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PostPosted: Sep 29, 2010 9:31 pm 
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The high temperature heat available from the PB-AHTR and LFTR makes them 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 10-50% of maximum. The difference between the reactor output (which is held constant) and thermal demand would go to 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), 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 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 using KCl-MgCl2 , 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 http://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. 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. 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.

A rough estimate of the cost of the TES can be obtained by starting with a solar thermal evaluation: 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 fol the salt tanks, delta-T= 95C, for 35-37% gross effic at 50MWe, using Rankine 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.
Attachment:
File comment: Plot of helium brayton cycle efficiency vs output power
MIT_Dostal_ThrottleEfficiency_fig11-4.PNG
MIT_Dostal_ThrottleEfficiency_fig11-4.PNG [ 144.99 KiB | Viewed 3680 times ]

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Last edited by Nathan2go on Oct 04, 2010 7:07 pm, edited 1 time in total.

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PostPosted: Sep 29, 2010 10:04 pm 
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I have speculated that if a high temperature reactor with an outlet temperature of 1000C were placed on the top of a salt dome, off peak heat could be used to melt the salt (800C) inside the salt dome just below the cap rock. This stored heat reserve could then be used for peak power production. A salt dome is usually 1000 feet high and 1 to 3 miles wide. There will be lots of salt to work with, the amount of stored heat would be large, and the cost of the salt would be low.

Does this idea have any chance of working?

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PostPosted: Sep 30, 2010 9:45 pm 
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Axil wrote:
I have speculated that if a high temperature reactor with an outlet temperature of 1000C were placed on the top of a salt dome, off peak heat could be used to melt the salt (800C) inside the salt dome just below the cap rock. This stored heat reserve could then be used for peak power production. A salt dome is usually 1000 feet high and 1 to 3 miles wide. There will be lots of salt to work with, the amount of stored heat would be large, and the cost of the salt would be low.

Does this idea have any chance of working?

Sure I suppose, but how does it compare with the solution using insulated above ground tanks?

- there is no opportunity to reduce corrosion by purifying the salt.
- there is no insulation, so the heat loss could be high. it would be interesting to see how the calculations work out though.
- location becomes a limiting factor (like wind farms).
- like with geothermal, there is a risk of induced sesmicity (and no one wants their reactor in an earthquake zone).
- due to the high temperatures, there is a risk of large changes to the underground rock formations, like changes to ground water flow and ground water contamination. I think that for nuclear waste repositories, designers assume that they can't let the ground around the waste get very hot, like geothermal type temperatures.

But I suppose it does get rid of the very large salt tanks.
200MWe*24 hours would be 111,800 tons of solar salt, 65,800 m^3, or a cube 40.3 meters high.

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PostPosted: Oct 01, 2010 3:13 pm 
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I like the KCl-MgCl2 eutectics too. 2:1 ratio makes the vapor pressure very low (KCl has low vapor pressure).

NaCl KCl MgCl2 ternary, 20:20:60 parts is lower melting, and only slightly more expensive. Disadvantage is slightly higher vapor pressure from increased MgCl2 content. But the 397 C melting point is nice. (EDIT: about 397 C melting, not 497 C :oops: )

For lower temps, NaNO3 KNO3 'solar salt' near eutectics are also attractive for two bonus reasons:

1. They trap tritium, by reduction of the nitrate to the nitrite: NaNO3 + H2 -> NaNO2 + H2O.
2. They are fully compatible with steam/water, even in full hot contact. Combined with lower operating temp, this makes them attractive for the proven steam cycles (>45% efficiency peak for <600 C steam Thot). We can buy these off the shelf. In fact there are solar thermal plants being commissioned right now that have all the required solar salt pumps and HX equipments, and salt to SG equips.


Last edited by Cyril R on Oct 02, 2010 3:21 am, edited 1 time in total.

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PostPosted: Oct 01, 2010 8:36 pm 
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Cyril R wrote:
...
this makes them attractive for the proven steam cycles (>45% efficiency peak for <600 C steam Thot). We can buy these off the shelf. In fact there are solar thermal plants being commissioned right now that have all the required solar salt pumps and HX equipments, and salt to SG equips.

Do you know how the heat rate of this type of cycle varies with output? (I haven't been able to find this.) Unlike baseload coal plants that run on cheap coal, this will be very important for this application. If the turbine is 100% oversized for load following, this means our average throttle setting will be only 50% of max.

I've seen some solar thermal sytem data that suggests that they'll run them at max power until the storage is depleted, then shutdown for the day. i.e. no plans for load following.


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PostPosted: Oct 02, 2010 3:15 am 
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Nathan2go wrote:
Cyril R wrote:
...
this makes them attractive for the proven steam cycles (>45% efficiency peak for <600 C steam Thot). We can buy these off the shelf. In fact there are solar thermal plants being commissioned right now that have all the required solar salt pumps and HX equipments, and salt to SG equips.

Do you know how the heat rate of this type of cycle varies with output? (I haven't been able to find this.) Unlike baseload coal plants that run on cheap coal, this will be very important for this application. If the turbine is 100% oversized for load following, this means our average throttle setting will be only 50% of max.

I've seen some solar thermal sytem data that suggests that they'll run them at max power until the storage is depleted, then shutdown for the day. i.e. no plans for load following.


I have papers which I believe are from Virginia Tech (no online versions unfortunately) that suggest Rankine supercritical cycles lose about 20% efficiency @ 50% load compared to max efficiency. So you might get 50% peak efficiency and 40% efficiency at 50% load. There are many factors that complicate things such as the number of reheats/steam bleed off lines/economizers. The more such fancy thingies we install, the harder it gets to load follow. Basically flexibility in load comes at 5-15% efficiency penalty, at least - even if you don't actually load follow this is the penalty you get from more flexible robust blading and vanes design. It is a bit similar to airline combustion turbines versus stationary combustion turbines for power generation (though it is even worse there since the engineers have to deal with, um, birds).

From the data I have, the closed Brayton cycles lose efficiency faster over varying power ranges. They seem to drop off almost immediately, whereas Rankines seem to first enter a plateau where it is still efficient. So @ 80% load a Rankine will still be very efficient.

Realistically we will use a number of steam turbines at each plant so that only one has to throttle at the same time when the powerplant load-follows. This reduces the total losses. From a larger, grid perspective, we'll do the same: only a few individual powerplants have to be throttled at the same time. This makes the penalty from throttling in the actual grid system very small.


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PostPosted: Oct 03, 2010 9:12 pm 
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Nathan2go wrote:
Axil wrote:
I have speculated that if a high temperature reactor with an outlet temperature of 1000C were placed on the top of a salt dome, off peak heat could be used to melt the salt (800C) inside the salt dome just below the cap rock. This stored heat reserve could then be used for peak power production. A salt dome is usually 1000 feet high and 1 to 3 miles wide. There will be lots of salt to work with, the amount of stored heat would be large, and the cost of the salt would be low.

Does this idea have any chance of working?

Sure I suppose, but how does it compare with the solution using insulated above ground tanks?

- there is no opportunity to reduce corrosion by purifying the salt.
- there is no insulation, so the heat loss could be high. it would be interesting to see how the calculations work out though.
- location becomes a limiting factor (like wind farms).
- like with geothermal, there is a risk of induced sesmicity (and no one wants their reactor in an earthquake zone).
- due to the high temperatures, there is a risk of large changes to the underground rock formations, like changes to ground water flow and ground water contamination. I think that for nuclear waste repositories, designers assume that they can't let the ground around the waste get very hot, like geothermal type temperatures.

But I suppose it does get rid of the very large salt tanks.
200MWe*24 hours would be 111,800 tons of solar salt, 65,800 m^3, or a cube 40.3 meters high.


Quote:
there is no opportunity to reduce corrosion by purifying the salt.


This corrosion issue can be addressed by applying corrosion resisting materials to the heat transfer equipment.


Quote:
there is no insulation, so the heat loss could be high. it would be interesting to see how the calculations work out though.
- location becomes a limiting factor (like wind farms).



It may be possible to form a large container of an appropriate material underground being either salt or rock; the purpose of it being to store off peak heat from a nuclear reactor.

The formation of this zone starts with circumscribing the zone of interest using underground drilling and fragmentation around the periphery of the zone as a preamble to an insulation process.

Once the cylindrical fragmentation zone is prepared, the insulation process begins. This process entails the injection of high temperature cement fortified with silica aerogel pellets into the fracture zone.

The insulating cement aggregate is pumped underground at high pressure and completely fills the spaces in an around the area of fragmentation volume on the periphery of the heat storage zone.

This border of insulation is wide enough to provide a solid and rigid retaining structure around the heat storage zone. This border insulates the heat storage zone to retard the flow of heat out of the heat storage zone even if some fractured material melts within the structure of the retaining volume.


When the heat storage zone is rock, it may not be necessary to heat the rock to a liquidus state. Rock of sufficiently high melting point may support heat storage in a solid form. Analysis of the appropriateness of the geology of each individual site must be done on a site by site basis.


A top and bottom of the heat storage zone can be formed in like manor. Also ground freezing can also be applied if required to exclude water from the fragmentation zone. Cement poured against a frozen wall, if properly designed, will set as planned, since the heat of hydration overcomes the surrounding heat loss.


Quote:
like with geothermal, there is a risk of induced sesmicity (and no one wants their reactor in an earthquake zone).[


When placed deep underground, the resulting high pressure will keep the rock solid and resistant to any geologic movement.

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PostPosted: Oct 03, 2010 10:20 pm 
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Cyril R wrote:
I have papers which I believe are from Virginia Tech (no online versions unfortunately) that suggest Rankine supercritical cycles lose about 20% efficiency @ 50% load compared to max efficiency. ...

Yes, and there is also the issue that changing the power output increases the wear and tear on the plant. And the question of how fast the output can be made to vary.
Cyril R wrote:
From the data I have, the closed Brayton cycles lose efficiency faster over varying power ranges.

As shown the graph attached to the first posting, there are several methods of throttling a Brayton cycle machine. I've seen several different sources that claimed when the output was varied by changing the helium inventory, the efficiency loss is very slight (the temperatures and pressure ratios stay the same).
Cyril R wrote:
Realistically we will use a number of steam turbines at each plant so that only one has to throttle at the same time when the powerplant load-follows.

Yes that helps with the average cost, but it does not really effect the question of whether energy storage is cost effective: if I cut output for an hour now, by how much can I increase it later, without buying a bigger reactor?

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PostPosted: Oct 03, 2010 10:26 pm 
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Axil wrote:

It may be possible to form a large container of an appropriate material underground ... This process entails the injection of high temperature cement fortified with silica aerogel pellets into the fracture zone.

Now you really need a strong justification of why you'd build this underground rather than on the surface. It sounds very expensive.
Quote:

When placed deep underground, the resulting high pressure will keep the rock solid and resistant to any geologic movement.

Right, but earthquakes can be induced by changing the temperature of a large mass of underground rock, which causes expansion or contraction, and therefore underground movement.

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PostPosted: Oct 04, 2010 5:00 am 
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Whatever the container material, metallic components will be required to extract heat for use or conversion to power. Salts generally oxidise or corrode metals.
Molten aluminium or magnesium are better heat conductors, have higher thermal capacity and are more benign to metals. Their melting points are comparable to salts being considered. As industrial metals, their cost will be less than exotic salts though higher than cheaper ones. Inside the reactor core, they absorb less neutrons than light water or sodium.
It is time to look beyond FLiBe for heat transfer or storage at low pressures. FLibe was invented to get thorium or uranium to dissolve into liquid phase just as UF6 was invented to get uranium to gas phase.


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PostPosted: Oct 04, 2010 7:05 pm 
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A nuclear power plant with low cost thermal energy storage is also the most consumer-friendly way to cleanly recharge electric cars. This is because the nuke with storage can deliver power when the consumer wants it: at dinner time.

Other systems require the consumer to charge his/her car at night, under control either of a timer or a smart grid. So if the consumer plans to use the car after dinner and needs a charge, she must then invoke some kind of manual over-ride mechanism.

This also implies a change in the way EV emissions of CO2 and other pollutants are calculated. The usual method is to base the kWh-to-emissions conversion on the average generation mix. But if the nuclear fleet size is growing faster than the demand from plug-in vehicles, and if the nuclear fleet is used for load following, then it makes more sense to declare the plug-in vehicles to be nuclear powered, and therefore emission-free. This will make the EVs even more cost-effective on a $/ton_CO2 basis.

With cheap storage on the grid (much cheaper than batteries), the smart grid can serve consumer needs, rather than requiring the consumers to server the grid.

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PostPosted: Oct 04, 2010 7:40 pm 
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jagdish wrote:
...Molten aluminium or magnesium are better heat conductors, have higher thermal capacity and are more benign to metals. ... As industrial metals, their cost will be less than exotic salts though higher than cheaper ones...

Perhaps these could be considered for short term storage, but for the multi-day storage capacities need for wind smoothing, only the cheapest materials will be viable.

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PostPosted: Oct 05, 2010 2:40 am 
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Quote:
Now you really need a strong justification of why you'd build this underground rather than on the surface. It sounds very expensive.



The cost effectiveness of the approach is proportional to the size of the heat storage required. For a small heat storage capacity, above ground storage is more cost effective.

For very large capacity, where economies of scale can be applied, the underground approach may be more cost effective.

Remember, for underground storage there is no cost for salt, tanks, fencing, guards, maintenance, roads, site preparation, or real estate.


Quote:
But I suppose it does get rid of the very large salt tanks.
200MWe*24 hours would be 111,800 tons of solar salt, 65,800 m^3, or a cube 40.3 meters high.


For a 10 GWt heat source (~5GWe), 48 hours of storage would require approximately 50 times your quote above: 5,590,000 tons of solar salt.

Quote:
Right, but earthquakes can be induced by changing the temperature of a large mass of underground rock, which causes expansion or contraction, and therefore underground movement.


Fracking, or hydraulic fracturing is going on all over the country to release shale gas. No major earthquakes have occurred.

Gas and oil drilling is now a high art. To cap a runaway well, they can target and hit a 7 inch pipe three miles underground.

They can inspect fracking deep underground with a micro camera through the bore hole.

Support grouting is done every day to dig tunnels and pits.

Rock fragmentation provides relief for underground movement caused by expansion or contraction.

In short, I think it can be done.

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PostPosted: Oct 10, 2011 2:29 pm 
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The recent design documents for small modular AHTRs suggested a thermal storage vault concept with FLiNaK coolant in it for thermal storage. This gets really expensive, considering the quantities of FLiNaK required. Sodium fluoroborate - sodium fluoride eutectic is also suggested but are still on the pricey side and has a big vapor pressure.

There is another option to store high temp heat, which is to use the secondary coolant and pass it through small coolant holes in big graphite blocks in a huge tank. Then to discharge, run the coolant in reverse and heat it up again. With thermal insulation between successive layers of graphite blocks to preserve the thermal gradient, and dense graphite's excellent thermal conductivity, it will be a quite efficient design. This is called a 'regenerator' and is commonly used in various industrial high temp energy storage applications.

This is probably the best way to go for a higher temperature storage system.

I wonder how cheap graphite blocks can be made, including fabrication and materials, if there is no nuclear or gas permeability requirement. The aluminium industry uses lots of such graphite in fluoride baths.


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