Seminar Report on Phasor Measurements Units

7/25/2019 Seminar Report on Phasor Measurements Units

1/15

1

INTRODUCTION

Operating of electric power systems is becoming more and more complex and is posing more

and more challenges every day as they are operated close to their stability limits. Electrical powersystems are expending (renewable energy source RES, distributed generation DG, independent power

producers IPPs, etc. which are often no dispatchable or controllable generation) while the energy

market (generation, distribution, transmission) is deregulated. In addition, regulatory pressure tends

to focus power system operators attention to grown the Return of Investment of their assets while

power consumption is increasing and power system infrastructures are aging. On the other hand, the

demand for higher reliability and power quality is increasing as power electronics driven sensitive

loads are added by the industrial consumers. Power electronic converters can be found wherever

there is a need to modify the electrical energy form (i.e modify its voltage, current or frequency).

Operational constraints have grown the amount of user stress while various blackouts have

happened in Europe and North America. This situation introduces a range of new requirements for

development and implementation of tools and equipment that will help the system operators andthe protection engineers in improving the system security when an event/fault occurs that may lead

to a wide area disturbance. The today technology enablers, that are basis for the new wide area

monitoring and controls implementation, are:

GPS(Global positioning System),

Ethernet Communication.

Several working groups analysing the context of last major blackouts in North America and

Europe have been launched by developing the use of new technologies (PMU, WAMS, WAPS) and by

implementing a coordinated investment strategy to modernize the power system infrastructure. So

there is a real willingness to develop and invest in new automation solution to get the most modern

and secure electricity grid.

Current and voltage synchrophasors or Phasor Measurement Units are some of the

parameters that can be used to observe the state of the system and improve the performance of

different system level applications. The Phasor Measurement Unit includes not only synchrophasor

and frequency measurements, but also recording and protection functions that make the device

usable both as a data source for the system level applications and an IED that can take local action in

case of wide area disturbance.


2/15

2

PHASOR MEASUREMENT UNIT

3.1Historical

In 1893, Charles Proteus Steinnmetz presented a paper on simplified mathematical description of thewaveforms of alternating electricity. Steinmetz called his representation a phasor. First phasor

measurement units developed in 1988 were based on Steinmetzs technique. Early prototypes of the

PMU were built at Virginia Tech, and Macrodyne launched the first PMU in 1992. However, their

implementations into the power systems were limited, as two main issues could not be addressed at

this time:

Real time phasor measurements (that are synchronized to an absolute time reference

provided by a Global Positioning Satellites GPS).

High speed and cost effective communication network.

The commercialization of the global positioning satellite (GPS) with accuracy of timing pulses in the

order of 1 microsecond made possible the commercial use of phasor measurement units.

3.2. Principle

A phasor measurement Unit (PMU) also called Synchrophasor, measures the electrical waves on an

electric power system to determine its state. A phasor is a complex number used to represent the

fundamental frequency component of voltage or current measured to a common time reference. This

common time reference is independent of the geographical position of the measuring device.

All measurements are done with the GPS one pulse per second (1pps) as the reference (in accordance

with reference [1]). The 1pps pulse can be from any external source provided the accuracy is in

accordance with the requirements.

peak

rms

Xi(n)

Xr(n)

1pps

Figure 1: Phasor measurement in relation to the common reference value

The result of the measurement is a vector X (synchronized phasor) as given below:

X X rjX i

X (X m 2)ej

Where Xm is the peak magnitude of the filtered synchronized vector and is the phase angle relative

to a cosine function at nominal frequency. IEEE C37.118 specifies that the angle is 0 degrees when

the maximum of the signal to be measured coincides with the GPS pulse and -90 degrees if the

positive zero crossing coincides with the GPS pulse.

Figure 1 illustrates this conversion, where X r(n) and X i(n) are the real and imaginary filtered RMS

components at a particular instance and is the phase angle in accordance with reference [1] . The


3/15

3

measured angle is reported over the communication channel in the range of to + radians.

A primary requirement is the accuracy of the measured phasor. Reference [1] defines the total

permitted vector error (TVE) for the static condition at nominal frequency as:

TVE ( Xr(n) Xr)

2 ( Xi(n) Xi)

2

X r

2

Xi 2where Xr (n) and Xi (n) are the measured real and imaginary components and Xr and Xi are the

reference values. This measurement accuracy varies with the magnitude and frequency of the input

signal.

3.3. Basic PMU architecture

The samples from the voltage and current inputs are collected by the A/D (Analog to digital

converter) at the rate of 48 samples/cycle but independent of the 1pps input. A well-proven

frequency-tracking algorithm controls the sampling interval in order to respond dynamically to

changes in system frequency. This data is sent to the measurement processors, which handle the GPS

and IRIG-B inputs, and provides synchronized phasor measurements. In addition to that acommunication processor handles the Ethernet communication. Figure 2 below shows the basic PMU

architecture. The synchronized measurements are transmitted upstream over Ethernet (TCP or UDP).

Protection and P594 GPSFibre optic Receiver

Digitised MeasurementAnalog A/D

1ppsSamples Processors

IRIG-BElectrical un-modulated

signal

Ethernet IEEE C37.118 DataProcessorData Frame over

Microprocessors Serial or Ethernet

P847 PMU(TCP/UDP)

Figure 2: PMU device

3.4. PMU function overview

As shown in Figure 3, the PMU data (phase currents, voltages, their derivatives, frequency, rate of

change frequency, digital signals) are:

Synchronized with UTC time from a GPS receiver with accuracy of < 1microsecond and

connected an accurate IRIG-B source.

Captured at a rate of 10, 12, 15, 20, 30 and 60 frames per second at 60 Hz.

Synchrophasors measure voltages and currents, at diverse locations and output accurately time-

stamped voltage and current phasors. Because these phasors are truly synchronized, synchronized

comparison of two quantities is possible, in real time. These comparisons can be used to assess

system conditions.


4/15

4

Figure 3: PMU function overview

3.5. Impacts of PMUs in State Estimation

The introduction of PMU technology is expected to significantly improve the observability of the

power system for State Estimation solution, Wide Area Protection and Control. The immediate

benefit is the use of the PMU data to correct topology errors (hence reduce the need for manualcorrection) and SE solution robustness, speed and accuracy.

PMU technology has the potential for a positive impact on SE in the following areas:

Enhanced Observability

Improve Solution accuracy, robustness

Faster Solution Convergence

Bad Data Detection and Topology Error Correction

3.6. PMU allocation

To date, electric companies have installed a small number of PMU devices in the field. Currently most

of the work is focused on the definition of requirements and the exploitation of the current

information for monitoring purposes. However, the nature of the allocation and result depends pretty

much on the following:

Problem being addressed

Measurements needed

How often we need the measurements

Robustness, accuracy and performance target

Current optimal PMU placement or allocation strategies focus on two alternatives:

Increase area of observability by gradual expansion of the geographical footprint as more

sites are included

Allocate PMUs so that inter-area oscillations and other critical dynamics will be correctly

monitored even without complete system observability; here the focus is on controllability to

implement actions to mitigate undesirable dynamic oscillations.

PMUs should be deployed in the network at critical buses to ensure that a sufficient picture of the

system topology is available to the control center. This system visualization shows the angular,

frequency and voltage differences between groups of generators, and the power flow. There is no


5/15

5

need to install PMUs at every bus of the system as it will not necessarily contribute to efficient

system operation and could cause congestion in the communications system.

3.7. Future perspectives

Simulations and field experiences suggest that PMUs can revolutionize the way power systems are

monitored and controlled. However, costs, available tools, number of data and communicationperformance will affect the number of PMUs to be installed in any power system and the

implementation of WAMS, WAPS and WACS solutions.

Synchrophasor measurements are becoming one of the new features available in some

multifunctional protection devices. There is an ongoing discussion in the industry regarding the

integration into the line protection. At this time, since the actual requirements for such

measurements is fairly limited and they are used predominantly by non-protection applications, many

protection professionals express preference to keep such functions in stand alone or disturbance

recording devices. On the other hand, there are new requirements for development of system

integrity protection schemes (SIPS) that may need the integration of phasor measurements in the

relays.

It is anticipated that over the next five to ten years over 1,000 PMUs will be deployed worldwide.

Each PMU typically monitors 6-8 phasor quantities.The phenomena involved during a power system

disturbance/blackout can be classified in 5 main classes: voltage collapse, frequency collapse, loss of

synchronism, large power swings and cascade of overloads. Preventive actions are implemented to

avoid such phenomena to occur by using wide area measurement systems. Curative actions are

implemented to avoid the spreading and so saving the rest of the power system by using manual or

automatic mechanisms depending of the quickness of the phenomena.

3.8. IEEE Standard

In 1995, the IEEE 1344 standard for synchrophasors was completed in 1995, and reaffirmed in 2001.In 2005, it was replaced by IEEE Standard C37.118-2005, which was a complete revision and dealt

with issues concerning use of PMUs in electric power systems. The specification describes standards

for measurement, the method of quantifying the measurements, testing & certification requirements

for verifying accuracy, and data transmission format and protocol for real-time data communication.

The standard is not yet comprehensive- it does not attempt to address all factors that PMUs can

detect in power system dynamic activity.


6/15

6

WIDE AREA MONITORING SYSTEM (WAMS)

4.1. Principle

As shows in figure 4, a phasor network consists of phasor measurement units (PMUs) dispersed

throughout the electricity system, Phasor Data Concentrators (PDC) to collect the information and a

Supervisory Control And Data Acquisition (SCADA) system at the central control facility.

All the PMUs are connected to a Phasor Data Concentrator (PDC) at either substation or control

center level.

Figure 4: PMU and PDC architecture

The complete network requires rapid data transfer within the frequency of sampling of the phasor

data. The PDC correlates the data, and controls and monitors the PMUs. At the central control facility,

the SCADA system presents system wide data on all generators and substations in the system every a

few seconds. The first PMUs were often using phone lines to connect to PDC, which then send data to

the SCADA and/or Wide Area Measurement System (WAMS) server. WAMS consists of measuring the

angle shift between the sub-networks using Phasor Measurement Units (PMU).

4.2. Inter-area system oscillation

One of the most common applications where PMU has already been used is Small Signal Stability

detection that is designed to detect slower inter-area system oscillations. These are mainly due topower oscillations between two areas of generation, running at slightly different speeds and

following small system perturbations such as load switching or tap changes. These oscillations do not

die away if there is insufficient system damping and could escalate and lead to an out-of-step

condition and therefore system separation if no pre-emptive action is taken. The PMU has an

advanced frequency tracking technique that can accurately measure and track small signal

frequencies and therefore provide an accurate measurement for the fast detection of small signal

oscillations.


7/15

7

Figure 5: PMU Data from two Key Buses in a system during a Disturbance

Figure 5 shows the Voltage and Frequency recorded at two generator buses 400 Km apart during a

drop in generation at another location. The oscillations in the magnitude and frequency can be clearly

seen but synchronized measurements allow the comparison of the phase of the oscillatory modes to

determine the parts of the system are oscillating against each other.

PMUs also provide a basis for a wide range of protection such as:

Monitoring angular instability

Monitoring frequency or rate of change of frequency

Monitoring voltage instability

State estimation (based on time-synchronized, measured data) Islanding

System recording or analysis

System restoration

4.3. On-Line stability solution (OSS)

The figure 6 presents the typical configuration for the OSS.

Figure 6: OSS configuration


8/15


9/15

9

WIDE AREA CONTROL SYSTEMS (WACS)

Wide Area Control System addresses automatic self-healing capabilities to some extent by proposing

decisive smart topology changes and control actions with the goal of maintaining the integrity of the

grid under adverse conditions. Dynamic islanding and fast load shedding are schemes available to

maintain as much as possible of a healthy transmission system. The process is designed to be highly

automated and is primarily constrained by the latest communication technology and PMU allocation

strategies.

The following issues should be considered as part of any development plan to address intelligent

recovery from catastrophic events:

Early, fast detection and monitoring of system security indices

Analysis of critical real-time information to trigger the dynamic security assessment

process

Wide-area information, control and protection schemes

Deployment of control actions for dynamic adjustment and reconfiguration

The plan for adaptive islanding requires a critical review of all steady-state and dynamic tools that are

available at the control center. This includes development of new tools and the coordination of the

existing applications for detecting and adjusting the configuration using technology and emergency

condition methods. The capability to model and simulate electricity grid behavior over a range of time

domains, frequency domains, and topological footprints need to be developed.

For Wide Area Control a redundant set of measurements is desirable. In the event of a failure of one

PMU, other adjacent PMUs and information from connected devices should provide reasonable

backup data. The EMS applications can improve the security margin using optimization techniques or

sensitivity routines that along with time domain simulation could predict the control actions to return

the system to normal.

The actions depend on the system state and problem and definitely the following applications will

use synchronized information:

State estimation

Fast time domain simulation

System state prediction

System recovery

The measurements are sent to the central point every 50 ms (20 times per second). This scheme is an

automatic real time system which detects loss of synchronism and take decision to separate out-of-

steep area and perform load-shedding when necessary in weak part of the systems to avoid

spreading over the power system. The communication needs are covered by a geostationary satellite

and terrestrial means.


10/15


11/15

11

SYSTEM INTEGRITY PROTECTION SCHEME

System Integrity Protection System is a tool to initiate system corrective actions as opposed to

equipment protection. Among the many system stress, scenarios that a SIPS may act upon are

transmission congestion, transient instability, voltage and frequency degradation and thermal

overloading. To implement effective, intelligent SIPS appropriate for the prevailing power system

condition, it is essential that a real time, fast-acting, system-wide data collection system be available.

An SIPS scheme can initiate load or generator rejection, load-shedding due to under-frequency or

under-voltage, out of step or loss of synchronism, system separation, remedial action schemes, short-

term or long-term stability control, etc.

These measures are normally inactive and are armed automatically when some system stress

condition occurs; alternatively, they may be armed manually from a control center. The remedial

action schemes (RAS) and system protection schemes (SPS) that have become popular in recent years

are SIPS systems. To create more intelligent SIPSs, one must rely on the newly available wide-area

measurement systems being deployed in many power systems.

Fig. 10: Time window per application


12/15

12

COMMUNICATION REQUIREMENTS

The communication requirements will differ when implementing Wide Area Measurement Systems or

Wide Area Control and Protection Systems.

Typically, UDP/IP through VPN (Telecom Service Provider) with some security capability is used for

WAMS. Such a solution can be provided by telecom provider and implemented between multiple

power networks and use standard communication system.

For Wide Area Control & Protection Systems, Ethernet VLAN using robust SDH Backbone is more

appropriated as redundancy; reliability and safety are the key requirements of such systems.

Redundancy of the communication links to ensure the information transmission in emergencies

(backup control centers) is also a key requirement to ensure good performance, reliable date and

secure communication. It is an essential pre-requisite for any self-healing processes at a wider

geographical grid level. Communications security is of the utmost importance since hackers could

otherwise compromise the integrity of the grid.

Options are classified according to the physical medium used for communication

Leased telephone circuits were among the first communication media used for these

purposes. Switched telephone circuits can be used when data transfer latency is not of

importance

More common electric utility communication media such as power line carrier and

microwave links have also been used, and continue to be used in many current applications.

The medium of choice now is fiber-optic links which have unsurpassed channel capacity, high

data transfer rates, and immunity to electromagnetic interference.

The two aspects of selecting communication channels are:

1.

Channel capacity

2. Latency


13/15

13

SYNCHROPHASOR TECHNOLOGY IN INDIA

The initiative taken up by Power System Operation Corporation Ltd. (POSOCO) in pilot manner in the

year 2010 by installing 4 PMUs in Northern Region. PMUs installed in all the 5 regions of the Indian

grid at strategically selected locations like generating stations, load centres , substations and

interconnecting substations. Total 64 PMUs have been installed in India, integrated throughrespective Regional PDCs installed at RLDC to Central PDC installed at NLDC, New Delhi. India

presently use 25 frames/ second speed PMUs.

Figure 11 : Current PMU Deployment in India


14/15

14

CONCLUSION

In order to ease the implementation of PMUs, there is a need to improve the interfaces and decision

support, to reduce the complexity so that system operators and managers have tools to effectively

and efficiently operate a grid with an increasing number of variables. Technologies include

visualization techniques that reduce large quantities of data into easily understood visual formats,

software systems that provide multiple options when systems operator actions are required, and

simulators for operational training and what-if analysis.

This paper has described a high-level plan to improve power system grid security. The primary intent

is to protect the electrical interconnection from a widespread collapse. Wide area controls are meant

to protect the grid as an entity. In some cases, the appropriate action would be islanding and blacking

out a portion of the grid in order to prevent widespread collapse (Defense Plan).

New Wide Area Systems will enable rapid diagnosis and provide solutions to specific grid disruptionsor outages. A successful intelligent grid control implementation will require careful coordination

between wide-area and local control schemes. Since many of the control actions will need to be

decided and executed quickly, the tools need to be reliable, prompt and correct. They need to have

secure backup schemes to ensure reliability. Secure, reliable communication has been identified as

the primary challenge to deploying automated, prompt self-healing wide-area grid control actions.

Another implementation challenge remains, the complexity, architecture, location and costs of such

type of Wide Area Systems. Some other difficulties are also reliability (acceptable over or under trip),

redundancy (where redundancy is required, identification of the critical path), performance of the

completed system including sensors and circuit breakers, and the maintenance aspects (impact

directly the reliability of the system).


15/15

15

REFERENCES

1. IEEE Standard for Synchrophasors for Power Systems (IEEE Std C37.118 - 2005)

2. Phadke, A.G., Kasztenny, B., Synchronized phasor and frequency measurement under transient

conditions, IEEE Transactions on Power Delivery, Vol. 24, No. 1, December 2008.

3. IEEE Standard Common Format for Transient Data Exchange (COMTRADE) for Power Systems,

IEEE C37.111-1991, Sponsored by the Power System Relaying Committee of the Power

Engineering Society.

4. Synchronized Phasor Measurements and Their Applications, A.G. Phadke and J.S. Thorp ,

Springer, New York, 2008.

5.

Phadke, A.G., Thorp, J.S., and Karimi, K.J., State estimation with phasor measurements, IEEE

Transactions on PWRS, Vol. 1, No. 1, February 1986, pp 233241.

6. Nuki, R.F. and Phadke, A.G., Phasor measurement placement techniques for complete and

incomplete observability, IEEE Transactions on Power Delivery, Vol. 20, No. 4, October 2005, pp

23812388.

7. D.Tholomier, HKang, BCvorovic, Phasor Measurements Functionality and Applications, Power

Systems Conference 2009, Clemson University Advanced Metering, Protection, Control,

Communication and Distributed Resources.

Seminar Report on Phasor Measurements Units

Documents