By: Donald Jones, P.Eng., retired nuclear industry engineer, 2017 October 11
The U.S. has finally recognized the potential attributes that nuclear power generation brings to the power grid. “US energy secretary Rick Perry has called on the Federal Energy Regulatory Commission (FERC) to act swiftly to address threats to grid resiliency through market reforms to recognise the attributes of baseload generation sources including nuclear”, and, “Traditional baseload generation, with on-site fuel supplies and the ability to provide voltage support, frequency services, operating reserves and reactive power, is essential to provide resiliency during events like the Polar Vortex of 2014, and more recently hurricanes Harvey, Irma and Maria, Perry said”. Also, “Perry’s proposed rule would allow for the recovery of costs of “fuel-secure generation units that make our grid reliable and resilient”. To be eligible, units must be located within FERC-approved organised markets; be able to provide “essential energy and ancillary reliability services”; and have a 90-day fuel supply on site. They must also be compliant with all applicable environmental regulations” (Reference 1).
Question is, can U.S. nuclear generation deliver on those attributes.
This is what the United States Nuclear Regulatory Commission (U.S. NRC) says, (Reference 2)
“Nuclear Power Plants (NPPs) are designed as base load units and are not designed to load follow (either by plant operator action or automatically via external control signal). While operators can adjust power in general, rapid changes are difficult and power changes are most problematic near the end of a fuel cycle (typically 18 months) where reactor power control is more complicated.
NPPs control systems will not be interfaced with or controlled from grid network control systems. Control of a NPP has to be handled by the NRC licensed operators to ensure nuclear safety.”
Thus in the U.S. it looks as if nuclear plants are not licensed to provide attributes like dispatchable load-following, automatic generation control (AGC) and primary frequency response although they would provide reactive power and voltage support and they certainly have adequate on-site fuel supplies. They also provide highly reliable baseload with a 92.5 percent capacity factor in 2016. Since nuclear units are operated at 100 percent full power they would not provide operating reserves. This is not to say they cannot do all the things that energy secretary Perry claims it just means the U.S. NRC prohibits them from doing so.
PJM Interconnection, a regional transmission organization (RTO) in the U.S. has this to say (Reference 3),
“Nuclear plants may be prohibited from providing primary frequency response based on their licenses”, and, “Traditionally, nuclear units in the PJM footprint have not been dispatchable or configured for load following. Reductions to nuclear units are done in a methodic and planned fashion, and the units typically take several hours to ramp down and to ramp back up. During emergency conditions, nuclear units would ramp down faster, but ramping up still would occur in a slower, more controlled fashion over several hours. As a result of negative Locational Marginal Prices (LMP) market signals, some nuclear units have begun to operate in a load following manner much like a large steam unit. These nuclear resources have been able to operate as dispatchable resources in a range between 85 percent and 100 percent of their economic maximum.”
In the rest of the world the situation is different (Reference 4),
“Globally, France’s PWRs routinely load-follow due to the high percentage of nuclear-generated electricity on their grid (nominally 75%). Canadian reactor units are also required to load-follow(Author’s note: should be load shaping or load cycling not load-following) due to the percentage of nuclear power there and German reactors load-follow primarily because of a relatively high contribution of intermittent wind generation on their grid. In the United States, many nuclear plants currently operating were designed to load-follow and were originally outfitted with automatic grid control (AGC) features. However, the US Nuclear Regulatory Commission policy precluded the use of automatic dispatching for true load following, although they allow manual load-shaping if conducted by a licensed reactor operator. Load-following with nuclear plants, especially larger plants, requires complicated procedures and plant components that can tolerate thermal cycling.
The 1170MWe Columbia station in Richland, Washington, is the only commercial nuclear plant in the USA that performs routine power manoeuvring to load-shape. The load-shaping is required in spring to avoid excessive spill-over at hydroelectric plants in the Bonneville Power Authority (BPA) network. Increasing wind generating capacity in the BPA network may also require new load-shaping at Columbia.”
So it looks as if load-cycling or load-shaping can be carried out in the U.S. by the licensed operators of a unit following procedures approved by the U.S. NRC for that unit but primary frequency response and AGC are not done. In France some nuclear units, basically similar to units in the U.S., do load-following, that is, make changes in power at short notice from the grid operator as the grid demand changes during the day in addition to planned load-cycling manoeuvres or even shutdown. Not all units are needed for load-following and a significant number operate baseload. Units also provide primary frequency response, and AGC.
Load-shaping, or load-cycling, is what Ontario’s Bruce Nuclear Generating Station’s eight units do using turbine steam bypass to accommodate surplus baseload generation on the grid. They do not load-follow, that is, respond to frequent power change dispatches from the Independent Electricity System Operator (IESO). On instructions from the IESO Bruce units perform a gradual reduction in electrical output of up to 300 MW per unit over a one to two hour period then hold at reduced output for the required length of time, usually several hours, before gradually increasing output over one to two hours. The slow power change is to reduce the thermal stresses on the thick walled components of the steam turbine. Much faster power changes can be made if demanded. Bruce gets paid for the energy it could have produced without the constraints, deemed generation. Darlington and Pickering nuclear stations run baseload at full power and do not load-cycle like Bruce. Load-following, primary frequency response and AGC is provided by other generating units on the grid.
In Ontario the IESO requirements for ancillary services market are:
- Black Start Capability
- Regulation Service
- Reactive Support and Voltage Control
- Reliability Must-Run
IESO describes black start as, “Certified black start facilities help system reliability by being able to restart their generation facility with no outside source of power. In the event of a system-wide blackout, black start facilities would be called on during restoration efforts by helping to re-energize other portions of the power system.”
CANDU power plants were not designed for black-start operation; that is, they were not designed to start up in the absence of power from the grid. The large power demand of the primary heat transport circulating pumps, and other large pumps, precludes a black start if the grid has collapsed and the reactor has tripped, even after the xenon transient. If the grid has collapsed and the unit has reverted to poison prevent mode, as it should, supplying house loads then the unit can be brought back on line on instructions from the power grid operators once the power grid is sufficiently established.
The IESO says, “Regulation service acts to match total system generation to total system load (including transmission losses) and helps correct variations in power system frequency. This service corrects for short-term changes in electricity use that might affect the stability of the power system. Regulation service has historically been provided by generation facilities with automatic generation control (AGC) capability, which permits them to vary their output in response to signals sent by the IESO. Current Regulation Service is for minimum of ±100 MW of automatic generation control (AGC) must be scheduled at all times with minimum overall ramp rate requirement for Ontario of 50 MW/minute.The IESO plans to expand its capability to schedule regulation by increasing the amount of regulation usually scheduled from 100 MW to 150-200 MW between 2017 and 2019 and have sufficient market depth to schedule up to 250 to 300 MW of regulation capacity on an as-needed basis by the year 2020.”
Ontario’s present CANDU stations were not designed to provide AGC and are now configured to operate baseload at 100 percent power. They operate in a turbine following reactor mode and thus do not contribute any primary frequency response to the power grid (Reference 5). The eight unit Bruce station provides base load and can run at reduced output using turbine steam bypass, if required.
Reactive Support and Voltage Control:
The IESO says, “Reactive support and voltage control service is contracted from generators and allows the IESO to maintain acceptable reactive power and voltage levels on the grid. Both active and reactive are required to serve loads. Reactive power flow is needed in an alternating-current transmission system to support the transfer of active power over the network. All generating facilities that are injecting energy into the IESO-controlled grid are required to provide reactive support and voltage control service in accordance with the market rules.”
Ontario’s nuclear units provide reactive support and voltage control.
The IESO says, ”Reliability must-run (RMR) contracts are used to ensure the reliability of the IESO-controlled grid. A RMR contract allows the IESO to call on the registered facility under contract to produce electricity if it is needed to maintain the reliability of the electricity system. RMR contracts obligate the market participant to offer into the IESO-administered markets the maximum amount of energy and operating reserve in a commercially reasonable manner and in accordance with stated performance standards.”
No Ontario nuclear units have a Reliability Must Run-contract.
So what is the present situation. In the U.S. the NRC prohibits short notice dispatchable load-following, primary frequency response, and AGC even though the units are likely capable of doing it. They can perform a planned load-cycle by changing reactor power under the control of a licensed operator if permitted to do so by the NRC. If the NRC continues with its restrictions on nuclear manoeuvring then the only attributes left for nuclear are reliable baseload operation and reactive support and voltage control. Coal-fired stations can provide the frequency control, operating reserve and all the other attributes that energy secretary Perry mentioned in his submission. Natural gas-fired units would also be covered by the market reform if they held adequate amounts of liquid fuel on site for emergency use. Since greenhouse gas free generation was not mentioned as an attribute, and not likely to be under the present administration, nuclear could be left out in the cold.
In Canada the situation is much the same, no frequent dispatchable load-following, no primary frequency response and no AGC. Load-cycling is allowed as long as it is done by steam bypass with no reactor power changes. Unlike variable and intermittent wind and solar generation nuclear provides very reliable baseload. It also supplies reactive support and voltage control but does not presently supply operating reserve since it runs at 100 percent full power.
Canadian nuclear plants are designed to meet Canadian Nuclear Safety Commission (CNSC) requirements (Reference 6) that apply to CANDU and Light Water designs. Load following is mentioned in section 7.3.1, Normal Operation, “changes in reactor power, including load-follow modes (if applicable) and return to full-power after an extended period at low-power”. Note the, “if applicable”.
The Ontario power grid presently compensates for the lack of flexibility in its nuclear units by making use of the load-following attributes of its significant hydro generation and to a limited extent its combined cycle gas turbine generating units, and the load-cycling at Bruce. There are a couple of ways that dispatchable load-following and frequency control including AGC could be provided by the present CANDU nuclear units. One approach would be to operate the units in the reactor following turbine mode but this would lead to the kind of reactor power change that the CNSC do not like even if not exactly prohibiting it. To satisfy the CNSC would take a lot of engineering and testing to show that there would be no impact on reactor safety by load-following using changes in reactor power. There could also be limitations on operation from the effect of Xenon-135 changes in the fuel due to the reactor power changes (Reference 7). The other and better approach would be to change the control system of the present CANDUs to one similar to the Enhanced CANDU 6 (EC6) (Reference 7) that would modulate steam bypass flow around the turbine to the condenser on an IESO signal or dispatch and avoid the automatic changes to reactor power that the CNSC do not like. This is easier said than done and if the IESO is comfortable with the present and future situation on the grid then it is not worth the effort. Bruce and Darlington certainly would not do this without adequate compensation and prodding from the IESO. Phasing out gas-fired generation in the future would result in a nuclear-hydro grid and then more flexibility would be required from the nuclear units.
1. Perry acts to support U.S. nuclear, World Nuclear News, 2017 October 2, http://www.world-nuclear-news. org/NP-Perry-acts-to-support- US-nuclear-0210177.html
2. U.S. Nuclear Regulatory Commission Input to DOE Request for Information/RFI (Federal Register / Vol. 75, No. 180 / Friday, September 17, 2010/Pages 57006-57011 / Notices) / Smart Grid Implementation Input – NRC Contact: Kenn A. Miller, Office of Nuclear Reactor Regulation, 301-415-3152
Comments relevant to the following two sections of the RFI: “Long Term Issues: Managing a Grid with High Penetration of New Technologies” and “Reliability and Cyber-Security,” Page 57010
https://energy.gov/sites/prod/ files/oeprod/ DocumentsandMedia/SmartGrid_-_ NRC_Input_to_DOE_ Requestrvjcomments.pdf
3 PJM’s Evolving Resource Mix and System Reliability, PJM Interconnection, March 30, 2017, http://www.pjm.com/~/media/ library/reports-notices/ special-reports/20170330-pjms- evolving-resource-mix-and- system-reliability.ashx
4.“Integrating nuclear and renewables”, Nuclear Engineering International, 2016 February 1, http://www.neimagazine.com/ features/featureintegrating- nuclear-and-renewables- 4795860/
5. A quick primer on how CANDUs fit into Ontario’s windy power grid – 2013 July, https://thedonjonesarticles. wordpress.com/2013/07/06/a- quick-primer-on-how-candus- fit-into-ontarios-windy-power- grid-2013-july/
6. CNSC REGDOC-2.5.2, Design of Reactor Facilities: Nuclear Power Plants, http://nuclearsafety.gc.ca/ eng/acts-and-regulations/ regulatory-documents/ published/html/regdoc2-5-2/ index.cfm
7. Enhanced CANDU 6 and NuScale SMR have capability to easily integrate wind and solar, 2016 August 17, https://thedonjonesarticles. wordpress.com/2016/08/17/ enhanced-candu-6-and-nuscale- smr-have-capability-to-easily- integrate-wind-and-solar/