The Energy Control Center

The following criteria govern the operation of an electric power
system:
• Safety
• Quality
• Reliability
• Economy
The first criterion is the most important consideration and aims to ensure the safety of personnel, environment, and property in every aspect of system operations. Quality is defined in terms of variables, such as frequency and voltage, that must conform to certain standards to accommodate the requirements for proper operation of all loads connected to the system.
Reliability of supply does not have to mean a constant supply of power, but it means that any break in the supply of power is one that is agreed to and tolerated by both supplier and consumer of electric power. Making the generation cost and losses at a minimum motivates the economy criterion while mitigating the adverse impact of power system operation on the environment.
Within an operating power system, the following tasks are performed in order to meet the preceding criteria:
• Maintain the balance between load and generation.
• Maintain the reactive power balance in order to control the voltage
profile.
• Maintain an optimum generation schedule to control the cost and
environmental impact of the power generation.
• Ensure the security of the network against credible contingencies.
This requires protecting the network against reasonable failure of equipment or outages. The fact that the state of the power network is ever changing because loads and networks configuration change, makes operating the system difficult. Moreover, the response of many power network apparatus is not instantaneous. For example, the startup of a thermal generating unit takes a few hours. This essentially makes it not possible to implement normal feed-forward control. Decisions will have to be made on the basis of predicted future states of the
system. Several trends have increased the need for computer-based operator
support in interconnected power systems. Economy energy transactions, reliance
on external sources of capacity, and competition for transmission resources have all resulted in higher loading of the transmission system. Transmission lines bring large quantities of bulk power. But increasingly, these same circuits are being used for other purposes as well: to permit sharing surplus generating capacity between adjacent utility systems, to ship large blocks of power from low-energy-cost areas to high-energy cost areas, and to provide emergency
reserves in the event of weather-related outages. Although such transfers have helped to keep electricity rates lower, they have also added greatly to the burden on transmission facilities and increased the reliance on control. Heavier loading of tie-lines which were originally built to improve reliability, and were not intended for normal use at heavy loading levels, has
increased interdependence among neighboring utilities. With greater emphasis on economy, there has been an increased use of large economic generating units. This has also affected reliability. As a result of these trends, systems are now operated much closer to security limits (thermal, voltage and stability). On some systems, transmission links are being operated at or near limits 24 hours a day. The implications are:
The trends have adversely affected system dynamic performance.
A power network stressed by heavy loading has a substantially different response to disturbances from that of a non-stressed system.
• The potential size and effect of contingencies has increased dramatically. When a power system is operated closer to the limit, a relatively small disturbance may cause a system upset. The situation is further complicated by the fact that the largest size contingency is increasing. Thus, to support operating functions many more scenarios must be anticipated and analyzed. In
addition, bigger areas of the interconnected system may be affected by a disturbance.
• Where adequate bulk power system facilities are not available, special controls are employed to maintain system integrity. Overall, systems are more complex to analyze to ensure reliability
and security.
Some scenarios encountered cannot be anticipated ahead of time. Since they cannot be analyzed off-line, operating guidelines for these conditions may not be available, and the system operator may have to “improvise” to deal with them (and often does). As a result, there is an ever increasing need for mechanisms to support dispatchers in the decision making process. Indeed, there is a risk of human operators being unable to manage certain functions
unless their awareness and understanding of the network state is enhanced.
To automate the operation of an electric power system electric utilities
rely on a highly sophisticated integrated system for monitoring and control.

Such a system has a multi-tier structure with many levels of elements. The bottom tier (level 0) is the high-reliability switchgear, which includes facilities for remote monitoring and control. This level also includes automatic equipment such as protective relays and automatic transformer tap-changers. Tier 1 consists of telecontrol cabinets mounted locally to the switchgear, and provides facilities for actuator control, interlocking, and voltage and current
measurement. At tier 2, is the data concentrators/master remote terminal unit which typically includes a man/machine interface giving the operator access to data produced by the lower tier equipment. The top tier (level 3) is the supervisory control and data acquisition (SCADA) system. The SCADA system accepts telemetered values and displays them in a meaningful way to operators, usually via a one-line mimic diagram. The other main component of a SCADA
system is an alarm management subsystem that automatically monitors all the inputs and informs the operators of abnormal conditions. Two control centers are normally implemented in an electric utility, one for the operation of the generation-transmission system, and the other for
the operation of the distribution system. We refer to the former as the energy management system (EMS), while the latter is referred to as the distribution management system (DMS). The two systems are intended to help the dispatchers in better monitoring and control of the power system. The simplest of such systems perform data acquisition and supervisory control, but many also have sophisticated power application functions available to assist the operator.
Since the early sixties, electric utilities have been monitoring and controlling their power networks via SCADA, EMS, and DMS. These systems provide the “smarts” needed for optimization, security, and accounting, and indeed are really formidable entities. Today’s EMS software captures and archives live data and records information especially during emergencies and system disturbances. An energy control center represents a large investment by the power
system ownership. Major benefits flowing from the introduction of this system include more reliable system operation and improved efficiency of usage of generation resources. In addition, power system operators are offered more in-depth information quickly. It has been suggested that at Houston Lighting & Power Co., system dispatchers’ use of network application functions (such as Power Flow, Optimal Power Flow, and Security Analysis) has resulted in considerable economic and intangible benefits. A specific example of $ 70,000 in savings achieved through avoiding field crew overtime cost, and by leaving equipment out of service overnight is reported for 1993. This is part of a total of $ 340,000 savings in addition to increased system safety, security and reliability has been achieved through regular and extensive use of just some network analysis functions

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