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PostPosted: Aug 10, 2014 11:31 am 
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As a resident of CA, I really like the idea of desalinating water with heat/power when electricity demand is low. Water, unlike energy, is easy to store, and water security is becoming a very big deal in our drought-stricken state. San Diego is in the process of building a 50M gal/day reverse osmosis desal plant in Carlsbad, just north of the city. Located next to the Encina power plant, its feedwater comes from the output seawater from the once-through cooling condensers. Essentially all of San Diego's water is currently imported, and its sources (Colorado River, Sacramento River, etc) are overdrawn. The desal plant will provide 10% of the region's potable water and will be drought-proof.

In the coastal village where I live, our drought-induced water restrictions include no landscape watering, no car washing and up to 500% penalties on the bills of households that use more than 50 gal/person/day (average usage in the Bay Area ranges from 98 GPD to 334 GPD). Our family is down to using about 35 GPD/person, and I am ready to pay significantly more for water at this point. Our community is building a small desal/purification plant on an emergency basis that will use a saline aquifer fed from the nearby ocean.

With climate change, droughts are projected to become more common in the Southwest. Nuclear + desal makes sense for California. If the state has excess generation during the afternoon, just make more drinking water. I see the 'duck curve' as an opportunity.


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PostPosted: Aug 10, 2014 12:49 pm 
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Cyril R wrote:
Hrm well, having a liquid that can be pumped always seems a major advantage. And i like the idea of using cheap sand to replace most of the nitrate. So my preference is for thermocline. But even two tank systems look great if the dT is high. Two tank is lowest tech risk.
Liquid is good, cheap is good. In terms of ease of application if the storage system can deliver heat at similar temperature as the original sourcethen that makes the power conversion system engineering much easier. The concept I mentioned of thermocline phase changing salt is very likely to be way too expensive.

This whole area is quite complex once you account for all the interactions, and something often overlooked, as the inefficiencies grow, so does the reactor size for any given electrical daily energy output, so the competing case of simply building two MSR's of similar capacity becomes more competitive as the inefficiencies and costs start to pile up.

Something that troubles me with the rock based thermocline is the dissolution of the rocks, leading to a need for salt cleanup or plating out of material in the heat exchangers.

Hopefully the solar guys can crack the code on this one for us, and we can pick up the technology when it is economic.


Last edited by Lindsay on Aug 11, 2014 2:29 am, edited 1 time in total.

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PostPosted: Aug 10, 2014 1:09 pm 
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NickL wrote:
As a resident of CA, I really like the idea of desalinating water with heat/power when electricity demand is low. Water, unlike energy, is easy to store, and water security is becoming a very big deal in our drought-stricken state. San Diego is in the process of building a 50M gal/day reverse osmosis desal plant in Carlsbad, just north of the city. Located next to the Encina power plant, its feedwater comes from the output seawater from the once-through cooling condensers. Essentially all of San Diego's water is currently imported, and its sources (Colorado River, Sacramento River, etc) are overdrawn. The desal plant will provide 10% of the region's potable water and will be drought-proof.

In the coastal village where I live, our drought-induced water restrictions include no landscape watering, no car washing and up to 500% penalties on the bills of households that use more than 50 gal/person/day (average usage in the Bay Area ranges from 98 GPD to 334 GPD). Our family is down to using about 35 GPD/person, and I am ready to pay significantly more for water at this point. Our community is building a small desal/purification plant on an emergency basis that will use a saline aquifer fed from the nearby ocean.

With climate change, droughts are projected to become more common in the Southwest. Nuclear + desal makes sense for California. If the state has excess generation during the afternoon, just make more drinking water. I see the 'duck curve' as an opportunity.
As I understand the technology options, desalination by reverse osmosis (RO) is the more cost effective that desalination from cogeneration so if the costs stack up, those lower priced periods could be used for that so long as the capital cost is low. If the capital cost is high, the plants need to run more hours per day to recover that capital and may be uneconomic even with that 2020 CalISO 'Duck curve'.

The colocation of seawater NPP's with desalination plants makes a lot sense and should minimise the cost of the desalination plant and process for multiple reasons.

But looking at that opportunity from another direction, by selective shutting down the RO equipment in a staged manner that could help manage that fast ramp in the evening and the peak that follows. Then return to full water production as the evening peak starts to subside. That combination might make a lot of sense.


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PostPosted: Aug 10, 2014 4:58 pm 
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Lindsay wrote:
Something that troubles me with the rock based thermocline is the dissolution of the rocks, leading to a need for salt cleanup or plating out of material in the heat exchangers.


That's no problem, if you have a high dT available, a simple two tank direct (salt only) storage option is only somewhat more expensive than the thermocline. In fact that's what I'd use for the first system.

Results with silica sand so far have been rather good though, with nil weight loss or loss of shape. I suppose even a tiny amount would be troublesome of course, with the quantities of filler involved. But it may be cheaper to replace HX tubing now and then (O&M cost) rather than paying more for salt and tanks (up front investment is harder).


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PostPosted: Aug 11, 2014 12:34 am 
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Lindsey, As I understand things the cost of the turbine and cooling system goes up considerably as the quality of the steam gets poor. An alternative to reverse osmosis is multi-effects distillation. In this design the main energy input is large volumes of 80C heat. If we have a high temperature reactor then exhausting the coolant at 80C rather than 30C would lose some electrical efficiency but may save a lot in the turbine system. The heat could then be used to generate water.

So even though such a system uses more energy to generate the water it may be lower cost overall.

This likely isn't viable using todays low temperature PWRs but the game changes with higher temperatures.


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PostPosted: Aug 11, 2014 2:27 am 
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Let's take those items one at a time.
Quote:
As I understand things the cost of the turbine and cooling system goes up considerably as the quality of the steam gets poor.
The turbines get bigger, but the material specifications are much lower, so I don't have a good feel for what that does to the turbine price. One thing that definitely happens is the cooling system becomes very large, general losses get bigger and overall the system produces less power, so per kW everything does get more expensive as a system.
Quote:
An alternative to reverse osmosis is multi-effects distillation. In this design the main energy input is large volumes of 80C heat.
As I understand it, it is better to run a low condenser pressure to make more electricity and use that to power the RO plant. Warm water passes more easily through the RO membrane, so there is a case for taking condenser discharge water and heating it further with a sub-atmospheric bleed. That said a multi-flash evaporator driven by bled steam at 80C would still be very efficient. The best combination on paper is to use a Brayton and harness the reject heat which does come for free.
Quote:
This likely isn't viable using todays low temperature PWRs but the game changes with higher temperatures.
Actually the steam conditions at the back end of a saturated steam NPP turbine aren't radically different than those of a high temperature steam turbine. What changes is the inlet pressure which is normally much higher when running higher steam temperatures.

There is a surprisingly large capacity for low pressure steam to do work if one has a low condenser pressure. An odd little story that demonstrates this: in early large ocean-going liners, the LP pistons on the reciprocating triple expansion engine were becoming so huge, that they were having trouble getting the steam in and out as well as problems with the physical size and mass of the LP pistons. The solution, to use a LP turbine which took LP exhaust steam at 0.62 bara (9 psia) pressure (sub-atmospheric) from two large triple expansion engines, the LP turbine then exhausting to a condenser at a vacuum. That LP turbine produced as much or slightly more power than the reciprocating engine that fed it. So 2 recips and one LP turbine, each unit producing approximately 1/3 of the total propulsion.
Wikipedia wrote:
The Olympic had 24 double-ended (six furnace) and 5 single-ended (three furnace) Scotch boilers. Two four-cylinder triple-expansion reciprocating engines each producing 15,000 hp for the two outboard wing propellers at 75 revolutions per minute. One low-pressure turbine producing 16,000 hp. 59,000 hp produced at maximum revolutions.[1]
The Olympic's main steam was 215 psi (14.8 bar) saturated steam.


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PostPosted: Aug 11, 2014 4:52 am 
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Let's take a better look at the two tank system.

NaNO3-KNO3 cost: $0.5/kg
NaNO3-KNO3 sensible heat capacity: 1.55 kJ/kg/K.

With a dT of 300K we store 465 kJ/kg salt/cycle. 0.13 kWh/kg. This is $3.85/kWh thermal for the salt. At 2 g/cc density, we also need about 3.85 liters of hot tank, and the same amount of cold tank. Assuming hot tank costs $0.2/l and cold tank costs $0.1/l.

So our tanks cost $1.15/kWh thermal and the salt costs $3.85/kWh thermal.

So our storage system itself only costs around $5/kWh even with the inefficient use of salt and tanks of the conservative two tank system.

At an average efficiency of 0.4, this means our electrical cost is $12.5/kWh. 300 cycles/year and 20 year operation means $0.2 cent/kWh. Adding interest should then put us into the ballpark of 1 cent/kWh.

This is quite low.

What is the cost of a high temp salt-steam generator?


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PostPosted: Aug 12, 2014 3:15 am 
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Lars has mentioned a thermal tank with an insulated barrier that rises and falls with the charge and discharge cycle, which permits hot and cold in the same tanks which sounds appealing to me.

If the same salt is also used in the secondary loop, keeping it simple you may have something. What's the upper continuous operating temperature for NaNO3-KNO3?
Quote:
What is the cost of a high temp salt-steam generator?
For MSBR (ORNL-4541) they estimated $20.36M for the STG island and $7.9M for the steam generators and reheaters, not expensive, but not cheap. In today's money I think that's something like $204/kWe for the STG island and $79/kWe for the steam generators and reheaters for a 1 GWe installation, very very rough numbers. (I used a CPI factor of 10:1)


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PostPosted: Aug 12, 2014 4:35 am 
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Lindsay wrote:
Lars has mentioned a thermal tank with an insulated barrier that rises and falls with the charge and discharge cycle, which permits hot and cold in the same tanks which sounds appealing to me.


Not worth the complexity. The cost of the cold tank is pretty insignificant. I have some experience with petroleum storage tanks with floating roofs. They are a nightmare compared to the wonderful simplicity of the fixed roof tank. Floaters are only considered against flammable mixtured in the vapor space, and they're not very good at even that (compared to inerting fixed roof systems). In a thermal app you get thermal cycling, contraction issues, high temperature sealing issues, on top of that. Heck, just the issue of a reliable, low leakage, insulated, moving seal with these large dTs, is probably insurmountable.

The two tank system doesn't cycle thermally. The cold tank is always cold, the hot tank always hot. Even during extended outages, the large thermal inertia of the salt ensures tiny cooling rates.

If you are going to use one tank, it would be a thermocline with a low cost filler. But it looks like two tanks is fine from a cost perspective. So thinking about it, I'd just use the two tank direct salt storage system.

Quote:
If the same salt is also used in the secondary loop, keeping it simple you may have something.


Would be great if we could set it up so that we get more natural circulation heat sink in a station blackout type event.

Quote:
What's the upper continuous operating temperature for NaNO3-KNO3?


There is no real hard limit, the stuff just gasses out more NOx at elevated temperatures and it gets more corrosive, more of a nuissance than a real hard limit. The conservative suggested limit for long term service is about 570C. Transients to 600-650C are no problem. Higher than that, hot oxygen has to be used as a cover gas which doesn't seem worth the hazards etc.

Quote:
Quote:
What is the cost of a high temp salt-steam generator?
For MSBR (ORNL-4541) they estimated $20.36M for the STG island and $7.9M for the steam generators and reheaters, not expensive, but not cheap. In today's money I think that's something like $204/kWe for the STG island and $79/kWe for the steam generators and reheaters for a 1 GWe installation, very very rough numbers. (I used a CPI factor of 10:1)


Thanks this is not so bad. No doubt it will be cheaper with your proprietary generations solutions system right?

Totting it all up, $12.5/kWh electrical for the storage tank and salt, for 8 hours storage this is $100/kWe. $300/kWe for the steam generator and reheaters. We're only up to $400/kWe. Still have to add some for foundations, pumps and steam cells and the power block but it doesn't sound prohibitive compared to the value of peaking power.


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PostPosted: Aug 12, 2014 2:52 pm 
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So I think that this is starting to coalesce as follows.

NaNO3-KNO3 salt at 570C top temperature, implies a related main steam temp of 550C (max). Bottom salt temperature 270C implies feedwater heating to no more than 250C. 300C range (hot to cold) within one heat exchanger is a bit challenging, but the ORNL U Tube steam generator should cope.

Hot and Cold tank for simplicity and reliability.

In terms of the details of stitching it all together, I think that you end up with a split path secondary salt loop. During base load operation at nominal output and when peaking, 100% of the hot secondary salt goes to the steam generator and reheater. During recharging periods the secondary salt splits between the steam generator and the solar salt heater. The base load steam generator and reheater combination provides steam at 600C and 620C respectively. For thermodynamic, operational and maintenance reasons I suggest running two identical high temperature STG's and mixing the steam flows to provide blended main steam and reheat steam.

The solar salt has a dedicated steam generator and reheater which produce steam at the same pressure but lower temperature than the base load assets. The two main steam streams are blended together averaging the temperature as are the two reheat steam streams. This provides the highest possible steam temperatures on average, dropping approximately 30C at maximum output, which would be quite acceptable.

There is opportunity for further optimisation, but this would be a pretty effective combination to cope with the 2020 CAlISO Duck. We did however miss some costs, I'll post on that in a minute.


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PostPosted: Aug 12, 2014 4:17 pm 
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Cyril R wrote:
Thanks this is not so bad. No doubt it will be cheaper with your proprietary generations solutions system right?

Totting it all up, $12.5/kWh electrical for the storage tank and salt, for 8 hours storage this is $100/kWe. $300/kWe for the steam generator and reheaters. We're only up to $400/kWe. Still have to add some for foundations, pumps and steam cells and the power block but it doesn't sound prohibitive compared to the value of peaking power.
We've missed a few elements, cooling tower, electrical system, additional I&C and a secondary salt to solar salt HX.

So for the total power island for the peaker including the cooling tower, electrical equipment, additional I&C, I think that we're still somewhere close to $500/kWe and overall (including thermal storage) something like $556/kWe of daily peaking capacity, which sounds quite competitive and worthy of further investigation.


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PostPosted: Aug 12, 2014 5:31 pm 
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For those of us who have already gone to a three loop system for other reasons,
all you need is a valve downstream of the SHX,
yr two tanks, a pump, and a line back to the steam generator,
and a return line from the SG to the cold tank.
The steam generator and TG would have to be speced to the peak load,
but I suspect this will be cheaper than a separate peaking TG and SG,

Having said this, the Caiso duck is not a problem we should focus on.


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PostPosted: Aug 13, 2014 12:18 am 
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http://nuclear.inl.gov/deliverables/doc ... l_salt.pdf
NaCl-MgCl2, KCl-MgCl2, KF-ZrF4,and NaF-NaBF4 could be the cost effective salts for heat storage. They could be in a storage outside the core as partly melted salts for phase change energy to add to heat storage.


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PostPosted: Aug 13, 2014 1:29 am 
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djw1 wrote:
For those of us who have already gone to a three loop system for other reasons,
all you need is a valve downstream of the SHX,
yr two tanks, a pump, and a line back to the steam generator,
and a return line from the SG to the cold tank.
The steam generator and TG would have to be speced to the peak load,
but I suspect this will be cheaper than a separate peaking TG and SG,

Having said this, the Caiso duck is not a problem we should focus on.

I agree that collectively we have bigger fish to fry, but MSR's are some way off and by the time they arrive all generators will be being asked "Can you cope with the 2020 CalISO Duck?" The gas fired CCGT OEM's are building plants to deal with that scenario right now. My concern is how ISO rules could be manipulated to be a barrier to base load NPP's in the future. In addition MSR NPP's do have the potential to provide significant thermal storage at an acceptable price which can help displace gas fired peaking plants that are relatively inefficient.


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PostPosted: Aug 13, 2014 1:47 am 
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djw1 wrote:
The steam generator and TG would have to be speced to the peak load,
but I suspect this will be cheaper than a separate peaking TG and SG.

Depending on the overall size of the installation, yes or no. I always work from a base of 1 GWe for most MSR concepts and support systems. For the STG we don't have single STG's that can deliver the peak power in this scenario of 1.86 GWe. One advantage for having two machines is the impact of a single unit trip is easier for the system to cope with and the cost of that spinning reserve is often recovered from the large single generating units on the system, which is another incentive to not be the biggest single unit on the grid.

Regarding the steam generators, ORNL used 16 for 1 GWe, I would use three, but the physical size and mass get more difficult to deal with as move you beyond 330 MWe/steam generator. Also three is a number that plays well is one unit has to be removed from service for any reason.


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