Whether a country privatizes or deregulates, adequate capacity reserves, properly designed interconnections and sufficient network maintenance are crucial to ensure high reliability levels. It is one thing to unbundle electric utility systems to encourage lower prices through competition in bulk power sales. It is another to expect the same high level of reliability that has been the hallmark of regulated electric systems, where franchised territories were protected from outside competition.
In a letter to the U.S. Federal Energy Regulatory Commission (FERC), Thomas R. Kuhn, president of the Edison Electric Institute (EEI), pointed out the possibility of experiencing lower levels of reliability. He wrote, "To the extent that increased transactions cause a system to be operated closer to its reliability limits for longer periods of time, the potential for system disruptions increases..."
Since electricity is essential for sustainable development, reliability of supply becomes a key element in a country's ability to organize its commerce and its manufacturing capabilities. Losses due to unreliability could be as high as 4% of gross domestic product (GDP).
In India, for example, the cost of power shortages to its industrial sector has been estimated at 1.5% of GDP and in Pakistan, 1.8%. In fact, a major power outage recently left millions of people in northeastern India without power for approximately six hours. On Dec. 20, 1996, long distance trains and hospitals were affected after a fault occurred in the power distribution network in Uttar Pradesh State, which borders New Delhi. Power losses are common in northeastern India since the national grid cannot meet the power demand of the region.
Reliability must be addressed worldwide, since virtually every country has or is privatizing or deregulating its system.
The Increased Importance of the Transmission Network In the realignments that have occurred within individual utilities, the major concern is to ensure compliance with long-term delivery, short-term delivery and spot market contracts. The critical nature of reliable performance is of equal importance to all of the new entities that are appearing on the electric power scene; comprising gencos, transcos and discos (generating companies, transmission companies and distribution companies).
Probably the most critical element in the new power delivery scenario is the transmission system, which will be called upon to accommodate all comers who need to deliver power to specific customers remote from their generating sources. The historic reality regarding transmission capability has always been a function of the line's capacity. A tie-line between systems that is not "stout" enough can impose constraints that will render the system unstable if it is overloaded. The usual remedy has been to reinforce the tie with additional lines between adjacent systems. Not surprisingly, the proliferation of additional ties among many systems has resulted in the formation of power pools around the world.
A Reliability Problem in Malaysia The immediacy of reliability issues surface when major disturbances result in the loss of a system due to cascading of individual substations down the line from the initial interruption. This scenario was recently reported by the Tengasa Nasional Board, which is the governing body of the national grid for Malaysia. The report dealt with a major disturbance that interrupted electricity supply to the entire Malaysian peninsula in August 1996.
The disturbance resulted from inadvertent trippings of several gas turbine generators that automatically disconnected supply to the transmission grid. The episode, the result of the presence of a faulty component in a 275-kV circuit breaker, subsequently produced a chain of interruptions that rendered the system inoperable. The system was restored to full operation 16 hours after the interruption.
A review of the interruption revealed that, in addition to the faulty circuit breaker, certain system characteristics added to the cascading effect, which caused the shutdown. Chief among the system's equipment under scrutiny were the gas turbine generators, which had unpredictable performance characteristics during the disturbance because of their high proportion compared to other types of generation. Accordingly, the spinning reserve will be increased in order to back up the generation from the gas turbines.
In the transmission area, all circuit breakers will be closely inspected to ensure that all components are of high quality. A review will determine if relay settings are appropriately set. System operating practices will be modified to provide an additional two stages of automatic underfrequency load shedding at the early stage of the existing low-frequency protocol.
Critical Interconnection Developments in Europe Transmission tie-lines are being added among diverse systems in Europe, Asia, Africa and South America. In the European market, the completion of a link between Germany and the Czech Republic is an example of the trends around the world, where adjacent systems are coupled to ensure long-term stability and reliability.
A dc connection ties the two 380-kV 50 Hz networks. A dc tie is used to overcome the inherent problems that an ac tie would bring-namely, fluctuations in voltage and frequency from the eastern system. These fluctuations are caused by the many long lines required between the widely dispersed generating stations, which have little reserve capacity. In contrast, the western system is characterized by large generating stations located close to load centers with ample reserves of power. In the west, voltage and frequency fluctuations are held within close tolerances.
A report to the IEEE at a meeting in Denver, Colorado, U.S., in July 1996, discussed the interconnection between CENTREL and UCPTE. CENTREL is the Eastern power grid comprising Poland, the Czech Republic, Hungary and Serbia-Croatia. UCPTE is the Union for the Coordination of Production and Transmission of Electricity, representing the western European countries of Germany, France, Spain and Italy, among others. The systems were integrated to increase supply security, to improve power quality, to decrease environmental burdens, to increase the possibility of exporting power and to lower the cost of power.
The plan was first discussed in May 1992 and, over the intervening years, the participants met to work on the various technical and financial problems that had to be addressed. These problems included: - Back-to-back coupling between the two systems. - Creation of an energy accounting system and a control center in Warsaw for the CENTREL block. - Evaluation of results of tests made on the CENTREL system. - Synchronization of CENTREL with UCPTE by means of two high-voltage lines.
The issue of reliability centers on the adequacy of communications among the various systems for monitoring tie-line data. The communications system currently in place ensures that technical requirements are met for load-frequency control. It requires redundant channels to Warsaw and uses a measuring period of 1 to 2 seconds. The intertie between CENTREL and UCPTE is expected to be extended sometime in the first decade of the 21st century. The Baltic countries of Romania, Bulgaria and the Ukraine are expected to join by the second decade.
Reliability Issues Addressed in the United States A common vehicle for assessing system reliability is a panel of experts that studies the operation of a system to determine the causes for interruptions and to recommend remedial measures. In the case of the European systems, such panels were in conference for many years to determine how best to integrate the disparate circuits to ensure reliable service after the introduction of tie points. In the case of the Malaysian episode, a similar body studied the system collapse to determine how to avoid future problems of a similar nature.
In the United States, the reporting of system disturbances has been formalized by the U.S. Department of Energy (DOE). Emergencies that can affect the reliability of bulk power systems must be reported by individual utilities to their Regional Councils, which then send copies of the reports to the offices of the North American Electric Reliability Council (NERC). The 10 Regional Councils consist of representatives from local electric utilities, independent power producers and power marketers.
NERC's annual review of system disturbances begins in November when the Disturbance Analysis Working Group meets to discuss each disturbances reported for the year. The group then contacts the Regional Council, or the utilities involved, and requests a detailed report of each incident. The group summarizes the report for review and analyzes it using NERC's operating and planning policies. A commentary includes conclusions and recommendations.
In 1995, for example, utilities in the United States reported 21 incidents of system disturbances, demand reductions, voltage reductions, public appeals or unusual occurrences. In its commentary on these incidents, the Working Group identified several key factors to improve reliability, including: - Relay scheme coordination and maintenance system modeling to reflect the nature of a neighboring utility system. - A need for timely and adequate communications among control areas during disturbances. - A need for planners and operators to work together during the design of new facilities and the modification of existing facilities. - Implementation of an ongoing review procedure to see if changes are needed to permit operators to handle system disturbances more effectively.
These comments highlight the need to evaluate transfer capabilities, to develop restoration plans, to review synchronization philosophy and field circuitry so utilities still match operational requirements and to provide for additional communications equipment to improve coordination during disturbances.
Power Quality and Service Delivery Contracts In France, Electricite de France (EDF), Paris, is focusing on improving the quality of electricity, which it defines as continuity of service and maintenance of voltage. In 1995, EDF reported that the average interruption of service was 78 minutes for all causes, repairs and climatic conditions. This outage time compares to previous years as follows: - 1991 - 113 minutes - 1992 - 115 minutes - 1993 - 97 minutes - 1994 - 100 minutes.
EDF is generalizing its new commitment policy regarding the reference service called for in the supply contract, which includes appointment punctuality, repair times, start up and termination times, mail response times and connection times. This commitment carries a requirement that financial payment will be made to customers if the agreed-upon results are not met.
In a similar manner, the Office of Electricity Regulation (OFFER) in the United Kingdom has published two types of standards for the 12 regional electricity companies under its jurisdiction in England, Wales and Scotland. Guaranteed standards set service levels that must be met in each individual case. If the company fails to provide the level of service required, it must make payment to the affected customer. An overall standard covers areas of service where it is not appropriate to give guarantees, but where customers in general have a right to expect predetermined levels of service.
Since the start of the standards in July 1991, all companies have contributed to the improved performance of the entire system. The total value of payments during 1995/96 was more than US$150,000 (85,000 pounds), a 30% decrease from the previous year.
Expectations for the Future In almost every geographical area around the world, the trend to move toward interconnected systems is intended to improve reliability. Not only is the interconnection important in this respect, but equally important is the technology that is employed for providing up-to-the-minute information on system characteristics.
Along with an integrated communications system that will transmit data from RTUs and from intelligent meters and relays, master stations will be able to process the data and effect proper control. In this context, systems that use tie lines for mutual support to increase reliability are using modern system software to ensure communications with the other systems. In this way, it will be possible to visualize all applications that are operating on adjacent systems and to integrate system demands throughout the interconnected grid.
Electric utilities of the future must continue to develop and install new hardware and software for their systems. Technological developments will guarantee long-range reliability in the new marketplace where power marketing will be essential to power delivery.
NERC's 10-year Assessment of Reliability in North America In its 10-year assessment on the reliability of the electric transmission grid in the United States and Canada, the North American Electric Reliability Council (NERC) identified several key issues and actions that need to be addressed to maintain high levels of reliability for the region
Increased competition in the wholesale electricity market and open access to the transmission systems will present new challenges to the reliable operation of the interconnected bulk electric system. Improved security processes with appropriate and timely information sharing and continued coordination among generation and transmission operations are important elements in meeting these challenges.
The adequacy of existing and planned resources and transmission systems is less certain than in the past because the electric industry is moving to a more competitive electricity supply environment and commitments to new resources are being delayed to the last possible moment. Delays in placing generation or transmission facilities in service as needed can jeopardize the future reliability of the bulk electric systems. The regional reliability councils and NERC will continue to assess overall generation and transmission adequacy and provide the market with the assessment results.
Regardless of the electric industry restructuring, NERC will continue to define and ensure compliance with its reliability planning and operating policies so that a continuous and adequate supply is maintained and transmission systems are operated within security limits. All participants in electricity markets must comply with NERC and Regional Council reliability policies and standards.
As utilities reorganize to separate their transmission operational reliability functions from their wholesale electricity merchant functions to comply with FERC Order 889 and to satisfy other business objectives, operational coordination and control for reliability must be maintained.
As the operation of the bulk electric systems becomes more complex, system operators must continue to receive training, have sophisticated tools to effectively monitor and assess the reliability of their systems, and have clear authority to take timely action to ensure reliability. (From the NERC report on Reliability Assessment 1996-2005.)
Capacity Margins on the Decline in the United States The difficulties that are expected in the United States may be typical of the general problem worldwide with respect to timely construction of additional lines. Recent experience shows that planning and siting of these lines, required for the accommodation of new generation into the grid, are taking longer because of regulatory and environmental requirements.
For example, the completion of the proposed Wyoming-Cloverdale 765-kV line between West Virginia and Virginia has been delayed because the U.S. Forest Service recommended against allowing the line to be built through federal lands. Since this line was intended to guard against a potential voltage collapse in the region, the possibility exists that a cascading failure could result in a blackout in the heavily industrialized region and in neighboring systems.
Compounding transmission line siting is the expected reduction in generation due to nuclear plant retirements. In New England, generating capacity is already in question because five nuclear plants with a capacity of more than 4000 MW have been shut down. The reduced availability of generation is especially critical because peak demand in the United States and Canada is expected to grow in the next decade. Demand in the United States will increase from about 625,000 MW to anywhere between 650,000 and 775,000 MW by the year 2005. Coupled with these demand projections, the capacity margins in the United States are expected to decline from about 18% in 1996 to about 13% in 2005. Indeed, if additional resources are not built, capacity margins in 2005, as presently planned, could decline to about 6%.