Application of Time-Synchronized Measurements in Power System Transmission Networks

The use of synchronized measurements, particularly synchrophasors, has a history of over 30 years of research and development. This technology allows measurements at different physical locations to be synchronized and time-aligned, then combined to provide a precise, comprehensive view of an entire region or interconnection. Figure 1.1 depicts the locations of currently deployed devices called phasor measurement units (PMUs) that are participating in the North American Synchrophasor Initiative (NASPI) project and provide synchrophasor measurements across North America. It should be noted that there are many more installed PMUs across the USA and around the world that are not part of the NASPI project. In the last few years, the effort of deploying and demonstrating a variety of applications that can benefit from synchronized measurements has been accelerated through the NASPI and other related industry efforts. Most recently, several utilities and regional market operators have developed plans for large-scale deployment of such a technology. In the deployment of the intelligent electronic devices (IEDs) for substation synchronized measurement applications, the focus at present is on two approaches: (a) use of PMUs (dedicated high-precision recording instruments) and (b) use of PMU-enabled IEDs (digital fault recorders (DFRs), digital protective relays (DPRs), digital disturbance recorders (DDRs), and other devices that have PMU measurement capability). While the number of PMUs across the US utility networks in the NASPI network is estimated at 250, the number of PMU-enabled IEDs sold by manufacturers is more than a million and is increasing. With the recent investments through the American Recovery and Reinvestment Act (ARRA) and other funding sources, the total number of PMUs and PMU-enabled IEDs may increase by an order of magnitude as the industry starts utilizing the capabilities of this technology to improve protection, control, and operation of the system in the next 5–10 years. The effective utilization of this valuable asset will require substantial manpower for substation installation, communications, data integration, and visualization.

One obvious application of GPS-synchronized measurements is the dynamic monitoring of the operating conditions of the system or the dynamic state estimation of the system. Since GPS-synchronized measurements can directly measure magnitude and phase of an electrical quantity (voltage and current) and since the state of the system often is defined as the voltage phasors at all buses of the system, some researchers have declared that GPS-synchronized measurements provide for the direct measurement of the system state and therefore there is no need for state estimation. This is not quite right since GPS-synchronized measurements are always tainted with measurement errors, and procedures for filtering the errors are necessary. These procedures are enabled by state estimators. Another important reason for using state estimators is that they provide the mathematical framework for validating the measurements against the model of the components of the system. This is the only practical approach to validate measurements. GPS-synchronized measurements enable new, better, accurate, and faster procedures for state estimation. In other words, GPS-synchronized measurements are the enabling technology to achieve system visibility and awareness at speeds not imagined before.

Power system operation is undergoing major technological advances with many new installations of synchrophasors all across the North American grid as well as in power systems all over the world. Recent initiatives by the US federal government in the general area of smart grid technology are contributing to installations of synchrophasor monitoring systems in many utilities in the North American power grid. The industry–university collaborative organization, North American Synchrophasor Initiative (NASPI), is serving as a major coordinating group in leading the recent efforts in this direction. Synchrophasor measurements together with modern communication technology facilitate the monitoring of the current state of the wide-area power system in near real time. Recent research aims to exploit the availability of such wide-area synchronized measurements from across the system into developing new real time tools for power system operation.

With the advent of deregulation in the power industry and a lack of transmission investment, today’s power systems are operated much closer to their limits. Stressed system conditions mean that operators are faced with scenarios that never occurred in the past. Various critical decisions need to be taken in real time and this requires sophisticated software tools. One of the main issues that needs to be tackled deals with online dynamic security assessment and control. The objective of dynamic security assessment and control is to ensure that the system can withstand unforeseen contingencies and return to an acceptable steady state condition without transient instability or voltage instability problems. In this chapter, the application of a software tool that uses artificial intelligence (decision trees; DTs) is discussed. The approach is developed by training a set of trees based on simulations that are conducted offline. With advances in computer technology, it is now possible to create and store large databases that can be used to train agents. In this case, the agents are the DTs and the DT building procedure identifies critical attributes (CAs) and parameter thresholds. In order to evaluate stability limits in terms of critical interface flows and plant generation limits, the use of synchronized measurements from phasor measurement units (PMUs) has been proposed.

Fault location on transmission lines is an important application in power systems. It allows operators, as well as protection and maintenance staff, to pinpoint where the fault has occurred and initiate corresponding effort to repair and restore the affected transmission line. Once the protective relays have detected a transmission line fault and tripped (disconnected) the line by issuing a control command to circuit breakers, the fault location application determines the location by measuring voltages and currents at either or both transmission line ends. Over the years, many different fault location techniques were developed, but very few have used synchronized samples or synchrophasors. Most recently, the use of synchronized samples and phasors in fault location has become a subject of interest since the technology has matured and is readily available.