How wind affects Ontario’s power system dynamics and effect on CANDU refurbishment

By: Donald Jones, P.Eng., retired nuclear industry engineer, 2014 April.

This is really something that the experts at the Independent Electricity System Operator (IESO) and the Ontario Power Authority (OPA) should be looking at with Candu Energy Inc., Ontario Power Generation (OPG), and Bruce Power but while we wait I will give it my ten cents worth.

Adding variable wind and solar generation to the Ontario grid displaces gas-fired generation and some hydro generation. Wind and solar have no inherent capability to help maintain frequency control of the grid. The gas and hydro generation do have this capability but it is being eroded by wind. The substantial amount of nuclear generation, in its present mode of operation, does not contribute to frequency control of the grid. All in all this will contribute to a degradation of frequency control on the grid unless changes are made.

The Ontario power grid is not very flexible. Present nuclear units do not provide much flexibility to the grid and provide no primary frequency control (see reference 1). The improved power output flexibility of the eight nuclear units at Bruce (see reference 2) has improved the flexibility of the Ontario grid somewhat, reducing but not eliminating the need to shutdown nuclear units during periods of surplus baseload generation (SBG) caused by low demand and excess generation. However it has done nothing that helps primary frequency control on the grid to limit variations in frequency caused by wind generation and normal load changes. Grid frequency can give an indication of the system balance between generation and load and needs to be accurately controlled for the proper functioning of the grid.

The way nuclear units connect to the Ontario grid is described in reference 1. All the nuclear units in Ontario operate in the turbine-following-reactor mode of operation so they cannot contribute to tight tolerance frequency control. The Bruce units operate in this mode and unit electrical output is changed by controlling the amount of steam bypassing the turbine and not by controlling reactor output, which remains constant. In this mode any automatic turbine governor action, primary frequency control, necessary to help maintain the nominal 60 Hertz grid frequency in its very tight control band is negated by the unit control system. Both Bruce Power and OPG have a waiver from the IESO to operate this way. Having relatively loose frequency control makes for larger frequency deviations during grid upsets. The nuclear operators, Bruce Power and OPG, correctly say that the other mode of operation, the reactor-following-turbine mode, that would provide primary frequency control results in a small reduction in reactor output and small variations in reactor power that result in less stable reactor operation that could degrade system reliability. However changes can be made to the control system to avoid variations in reactor power, a technical/licensing concern, while the small reduction in reactor power, a financial concern, is an inherent characteristic of primary frequency control, see later. The present mode of nuclear operation might have been adequate when the grid had little or no wind generation but more and more wind coming onto the grid will affect the dynamics of the grid, see later. Any change from the present mode of operation would require changes to the reactor operating licences by the nuclear regulator, the Canadian Nuclear Safety Commission.

Modern wind turbine units that have the turbine-generator decoupled from the grid by electronic power converters, asynchronous units, cannot inherently contribute the inertia of their rotating masses, inertial response, to the grid when grid frequency changes or contribute to primary frequency control. Sophisticated engineering may be able to emulate some of the inertial response and primary frequency control provided by synchronous generators but given the inherent limitations of wind generation (depends on availability of wind) the economics may not justify it because of upfront equipment cost, potential to increase loading impacts on turbine components, and need for units to operate below their full power output. In fact there can be no technical, economic or environmental justification for wind at all in Ontario. Solar units have no inherent inertial response capability or governor-like frequency response. This leaves the primary frequency control of the Ontario grid dependent only on the hydro units and on any gas-fired units that are on line. System load also contributes to primary frequency control by opposing the change in frequency, falling with decreasing frequency and rising with increasing frequency. The nuclear units do contribute the inertia of their rotating masses, inertial response, just like the gas and hydro units if grid frequency changes. Having small amounts of inertial response and primary frequency control on the grid means frequency will exceed the allowable band around the nominal 60 Hertz more often and sustained out of band frequency will need secondary frequency control, regulation service, to bring frequency back into the allowable range (see reference 1). Primary frequency control arrests frequency excursions during a system upset.

The presence of large amounts of wind generation has changed the dynamics of the grid by displacing the synchronous generators that have provided passive inertial response and active primary frequency control. This is especially so at night and on weekends if wind generation is high when grid demand is low. The large gas-fired stations will be taken off line leaving the combined heat and power units, nuclear, and some hydro units on line. Primary frequency control would then be degraded and mostly left to the hydro units with inertial response from the nuclear and hydro units. The inherently variable wind generation in these circumstances could result in a jittery grid and lead to frequent frequency excursions outside the allowable control band that require more use of Automatic Generation Control (AGC), the regulation service normally provided by one or more hydro units at Niagara Falls, other contracted generators, and even loads. To avoid/reduce use of a large AGC capable generating unit under these circumstances and to keep frequency in the allowable control band use could initially be made of the IESO’s recently procured 10 MW of regulation service from three variable small load suppliers. These make use of aggregated loads, flywheel storage and battery storage with between 1 MW and 4 MW being provided by each supplier. Indeed this concern must have been the rationale for these variable load regulating services in the first place and much more will be needed to make up for the effect of variable wind and the loss of inertial response and primary frequency control of the synchronous generators displaced by wind. The IESO and the OPA are also in the process of procuring 50 MW (shouldn’t that be MWh?) of energy storage some of which will be used for frequency regulation. Having fast acting primary frequency control from nuclear units with enabled governors may have obviated the need for these variable load regulation services. However having nuclear come to the aid of wind makes no technical, economic or environmental sense.

The Enhanced CANDU 6 (EC6) that was proposed for Darlington would be able to provide very fast primary frequency control since it would operate in a steam bypass (rather than reactor)-following-turbine mode of operation enabling it to quickly respond to grid frequency perturbations (see reference 3). If the Bruce and Darlington nuclear units could have their control systems changed to the EC6 design during refurbishment it would lead to a great improvement in primary frequency control of the grid since nuclear generation is a substantial portion of the grid. In addition it would increase flexibility by having the capability to provide frequent dispatchable load following as well as reducing unit electrical output to zero if necessary. However to make the changes necessary to reduce unit electrical output to zero would need a change to the reactor operating licence since steam bypass/condenser capacity alone is not sufficient and reactor power would have to be reduced to around 60 percent full power. Since such extreme reactor power changes (from 100 percent to 60 percent full power) would be infrequent and can be made very slowly (unlike a unit operating in reactor-following-turbine mode where reactor is subject to frequent small reactor power changes to help maintain nominal grid frequency) there should be less difficulty in getting approval from the nuclear regulator. Licensing approval might be helped by the fact that EC6 has completed the final pre-licensing vendor design by the nuclear regulator that concluded that the design had adequately addressed Canadian regulatory requirements and expectations.

If Bruce Power and OPG refuse to pursue a licence change (why should they, it costs money, especially if they have to reconfigure the adjusters) the IESO/OPA should at least ask them to provide primary frequency control by going to a turbine steam bypass-following-turbine mode of operation, like EC6. After all, primary frequency control is what is normally expected from all generators on the system. This would also give the capability to do limited load cycling like the present Bruce units (down to around 60 percent unit full electrical output, compared to down to zero with the EC6) and even frequent dispatchable load following and, with an AGC compatible governor the units could also supply secondary frequency control if needed. All this can be done because the reactor does not necessarily take part in the electrical power manoeuvres. Nuclear units that provide primary frequency control could operate at, say, 97.5 percent of full power output to accommodate +/-2.5 percent of full power for primary frequency control (could be more if required since reactor is not involved in the output changes) so the economics of operating at reduced power would have to be considered and payment schemes devised. Operating like this would quickly and automatically provide up to +/- 300 MW of nuclear to the grid to stabilize frequency by governor action during an upset. For a severe under frequency event this will allow time for contracted operating reserve and AGC, secondary frequency control, to kick in to stabilize the system and return frequency back to its allowable band. If one unit were providing AGC it would operate significantly below its full output power depending on the requirements of the IESO for paid regulation service, currently a minimum of +/- 100 MW at 50 percent/minute minimum ramp rate. AGC service could be shared amongst several generators.

If the Bruce and Darlington units made the control changes to operate like the EC6 during their refurbishment and received licence approval from the nuclear regulator for reactor power changes then Ontario would have one of the most flexible power grids in the world together with very strong frequency control. Nuclear flexibility and strong nuclear primary frequency control will be essential for the future power grid (see reference 4) that will be mainly composed of nuclear and hydro generating stations but predominantly nuclear. Something has to be done to get Ontario off pricy greenhouse gas emitting frackgas-fired generation, and without gas there can be no rationale for wind.



1. A quick primer on how CANDUs fit into Ontario’s windy power grid, 2013 July, Don Jones,

2. Ontario’s already “flexible nuclear” CANDU even better by satisfying IESO requirements to replace flexible coal, Don Jones, 2012 October 20,

3. Contenders for nuclear flexibility at Ontario’s Darlington B, AP1000 and EC6, and the winner is …., Don Jones, 2013

4. An alternative Long-Term Energy Plan for Ontario – Greenhouse gas-free electricity by 2045, Don Jones, 2011 May,


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