Depends on where you are. The Swiss Nant de Drance project took advantage of two existing reservoirs, separated by 425 m vertical. Cost over 2 billion dollars for 20 GWh, about $104/kWh. And if you need the 900 MW for more than 22 hours, you're screwed. That's if you have ideal topography and the dam is already there. You won't find any mountains in northern Germany. In fact, you will find very few hills. For almost everywhere, a bit of gas turbine is the way to go, economically and environmentally.
13GW of OCGTs for 46h of run time in 11 years? Capacity factor of 0.05%? Jesus, they might as well run the plants on gasified diamonds at that rate.
Would probably make more sense to get customers to use electricity for heat on some industrial process that they could switch over to gas quickly during high grid demand times in order to keep the load factors higher and stabilize the grid output overall. Just gotta make the power cheap!
The GKG model assumes that the hourly demand must be met. So yes that last bit is expensive, and you can imagine load shedding schemes. But the impact on the overall cost of electricity is small. Please see Low CO2 electricity: the options for Germany at gordianknotbook.com. And the OCGT perform two other important functions. They handle unplanned outages and unexpected load spikes.
The GKG model assumes perfect foresight. In the real world, we do not have that luxury. Any decent grid needs reserve capacity which by definition means it is almost never used.
I think a good approach will be to use the excess for a “dispatchable demand” to make syn fuels / chemicals and the like. Stage 1 of peak normal demand is to turn that off. The real backup in a pinch is to then use some of those fuels for backup power.
Depends on the capital costs of the synfuel production system. Marginal improvement in nuclear's capacity factor at the expense of pushing the capacity factor of the synfuel system down is almost certainly not the way to go. This is certainly true when it comes to desal,
It's going to be an issue with synfuels no matter how we do it. The nice thing is we can separate making H2 from the synfuels/chemicals to an extent. At least hours to days buffer is not too hard.
In your example, the rapid tail off of firm CF as you go up in the peak power capacity mirrors the increase in CF available for disptschable demand users.
For Ontario data. Firm power sized for 1.5x average demand would just cover peak demand for the current t system. (It would be short of future heating peak though). But a dispatchable demand user sized for 0.5x avg demand would get 80-90%CF from the excess. The rarer the call to use the peak for regular dema d, the higher the CF available for the alt user.
If I were designing a grid with a demand histogram like Fig 3, I would use smart meters to cut off demand above 85 MW. A 10% discount on their monthly bill should be enough to get volunteers for the smart meters.
A bit of pumped hydro would handle the peaks gracefully.
Depends on where you are. The Swiss Nant de Drance project took advantage of two existing reservoirs, separated by 425 m vertical. Cost over 2 billion dollars for 20 GWh, about $104/kWh. And if you need the 900 MW for more than 22 hours, you're screwed. That's if you have ideal topography and the dam is already there. You won't find any mountains in northern Germany. In fact, you will find very few hills. For almost everywhere, a bit of gas turbine is the way to go, economically and environmentally.
13GW of OCGTs for 46h of run time in 11 years? Capacity factor of 0.05%? Jesus, they might as well run the plants on gasified diamonds at that rate.
Would probably make more sense to get customers to use electricity for heat on some industrial process that they could switch over to gas quickly during high grid demand times in order to keep the load factors higher and stabilize the grid output overall. Just gotta make the power cheap!
The GKG model assumes that the hourly demand must be met. So yes that last bit is expensive, and you can imagine load shedding schemes. But the impact on the overall cost of electricity is small. Please see Low CO2 electricity: the options for Germany at gordianknotbook.com. And the OCGT perform two other important functions. They handle unplanned outages and unexpected load spikes.
The GKG model assumes perfect foresight. In the real world, we do not have that luxury. Any decent grid needs reserve capacity which by definition means it is almost never used.
I think a good approach will be to use the excess for a “dispatchable demand” to make syn fuels / chemicals and the like. Stage 1 of peak normal demand is to turn that off. The real backup in a pinch is to then use some of those fuels for backup power.
Depends on the capital costs of the synfuel production system. Marginal improvement in nuclear's capacity factor at the expense of pushing the capacity factor of the synfuel system down is almost certainly not the way to go. This is certainly true when it comes to desal,
My guess is it is also true for synfuels.
It's going to be an issue with synfuels no matter how we do it. The nice thing is we can separate making H2 from the synfuels/chemicals to an extent. At least hours to days buffer is not too hard.
In your example, the rapid tail off of firm CF as you go up in the peak power capacity mirrors the increase in CF available for disptschable demand users.
For Ontario data. Firm power sized for 1.5x average demand would just cover peak demand for the current t system. (It would be short of future heating peak though). But a dispatchable demand user sized for 0.5x avg demand would get 80-90%CF from the excess. The rarer the call to use the peak for regular dema d, the higher the CF available for the alt user.
If I were designing a grid with a demand histogram like Fig 3, I would use smart meters to cut off demand above 85 MW. A 10% discount on their monthly bill should be enough to get volunteers for the smart meters.