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PostPosted: Mar 03, 2013 2:43 pm 
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How does the feedwater heater do any condensation at all? Surely the input to a feedwater heater is water... fully condensed?

If the condenser has less than 100% mass flow, then there must be condensation in the turbine itself. On one hand, this seems like a great thing, since the heat of vaporization is so huge compared to just heating up steam. We'd like to convert as much of that heat of vaporization as possible into mechanical work. On the other hand, I keep reading about turbine blade erosion, presumably from water droplets. Once the system is condensing over half the steam in the turbine, it seems that the erosion problem must have been managed somehow.

What stops us from expanding the steam to below ambient temperature, condensing out even more water, and then recompressing what is left to a temp above ambient in order to condense the last bit. This lets us extract more of the heat of vaporization, so it's not a free lunch.


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PostPosted: Mar 03, 2013 5:23 pm 
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iain wrote:
How does the feedwater heater do any condensation at all? Surely the input to a feedwater heater is water... fully condensed?

If the condenser has less than 100% mass flow, then there must be condensation in the turbine itself. On one hand, this seems like a great thing, since the heat of vaporization is so huge compared to just heating up steam. We'd like to convert as much of that heat of vaporization as possible into mechanical work. On the other hand, I keep reading about turbine blade erosion, presumably from water droplets. Once the system is condensing over half the steam in the turbine, it seems that the erosion problem must have been managed somehow.


The feedwater heaters take steam bled off from the turbine, so that's mostly steam with some moisture. The heaters are basically heat exchangers that condense the steam coming from the steam turbine bleed valve and transmit the heat to the condensate on the other side. The condensate from the steam bled side is then drained to the previous feedwater heater to do some more heat exchanging along with another steam bled line. At some appropriate point (feedwater heater) it's going to just get mixed back into the feedwater with a booster pump to bring it up to the appropriate pressure. So that steam has never seen the main condenser. In stead it has condensed in the feedwater heaters, and then done more heat exchanging as hot water downstream the feedwater trains till it reaches a low enough enthalpy to just be mixed into the feedwater again.

Basically the feedwater heaters allow more of the heat of vaporisation to be used productively without too many compromising water droplets in the actual turbine itself.


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PostPosted: Mar 04, 2013 3:21 am 
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This makes sense, thanks!

A coal fired steam turbine wants to suck all the heat out of the flue gases, so the heating system has got heat coming in at all temperatures from ambient (ideally) to peak furnace temp. So I'd expect a limited role for feedwater heaters.

A nuclear steam turbine gets heat from the nuclear island across a small range of temperatures, e.g. 600 to 700 C for an MSR. That means that heat added to the turbine loop at any temperature below, in this case 600 C, is just needlessly giving up efficiency. So I'd expect a nuclear steam turbine, including those on a PWR, to do more feedwater heating. Is that right?

The Wikipedia article on steam turbines could use a lot of help.


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PostPosted: Mar 04, 2013 4:19 am 
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Actually ORNL based their steam turbine on the Bull Run coal fired supercritical unit. They only used higher feedwater temperatures than the Bull Run plant to avoid freezing, but it actually hurts the efficiency because a lot of extra booster pump power is needed beyond some point and that doesn't weigh up to the thermodynamic savings. Bull Run plant had feedwater at around 270-280 C and supercritical water outlet at 540 C, net turbine efficiency of 44.8%. ORNL's was 44.4% because of the higher feed water temperature booster pump work (either electricity or unexpanded supercritical water) needed.

If the outlet temperature is increased, the optimal feedwater temperature increases also. For a 600 C supercritical water you'd want >300 C feedwater. So a more modern supercritical unit avoids the feedwater penalty. Personally I prefer the third loop with a nitrate salt, this allows ORNL's steam turbine at 540 C which is nicer on materials than 600 C.


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PostPosted: Mar 04, 2013 1:41 pm 
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If the feedwater temperature for the boiler is 270-280 C, doesn't that mean the flue gas coming from that boiler is at least 280 C? What do they do with that energy?


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PostPosted: Mar 04, 2013 3:11 pm 
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iain wrote:
If the feedwater temperature for the boiler is 270-280 C, doesn't that mean the flue gas coming from that boiler is at least 280 C?


Yes, that should be the case. No point in heating up the flue gas with feedwater.


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What do they do with that energy?


Perhaps they use a heat recovery HX and use the condensate as heat sink? Or as a seperate feedwater heating train? I don't know, coal boilers are really not my thing.


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PostPosted: Mar 04, 2013 6:06 pm 
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iain wrote:
What do they do with that energy?
I would preheat the combustion air.

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PostPosted: Mar 04, 2013 6:31 pm 
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iain wrote:
If the feedwater temperature for the boiler is 270-280 C, doesn't that mean the flue gas coming from that boiler is at least 280 C? What do they do with that energy?

They exchange the heat from the warm flue gases leaving the economiser with incoming combustion air, preheating that. One limiting factor is that the flue gases normally contain sulphur compounds which can result in sulphurous and sulphuric acid if the dew point of the gas mixture is reached which may limit how much heat recovery is attempted.

Regarding feedwater heaters, they make a big difference to the overall cycle efficiency and exhaust steam flow. I'm looking at a model of 250 MWe subcritical STG and the inlet flow is 205 kg/s, yet the exhaust flow to the condenser is only 130 kg/s the difference has been bled off into the 7 feedwater heaters producing a final feed temp of 250C. A more modern machine would probably have 8 stages of feedwater heating and a higher final feedwater temperature than this machine.


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PostPosted: Mar 05, 2013 5:26 am 
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Lindsay wrote:
iain wrote:
If the feedwater temperature for the boiler is 270-280 C, doesn't that mean the flue gas coming from that boiler is at least 280 C? What do they do with that energy?

They exchange the heat from the warm flue gases leaving the economiser with incoming combustion air, preheating that. One limiting factor is that the flue gases normally contain sulphur compounds which can result in sulphurous and sulphuric acid if the dew point of the gas mixture is reached which may limit how much heat recovery is attempted.

Regarding feedwater heaters, they make a big difference to the overall cycle efficiency and exhaust steam flow. I'm looking at a model of 250 MWe subcritical STG and the inlet flow is 205 kg/s, yet the exhaust flow to the condenser is only 130 kg/s the difference has been bled off into the 7 feedwater heaters producing a final feed temp of 250C. A more modern machine would probably have 8 stages of feedwater heating and a higher final feedwater temperature than this machine.


Even the really old Bull Run supercritical coal plant, which ORNL used as reference turbine for all their MSR work, had a high feedwater temp of at least 270 Celsius, at 248 bar.

http://en.wikipedia.org/wiki/Bull_Run_Fossil_Plant

This thing is from 1962! Using 1960 technology. Yet the net turbine efficiency is 44.8%. With some minor tweaks (modern generator windings etc.) you could be at 45% net efficiency already, with just 540 Celsius supercritical water.

Notice the bull run plant has a winter output of under 900 MWe. Yet the MSBR gets 1000 MWe winter output. This added power is from reduced parasitic load and wastage of flue gas heat in smokestacks.

It seems really nice to benefit from decades of operation of a supercritical turbine, rather than going for some more modern higher temperature version that may wear out faster.

I'm wondering about the effect of primary reheat on main condenser work.


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PostPosted: Mar 05, 2013 6:00 pm 
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Cyril R wrote:
It seems really nice to benefit from decades of operation of a supercritical turbine, rather than going for some more modern higher temperature version that may wear out faster.

I'm wondering about the effect of primary reheat on main condenser work.
Here are some more modern plants using Siemens STG's that are rapidly accumulating operating experience, we shall soon know whether steam temperatures at 600C+ have different reliability statistics to those running at lower temperatures.

Plant Output Main Steam Reheat Steam Commercial operation date
Lünen Germany 1 x 800 MW 270 bar / 600°C 610°C 2012
Eemshafen Netherlands 2 x 800 MW 275 bar / 600°C 610°C 2012
Westphalia Germany 2 x 800 MW 275 bar / 600°C 610°C 2011
Wai Gao Qiao 3 China 2 x 1000 MW 270 bar / 600°C 600°C 2008
Yuhuan China 4 x 1000 MW 262 bar / 600°C 600°C 2007
Isogo Japan 1 x 600 MW 251 bar / 600°C 610°C 2001

My best guess is that with modern materials and manufacturing processes, improved QA, modern design tools, better water chemistry, better control/start-up strategies to limit low cycle fatigue, etc. That the modern machines will have equal reliability whether running at 600C or 540C, but we don't seem to have the data yet to make the case for one over the other. The oldest of those, the Isogo machine has been pulled apart for a major inspection after 48,000 EOH and was found to be in excellent condition throughout, but that is just one data point.

Regarding the effect of reheat. Reheat stretches the vapour part of the steam/water cycle allowing more energy to be added and extracted before the condenser, so on a kWe/kWcond basis the electrical output goes up per unit of heat rejection. If you took a fixed machine and increased the reheat temperature, and could by magic maintain the same mass flow the power would go up and the heat rejection would go up, but the power increase would be greater than the increase in heat rejection, providing that the exhaust steam remains saturated in all cases (which it should).

One of the practical reasons that I like the higher steam temperatures is that they better match the reactor temperatures and provide some additional temperature margin for managing salt freeze risk if using fluoride salts. That said, there's nothing wrong with running nitrate salts and 540C steam conditions that combination works well, you loose a little in the efficiency stakes, but nothing to loose sleep over. There may even be some up side in terms of having a more flexible/upset tolerant system overall.


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PostPosted: Mar 05, 2013 6:46 pm 
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A small sidebar for very efficient large STG's (700 MWe+) by calculation (a paper turbine). All cases single reheat. The key constraint in all cases is exhaust dryness going to the condenser, set at 0.88 dry as the minimum permitted value. 8 feedwater heaters allowed to optimise their settings for best efficiency. Cylinder isentropic efficiency is fixed.

Considering sub and supercritical steam conditions available today commercially.

175 bara 540C/540C => X% net efficiency
175 bara 600C/620C => X+1.47% net efficiency

288 bara 540C/540C => Y% net efficiency (note, 288 bara is best efficiency point for 540C steam)
300 bara 600C/620C => Y+2.23% net efficiency

For 540C steam conditions boosting the pressure from 175 bara to 288 improves net efficiency by 0.92% in the model. Boosting steam temperature from 540C to 600/620C at 175 bara improves net efficiency by 1.47% in the model. That's the sort of difference that changing pressure and changing temperature provide.


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PostPosted: Aug 01, 2017 12:04 pm 
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I hate to dig up old threads but this is an interesting concept I've come across indepedently from this discussion, in the context of Seawater cooling.

This study from the 90s suggests the use of direct contact condensers with direct wet cooling systems.
Essentially the advantage of a direct contact condenser in this case is that it is (relatively) compact and simple to build and maintain compared to a giant condenser with a huge number of vacuum penetrations and all that for all the tubes.
It produces water that is negligible subcooled and has apparently superior degassing to a conventional condenser - apparently allowing for the deaerator in the feedwater chain to be eliminated!

This produces a feedwater stream that needs to be cooled for the sprays - and how it is cooled is agnostic.
IN the case of seawater cooling this is merely a function of seawater temperature and how big a heat exchanger you are willing to provide.

PCHEs might be subject to biofouling but it is worth noting that this sytem could easily divide the exchangers into a fairly large number of banks and they could be valved in and out as required for cleaning or to keep velocity in the service units high even if only relatively little seawater must be pumped (in winter with low seawater temperatures). So large scale regular cleaning of units is not out of the question or hard to arrange.

Using the PWR at Sizewell B as an example [for reactor power and intake characteristics], if we assume less than 1C 'temperature rise' in the condenser itself, and select 1C temperature difference across the exchanger, using a PHE or PCHE we get a size of close to 400,000 square metres of contact area.
Which is an awful lot with a PHE, but if a PCHE can be made to work suitably reliable for seawater service that would end up with a volume of only ~330 cubic metres.

Supposedly going from a typical ~3" Hg condenser pressure to ~1" (~3.4kPa) improves heat rate by 6%.
~1" of pressure translates to a condenser temperature of ~26.5C

Add two celsius of temperature drop and you are at ~24.5C

Peak seawater temperature at sizewell is in vicinity of 21-22C, which means with a ~2.5-3C temperature rise you could obtain that 1" Vacuum and get that heat rate improvement.
And 2.5-3C rise would require you to approximately treble your seawater intake volume, increasing pump demand by ~10MWe.

But even a 1% improvement in heat rate gets you that ten megawatts with ease, let alone six.
And in cooler weather you can shut off heat exchangers for cleaning or to reduce pump power without increasing biofouling.
(Winter seawater temperatures are 6C or so, which gives you ~18.5C of temperature rise to play wtih, cutting pump power from its regular ~5MWe (or 15MW summer peak) to only 3MWe.

And whilst lower condenser temperatures increase feedwater heating requirements a condensing temperature of 26.5C allows you to capture the heat from the turbogenerator hydrogen coolers that would ordinarily be far too cold.

Just my two cents.


Last edited by E Ireland on Aug 01, 2017 4:29 pm, edited 1 time in total.

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PostPosted: Aug 01, 2017 3:01 pm 
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I thought I read they have a 6-7C delta T planned in? Wouldn't we have more than a 1C rise in the condenser?

The big cost area in the new nuclear plants is tunnelling about 2km out - Hinkley C has two inlet tunnels and one outlet tunnels, each 7m in diameter and totalling 11km in length. Given they're going a few km out, I'd be surprised if the temperature goes up to 21C-22C. English beaches aren't that great!


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PostPosted: Aug 01, 2017 4:26 pm 
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This is true with a surface condenser - but this is not a surface condenser.
The delta-T on the condenser itself is negligible because the steam is being condensed by a very fine mist of water droplets which have huuge surface area.

And using compact heat exchangers we can get area to cool the feedwater mist very efficiently with seawater, reducing the effective delta-T to only 1-2 celsius.

Hinkley Point C has such enormous intake structures partially because it is built on the Severn Estuary in an area with a 15 metre tidal range.
Wylfa has a more typical set of intake structures only a few hundred metres from shore.
21-22C is the peak sea temperature recorded at Sizewell B.


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PostPosted: May 01, 2018 7:11 am 
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Cyril R wrote:
...
Perhaps the cost of this vessel will be considerable, I don't know. It's temperature and fouling requirements are very low but it is a vacuum vessel which could cost some.

The cost of the vessel should also reduce since the volume needed to hold the spray condenser should be quite a bit smaller and the shape can be more optimized to withstand the pressure.

Another point is that IF the pressure is actually lower with the spray condenser, there will be slightly less heat to remove.

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