Beyond Zero Emissions

Prof. Robert B. Laughlin
Department of Physics
Stanford University, Stanford, CA 94305
(Copied 1 Dec 09)

Interview with Rainer Aringhoff

Beyond Zero talks to Rainer Aringhoff of Solar Millennium about solar power with salt storage providing 24 hour baseload power

By Melissa Crotty (Transcript)
May 14, 2009

Rainer Aringhof, Solar Millenium

Rainer Aringhoff of Solar Millennium discusses Thermal Solar technology with Matthew Wright and Scott Bilby of Radio 3CR.

Thermal Solar plants with storage can now produce steady energy 24 hours a day in summer, and the addition of salt storage to solar thermal plants actually reduces their overall cost. Larger plants, to around 250 Megawatts, are now being planned.

Rainer began working in solar energy in the 1980s. He worked in California after the first 'oil crisis' when solar plants were first established there. These are still in operation today with outputs higher than they had originally due to new technology.

Spain has become Solar Millenium’s most important market for solar technology with their Andasol plants. Andasol 1 for example, will supply up to 200,000 people with climate-friendly electricity and save about 149,000 tons of carbon dioxide per year compared with a modern coal power plant.


Scott Bilby: This morning on beyond zero we're talking with Rainer Aringhoff from Solar Millennium. Solar Millennium is a company that develops and implements solar thermal solar plants; with existing plants currently in Spain. They also have a focus on other areas around the world including the United States, China and North Africa.

Rainer is the president of the new United States subsidiary of Solar Millennium and he was previously general manager of Solar Millennium in Germany, the parent company. Today we are lucky to be talking to Rainer about the solar plants that he has helped build in Spain and that will soon be very close to providing extended electricity generation, due to the soon to be completed addition of large molten salt thermal storage tanks that will store at least 7 hours of extra heat that can be put back into the electricity grid.

Hello Rainer. Thank you for joining us this morning.

Rainer Aringhoff: Hello, good morning.

Scott: And of course its afternoon over there.

Rainer: Right.

Scott: Now, can you tell us a little about your history because from what I've been reading about you, you've been involved with the solar industry for a very long time, going way back to the SEGS (Solar Electricity Generating Systems) plants, or the original solar plants that were built in the U.S. in the 1980's.

Rainer: Right, yes, I was part of that time of the German group, of the German/British group, Pilkington that were the provider of all of the concentrating reflectors of these plants and we actually had a know-how transfer and marketing agreement with Luz (Luz International built and operated solar thermal plants in the 1980s that are still running today) at that time was a pioneer of that parabolic trough technology had developed joint projects in Brazil, Morocco and India, Israel and at that time I was already regularly flying in with my technical colleagues and could see the build out of the SEGS plant, of the S-E-G-S, as you have to be carefully pronouncing them here in California ...

[Laughter in studio]

... and so these were the solar electric generating systems (SEGS) and these systems are still operating and I think this is one of the biggest success in introducing a new technology because all that came as the response to the first oil price crisis. There was a favourable regulation here in California specifically, that triggered a lot of renewable investment and build-out and there were wind parks, these were the largest wind parks at those times in the mid 1980's and the solar plants were the biggest ever built at that time.

People were introducing demonstration plants of a Megawatt, and these were the first ones where 30 megawatts, the last one built was 80 Megawatt net capacity. That was a real sensation. And the really good story about that is they are still operating and they are operating very well and they are even, they have a higher output today than they initially had because also of further advancements in the technology.

Matthew Wright: Yes, that's fantastic.

Scott: And can you tell us how you got involved with Solar Millenium?

Rainer: Well, I worked for many years with that technical company that is now part of the Solar Millennium Group, FlagSol, as the engineer of all of the plants we are planning. And in 2000 basically Solar Millennium was founded initially as a fund for ecologically oriented investors and, but it was the first company, or at least the first investment company that concentrated just on solar thermal power plants. That was a very big bet at that time, in 2000, and so then we carefully developed projects knowing basically from the 1990's where the market in California collapsed, energy payments were reduced, so new plants were not attractive economically anymore. There was the whole privatisation and the whole freewheeling deregulation in California going on, the result was that mainly gas turbines have been built and then in 2000 in 2001 there was the energy crisis here and then suddenly they were running short of peaking capacity.

So, California was a pretty unstable energy-economic environment, at least to say that somehow they almost forgot about the little treasure they had in their back yard, in the Mojave Desert. We concentrated at that time on developing new markets, and Spain is our prime market that we invested in, where we believed in, and today actually it is the most important singular market in the world for solar thermal technology.

Matthew: Now, in Spain you have a number of plants you've just developed, the Andasol plants. The first one I believe is now operational. Now, can you explain for some of our listeners that may not understand how trough plants work, just basically what it is and then tell us what is particularly special about the Andasol plant being the first one to have salt storage.

Rainer: Yes, the background was we all started from the same technology base, which was were basically the SEGFS plants in California. In the 1990's we developed and improved the design a little bit, the structural firmness of these collectors, but you basically have a steel structure that is supporting an exact parabolic trough and this parabola is a 100 metre, or meanwhile 200 metre, long devise and in its focal line there is an absorber tube. This absorber tube is where the incoming solar radiation is concentrated and is concentrated on to this focal line of this absorber tube and there you convert the radiation into heat, in heating up a working fluid, which in that case is a synthetic oil, and that is pumped through the field, heated up in the collectors and then pumped to a central power block. There you are in a series of heating exchangers basically produce steam and that steam is running the steam turbines and the generators that produce electricity. So, that's the basic concept of a parabolic trough plant.

In the specific case in Spain we introduced a thermal storage. The main reason for doing so there was that we had an artificial hurdle which was a capacity restriction to be eligible to an attractive tariff and that was 50 megawatt net electric. That actually is not the optimal size, 150 - 250 Megawatt would be more suited and more cost effective, but legislation has simply fixed it to this level of 50 Megawatt and our response to that was that we are expanding the operation after sunset through the deployment of the thermal storage.

What we do is, we are slightly over-sizing the solar field. Normally you have a certain ratio which you are defining through your design, that you need so and so many concentrating square metres of reflecting surface in the collector, that is sufficient to produce the heat to exactly fill in the steam for that, in that case 50 Megawatt steam turbine. We have oversized the solar field and are feeding on the one hand side of delivering the energy during the day to the heat exchanger to produce the steam so that the steam turbine is running nominal capacity from the morning, say in the summer 8 o'clock in the morning to 7pm in the evening. While at the same time, because of the over-sizing of the solar field, we produce more heat and that heat is given into a tank that is filled with molten salt and we basically heat that what we term the ‘cold tank’ with that heat from the solar field and raise the temperature by about 100 degrees Celsius and when the sun sets we are discharging the hot tank and are producing steam further after sunset and by this we can operate the plant in summer almost 24 hours, 24/7.

Matthew: So, across the summer you are actually running the plant around the clock, so effectively ...

Rainer:: In summertime. It depends how you are exactly setting your design points but in summer we are actually operating 24 hours a day, yes.

Matthew: Okay, so that's a base load around the clock plant in summer!

Rainer:: Yes, right.

Matthew: That's exactly what our politicians in Australia need to hear.

Rainer: Yes, yes, now you, you have different scenarios or you have quite a flexibility in how you are operating and how you are designing your thermal storage; but probably first telling a little about the structure, I'm using metric terms, is that ok for you?

Scott: Perfect.

Matthew: That's Australia.

Rainer: Each of these tanks have a diameter of about 36 meters and a height of 14 meters and is basically a very well insulated tank that is filled with molten salt. It's a mixture of nitrite/nitrate, and it's basically if it solidified it's fertiliser. It's one of the common fertilisers in the world.

We have two of those tanks, similar size, altogether there are 31,000 tonnes of molten salt filled in. We have to keep the mixture always liquid, at that, or today with that mixture we have a lower freezing point of about 220 degrees Celsius, and we are heating it up to 390. We always try to keep the temperature that it doesn't fall below 250, 260 degrees Celsius just to have a safe margin. And we are using that storage in a way what we call is simply, it's an adder, it's a capacity adder. So, we are prolonging the operation of the plant at a given nominal capacity simply by ours, this is one concept you can use for thermal storage, which then leads to the potential effect that depending on your design and depending how much you are oversizing your solar field, you can basically run it around the year, base load.

That's probably not the most cost efficient one. There is a cost minimum in the design of these storages and related to your production costs per kilowatt hour; that is at about 12 cents, excuse me, at about 12 hours, full load hours average over the year. That system would have a cost minimum, so that the cost are even getting lower than for a system without thermal storage. So, that's the good news in that.

The other is however, utilities don't always have the same appetite for the baseload hours. Very often, and specifically here in California, we have the situation that utilities are mostly interested to cover the extreme summer afternoon peaks that are basically coming through the load of running hundred thousands or millions of air conditioners, where there is this perfect match that you are running air conditioners because of the sun, that means it's at the hours where also the production is highest for these thermal plants.

And here in California we basically design systems where we are expending probably a little bit, or sometimes we can even shift the power and don't produce in the morning, but increase the capacity of the steam turbine and flushing it all out in the afternoon and early evening, so that we have a real peaking plant; and the utilities here are paying about three times more for the peaking hour than for the regular cruising, or baseload, hour. And that is why for them it is very attractive to have a system that is dispatchable and online during the peaking hours. So there, we have smaller thermal storages and shifting power from mornings to afternoons or evenings.

Matthew: That's fantastic.

Rainer: We have all this flexibility.

Matthew: Rainer, I was wondering if an ordinary plant had a capacity factor of about 25%, so about one quarter of the year it was operating without a storage set up, would the cost of the storage actually be less than building another plant and paying for another turbine? Is storage cheaper than turbines?

Rainer: Exactly. That was exactly our calculation we made for Spain. You had a given select rate tariff, which is a feed-in tariff in that case, that was regulated by the legislation to attract the build out of this certain technology and there we have the capacity that is limited and we have a fixed tariff. So, it was attractive to produce as much as with that plant considering that you have a limited capacity.

Matthew: Just to recap. To store 7.5 Megawatt hours of power is cheaper than installing one megawatt of turbine.

Rainer: It is cheaper to increase your solar field, which is additional cost, and to add a thermal storage rather to build a new plant with a solar field and another steam turbine. That was exactly the triggering point for us, to dare, because this is a technology innovation and that step and setting up for the first time a large scale commercial thermal storage.

Scott: That's very interesting news, Rainer because in Australia here we've had some people arguing the opposite in fact. I think that you've just made it quite clear, from being as experienced as you are with real examples out in the field that, yes, you don't need all these extra turbines going cause they are just adding too much of an overhead.

Rainer: Yes.

Matthew: Now, I would just like to say we are speaking to Rainer Aringhoff from Solar Millennium. He's the president of the U.S subsidiary there. Reiner, just going back to the Andasol plants in Spain, I'm just wondering with those two salt storage tanks, is the cold salt tank always the cold salt tank and the hot always the hot, or can you switch them over?

Rainer: Well, you have a two tank system because if you discharge you basically convert your hot tank into a cold tank, because you give the heat to the heat exchanger and so it will flow back into the tank at a lower temperature. As I said the spread is between 260 degrees Celsius and 390 degrees Celsius. So the hot tank, once filled, it is hot. You are discharging that hot tank and then in giving the heat to the heat exchanger the molten salt that is cooled down is pumped back into the storage, into the cold tank, and the other morning or the other day when the sun is available you are filling it up, you are heating it up again.

Matthew: So, you alternative from on tank to another each day.

Rainer: Yes.

Matthew: That makes sense. Now thermal efficiency, is it end-to-end 95%? So, if say you are running the oil from the field and you're converting it to steam and driving the turbine versus sticking in the storage and having all those heat exchanges, how much of the delivered heat at the turbine do you get; is that the 95% figure?

Rainer: Well, I think there are different technical questions in that. And again, also forgive me, I'm by education an economist, I'm not an engineer, but I worked quite a while in that field so I know some of the background.

The point is you have your collector system and what we term the HTF, the heat transfer fluid system, and there you have your efficiencies. You basically you have radiation to average annual output of your HTF system to the heat exchanger is a little bit higher than 50%. So, you are converting 50% of the sun's rays energy content into the heat that you are giving to the conventional part, to your power block island.

Now, the storage is another feature that we added. The storage itself is extremely efficient; it's about 97%. So, we have 3% losses in operating the thermal storage there.

The other losses are with the heating up and the pumping of that fluid and certainly then in your conventional power cycle. And the overall power cycle efficiency is on the order of 39%, which is a very regular steam turbine efficiency, and the overall system efficiency is about 16 % solar radiation to net electric output of the plant.

Matthew: Okay, I think the question I was asking was, what's the difference if you were just running directly to steam or if you're running through the storage; is it like 39 versus 38 % or ...

Rainer: No, no, that efficiency, no ... if I grasp your question correctly the point will more be the storage only helps you shifting that energy that you have collected. The conversion happens on the one-hand side in the absorber tube and then in your HTF system, your heat transfer system, that is converting it into steam, so I don't know if I grasp your question. Do you mean if you would apply steam rather than the heat transfer fluid that would be more effective? Or what was your question then?

Matthew: We're kind of running out of time and we want to ask you what's happening in America? So perhaps just finishing up we'll do that.

Scott: Yes, Reiner we've only got about a minute to go unfortunately, the show is far too long (short?) but I would love to know, because you're heading up the US now, what is on the horizon there? What are you excited about say in the south west of the United States that you think you'll be able to get your teeth into?

Rainer: Well, we are, most of all we are back to the roots. We are back to where it all started. Secondly, we are back to the area that is probably one of the most interesting areas in the world for the deployment of solar thermal power plants. There are three highest potential areas; that is the south west of the U.S, that is Chile and that is Australia. Those have the highest solar resource.

Now, in California we have this specific that we have the load centre just about 80 to 100 miles south of where the highest radiation potential is. So, these are ideal conditions. We are struggling definitely with certain, lets say, certain regulatory problems that we are still facing because nobody has thought so far here until just recently about the revival, and the bold revival, of concentrating solar power. But there are a lot of projects underway and we are confident that California will again be one of the leading states in the world in deploying this technology.

Plus, not to forget, we are increasing sizes here dramatically. We are going to 250 Megawatt units which means that we are really just by this bringing cost down by about 20% compared to the plant in Spain; plus the effect that the radiation is about 20% better here than even in southern Spain.

So, that's an exciting prospective we are seeing here and with a new administration in Washington, plus the keen interest of the state of California and the governor pushing a lot, we feel this is one of the prime locations in the world to work.

Scott: That's fantastic news. It's great to hear about those efficiencies. And Rainer we'll have to leave it off there but thank you for giving us some great news on the solar thermal power plants and the salt storage and also that we have to be careful how we pronounce the expression 'SEGS plant'! [Laughs]

Rainer: [Laughs] Thank you very much.

Scott: Thank you very much.

Matthew: Thank you Rainer.

Rainer: Okay, goodbye.

Transcript by Melissa Crotty.