Post by David B. Benson on May 5, 2012 13:49:34 GMT 9.5
Some time ago I opined that adding a thermal store to NPPs might be a suitable way to incorporate balancing agents for wind and solar PV as well as general load following. Cyril R replied to indicate it was certainly feasible. The remaining question is the economics of doing so.
From an earlier thread on BNC discussing CSP a comment was offered to the effect that adding just the thermal store (and its heat exchangers) cost about US$2000/kW; this for overnight store suitable for some of the load following. NO mention of the thermal efficiency was stated although I'm under the impression that about 85% is readily achievable.
At that cost and using 85% efficiency, CF=60%, heat from the NPP at an equivalent of US$76/MWh, from the NREL simplified LCOE calculator, I find that electricity from the thermal store has a busbar cost of US$136/MWh. Possibly it is more cost effective to ramp the NPP?
Post by anonposter on May 5, 2012 13:57:47 GMT 9.5
The big problem I can see to using nuclear to backup wind and solar is that whilst wind and solar would likely do better in combination with nuclear you'd probably be able to do better just using nuclear on its own (at least with natural gas backup there's the argument that wind and solar are reducing the amount of expensive fuel burned and hence also CO2 emitted).
Though using some energy storage in combination with nuclear might make sense depending on cost of storage system and how it compares with load following a reactor (as you note that doesn't appear to be the case now).
Post by David B. Benson on May 5, 2012 14:58:54 GMT 9.5
Once a mostly NPP grid is in place (as in France), the question of whether it is economic to add wind or solar PV comes down to the economics of those generators and providing suitable balancing agents for the intermittent generators. It appears that in the USA, with the current incentive structure in place, wind is about US$63/MWh in comparison to baseload NPPs at around US$76/MWh. Therefore if it is technically feasible to ramp the NPPs to balance wind, the wind operator can pay the NPP operator a small fee to do so and still make money.
Alternatively, and the question for this thread, is whether it makes more sense to add a thermal store to an NPP so that largely ramping is avoided and the thermal store handles most of the variations.
Post by anonposter on May 5, 2012 15:31:04 GMT 9.5
Of course that wind power price is based on some pretty heavy subsidies, then there's the marginal cost of power, that the cost difference of nuclear between full power and idle is so close to zero means that backing off a nuke to make way for something else just doesn't seem to make much sense.
The big question to determine whether energy storage is worth doing would be how much could it come down to.
Post by David B. Benson on May 5, 2012 16:17:16 GMT 9.5
Yes and running an NPP at a lower CF results in higher LCOE. For example, suppose (to provide reserves) the NPP fleet operates during the daytime (6 am to 11 pm) at CF=85%. Then new NPPs might have a fleet average LCOE of US$97/MWh during the daytime. But at night the load is only about 70% of the daytime load, so at night the LCOE is US$138/MWh (an inversion of most current markets). If instead a thermal store is charged overnight, the NPP fleet can continue to run at CF=85%. But then when using the thermal store the busbar rate for that portion of generation is US$158/MWh.
Which all assumes I have about the right costs for everything, excluding adding in subsidies for the various forms of generation.
I'll have to think about the matter a bit more, but I would appreciate some advice regarding just how expense building a thermal store would be.
To be honest, I don't get why you would consider adding thermal energy storage to a nuclear power plant, when a nuclear power plant typically runs at 100% capacity all the time.
If you were at the situation where you couldn't run the power plant at 100% capacity because there just isn't the demand all the time (and you don't have anything else you can throttle back, we are talking something like the French grid here).
Post by LancedDendrite on May 8, 2012 0:14:39 GMT 9.5
Dedicated thermal storage may not be the way to go. Conversion of existing hydroelectric facilities to pumped-storage could absorb excess power due to diurnal load cycles as well as mitigating water shortage issues. That would be able to handle existing scales of electricity demand, I would think.
As for load following, once you have replaced all of the baseload coal plants (eventually) you will probably have Gen IV reactors ready by then that can actually do OCGT-style load following using Brayton cycle turbines.
Post by David B. Benson on May 8, 2012 12:48:22 GMT 9.5
Luke Weston --- The load is not constant having at least a diurnal and a weekly pattern. From the standpoint of the NPP it would be more efficient to run at (nearly) full, storing the excess produced overnight in the thermal store for use in the daytime when demand is high. (The other choice, of course, is to ramp the NPP, as is done in France, and indeed that might be more cost effective.)
lanceddendrite --- For this exercise I am assuming that there is essentially no hydro available.
Then there's a simpler way to meet peaking requirements than thermal store - just retrofit turbine bypass valves onto existing power plants so that steam can go directly to the condenser. Fuel waste isn't a big issue for nuclear plants anyway, so a combination of reactivity management (remembering that excessive changes in reactivity causes Xenon-135 problems) and steam bypass should be fine. Just plan a diurnal-based reactivity change cycle and throttle the condenser bypass as needed for changes on smaller time-scales.
The French have plenty of experience with reactivity control for load-following, I think that the Canadians have done a bit of turbine bypass work on with CANDUs. So I doubt that load-following will be a big enough issue to justify 'thermbine' retrofitting.
Post by Nathan Wilson on May 15, 2012 13:46:38 GMT 9.5
Here is a re-post of a write-up I submitted on the Energy From Thorium site in July 2010. It is based on the PB-AHTR, but the results for the IFR would be very similar. Note that the cost estimate (about $1/W) is much lower than what David assume up-thread.
My concern here is grids with very large renewable penetration (>20%). Note that when a nuke is used in load-following mode to backup renewables, nuclear power is essentially discarded in an amount equal to the renewable energy available. In other words, it guarantees that renewable supporters will fight nuclear power to the death.
The storage option allows nuclear and renewables to be more equal contributors (70:30?) to a post-carbon electrical system. And thermal energy storage allows every city to have local storage (which improves reliability), not just those with the right geography for pumped hydro or CAES.
The high temperature heat available from the PB-AHTR (and LFTR and IFR) makes it suitable for use with thermal energy storage (TES) systems, to improve load following capability (especially for use with wind power). In particular, molten-salt systems are a good fit; particularly in combination with helium Brayton cycle power conversion (they can load-follow with no efficiency loss, via changes in the helium inventory/pressure).
In such a system, the power conversion system would be upsized 20-100% above what the reactor can supply, and would be throttleable down to about 10-30% of maximum. The difference between the reactor output (which is held constant) and thermal demand would go to/from hot salt storage.
Three different storage durations are relevant: 1 hour storage to provide regulation and spinning reserve, 4-12 hour storage for day/night load leveling (including plug-in vehicles and solar PV), 16-48 hour storage to compliment high penetration wind power. None are needed in a fossil fuel dominated energy system; all are needed for zero-carbon electrical systems.
There are two possible arrangements: two-salt and three-salt.
With the two-salt arrangement, the secondary coolant salt is also the TES salt. This would probably be preferred for small amounts of storage. Of the salts considered in this study nuclear.inl.gov/deliverables/docs/ornl-tm-2006-69_htl_salt.pdf (Assessment of Candidate Molten Salt Coolants for the NGNP/NHI Heat-Transfer Loop: Williams – 2006), only the chloride salts which are the major components of sea-salt are affordable in large quantities: NaCl, KCl, and MgCl2. The KCl-MgCl2 blend is the cheapest ($0.21/kg), melts at 426C, and has 0.46 cal/cc/C for volumetric heat capacity. Adding lithium salt would decrease the freezing temperature, but at a very high cost. Similarly, fluorine based salts like flinak and NaBF4-NaF (the proposed secondary coolants from PB-AHTR and DMSR respectively) have better heat capacity, but costs fifty times as much.
After the salt cost, the next most important determinant of TES cost is the salt temperature excursion (delta-T). If the reactor has an outlet temperature of 704C, for good freeze-margin, a reasonable salt temp excursion might be from 526 to 684C, so delta-T =158C. A higher delta-T would store more energy, so would be more cost effective; this option gets more competitive with higher reactor temperatures.
The three-salt arrangement allows the TES to use “solar salt” (see www.solar-reserve.com/homePage.html), a blend of NaNO3 and KNO3, which has a melting temperature of 141C and useful range of 288C to 566C, for an excellent 278C delta-T (this is also the preferred salt for the IFR, which would have about a 550C outlet temp). Solar salt also has higher heat capacity than the chloride salt (0.72 vs 0.46 cal/cc/C), so the energy storage per kg of salt is 2.75 times higher, potentially cost reducing the TES. The savings is somewhat less, since solar salt is about 50% more expensive than chloride salt, and the lower operating temperature will lead to lower power conversion efficiency; additionally, a secondary coolant to TES heat exchanger is required.
Solar Salt also gives the option to have a simple air vent on the tanks. The chloride salt would probably require an inert cover gas to reduce oxygen contamination, which could lead to corrosion problems (the secondary salt in LFTR systems always has a cover gas, at least for tritium recovery). If a cover gas system is found to be practical however, the usable temperature of solar salt may extend all the way to 650C with an oxygen cover (according to Sargent & Lundy 2003), which would greatly reduce efficiency loss caused by operating from storage.
The final concern with a nuclear-heated TES is the need for a power conversion system which can fully utilize the temperature range of the TES salt. The traditional multi-reheat Brayton cycle (e.g. www.nuc.berkeley.edu/PB-AHTR/resources.html “A Reference 2400 MW(t) Power Conversion System Point Design for Molten-Salt-Cooled Fission and Fusion Energy Systems,”) only has 50-100C of temperature drop in each turbine stage prior to re-heat, so a requirement that the turbines cool the gas by 158 or 278C will likely involve an efficiency decrease (it would lower the average temperature of heat input to the cycle). The otherwise promising super-critical CO2 cycle is not suited to efficient load-following, as the efficiency drops steeply with output power (although a plant with multiple modular turbines could approximate load following with course steps).
A rough estimate of the cost of the TES can be obtained by starting with a solar thermal evaluation: www.nrel.gov/csp/troughnet/pdfs/40166.pdf NREL/SR-550-40166 Thermal Storage Commercial Plant Design Study for a 2-tank Indirect Molten Salt System, 2006. This describes a system for a solar-trough plant, with Tcold=290C, Thot= 385C for the salt tanks, delta-T= 95C, for 35-37% gross effic at 50MWe, using Rankine steam cycle w/ reheat.
35,100 tons of salt gave 10.3 hours storage at 36.8% efficiency. Systems in the 6-12 hour range costs $30/kWht.
Scaling the cost for the higher temperature range: $30/kWht * (385-290C) / (566-288C) = $10.25/kWht
Assuming 40% efficiency, storage system costs for 12h, 24h, and 48h are: $10.25/kWht / 0.40 * 12h * (1, 2, 4) = $308, $615, and $1230/kW; plus the $281/kW to upsize the power converter (Sargent & Lundy 2003)
This is well below the cost cited for pumped hydro storage and more efficient also. The round trip energy efficiency is likely to be above 97% with the two-salt system, and around 85% with three-salts (assuming the efficiency drops from 46% to 40% when operating on stored solar salt as a result of the lower temperature).
For each kW of wind power on a grid system, only about 0.3 kW of storage is needed. Assuming 24 hour storage, this would add $271 to the cost of each kW of wind. This is about a 15% premium over the wind cost alone, and significantly reduces the fossil fuel otherwise needed to integrate the wind power.
A thermal energy storage system coupled to a high temperature reactor is therefore a promising concept, but much more detailed study is required.
Post by Nathan Wilson on May 15, 2012 13:51:38 GMT 9.5
David, the pessimistic assumption in your calculation at the start of the thread is that you have to pay for the energy going into storage.
If you want to compare the economics of storage with that of curtailment, then it is fair to assume that you are storing energy that would have been discarded, i.e. it's free. In the US, renewables are dispatched as "must take" so when supply exceeds demand, the utilities must turn-off every other generator before renewables.
Then there's a simpler way... just retrofit turbine bypass valves onto existing power plants so that steam can go directly to the condenser...
Note that 100 MW plant with thermal storage could, for example, output 130 MW during the day, and 70 MW at night. It brings in more revenue than the 100 MW w/ steam bypass.
Also, when run at 100MW, the plant with a 130MW turbine and thermal storage provides 30MW of spinning reserve. Every grid must have about spinning reserves of 15% of demand or enough reserve to cover failure of any generator or power line. A thermal plant that is shut down can take an hour to turn-on again, so at least one fossil fuel plant is always run at part load (which is less efficient) in order provide this spinning reserve.
Alternatively, thermal storage could be treated as a potential retro-fit add-on, (like post-combustion carbon capture on a coal plant), to be used only in the case of a renewable energy breakthrough.
Post by David B. Benson on May 15, 2012 15:36:46 GMT 9.5
Nathan Wilson --- Not everywhere, even in the USA, is wind must take. Bonneville Power Authority (BPA) curtails wind for which BPA is the balancing authority when the situation is over-constrained to avoid producing excess power. This seems to happen almost every spring now.
Every grid must have about spinning reserves of 15% of demand or enough reserve to cover failure of any generator or power line. A thermal plant that is shut down can take an hour to turn-on again, so at least one fossil fuel plant is always run at part load (which is less efficient) in order provide this spinning reserve.
In terms of electrical characteristics, anything coal can do, nuclear can do as well. If we make Gen III+ a 'drop-in' replacement for coal, (not actual nuclear refits, but substitutes) then we shouldn't expect it to do what coal isn't doing at the moment. Coal-fired power stations sometimes dedicate a fraction of their peak output to provide spinning reserve services to grid operators. Nuclear is perfectly capable of doing this as well if need be.
As for helping to facilitate renewables penetration, trying to make nuclear power stations carry the burden for misbehaving renewables seems unfair on the poor nuclear power station! If wind and solar want to be integrated into the grid as a substantial proportion of total generation, they must be forced to be 'good citizens' as well. If the grid needs storage to make up for their erratic output, they (the renewable generator owners) can build it themselves. Mandatory available reserve standards during unscheduled outages for all generators and the removal of illogical 'must-take' policies for wind and solar PV would seem to be appropriate policy solutions to this.
I'm all for investigating engineering methods of making NPPs more flexible. I just question the need. Thermbines seem great, but remember that anything like that (even as a retrofit) adds to the capital cost of the plant and must be repaid. Simple solutions to load following have been available for quite some time.
Hell, SMRs can do even better than 'utility-scale' (600MWe+) reactors because you would only need to reduce the power output of a lot of generators by a small amount per reactor.
Post by David B. Benson on May 16, 2012 9:00:10 GMT 9.5
LancedDendrite --- I suspect you underestimate the reserve required when wind is integrated into a grid. I know of two cases in the USA from last year where there was essentially no wind for 6 weeks or more. I agree that somehow the wind farm operators ought to pay for that reserve as well as for the balancing agent necessary for 5 minute though 24 hour variations.
Assuming no hydro and a low carbon requirement so that natgas is rarely used, one is left with NPPs which either ramp quickly or else adding thermbines to handle the most rapid ramping. This looks fairly efficient and more so than anything I know of that the wind farm operators could do by themselves. I'm looking for a technically feasible economic solution, not so much (yet) who has to pay for what portions; the latter can readily be done once the former is established.
Nathan Wilson --- I appreciate your lengthy post yesterday about molten salts but I'm unsure which temperature range to consider when adding a thermbine to a plain old LWR.
LancedDendrite... which temperature range to consider when adding a thermbine to a plain old LWR.
This document www.nrel.gov/csp/troughnet/pdfs/27925.pdf = Survey of Thermal Storage for Parabolic Trough Power Plants, from 2000 describes a few solutions in the LWR temp range: mineral oil alone (or with rock, iron, concrete, or phase change salts).
The only LWR data I have handy (from Westinghouse IRIS) shows feedwater at 224C and steam at 317C.
Mineral oil tops out at 300C, and is extremely flammable at this temp. The NREL reports said that in 1991 it was about the same cost as solar salt, but you'll need a tank 5x bigger due to the reduced volumetric heat capacity.
the NPP is claimed to have a thermal efficiency of at least 32.7% (I presume only obtainable at or near full power) and a maximum hot leg temperature of 321 degrees Celsius. Since the Rankine cycle is multistage reheat it isn't obvious what the cool leg temperature is, but in attempting to spec a thermbine I doubt it matters.
My thought for this spec is that the thermbine's turbine is separate from the main power conversion unit since it needs to be fast reacting, ramping in excess of 7%/minute. (CCGT operators who can ramp that fast still cannot keep up with perceived load changes when load is increasing in the morning and the wind is dying at the same time). Any further suggestions?
Post by Nathan Wilson on May 17, 2012 16:19:43 GMT 9.5
David, the Westinghouse document that you linked gives 227C for the feedwater temp (headed into the steam generators). I think that's the one to use as a starting point for Tcold, rather than the cold leg (headed into the reactor). Tcold for the thermal storage media has to be about 20C higher for heat to flow, so maybe 247C?
I looked back at the solar salt datasheet from Coastal Chemicals. They say that solar salt melts at 222C. NREL recommends 265C as the lowest working temp, I think based on viscosity.
The reactor outlet temp is 321C, so maybe the thermal store can have a Thot of 300C. That gives you only 35C of temperature change across your thermal media using solar salt, or 53C using oil.
So solar salt would need less volume than oil, but would cost much more than the storage system for trough type solar thermal plants. About $30/kWht * (385-290C)/(300-265C) = $81/kWht.
This narrow temp range really demands a phase change material. I don't know how you'd incorporate it into a workable system, but maybe it's possible.
A high temperature reactor is really much better for this. The salt can have a much higher temperature swing, plus the turbine is more efficient, so each unit of stored heat gives more stored electricity.