This entry discusses electric power transmission system functions, the benefits produced, components, ratings and capacity, alternating current (AC) and direct current (DC) transmission, transmission system operations, the need for coordination, control areas, NERC and reliability councils, reliability standards, transmission access, and new technology.
The transmission system provides the means by which large amounts of power are delivered from the generating stations where it is produced to other companies or to locations where voltage is reduced, to supply subtrans-mission systems or substations where it is distributed to consumers. Transmission in the United States is mostly by three phase, 60 Hz (cycles per seconds) alternating current (AC) at voltages between 115,000 and 765,000 V. Direct current (DC) is used at a few locations but its potential role is increasing.
Benefits of Interconnection
Electric power must be produced at the instant it is used. Needed supplies cannot be produced in advance and stored for future use. It was soon recognized that peak use for one system often occurred at a different time than peak use in other systems. It was also recognized that equipment failures occurred at different times in various systems. Engineering analyses showed significant economic benefits from interconnecting systems to provide mutual assistance. The investment required for generating capacity could be reduced. Reliability could be improved. Differences in the cost of producing electricity in the individual companies and regions often resulted in one company or geographic area producing some of the electric power sold to another company in another area for distribution. This lead to the development of local, then regional, and subsequently, five grids in North America with three United States transmission grids, as shown in Fig. 1. Fig. 2 shows the key stages of the evolution of these transmission grids.
Summarizing the transmission system:
• Delivers electric power from generating plants to large consumers and distribution systems.
• Interconnects systems and generating plants to reduce overall required generating capacity requirements by taking advantage of:
— The diversity of generator outages, i.e., when outages of units occur in one plant, units in another plant can provide an alternative supply.
— The diversity of peak loads because peak loads occur at different times in different systems.
• Minimizes fuel costs in the production of electricity by allowing its production at all times at the available sources having the lowest incremental production costs.
• Facilitates the location and use of the lowest cost additional generating units available.
• Makes possible the buying and selling of electric energy and capacity in the marketplace.
• Helps provide for major emergencies such as hurricanes, tornadoes, floods, strikes, fuel supply disruptions, etc.
Transmission of Real and Reactive Power
The delivery of electric energy to perform desired functions requires the delivery of “real” and “reactive power.” The real power is produced in the power plant from fuels or energy sources and provides the energy that is used. This real power must be accompanied by reactive power that provides the electric fields required by various devices for the utilization of this energy. This reactive power does not include any energy. It is produced by the fields of the generators, by capacitors installed for that purpose, and by the “charging current” of the transmission system.
Transmission systems have resistance (R), which causes the heating of conductors and the loss of energy when current (I) flows and reactance (X), which causes voltage drops when current flows. Reactance can be positive or negative; positive when it is an inductive reactance and negative when it is a capacitive reactance.
The transmission system consists of three-phase transmission lines and their terminals, called substations or switching stations. Transmission lines can be either overhead or underground (cable). High-voltage alternating current (HVAC) lines predominate, with high-voltage direct current lines (HVDC) used for special applications. Overhead transmission, subtransmission, and primary distribution lines are strung between towers or poles. In urban settings, underground cables are used primarily because of the impracticality of running overhead lines along city streets. While underground cables are more reliable than overhead lines (because they have less exposure to climatological conditions such as hurricanes, ice storms, tornadoes, etc.), they are also much more expensive than overhead lines to construct per unit of capacity and they take much longer to repair because of the difficulty in finding the location of a cable failure and replacement.
Fig. 2. Stages of transmission system development.
The primary components of an overhead transmission line are:
• Conductors (three, one per phase)
• Ground or shield wires
• Support structures
• Land or right-of-way (ROW)
Conductors consist of stranded aluminum woven around a core of stranded steel that provides structural strength. When there are two or more of these wires per phase, they are called bundled conductors.
Ground or shield wires are wires strung from the top of one transmission tower to the next, over the transmission line. Their function is to shield the transmission line from lightning strokes. Insulators are used to attach the energized conductors to the supporting structures, which are grounded. The higher the voltage at which the line operates, the longer the insulator strings.
The most common form of support structure for transmission lines is a steel lattice tower, although wood H frames (so named because of their shape) are also used. In recent years, as concern about the visual impact of these structures has increased, tubular steel poles also have come into use. The primary purpose of the support structure is to maintain the electricity carrying conductors at a safe distance from the ground and from each other. Higher-voltage transmission lines require greater distances between phases and from the conductors to the ground than lower-voltage lines and therefore they require bigger towers. There has been some concern about the biological effects of transmission lines with the general conclusion being that there are no serious effects.
The capability of an individual overhead transmission line or its rating is usually determined by the requirement that the line does not exceed code clearances with the ground. As power flows through the transmission line, heat is produced. This heat will cause an expansion of the metal in the conductor, and as a result increase the amount of its sag. The amount of sag will also be impacted by the ambient temperature, wind speed, and sunlight conditions. The heating can also affect the characteristics of the metals in the conductors, reducing their strength.
Ratings are usually of two types—normal and emergency—and are usually determined for both summer and winter conditions. Some companies average the summer and winter ratings for the fall and spring. Ratings are also specified for various time periods. A normal rating is the level of power flow that the line can carry continuously. An emergency rating is the level of power flow the line can carry for various periods of time, for example, 15 and 30 min, 2, 4, and 24 h, and so forth.
In recent years, there has been a trend in calculating ratings for critical transmission lines on a real-time basis, reflecting actual ambient temperatures as well as the recent loading (and therefore heating) patterns.
The majority of the transmission cable systems in the United States are high-pressure fluid filled (HPFF) or high-pressure liquid filled (HPLF) pipe-type cable systems. Each phase of a high-voltage power cable usually consists of stranded copper wire with oil-impregnated paper insulation. All three phases are enclosed in a steel pipe. The insulation is maintained by constantly applying a hydraulic pressure through an external oil adjustment tank to compensate for any expansion or shrinkage of the cable caused by temperature variations.
Cable capacity is determined by the effect of heat on the cable insulation. Because the cable is in a pipe that is buried in a trench, dissipation of the heat is a major issue in cable design and operation. Cable capacity can be increased by surrounding the pipe with thermal sand, which helps dissipate heat.
A limitation on the application of ac cables is their high capacitance, which increases with their length. Cable capacitance causes a charging current to flow equal to the voltage divided by the capacitive reactance. This can limit the length of cable that can be used without some intermediate location where shunt reactor compensation can be installed to absorb the charging current.
Substations are locations where transmission lines are tied
together. They fulfill a number of functions:
• Allow power from different generating stations to be fed into the main transmission grid.
• Provide for interconnections with other systems.
• Provide transformers to be connected to feed power into the subtransmission or distribution systems. Transformers are generally equipped to change voltage ratios, with fixed taps that require de-energization to change and tap changing equipment that can change taps while the transformer is in operation.
• Allow transmission lines to be independently switched to isolate faulty circuits or for maintenance.
• Provide a location where compensation devices such as shunt or series reactors or capacitors can be connected to the transmission system.
• Provide a location for protection, control, and metering equipment.
Substation equipment includes:
• Bus work through which lines, transformers, etc., are connected.
• Protective relays that monitor voltages and currents and initiate disconnection of lines and equipment in the event of failures or malfunctions.
• Circuit breakers that interrupt the flow of electricity to de-energize facilities.
• Shunt capacitors to help provide needed reactive power.
• Disconnect switches.
• Lightning arrestors.
• Metering equipment.
• System control and data acquisition (SCADA) systems.
• Shunt reactors to limit high voltages.
• Series reactors to increase the impedance of lines.
• Phase angle regulating transformers and other devices to control power flow and voltage in specific circuits.
The bus/circuit breaker connection arrangements used in substations affect substation costs, ease of maintenance, and transmission reliability.1-6-1
Direct Current Transmission
An alternate means of transmitting electricity is to use HVDC technology. Direct current facilities are connected to HVAC systems by means of rectifiers, which convert alternating current to direct current, and inverters, which convert direct current to alternating current.
Starting in the 1970s, thyristors became the valve type of choice for the rectifiers and inverters. Thyristors are controllable semiconductors that can carry very high currents and can operate at very high voltages. They are connected in series to form a valve, which allows electricity to flow during the positive half of the alternating current voltage cycle but not during the negative half. Because all three phases of the HVAC system are connected to the valves, the resultant voltage is unidirectional but with some residual oscillation. Smoothing reactors are provided to dampen this oscillation.
High-voltage direct current lines transmission lines can either be single pole or bipolar, although most are bipolar—they use two conductors operating at different polarities, such as + / — 500 kV. There have been a number of applications for DC transmission:
• To transmit large amounts of power over long distance is not feasible with AC.
• To transmit power across water where the capacitance of AC cables would limit circuit capacity.
• The need to connect two AC systems in a manner that prevents malfunctions or failures in one system from causing problems in another system.
• To provide direct control of power flow in a circuit.
• To limit short-circuit duties.
• To increase the ability to transfer power over existing right-of-ways because DC requires two conductors versus three for AC.
The difficulty of DC is its higher costs and the lack of reliable DC current breakers.
HOW TRANSMISSION SYSTEMS WORK
Because of the synchronous operation of all generators, an interconnected electric power system functions as a single large machine that can extend over thousands of miles. One of this machine’s characteristics is that changes in any one portion of it instantly affect the operation of all other portions. Future plans for any one part of it can affect transmission conditions in other parts of it.
In system operation, the effects of contingencies in one system can be felt throughout a large geographic area. For example, if a large generating unit is lost in New York city, the interconnected power system (the machine) suddenly has less power input than power output and slows down. As the individual rotors of every generator in this system slow down in unison and system frequency declines, each rotor gives up a certain amount of its rotating energy (w2R) to compensate for the lost input from the unit that has tripped off.
Instantaneously, with the loss of a large unit or power plant, there is an inrush of power from units all over the synchronous network, feeding into the system or region that has lost the generator unit. While these inrushes of power from individual units long distances away are not large, they accumulate and build up like water flowing from creeks into a river, increasingly loading the transmission lines near the system that has lost generation. This surge of power exists until automatic generator controls cause them to increase their output to compensate for the lost generating capacity and restore system frequency.
The very reason that systems have been tied together and operate in synchronism causes this effect. By having the various generator units throughout the region assist with the loss of a large generator unit in a specific system, the total amount of spare or reserve generating capacity required can be reduced. This is similar to the insurance business. The larger the number of policy holders, the better able the insurance company is to cope with any specific major disaster and the less percentage reserves it requires. The great strength of operating in synchronism and being tied together in an integrated system is the ability of one system to be helped by others. Its greatest weakness, however, is that the inrush of power into any one system can cause transmission system overloads in other systems.
Because of these characteristics of modern electric power systems, the design and operation of the key elements in a synchronous network must be coordinated. Business decisions, government legislation and regulations, and other institutional processes must be compatible with the technical characteristics. Many problems can be solved by technical solutions, some can be solved by institutional solutions, and in some cases, problems can be solved by coordinating both.
In AC transmission networks, the flow of power in the various circuits is determined by Kirchhoff’s Laws. Power flow is determined by the impedance of the individual circuits, the location in the network of the sources of power, and the location of the substations to which power is delivered. The flow of electrical power in the synchronous grid does not respect company boundaries, contracts or ownership of facilities. Power cannot be scheduled to flow over a specific line or lines, but will divide in accordance with Kirchhoff’s Laws.
This sometimes results in two phenomena known as “parallel path flow” and “loop flow.” Parallel path flow results when power to be delivered from system A to system B goes through systems in parallel. Such flows can increase transmission loadings in these other systems, reducing their ability to be used by the owners for their own purposes. Loop flows are circulating flows that occur with all systems supplying their own loads from their own sources. They are the result of network characteristics and often the result of deliberate network designs to limit total transmission investment requirements.
Transmission limits can be determined by a number of factors, a common one being the maximum allowable thermal loading on circuits. Current flowing through conductors causes heating, which causes expansion and “sagging,” reducing clearance to ground, possibly contacting trees or other obstacles, and resulting in a circuit trip out.
Potential stability disturbances can limit the amount of power that can be transferred. If stability limits are exceeded, the occurrence of a critical fault can cause generators to oscillate wildly and trip out. Voltage conditions can limit the ability to transfer power. An inadequate supply of reactive power can cause transmission voltages to become too low, causing excessive transmission currents and voltage instability, resulting in circuit trip outs.
While recognizing these various causes of transmission limits, it is also essential to recognize that the ability to deliver power is the ability of the interconnected network, i.e., the system that forms the grid, to transfer power, not the sum of the capacities of the individual circuits involved. Often, one circuit can become overloaded while another has unused capacity because of Kirchoff’s Laws.
The restructuring and deregulation of the electric power industry has lead to significant changes in the use of transmission systems. The owners of transmission lines must make them available to everyone who wants to use them on the same basis as they are used for their own customers. This has increased the complexity and difficulty of planning and operating transmissions systems because there are many more potential users whose decisions affect the entire system.
Short Circuit Duties
An often overlooked factor is that transmission systems must have the ability to interrupt the very high currents that result when short circuits occur. This is done by circuit breakers that must have an interrupting capacity sufficient to interrupt the magnitudes of the fault currents involved. These fault currents are increased as generation and new transmission lines are added to the system. Transmission system design requires studies of the ability of circuit breakers to interrupt expected faults. When breaker capability is not adequate, expensive replacements or changes in substation or system designs may be needed.
Transmission System Losses
Power losses in the transmission system consume 3%-5% of the electric power produced. Because they are supplied by the highest cost generation available, they are responsible for more than 5% of the cost of energy produced. Many believe that the deregulation of the electric power industry has increased transmission losses.
There are two basic types of power (MW) losses in transmission systems:
• Core losses are dissipated in the steel cores of transformers. These losses typically vary with at least the third, and often higher, powers of the voltage variations at their terminals. If transmission voltages are fairly constant, core losses are also constant. An increase in the power carried by a transmission system does not substantially affect the core losses, but a variation in transmission voltage can.
• Conductor losses are dissipated in transmission lines and cables and transformer windings. As these losses depend on the resistance of the circuit (R) and vary with the square of the current and therefore approximately with the square of the power carried by each component, they vary greatly between light load and heavy-load times and are also affected by increases in the power carried by the transmission system.
There are also reactive power (MVAR) losses in the transmission system. These losses depend on the reactance of the system (X) and again vary as the square of the current.
When electrical energy is transported across large distances through the transmission system, a portion of the energy is “lost.” For a given amount of electric power, the higher the operating voltage of the transmission line, the lower the current flowing through the line. Therefore, use of higher transmission voltages permits the transmission of electric power with lower currents and a resulting reduction in energy losses.
The losses in the transmission system at a specific moment, typically at the time of system peak, are measured in megawatts and are referred to as “capacity losses.” The energy expended in transmission losses over a given period is given in megawatt-hours and is referred to as “energy loss.” Capacity losses require the installation of additional generation and transmission equipment; energy losses require the consumption of fuel or equivalent energy sources. The increase in a system’s total losses due to a specific action is referred to as an “incremental loss.”
In addition to real power losses, significant reactive power losses occur in the transmission systems, and these reactive losses are typically about 4 or 5 times the real power capacity losses.
OPERATION OF ELECTRIC BULK POWER SYSTEMS
Need for Coordination
The operation of the bulk power system in the United States involves the interdependency of the various entities involved in supplying electricity to the ultimate consumers. These interdependencies have evolved as the utility industry grew and expanded over the century.
In a power system, the coordination of all elements of the system and all participants are required from an economic and a reliability perspective. Generation, transmission, and distribution facilities must function as a coordinated whole. The scheduling of generation must recognize the capability of the transmission system. Voltage control must involve the coordination of reactive power supplies from all sources, including generators, the transmission system, and distribution facilities. Actions and decisions by one participant, including decisions not to act, affect all participants.
In parallel with its early growth, the industry recognized it was essential that operations and planning of the system be coordinated and organizations were formed to facilitate the joint operation and planning of the nation’s electric grid. Initially, holding companies and then power pools were established to coordinate the operation of groups of companies. Recently, new organizations, independent system operators (ISOs) and regional transmission operators (RTOs), have been formed to provide this coordination.
Reliability Councils and Nerc
After the Northeast Blackout of 1965, regional electric reliability councils were formed to promote the reliability and efficiency of the interconnected power systems within their geographic areas. These regional councils joined together shortly afterwards to form a national umbrella group, NERC—the North American electricity reliability council. At present, there are ten regional councils. Each Council has a security coordinator who oversees the operation of the grid in their region.
The members of NERC and these regional councils come from all segments of the electric industry; investor-owned utilities; federal power agencies; rural electric cooperatives; state, municipal and provincial utilities; independent power producers; power marketers; and end-use customers. These entities account for virtually all the electricity supplied in the United States, Canada, and a portion of Baja California North, Mexico.
When formed in 1968, the NERC operated as a voluntary organization to promote bulk electric system reliability and security—one that was dependent on reciprocity, peer pressure, and the mutual self-interest of all those involved.
The growth of competition and the structural changes taking place in the industry have significantly altered the incentives and responsibilities of market participants to the point that a system of voluntary compliance is no longer adequate. New federal legislation in the United States has required formation of an electric reliability organization (ERO) to monitor and enforce national reliability standards under FERC oversight. In response to these changes, NERC is transforming itself into an industry-led self-regulatory reliability organization ERO that will develop and enforce reliability standards for the North American bulk electric system.
While overall system control is, in some cases, the responsibility of newly formed ISOs and RTOs, more than 140 “control areas” still perform needed functions.
A control area can consist of a generator or group of generators, an individual company, or a portion of a company or a group of companies providing it meets certain certification criteria specified by NERC. It may be a specific geographic area with set boundaries or it may be scattered generation and load.
The control centers require real-time information about the status of the system. This information includes power line flows, substation voltages, the output of all generators, the status of all transmission lines and substation breakers (in-service or out-of-service), and transformer tap settings. Some areas are implementing real-time transmission line rating systems requiring additional information such as weather conditions, conductor temperatures, and so forth.
Each control area monitors on an on-going basis the power flow on all of its interties (in some cases delivery points) and the output of each generator within its control. The sum of the internal generation and the net flow on the interties is equal to the consumer load and all transmission losses within the area.
The various commercial interests that are involved within the area are required to notify the control area personnel of their contractual arrangements on an ongoing basis for either sales or purchases of electricity with entities outside the area’s boundaries.
Oasis and Transmission Capacity
The open access same-time information system (OASIS) is an Internet-based bulletin board that gives energy marketers, utilities, and other wholesale energy customers real-time access to information regarding the availability of transmission capacity. OASIS provides the ability to schedule firm and nonfirm transactions.
The North American electricity reliability council has defined transmission capacity as follows:
Available transfer capacity (ATC) = Total transfer capability (TTC) — Existing commitments — transmission reliability margin (TRM) — Capacity benefit margin (CBM), where:
• Available transfer capability is a measure of the transfer capability remaining in the physical transmission network for further commercial activity over and above already committed uses.
• Total transfer capability is the amount of electric power that can be transferred over the interconnected transmission network in a reliable manner while meeting all of a specific set of defined pre- and post-contingency system conditions.
• Transmission reliability margin is the amount of transmission transfer capability necessary to ensure that the interconnected transmission network is secure under a reasonable range of uncertainties in system conditions.
• Capacity benefit margin is the amount of transmission transfer capability reserved by load serving entities to ensure access to generation from interconnected systems to meet generation requirements in emergencies.
With this information, the control area operators can compare the total scheduled interchange into or out of the control area with the actual interchange. If the receipt of electricity exceeds the schedule, the control area must increase generation levels. If the receipt is too low, generation within the control area is reduced. These schedules are typically made a day ahead and then adjusted in real time. Because these adjustments are ongoing simultaneously by all control areas, the adjustments balance out.
The process where individual contracts scheduled within OASIS are identified as to source and customer is known as tagging. This information, while it may be commercially sensitive, is critical if system operators are to adjust system power flows to maintain reliable levels.
Concurrently, the system operators can also evaluate the expected power flows internal to the control area to determine if adjustments are required in the generation pattern to insure that all internal transmission facilities are operated within the capabilities.
Each control area also participates in maintaining the average system frequency at 60 Hz. The system frequency can deviate from normal when a large generating unit or block of load is lost. In addition to adjustments made because of variations of tie flows from schedule, another adjustment is made to correct frequency deviations.
Reliability standards have been developed by the regional reliability councils and NERC for many years. They define the reliability aspect of the interconnected bulk electric systems in two dimensions:
• Adequacy—the ability of the electric systems to supply the aggregate electrical demand and energy requirements of their customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.
• Security—the ability of the electric systems to withstand sudden disturbances such as electric short circuits or unanticipated loss of system elements.
Detailed reliability standards exist that specify allowable system voltage and loading conditions for various system contingencies. These are developed by the various regional reliability councils and must meet the minimum standards established by NERC. There are standards for various single contingencies and for various combinations of outages.
Meeting reliability standards in the planning of the transmission system is difficult because the time required to install new transmission is longer than the time required to install new generation. Attempting to meet reliability standards in planning for future transmission needs involves considerable uncertainties because future generation locations are not known. The general industry consensus is that the restructuring and deregulation of the electric power industry has resulted in a decrease in reliability. How will this affect future transmission policies is uncertain.
Future developments may have long-range effects on transmission requirements, transmission system characteristics, and the capacity of the various networks. New transmission technologies, some involving “power electronics,” are under study. These include:
• The development of methods to control the division of flow of power in AC networks.
• The development of “smart systems” or “self-healing” systems that may involve a redesign and upgrade of presently electromechanically controlled transmission systems.
• The subdivision of huge synchronous AC networks into smaller synchronous networks interconnected by DC.
There are other possible developments that may have a significant effect on transmission systems, including:
• The development of significant amounts of small distributed generation, including the use of solar energy, wind power, micro turbines, etc.
• A major national shift to large nuclear or coal units to reduce dependence on foreign oil and gas.
• The development of low-cost energy storage devices to allow power to be produced at one time for use at another.
• Increasing use of hydrogen as a mechanism for transferring energy from one location to another, including possible linking of hydrogen production with off peak generating capacity.
The future holds many uncertainties and requires analyses similar to post national power surveys to determine how to develop transmission systems to meet potential future developments. Failure to make such analyses will result in wasteful transmission additions and design of a poor system.