Voltage Collapse — a Poorly Understood Power System Failure Mechanism

In a previous blog, I explained a form of grid collapse that can occur on the power system when an interconnected area has a significant loss of capacity and balance cannot be re-achieved quickly. As system frequency declines, other generation shuts down, and the system may cascade quickly to a dark and quiet place.

During one major blackout, subsequent analysis revealed that there was another mechanism that played a major role, and that was voltage collapse. That concept is very different but delivers a similar result.

The maximum power that can be delivered through a transmission line can be shown to be proportional to the product of the voltages at each end of the line. A transmission line that is operating with 230kV at both ends of the line can deliver twice the power of the same line that is operated with 230 kV at one end and 115 kV at the other. While this voltage difference may seem unusual, it may occur if there is a fault on another nearby line.

Faults occur frequently, often caused by lightning, and grid design must ensure that such faults do NOT lead to a collapse. Planners discovered, through calculations and simulations, they can design the grid to automatically react to faults without ending in a collapse. This mathematically intense exercise is one that is critical to maintaining system reliability and stability above minimum standards. The people performing this analysis are generally employed in transmission planning or system operation planning functions. These people have a detailed understanding the inner workings of the grid. They are also the people behind the scenes in purchase decisions that have stability impacts, such as load shedding or system voltage management.

When a fault occurs on a transmission line, the voltage at the substations at each end of that line will be depressed until the fault is cleared. This voltage depression causes the line end voltage on every other line, connected to each of the two substations, to decline, and this in turn reduces the carrying capacity of the nearby transmission lines.

At this point, I use a little analogy. Consider an elephant that is pulling a heavy cart up a hill and is assisted by a second elephant that is connected to the first with a heavy chain. If something happens that the chain suddenly becomes a thin rope, the rope may stretch somewhat and then it breaks. Transmission lines may do the same. If a transmission line that is carrying a load that is near its peak capacity experiences a lowered voltage at one end, it may be unable to carry the required capacity, and when that happens, the frequency at both ends of the line may begin to deviate very slightly. After a very short time, if the voltage at the station near the fault does not recover, other lines may trip offline and a collapse may be initiated.

Planners perform detailed analysis on these potential events and have determined that the time to clear a faulted line may need to be short to maintain the stability of surrounding transmission lines. This total clearing time may need to be a fraction of a second (3-5 cycles or 50-84 msec).

Protective relays are devices that monitor grid operation and isolate faulted lines quickly. Their history is interesting, because it has played a key role in management of the grid from its beginning. Significant changes in technology have occurred over time:

  • The earliest protection systems controlled lines, with a current-based time-delay to trip with a high current. In theory at least, the faulted line had the highest current, and would trip first.
  • In 1918, a Canadian born engineer, Charles Fortescue, published a paper demonstrating Symmetrical Components, an analysis process that allowed fault currents to be identified. Fortescue’s theorem enabled more sophisticated protective relay designs. Impedance or distance relays were a popular example.
  • After about 1950, powerline carrier, microwave and later fibre optic systems enabled the use of telecommunications between stations at each end of lines to coordinate protection. Differential protection, transferred trip and other systems became common.
  • GPS Satellites, put into orbit after 1978 have become standards for navigation. The GPS system provides an accurate time standard anywhere, and this has been valuable for grid control. The voltage “phase angle”, used extensively by planners, could suddenly be measured. Synchrophasers, or Phase Measurement Units (PMUs), based on GPS, have many uses in power system protection and control and are now included in new protection systems.

Protective relays can now detect and locate a fault with good reliability. The protection system can then trip the faulted line within the time constraint required to maintain stability. This capability has resulted in an ability to operate transmission lines at higher capacity levels, with lower stability margins, to reduce the needs for costly additional line capacity.

The planners task went further, setting capacity constraints and processes to allow for scheduled maintenance. Utilities use an “N-1” criteria, to ensure that stability is maintained after the loss of the largest potential component loss that is probable under all operating conditions. Planners, both in initial design and operations, need to consider many scenarios for configurations during system maintenance.

Some examples of operating plans are interesting. The Pacific Intertie is a 3,100 MW DC transmission line that connects the BPA Celilo Converter near The Dalles generating station on the Columbia River in Oregon, to the Sylmar Converter Station owned by LADWP, near Los Angeles. The line is frequently used to deliver power exported by BC Hydro or BPA to Los Angeles. If the intertie is heavily loaded, and a fault occurs, tripping the intertie, other parallel AC lines would not be capable of handling the capacity needed and would trip as well. To avoid the secondary trips, generation shedding is used in the north, and load shedding in the south, to maintain balance at both ends of the intertie. In the case of BC Hydro exporting, a fault on the Pacific Intertie will result in several generators being tripped offline at the Bennett dam in northern BC, not far from the Alaska border. These generators would be offline in much less than 1 second after a fault was detected on the intertie. Systems of this type have become common, needed to maintain stability.

Even these systems may not always have the required capacity. A 500 kV fault occurred relatively recently on a hot summer day near a major city in the southern US. The fault depressed voltage in the entire city for a short time but was cleared within the expected time. It was expected that the system would remain normal, but the city collapsed into darkness. The cause was apparently the fact that it was very hot, and many air conditioning systems were running at peak capacity. When the voltage drop occurred, caused by the fault, many air conditioning compressor motors “stalled” and stopped rotating, drawing a much larger current than normal. That in turn, caused an increased decline in voltage, and more compressors stalled. The city voltage collapsed. This situation demonstrated that the role of users may have a valuable role in maintaining system stability. In this case, the motors running air conditioners likely needed to be designed to withstand a short duration of low voltage. But new DER and voltage management systems that can provide rapid support will have growing value in maintaining stable operation

Companies such as Generac may find opportunities to partner with utility planners and operators in contributing to grid stability and resilience through the application of optimized and fast systems to address voltage and frequency deviations. There may be real value in working with planners to be positioned to support their internal needs to manage stability and resilience.

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