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by Charles Rhodes

One of the most challenging aspects of public electricity grid operation is restarting the high voltage transmission grid after a prolonged wide area electricity transmission outage. In addition to the normal grid related electricity problems there may be other fundamental problems such as:
1) Only a very limited subset of generation equipment has the necessary features to enable grid restart. These features include:
a) A synchronous generator with variable excitation for voltage adjustment and sufficient capacity and moment of inertia;
b) A high degree of stable prime mover modulation for precise power adjustment during the black start procedure.

2) In the past electricity utilities often relied on fossil fuel based generation for black start procedure execution. As fossil generation is gradually being replaced by wind and solar generation, the practical problems of executing an orderly black start procedure are becoming increasingly more difficult.

3) Nuclear Reactor Poisoning: In some situations it takes three days to restart thermal neutron type power reactors due to temporary reactor poisoning by short lived fission products.

4) If the natural gas transmission system relies on electrically powered compressors it may be impossible to restart natural gas fired combustion turbines until after the natural gas transmission system pressure is restored.

5) Electricity distribution systems rely on batteries to maintain their substation communication and control systems during a grid power failure. If the grid power failure is prolonged each affected substation may require a site visit by a service person with a fully charged battery to restore communications and then power to the area served by that substation. The substation cannot be commanded to reconnect to the grid without control power which is usually soon lost if the substation automatically disconnects from the grid on loss of grid power. Worse yet, in certain circumstances the substation control software may need to be reloaded.

6) Restarting a long transmission line requires connection of a large reactance at the load end as well as connection of a large generator at the source end. There may also be a requirement for voltage support at the load end. If there is not suitably sized fully functional equipment immediately available for this purpose there is a big problem with reflected power on the unloaded transmission line which causes high voltages that immediately trip safety protection systems. Power cannot be restored to consumers until after correct transmission voltages are established. Otherwise consumer owned appliances will likely be damaged.

7) Wind and solar generation are unsuitable for black starting a transmission system due to their rapidly varying outputs and their reliance on the grid itself for voltage and frequency control. Typically variable generation like and wind and solar is added late in the restoration process when the grid island is sufficiently robust that it can accept the variability inherent in wind and solar energy production.

7) Lack of availability of critical skilled control and service personnel due to other emergencies precipitated by the prolonged wide area power failure. For example driving may be slow because all the traffic lights are out and few if any service stations can pump gasoline or recharge electric vehicles. These personnel might also have family related life and property threatening matters such as floods and potential plumbing freezeups caused by the power failure to which they must attend. Frequently their family members are not capable of managing emergency standby generation.

by Paul Acchione

Assuming that all of the aforementioned problems are resolved the grid restart procedure proceeds as follows:

Standard utility practice is to open all breakers connected to a blacked-out HV transmission line. This is done to prepare for controlled restoration. Someone has to charge the line with sufficient MVAR (megavolt-amps reactive) and prove that the line does not have a ground fault on it. Once the line is energized and terminated and voltage is within spec the loads are added gradually at a rate that the connected generator(s) can handle.

The HV lines are usually long. The lines we have here in Ontario from the Bruce reactor site to the Toronto area is almost 200 km long and require 180 MVAR each to energize the lines. You need a large unit to provide that many MVAR. Also the Toronto end requires voltage support after the line is energized from the Bruce end.

No transmission system operator I know would try to energize a dead HV line with unknown loads connected to it. They will energize a dead HV line after the loads have been disconnected.

If the loads were left connected before energization it is necessary to supply both MVAR and MW to pick up the line. That requires substantial spinning reserve behind the energizing breaker otherwise the line will trip out again on under-frequency or under-voltage and you have to start all over again. Most large machines cannot tolerate a step change of more than about 10% of rated full load or acceleration or frequency trips designed to protect the steam turbines will be triggered.

Except for small losses reactors (and/or synchronous condensers) do not consume MWs they consume MVARs. They do not apply a sustained load on the generator. The reactors and/or synchronous condensers are connected immediateely after the HV line is energized and they control the voltage on the unloaded line.

The HV line can be energized from the generator-end at a reduced voltage. After the reactors and/or synchronous condensers are connected the unit operator can adjust the generator excitation system to raise the voltage to its full rated value The process is controlled and there are no MW demands loading down the generators until both frequency and voltage are within spec. The voltages must be correct before loads are connected. Either low or high voltages can quickly damage consumer owned appliances. After correct voltage is confirmed the loading can begin by energizing distribution buses which typically will have loads sitting there connected to dead buses. The individual distribution buses typically are small compared to generating station sizes. Most distribution buses are 10 MW max. and a feeder supplying a number of buses for a larger sub-division is typically 100 MW max. Early in the restoration the smaller buses are energized individually, later in the restoration a feeder or entire subdivision can be energized. The pace of restoration speeds up as the energized electrical island gets larger. Eventually the individual grid islands are frequency and phase synchronized and then are reconnected to the North American grid.

If operators are planning to pick up load they will likely advance the local frequency a bit above 60 Hertz to give them room after the load pickup so the frequency does not fall too low. There are low frequency trips at both the load-end and the generator-end. Trips will kill the restoration and the process has to start over again. Operators tend to slow down if they get trips. Ideally operators try to take baby steps during initial restoration that will not cause trips. Remember that the operators involved are in different control rooms so the instructions need to be relayed by phone or computer among the ISO co-ordinating operator, RTO transmission control room operator(s), local distribution company control room operator(s) and generating station operator(s).

The process is complicated by the fact that system dynamics are related to the amount of generation on-line at any instant. For example if there is a 100 MW generator the load steps are 10 MW max. If there is one 1000 MW mechanical synchronous generator or there are ten 100 MW mechanical synchronous generators in the electrical island the operators can add 100 MW load steps. Itís not a constant number, it's a ratio. Also further complicating restoration is that the frequency drop during load application depends on the response time of the generator. So if you have a 10% load step with typically a 4% speed droop (loop gain) you would expect a steady state frequency drop after each load application of 10% x 4% x 60 Hz = 0.24 Hz.

However, the electrical grid is lightly damped so a fast responding electro-hydraulic speed governor on a fossil or nuclear unit would give you a frequency drop of about 2 x 0.24 Hz = 0.48 Hz. But, a mechanical speed governor on older hydroelectric units could give you a frequency drop of 2 Hz or more because the response time of those older governors is slow. At 56 Hz you typically have low frequency trips so you canít let frequency drop that much during restoration.

A further complication is that power inverters used to connect solar generation, wind generation and small turbine systems to the grid usually have no monent of inertia or equivalent frequency stabilization to assist in suppression of grid power and frequency oscillations.

There are a lot of variables and the operators have a difficult job trying to manage the restoration without creating unnecessary trips. After application of a load block they must re-establish steady state conditions near 60 Hz before the next load block can be added.

Thatís why grid restoration takes so long.

This web page last updated March 30, 2021.

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