Utility frequency

The first applications of commercial electric power were incandescent lighting and commutator-type electric motors. Both devices operate well on DC, but DC could not be easily changed in voltage, and was generally only produced at the required utilization voltage.

If an incandescent lamp is operated on a low-frequency current, the filament cools on each half-cycle of the alternating current, leading to perceptible change in brightness and flicker of the lamps; the effect is more pronounced with arc lamps, and the later mercury-vapor lamps and fluorescent lamps. Open arc lamps made an audible buzz on alternating current, leading to experiments with high-frequency alternators to raise the sound above the range of human hearing.

Commutator-type motors do not operate well on high-frequency AC, because the rapid changes of current are opposed by the inductance of the motor field. Though commutator-type universal motors are common in AC household appliances and power tools, they are small motors, less than 1 kW. The induction motor was found to work well on frequencies around 50 to 60 Hz, but with the materials available in the 1890s would not work well at a frequency of, say, 133 Hz. There is a fixed relationship between the number of magnetic poles in the induction motor field, the frequency of the alternating current, and the rotation speed; so, a given standard speed limits the choice of frequency (and the reverse). Once AC electric motors became common, it was important to standardize frequency for compatibility with the customer's equipment.

Generators operated by slow-speed reciprocating engines will produce lower frequencies, for a given number of poles, than those operated by, for example, a high-speed steam turbine. For very slow prime mover speeds, it would be costly to build a generator with enough poles to provide a high AC frequency. As well, synchronizing two generators to the same speed was found to be easier at lower speeds. While belt drives were common as a way to increase speed of slow engines, in very large ratings (thousands of kilowatts) these were expensive, inefficient, and unreliable. After about 1906, generators driven directly by steam turbines favored higher frequencies. The steadier rotation speed of high-speed machines allowed for satisfactory operation of commutators in rotary converters.[3] The synchronous speed N in RPM is calculated using the formula,

${\displaystyle N={\frac {120f}{P}}\,}$

where f is the frequency in hertz and P is the number of poles.

Direct-current power was not entirely displaced by alternating current and was useful in railway and electrochemical processes. Prior to the development of mercury arc valve rectifiers, rotary converters were used to produce DC power from AC. Like other commutator-type machines, these worked better with lower frequencies.

With AC, transformers can be used to step down high transmission voltages to lower customer utilization voltage. The transformer is effectively a voltage conversion device with no moving parts and requiring little maintenance. The use of AC eliminated the need for spinning DC voltage conversion motor-generators that require regular maintenance and monitoring.

Since, for a given power level, the dimensions of a transformer are roughly inversely proportional to frequency, a system with many transformers would be more economical at a higher frequency.

Electric power transmission over long lines favors lower frequencies. The effects of the distributed capacitance and inductance of the line are less at low frequency.

Generators can only be interconnected to operate in parallel if they are of the same frequency and wave-shape. By standardizing the frequency used, generators in a geographic area can be interconnected in a grid, providing reliability and cost savings.

The first generators at the Niagara Falls project, built by Westinghouse in 1895, were 25 Hz, because the turbine speed had already been set before alternating current power transmission had been definitively selected. Westinghouse would have selected a low frequency of 30 Hz to drive motor loads, but the turbines for the project had already been specified at 250 RPM. The machines could have been made to deliver 16+2⁄3 Hz power suitable for heavy commutator-type motors, but the Westinghouse company objected that this would be undesirable for lighting and suggested 33+1⁄3 Hz. Eventually a compromise of 25 Hz, with 12-pole 250 RPM generators, was chosen.[3] Because the Niagara project was so influential on electric power systems design, 25 Hz prevailed as the North American standard for low-frequency AC.

A General Electric study concluded that 40 Hz would have been a good compromise between lighting, motor, and transmission needs, given the materials and equipment available in the first quarter of the 20th century. Several 40 Hz systems were built. The Lauffen-Frankfurt demonstration used 40 Hz to transmit power 175 km in 1891. A large interconnected 40 Hz network existed in north-east England (the Newcastle-upon-Tyne Electric Supply Company, NESCO) until the advent of the National Grid (UK) in the late 1920s, and projects in Italy used 42 Hz.[7] The oldest continuously operating commercial hydroelectric power station in the United States, Mechanicville Hydroelectric Plant, still produces electric power at 40 Hz and supplies power to the local 60 Hz transmission system through frequency changers. Industrial plants and mines in North America and Australia sometimes were built with 40 Hz electrical systems which were maintained until too uneconomic to continue. Although frequencies near 40 Hz found much commercial use, these were bypassed by standardized frequencies of 25, 50 and 60 Hz preferred by higher volume equipment manufacturers.

The Ganz Company of Hungary had standardized on 5000 alternations per minute (412⁄3 Hz) for their products, so Ganz clients had 412⁄3 Hz systems that in some cases ran for many years.[8]

In the early days of electrification, so many frequencies were used that no single value prevailed (London in 1918 had ten different frequencies). As the 20th century continued, more power was produced at 60 Hz (North America) or 50 Hz (Europe and most of Asia). Standardization allowed international trade in electrical equipment. Much later, the use of standard frequencies allowed interconnection of power grids. It was not until after World War II – with the advent of affordable electrical consumer goods – that more uniform standards were enacted.

In the United Kingdom, a standard frequency of 50 Hz was declared as early as 1904, but significant development continued at other frequencies.[9] The implementation of the National Grid starting in 1926 compelled the standardization of frequencies among the many interconnected electrical service providers. The 50 Hz standard was completely established only after World War II.

By about 1900, European manufacturers had mostly standardized on 50 Hz for new installations. The German Verband der Elektrotechnik (VDE), in the first standard for electrical machines and transformers in 1902, recommended 25 Hz and 50 Hz as standard frequencies. VDE did not see much application of 25 Hz, and dropped it from the 1914 edition of the standard. Remnant installations at other frequencies persisted until well after the Second World War.[8]

Because of the cost of conversion, some parts of the distribution system may continue to operate on original frequencies even after a new frequency is chosen. 25 Hz power was used in Ontario, Quebec, the northern United States, and for railway electrification. In the 1950s, many 25 Hz systems, from the generators right through to household appliances, were converted and standardized. Until 2009, some 25 Hz generators were still in existence at the Sir Adam Beck 1 (these were retrofitted to 60 Hz) and the Rankine generating stations (until its 2009 closure) near Niagara Falls to provide power for large industrial customers who did not want to replace existing equipment; and some 25 Hz motors and a 25 Hz power station exist in New Orleans for floodwater pumps.[10] The 15 kV AC rail networks, used in Germany, Austria, Switzerland, Sweden, and Norway, still operate at 16+2⁄3 Hz or 16.7 Hz.

In some cases, where most load was to be railway or motor loads, it was considered economic to generate power at 25 Hz and install rotary converters for 60 Hz distribution.[11] Converters for production of DC from alternating current were available in larger sizes and were more efficient at 25 Hz compared with 60 Hz. Remnant fragments of older systems may be tied to the standard frequency system via a rotary converter or static inverter frequency changer. These allow energy to be interchanged between two power networks at different frequencies, but the systems are large, costly, and waste some energy in operation.

Rotating-machine frequency changers used to convert between 25 Hz and 60 Hz systems were awkward to design; a 60 Hz machine with 24 poles would turn at the same speed as a 25 Hz machine with 10 poles, making the machines large, slow-speed, and expensive. A ratio of 60/30 would have simplified these designs, but the installed base at 25 Hz was too large to be economically opposed.

In the United States, Southern California Edison had standardized on 50 Hz.[12] Much of Southern California operated on 50 Hz and did not completely change frequency of their generators and customer equipment to 60 Hz until around 1948. Some projects by the Au Sable Electric Company used 30 Hz at transmission voltages up to 110,000 volts in 1914.[13]

Initially in Brazil, electric machinery were imported from Europe and United States, implying the country had both 50 Hz and 60 Hz standards according to each region. In 1938, the federal government made a law, Decreto-Lei 852, intended to bring the whole country under 50 Hz within eight years. The law did not work, and in the early 1960s it was decided that Brazil would be unified under 60 Hz standard, because most developed and industrialized areas used 60 Hz; and a new law Lei 4.454 was declared in 1964. Brazil underwent a frequency conversion program to 60 Hz that was not completed until 1978.[14]

In Mexico, areas operating on 50 Hz grid were converted during the 1970s, uniting the country under 60 Hz.[15]

In Japan, the western part of the country (Nagoya and west) uses 60 Hz and the eastern part (Tokyo and east) uses 50 Hz. This originates in the first purchases of generators from AEG in 1895, installed for Tokyo, and General Electric in 1896, installed in Osaka. The boundary between the two regions contains four back-to-back HVDC substations which convert the frequency; these are Shin Shinano, Sakuma Dam, Minami-Fukumitsu, and the Higashi-Shimizu Frequency Converter.

Utility frequencies in North America in 1897[16]

Utility frequencies in Europe to 1900[8]

Even by the middle of the 20th century, utility frequencies were still not entirely standardized at the now-common 50 Hz or 60 Hz. In 1946, a reference manual for designers of radio equipment[17] listed the following now obsolete frequencies as in use. Many of these regions also had 50-cycle, 60-cycle, or direct current supplies.

Frequencies in use in 1946 (as well as 50 Hz and 60 Hz)

Where regions are marked (*), this is the only utility frequency shown for that region.

TEC availability

Regulation of power system frequency for timekeeping accuracy was not commonplace until after 1916 with Henry Warren's invention of the Warren Power Station Master Clock and self-starting synchronous motor. Nikola Tesla demonstrated the concept of clocks synchronized by line frequency at the 1893 Chicago Worlds fair. The Hammond Organ also depends on a synchronous AC clock motor to maintain the correct speed of its internal "tone wheel" generator, thus keeping all notes pitch-perfect.

Today, AC power network operators regulate the daily average frequency so that clocks stay within a few seconds of the correct time. In practice the nominal frequency is raised or lowered by a specific percentage to maintain synchronization. Over the course of a day, the average frequency is maintained at a nominal value within a few hundred parts per million.[20] In the synchronous grid of Continental Europe, the deviation between network phase time and UTC (based on International Atomic Time) is calculated at 08:00 each day in a control center in Switzerland. The target frequency is then adjusted by up to ±0.01 Hz (±0.02%) from 50 Hz as needed, to ensure a long-term frequency average of exactly 50 Hz × 60 s/min × 60 min/h × 24 h/d = 4320000 cycles per day.[21] In North America, whenever the error exceeds 10 seconds for the Eastern Interconnection, 3 seconds for the Texas Interconnection, or 2 seconds for the Western Interconnection, a correction of ±0.02 Hz (0.033%) is applied. Time error corrections start and end either on the hour or on the half-hour.[22][23]

Real-time frequency meters for power generation in the United Kingdom are available online – an official one for the National Grid, and an unofficial one maintained by Dynamic Demand.[24][25] Real-time frequency data of the synchronous grid of Continental Europe is available on websites such as www.mainsfrequency.com. The Frequency Monitoring Network (FNET) at the University of Tennessee measures the frequency of the interconnections within the North American power grid, as well as in several other parts of the world. These measurements are displayed on the FNET website.[26]

In the United States, the Federal Energy Regulatory Commission made time error correction mandatory in 2009.[27] In 2011, The North American Electric Reliability Corporation (NERC) discussed a proposed experiment that would relax frequency regulation requirements[28] for electrical grids which would reduce the long-term accuracy of clocks and other devices that use the 60 Hz grid frequency as a time base.[29]

The primary reason for accurate frequency control is to allow control of the flow of alternating current power from multiple generators through the network. The trend in system frequency is a measure of mismatch between demand and generation, and is a necessary parameter for load control in interconnected systems.

The frequency of the system will vary as load and generation change. Increasing the mechanical input power to any individual synchronous generator will not greatly affect the overall system frequency, but will produce more electric power from that unit. During a severe overload caused by failure of generators or transmission lines, the power system frequency will decline due to an imbalance of load versus generation. Loss of an interconnection while exporting power will cause system frequency to increase upstream of the loss, but may cause a collapse downstream of the loss, as generation is now not keeping pace with consumption. Automatic generation control (AGC) is used to maintain scheduled frequency and interchange power flows. Control systems in power stations detect changes in the network-wide frequency and adjust mechanical power input to generators back to their target frequency. This counteracting usually takes a few tens of seconds due to the large rotating masses involved (although the large masses serve to limit the magnitude of short-term disturbances in the first place). Temporary frequency changes are an unavoidable consequence of changing demand. Exceptional or rapidly changing mains frequency is often a sign that an electricity distribution network is operating near its capacity limits, dramatic examples of which can sometimes be observed shortly before major outages. Large generating stations including solar farms can reduce their average output and use the headroom between operating load and maximum capacity to assist in providing grid regulation; the response of solar inverters is faster than generators because they have no rotating mass.[30][31] As variable resources such as solar and wind replace traditional generation and the inertia they provide, algorithms have had to become more sophisticated.[32] Energy storage systems such as batteries are fulfilling the regulation role to an expanding degree as well.[33]

Frequency protective relays on the power system network sense the decline of frequency and automatically initiate load shedding or tripping of interconnection lines to preserve the operation of at least part of the network. Small frequency deviations (e.g., 0.5 Hz on a 50 Hz or 60 Hz network) will result in automatic load shedding or other control actions to restore system frequency.

Smaller power systems, not extensively interconnected with many generators and loads, will not maintain frequency with the same degree of accuracy. Where system frequency is not tightly regulated during heavy load periods, system operators may allow system frequency to rise during periods of light load to maintain a daily average frequency of acceptable accuracy.[34][35] Portable generators, not connected to a utility system, need not tightly regulate their frequency because typical loads are insensitive to small frequency deviations.

Load-frequency control (LFC) is a type of integral control that restores the system frequency and power flows to adjacent areas back to their values before a change in load. The power transfer between different areas of a system is known as "net tie-line power".

The algorithm involves defining the term area control error (ACE), which is the difference between the net tie-line power error and the product of the frequency error ${\displaystyle \Delta f}$ (the difference between the actual and target frequency) with a frequency bias constant B: ${\displaystyle ACE=\Delta P_{T}-B\Delta f}$, where ${\displaystyle \Delta P_{T}}$ is the change in the tie-in power outflow.[36][37][38] When the area control error is reduced to zero, the frequency and tie-line power are at their "normal" values.[39] The frequency bias coefficient B has a negative value (typically expressed in MW/0.1Hz, thus there is sometimes a 10x coefficient in front of B), so that when the frequency is lower than the target (negative ${\displaystyle \Delta f}$) the area power production should increase.[40]

Tie-line bias LFC was known since 1930s, but was rarely used until the aftermath of the Second World War. It got popular after a 1956 article by Nathan Cohn, "Some Aspects of Tie-Line Bias Control on Interconnected Power Systems". Cohn considered a simplified system with a tie-in line in between two identical areas. One area exhibits a step change in power ("fault").[41] The system response to a fault, per Cohn, consists of three stages:[38]

1. after the fault, frequency drops (inertial response) and stabilizes due to governor control, tie-in line inflow, and load reduction associated with lower frequency. LFC is too slow to engage at this point;
2. after some time, LFC in the unaffected area kicks in (it is presumed that the faulty area is unable to increase power due to the fault);
3. the fault area is recovers and tie-in power flow returns to normal.

At the beginning of the second stage the net change in load power in the fault area ${\displaystyle \Delta L=\Delta P_{T}+\Delta P_{G}-\Delta P_{L}}$, where ${\displaystyle \Delta P_{G}=-{\frac {\Delta f}{R}}}$ is the change in generator power due to governor control (R is the governor regulation coefficient, the control is assumed to be linear), ${\displaystyle \Delta P_{L}=D\Delta f}$ is the load reduction due to lower frequency (D is the damping coefficient that aggregates the effects of frequency change - droop speed control, lower load due to lower frequency, damper winding in the generator becoming engaged, the change is again assumed to be linear[41]). At the same time in the no-fault area ${\displaystyle \Delta P_{T}=\Delta P_{G}-\Delta P_{L}}$ (the different sign of ${\displaystyle \Delta P_{L}}$ is due to the fact that outflow of one area is an inflow for another one). Substitution of the expressions for ${\displaystyle \Delta P_{T},\Delta P_{G},\Delta P_{L}}$ into the balance of the fault area yields ${\displaystyle \Delta L=-2(D+{\frac {1}{R}})\Delta f=-2\beta \Delta f}$.[38]

At the end of the second stage the power of the generator in the no-fault area increases by ${\displaystyle \Delta P_{G2}=-{\frac {\Delta f}{R}}+\Delta P_{LCF}}$ due to the actions of governor and LFC respectively, with the fault area unchanged. Since the LFC algorithm drives the ACE to zero, at the end of the second stage ${\displaystyle ACE=\Delta P_{T}-B\Delta f=0}$. As a result, in the no-fault area ${\displaystyle \Delta P_{T}=-{\frac {\Delta f}{R}}+\Delta P_{LCF}-D\Delta f=-\Delta f(D+{\frac {1}{R}})+\Delta P_{LCF}}$. Thus ${\displaystyle B\Delta f=\Delta P_{LCF}-\beta \Delta f}$.[38]

Rate of change of frequency (also RoCoF) is simply a time derivative of the utility frequency (${\displaystyle {df}/{dt}}$), usually measured in Hz per second, Hz/s. The importance of this parameter increases when the traditional synchronous generators are replaced by the variable renewable energy (VRE) inverter-based resources (IBR). The design of a synchronous generator inherently provides the inertial response that limits the RoCoF. Since the IBRs are not electromechanically coupled into the power grid, a system with high VRE penetration might exhibit large RoCoF values that can cause problems with the operation of the system due to stress placed onto the remaining synchronous generators, triggering of the protection devices and load shedding.[42]

As of 2017, regulations for some grids required the power plants to tolerate RoCoF of 1-4 Hz/s, the upper limit being a very high value, an order of magnitude higher than the design target of a typical older gas turbine generator.[43] Testing high-power (multiple MW) equipment for RoCoF tolerance is hard, as a typical test setup is powered off the grid, and the frequency thus cannot be arbitrarily varied. In the US, the controllable grid interface at the National Renewable Energy Laboratory is the only facility that allows testing of multi-MW units[44] (up to 7 MVA).[45] Testing of large thermal units is not possible.[44]