates to power flow between
busses. Power flow in an AC system is determined by the relative phase angles, with real
power flowing from a higher to lower phase angle. In cases where there is a phasor
measurement on busses that are only connected by a single line, the phase angle can be
computed from the power flow and line impedance. In most cases there will be more
than one path for power flow between busses. The phase angle will be determined by the
bulk impedance and power flow using all paths between the busses. The best way to
validate system phase angle measurement is by comparing the phasor measurements
between busses with a state estimation solution. The comparison should be done using
measurements taken at the same time. Since SCADA will typically span a number of
seconds, the best approach is to average the phasor values over the same time range.
However in a steady-state situation, a snapshot will probably be adequate. The angles
should be within 0.5 degrees generally. Some allowance can be made for long corridors
or areas where measurements for state estimation are sparse, perhaps up to 1 degree
errors. Angle differences above 2 degrees bear investigation. Differences under 0.5
degrees may still indicate errors, but are generally within the differences in measurement.
Appendix D: Installation Checkout at the Control Center
Each PMU provides a frequency measurement with a 0.001 Hz resolution. The minimum
required accuracy is 0.005 Hz. These frequency measurements reflect the change in local
bus phase angle, so during system swings and other events the measurements will vary
considerably. However during quiet periods of quasi steady-state, the individual
measurements should be consistently within a 0.002 Hz range and should compare within
the accuracy limit across the system. This frequency measurement is higher accuracy and
resolution than typical SCADA based measurement. In steady state the two
measurements should track each other within 0.002 Hz, and at least within the 0.005 Hz
limit. Note that these comparisons need to be made when the system is at steady-state.