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Beyond Fossil Fuels: Lucien Bronicki on Geothermal Energy

The chairman and chief technology officer of Ormat Technologies weighs in on the hurdles facing his industry
clean tech, geothermal resource, Ormat, organic rankine cycle



ORMAT TECHNOLOGIES, INC.

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Editor's note: This Q&A is a part of a survey conducted by Scientific American of executives at companies engaged in developing and implementing non–fossil fuel energy technologies. Bronicki replied to the survey in a phone interview; what follows is an edited and condensed transcript of that conversation.

What technical obstacles currently most curtail the growth of geothermal energy? What are the prospects for overcoming them in the near future and the longer-term?
Geothermal can be divided in two. We have the power plants which convert the heat, in the form of steam or hot water out of the ground, and of course we have the resource itself.

Geothermal has been used for more than 100 years. Wherever you had steam coming out of the ground, you could put a steam turbine and you are in business. It is a little bit more complicated, but this is the basic idea, and the steam, after going through the turbine and the cooling tower, finds its way into the atmosphere, which means that you deplete not only the heat but also the aquifer.

So, for instance, at the Geysers, which is still the largest single geothermal field in the world, output dropped substantially in the last 40 years not because the Earth got cooler but because the aquifer was depleted.

What Ormat's contribution was to the state of the art was to extend the range of possible resources which can be used, the resources which are at lower temperatures. You still need a temperature difference, but you have extended the range by using the Organic Rankine Cycle, which is an old invention but was never really used for anything.

Also, most of our plants are air-cooled, which means that we inject everything. And therefore the sustainability of the system is extended, because you don't consume the water. Of course there are places where there is sufficient supply of cold water from rain and so on, which is called natural recharge. But in most places today water is a problem, not only for geothermal but for coal-fired plants, for nuclear plants, for any thermal regeneration.

Now, to build a power plant, our approach is to tailor-make the power plant to the resource. So it takes some engineering into do it, but I would say this is negligible. From the moment you have the permits to go on a site until you complete the plant and start it up is in the range of one year. But to explore the resource, which is done with geophysical methods similar to what is done in oil and gas, is more complex and takes longer.

We need three elements, really, to have a good resource. One is to have heat. This is relatively easy to detect. But you need two other things. You need water, which is the element that brings the heat from the depths to the surface. And you need rocks which are the edge of fractures, a fault or a permeable, so that this water can flow, so that when you drill a well the water tends to flow into the well and come out. Then, of course, you also have to reinject it back. Both need permeability or a fault. And this exploration takes time.

So, if we leave aside the site permitting, which also takes time, then exploration activities are something on the order of three years. And with the field development it may be even up to four years.

As to the technical obstacles, there is the availability of companies which deal with the geophysical approach and then the availability of drilling rigs. Until about a year ago both were very difficult to get, and we had to buy our own rigs. Short-term I would say these availabilities are not an obstacle. Nobody knows for how long, but today they are available.

Long-term, though, it is an obstacle, because most of the geologists and even the drilling personnel are older people. Young people did not come to the field. There were no programs of training, and whoever was available was grabbed by the oil industry.

So today we are working with the University of Nevada, Reno, and with M.I.T. There is a renewed interest among students in going back to geology, hydrology. But this is something that takes time. And the people have left over the years with all the sitting and waiting. So if geothermal is to grow it's important to start it now, and in the U.S. many universities are now enrolling more students in this field.

A lot of time was wasted in the U.S., because at the laboratories which are working on long-term projects and basic science, the budgets were reduced and geothermal was certainly not their priority. About three years ago the geothermal budget was cut to zero, and people left. Again, they were mostly not young people, so this was a big loss. Today there are signs that more money will go to the national laboratories and the universities.

It may be one of the problems with geothermal is that it's not so well known in spite of the fact that until about one or two years ago, geothermal was producing the same amount of kilowatt-hours as wind in the U.S., but everybody knew about wind energy. Very few people knew about geothermal energy.

As for the plants themselves, efficiencies have been improved, but we are close to the diminishing returns. Geothermal working at lower temperatures is material-intensive—we have big heat exchangers. And therefore the impact from the high material costs of the past few years impacted the cost of the power plant. But there is not much we can do from the point of view of drastically reducing it. The turbines are extremely efficient; out of what the second law of thermodynamics allows you we are getting pretty close to the limit. And therefore the big changes that will occur are improving the exploration techniques so that the time is reduced and the probability to find the right spot for drilling the well is improved.

Today I would say about one third of the wells are dry wells, low-production wells, which means that if you had better exploration accuracy, you could reduce the cost by one third. So there is a lot of gain there.

Another thing that I have to stress is that the geothermal that I have been describing is what's called hydrothermal. There was a study by M.I.T. of what is called enhanced or engineered geothermal (EGS)—this is an approach that was developed by Sandia National Laboratory. There is much more hot dry rock in the world than areas I described that have both hot rocks and also water and faults or permeability. The idea of the hot dry rock is to drill at least two wells and, again by similar techniques to oil and gas, to make fractures between the two wells so you can have a kind of heat exchanger. You pump cold water on one side, it goes through these fractures and comes up.

The estimate for the potential of hydrothermal in the U.S. is between 10,000 and 20,000 megawatts (MW), which is not negligible. It's not going to solve the problem, but it's not negligible. The potential of EGS with hot dry rock is 100,000 MW.

But there are still many challenges. Unlike conventional geothermal, you now have to find rock which you can also fracture. And you have to spend energy to pump water through it. And you have to bring the water from another area if there is no water locally. And you have to be careful not to lose water in the operation.

So these are additional energy loses for pumping, but this a big potential. It got a lot of interest, but we are unfortunately still many years away. We have a project which is partially supported by the DOE in cooperation with a number of universities and laboratories, but this is long-term. To start producing megawatt-hours this is, I would guess, 10 years away.

Are there obstacles to scaling up geothermal to serve a larger national or global customer base?
From this point of view geothermal is base load: 24 hours a day, seven days a week.

Therefore, the utilities like it very much. There is a small difference between winter and summer, as with any thermal power plant, nuclear power plants in particular, but it is base load. So when the utilities buy geothermal, they don't have to have standby power in the form of gas turbines as they do with windmills. So this is not an obstacle. The other obstacle that we don't have is that even if you have to build a power line, this power line is a dedicated power line. This power line is used 24 hours a day. If you build a power line for a wind or a solar plant, the capacity of this power line is only used during a certain number of hours. Which means that your return on investment is smaller for this power line.

Can the existing energy infrastructure handle growth in geothermal energy? Or does that, too, need further modification?
I will give you two examples where power lines were built in the U.S. for geothermal. One is in the Imperial Valley, where we and other developers participated in building a dedicated line from the valley to the network of Southern California Edison. And there is one dedicated line in Nevada which goes from one specific power plant to the network of California. So there are at least two cases that it was done.

But many geothermal resources are really close, and this is how we look for new prospects—we look at where the power line is. If the power line is too far and this means permitting and so on, for all practical purposes, we keep it for the future and we don't develop it because the permitting is a very, very important element, at least in the U.S. Just to offer an example which was given by the governor of Nevada at one of the events the geothermal industry had: to get the permits for exploratory drilling for oil takes three weeks. For geothermal, it's six months.

Why? Because people know exactly what to do and what to ask for.

Given the current economic crisis, can your industry get the necessary capital (from public or private sources) to adequately finance its growth?
Of course it does have an impact, but from the point of view of, say, the projects Ormat has on the way, we are not yet impacted. This is because of the way we have been building in the last few years: We use our own funds that we are able to raise for a construction loan. The construction loan is the loan that you need when the risk is the largest, which is building, drilling, and so on. And therefore if you want to close financing, it's very complicated. It takes a very long time. We did it in the beginning, but when we got more at ease with capital we decided as a policy to do projects where we can spend our own funds during this period and then go for financing when the plant is operating.

But this is a big problem. No question. I assure you if this situation is not going to change, it will impact not only the newcomers but established companies like ours also.

One word about Ormat because we are a special animal—we are vertically integrated. We actually started from solar energy. And we went into geothermal because solar was too expensive; we went into geothermal trying to sell equipment, but this was too small for the utilities. So we became a developer.

First we were just a niche contractor for supplying our equipment but were also installing it. And then slowly when we got richer we started to keep equity in what we built, and this enabled two things. One is that we don't have margin upon margin upon margin. We are able to compete because if you have to subcontract, everybody has to get a margin on it. Of course we do subcontract a lot, but most of the time we don't have a prime contractor. We are the prime contractor. We don't have an engineering firm. And this enabled going on much smaller projects than the 1,000-megawatt coal-fired plant to keep the margins low.

From a strategic standpoint, which is the bigger competitor for geothermal: incumbent coal, oil and gas technologies or other alternative energy technologies?
In the U.S. the main competitor is coal, which has the lowest price; you still have areas where the cost of producing electricity from coal is three cents or less [per kilowatt-hour]. But this is not for the long term—if the EPA rules limiting the emission of mercury pass, the additional scrubbers will double the price of the electricity produced. I am not even speaking, of course, about carbon sequestration—nobody knows how much that will cost. So everybody is guessing.

Longer-term the main competitor is gas, because gas is much more environmentally friendly. A combined-cycle plant is the most efficient way of using hydrocarbons. A gas-fired combined cycle plant is cheaper than a coal-fired plant. So this is a very tough competitor. But the gas prices today are of course are much lower than they were a year ago, when they were high enough in Nevada, for instance, that we were the cheapest source of electricity.

Is there a cost target that you and others in your industry are aiming to achieve in, say, five years?
I think that if we are successful in getting less than 30 percent or 35 percent dry wells and accelerating different elements, we probably will be below 10 cents, something around eight cents, for [a kilowatt-hour of] base-load electricity.

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