<div><div> <h2>CHAPTER 1</h2> <p><b>THE REAL-TIME AND STUDY-MODE DATA ENVIRONMENT IN MODERN SCADA/EMS</b></p> <p>Sudhir Virmani and Savu C. Savulescu</p> <br> <p><b>1.1 INTRODUCTION</p> <p>1.1.1 General Background</b></p> <p>Most large industrial control systems need to collect data at a central location, or at distributed sites, from a range of equipment and devices in the field, and to process this data in order to make a decision regarding any action required. Electric power control systems work basically in the same way but impose particularly stringent requirements on remote data acquisition and related processes because:</p> <p>• Power systems may encompass large geographical areas as almost all electric utilities have strong electrical interconnections with neighboring systems, which are generally owned and operated by different entities. Examples include: the interconnected systems in North America, such as the Western Interconnection, which consists of the power systems in all the western U.S. states plus the provinces British Columbia, Alberta, and Manitoba in Canada; and the large interconnection in mainland Europe, covering all the mainland European Union member countries plus some nonmembers.</p> <p>• Interconnected power networks are therefore very large, with potentially tens of thousands of nodes and branches and thousands of generating units.</p> <p>• Power systems in general must operate synchronously and this requires that all the interconnected systems must operate cooperatively in order to maintain reliability of the entire system.</p> <p>• Because of these strong interconnections, any disturbance in one part of the large network can affect the rest of the network.</p> <p>• Power system disturbances can propagate very rapidly (milliseconds to seconds) and this requires high-performance control systems, some of which are local, such as protective relays that operate in milliseconds, and some at central sites such as SCADA/EMS systems, which typically operate on the time frame of seconds (monitoring and control) to several days (scheduling).</p> <p>• Power system operations typically entail control requirements that can be met only by implementing complex hierarchies of regional and central/national control systems.</p> <p>• Power system operations in the context of large regional or subcontinental electric markets typically require exchange of information and coordination of control actions among various entities, such as independent system operators, security coordinators, and transmission system operators, thus leading to a higher degree of coordination and control systems.</p> <br> <p><b>1.1.2 Anatomy of a SCADA System</b></p> <p>The data acquisition systems that are implemented in the utility industry therefore have to be able to support these needs. Furthermore, in order to make sure that the control actions being taken are correct and safe, certain control actions performed centrally require a positive confirmation, that is, they must be supervised. This is the <i>supervisory control</i> function and, therefore, the overall system is called supervisory control and data acquisition or SCADA.</p> <p>The basic elements included in, and the minimum capability of, a typical SCADA system, consist of:</p> <p>• Interfaces in the field (substations) to equipment and devices located within the substation.</p> <p>• Ability to scan these interfaces to obtain the values of various quantities such as real and reactive power, current, voltage, and switch and circuit breaker position. The data are either reported by exception or scanned periodically. Typical scan rates are every 1–2 seconds for generation and interchange data and circuit breaker status indications; every 2–15 seconds for line flow and voltage measurements, and every 15 minutes to one hour for energy values.</p> <p>• Transmission of these data items to a central location known as the SCADA (or SCADA/EMS, as shown in Section 1.4) center.</p> <p>• Processing and analyzing this information at the SCADA center and displaying it to the operator.</p> <p>• Determining any control action to be taken either automatically or by operator request. The control actions required can be for controlling real power, reactive power, voltage, circuit breakers, and power flows.</p> <p>• Transmitting the request for control to the field equipment.</p> <p>• Monitoring the completion of the control request.</p> <p>• Building the real-time database and periodically saving real-time information for archival purposes.</p> <br> <p><b>1.1.3 Real-Time Versus Study-Mode Processes</b></p> <p>Most of the SCADA functions are executed in real-time. By real-time we mean that the:</p> <p>• Input data reflect the most recent picture of the system conditions. In the field (substation), they come directly from devices that capture analog values and status indications; at the SCADA center they are stored into, and retrieved from, the real-time database.</p> <p>• Processing is performed within very short delays typically not exceeding a couple of seconds.</p> <p>• Output is usable almost instantly; again, "instantly" in this context means approximately one to two seconds.</p> <br> <p>The monitoring of data generated by a real-time process is a typical example of real-time activity. But the information generated in a SCADA system can be used in many other ways that do not qualify as real-time. For example, statistics can be built to record how many times the taps of a tap changing under load (TCUL) transformer have moved during a specified period of time. The tap changes were recorded in the real-time database immediately after they occurred, and then they were exported to some archival system and became historical data. The calculations entailed in building the statistic constitute a "study" performed with "real-time" data and, perhaps, some additional information; thus we will say that this is a "study-mode" calculation.</p> <p>In the computational environment of a modern power system control center, some functions are performed only in real-time, whereas some others are performed only in study mode. However, as we will see in the next section, there are functions that can be used both in real-time and in study mode.</p> <p>Let us say in passing that real-time and online are not necessarily interchangeable attributes. On line implies that the calculations are available to the operator in the SCADA/EMS system itself, hence they are online as opposed to being available on some other separate system. However, there is no guarantee that the online computational process will be fast enough to produce results that can be labeled real-time. These considerations should help the reader understand the difference between the real-time stability assessment, stability monitoring, and online stability assessment concepts that are often mentioned throughout this book.</p> <br> <p><b>1.1.4 Next Level of Functionality: The EMS</b></p> <p>In order to determine the control actions required, it is necessary to simulate the operation of the power system in close to real-time. The software tools needed include what are commonly referred to as energy management system (EMS) applications. A very terse and unstructured summary of these functions is given below:</p> <p>• Automatic Generation Control (AGC) to determine the real power output of all the generating units in the system to maintain interchange and frequency. In the interconnected system, each member (control area) performs the AGC function by computing the area control generation load mismatch (area control error or ACE) at the nominal frequency (60 Hz or 50 Hz) and adjusts its generation to reduce the mismatch to acceptable limits.</p> <p>• Economic Dispatch (ECD or EDC) to determine the optimal level of real power output for each generator to minimize the total production cost (this function works in conjunction with the AGC function).</p> <p>• Reserve Monitoring (RM) to compute the real power capability available in the system to meet changes in demand.</p> <br> <p>The above functions consider the generating units only and generally tend to ignore the network (transmission lines, transformers, reactors/capacitors) and voltage. Some ECD implementations do include an approximate model for transmission system losses.</p> <p>In order to obtain a more comprehensive view of the system, the following network analysis functions are required:</p> <p>• The State Estimator is used for determining the complete state of the system (voltage and phase angle at each node) based on the measurements from the field. These measurements are generally "noisy" and not available for every element. The state estimator determines the best estimate of the state using a set of redundant measurements, taking into account the measurement error characteristics and missing and bad data.</p> <p>• Static security analysis, or contingency evaluation, determines the effect of possible outages such as loss of branches (transmission lines, transformers), generating units, and combinations thereof.</p> <br> <p>These two functions run both in real-time, either executed periodically, with a period of a few seconds to a few minutes, or triggered by events or operator requests, and in study-mode, that is, executed if and when needed to assess postulated scenarios closed to, or derived from, the current operating conditions.</p> <p>In addition, there are other functions that are executed in study-mode, including:</p> <p>• The load-flow/optimal power flow, which is used to calculate all of the system variables, with the optimal power flow being used to compute these variables based on optimizing certain system quantities (production cost, losses, voltage levels, transformer tap changes). These are initialized using the results of the state estimator, and additional data needed, such as generator data, is retrieved from the database.</p> <p>• Hourly load forecasting which is used to predict the hourly total load/total demand that the system will have to supply over the next few hours to up to several days. This function enables the operator to schedule facilities for maintenance, for reconnection, and for start-up and shutdown of units</p> <p>• Unit Commitment/Hydro-Thermal Scheduling is used to schedule the start-up and shutdown of generation units to meet the forecasted demand. This function typically looks ahead for 24–168 hours depending on the characteristics of the generating units being scheduled. This is a nonlinear optimization problem with both integer and continuous variables. Consequently, it is a computationally intensive function for systems with a large number of generating units that have to be scheduled. It should be noted that whereas in vertically integrated utilities the unit commitment/hydro thermal scheduling is part of the EMS/SCADA, in deregulated electricity markets, the software that performs unit commitment/hydro thermal scheduling is part of the market system. However, the functionality is the same; only the responsibility is separated.</p> <br> <p>When these EMS functions are included, one generally refers to the system as a SCADA/EMS system although historically the EMS acronym implied that the system included both SCADA and EMS functions.</p> <p>Finally, there are a number of support functions required in SCADA/EMS systems such as:</p> <p>• Alarm processing,</p> <p>• Display generation,</p> <p>• Report formatting and printing,</p> <p>• Storage of real-time data in a historical information system (HIS) for archival purposes,</p> <p>• Special-purpose functions for data conversion and interfacing to local devices, such as mapboards, time and frequency standards, and chart recorders, and</p> <p>• Communication interfaces with the SCADA/EMS systems of other electric utilities.</p> <br> <p>As one may infer from the above, the infrastructure needed in the current-day SCADA/EMS systems is very extensive and includes:</p> <p>• A large-scale telecommunication network that interconnects the field equipment to the SCADA/EMS center. The telecommunication technologies include a mix of leased telephone lines, power-line carrier, microwave radio, copper and fiber optic cable, as well as VHF and UHF radio. Most electric utilities are implementing large-scale backbone networks using fiber optic cables and moving from a radial system to a more meshed system using IP.</p> <p>• Powerful computer systems at a central location or, for hierarchical control systems, at one location on top of the hierarchy and several subordinated computer systems at the other locations.</p> <p>• Operator interface equipment that can respond to multiple requests for new displays within one second.</p> <p>• Large data storage and long-term historical data archival capabilities that are easily accessible to operators and engineering personnel.</p> <br> <p>Last, but not least, the system must have a very high availability. At the SCADA/ EMS center, 99.9% availability is required and is achieved by providing redundant computer and local communication systems.</p> <p>The brief enumeration of functions and capabilities presented in the previous paragraphs suggests that in order to understand the complex data interfaces and software interactions between the SCADA/EMS system, on the one hand, and a sophisticated add-on application such as stability assessment software, on the other hand, we need to step back and follow a systematic approach aimed at identifying the:</p> <p>• Overall architecture in a simple format, such as a conceptual overview diagram, that depicts the major building blocks and would make it easy to visualize the information flow between them.</p> <p>• Functional architecture, for the purpose of positioning the stability assessment application in the SCADA/EMS data and functional environment.</p> <p>• Implementation architecture, which provides clues about the integration, tight or loose, of software that performs real-time and study-mode stability assessment.</p> <br> <p>This analysis is briefly developed in Section 1.2.</p> <br> <p><b>1.1.5 The Impact of Wide-Area Monitoring Systems</b></p> <p>Phasor measurements, a technology developed in the late 1970s and early 1980s, mainly due to the visionary work of Arun Phadke, are being finally deployed extensively in power system networks. To some extent, this has been facilitated by the availability of relatively inexpensive GPS receivers that enable the synchronization of the phasor measurements over large geographical areas, but it is also due to the better and more powerful electric utility telecommunication networks, largely fiber optic based, and faster low-cost processors. Direct measurement of the voltage and current phasors throughout the entire network essentially eliminates the need for state estimators in an ideal case (complete and error-free measurement set) and gives a complete picture of the system on a milliseconds (25 cycles) time frame.</p> <p>However, due to measurement errors and bad or missing data, state estimation will be necessary but will be simpler since a linear model suffices. Most phasor measurement units calculate phasor values by sampling the analog signal for each phase at sampling rates of 12 times per cycle and higher, and using discrete Fourier transform analysis to compute the positive sequence values. Phasor reporting time is synchronized throughout the power network, and the phasors are estimated from sampled data, which is referenced to the phasor reporting time. Availability of phasor values on a milliseconds time scale thus has very important consequences for power system operation since it allows monitoring of power system dynamic behavior.</p> <p>In the technical literature, these measurements are referred to as wide-area monitoring systems and have been deployed in many countries worldwide, for example, the United States, with more concentration in the western states (California, Oregon, etc.); in Switzerland, especially on the interconnection tie lines; in many generating plants and interconnection points in Southern China; and in Canada (BC Hydro). Phasor measurements are not simply ideal for steady-state analysis; they can be used to detect possible system separation and system oscillations in close to real-time and, in principle, may allow for closed-loop control for maintaining system stability. One of the principal problems with the current EMS state estimation and related functions such as contingency analysis is the need for a model for the "external system," that is, the system outside the internal area. This is still an unsolved problem, even with greater inter-control center communication. Phasor measurements can help to largely overcome this problem since the availability of synchronized phasor measurements from the external areas can make the modeling of external networks more accurate and simpler, since a reduced-order model can be used. Furthermore, since phasor measurements give information on a millisecond time frame they can assist in the rapid detection of system separation and potential blackouts.</p> <p>However, it must be noted that phasor measurements are another mechanism for monitoring the system and do not have predictive capability. In other words, one still has to perform some analysis to determine where the system will be at a future time. Furthermore, at the present time, closed-loop control for transient operation has not been realized in practice and remains a subject of active research. However, installation of phasor-measurement units is becoming more common and their use can only increase, especially as the cost of these units continues to fall. In fact, many companies are providing the ability for determining phasors as part of the digital relays, which are being used in substation automation. Thus, if a substation is being upgraded, adding phasor measurement is a low-cost option requiring only a GPS receiver. </div></div><br/> <i>(Continues...)</i> <!-- Copyright Notice --> <blockquote><hr noshade size='1'><font size='-2'>Excerpted from <b>Real-Time Stability Assessment in Modern Power System Control Centers</b> by <b>S. C. Savulescu</b>. Copyright © 2009 The Institute of Electrical and Electronics Engineers, Inc.. Excerpted by permission of John Wiley & Sons. <br/>All rights reserved. No part of this excerpt may be reproduced or reprinted without permission in writing from the publisher.<br/>Excerpts are provided by Dial-A-Book Inc. solely for the personal use of visitors to this web site.</font><hr noshade size='1'></blockquote>