Combining two renewable power technologies may not be conventional, but it can make technical and financial sense. Mike Scott looks at the various kinds of hybrid and asks why two is sometimes better than one.
One of the most obvious issues for renewable energy is the intermittent nature of technologies such as wind, solar and wave. There are a number of ways to overcome this,
including the use of energy storage or combining renewable generation with fossil fuel technology ranging from diesel generators to coal-fired power stations.
But an increasing number of renewable energy projects are combining two or more types of renewable energy technology to create “hybrid” schemes. Projects have been reported all over the world with a variety of technology combinations involving wind, photovoltaics
(PV), solar thermal electricity generation (STEG), biomass, hydro and geothermal.
“As a concept, hybridisation makes a lot of sense from a technical and financial perspective,” says Marc Fevre, energy, mining and infrastructure partner at law firm Baker Mackenzie. “You can reduce a lot of the risk of relying on renewables that are not available 100% of the time and often one of the technologies will be tried and tested so you limit your technology risk.”
There will be a growing number of these projects in years to come, driven by the increasing cost of fossil fuels, says Ian Baring-Gould, wind and water technology manager at the National Renewable Energy Laboratory in Colorado. “There are not many examples at the moment, but these things will be scaled up in future.”
“Hybrid projects ensure full use of the renewable source and continuity of power generation from renewables,” adds Sauro Pasini, head of research at Enel, the Italian utility whose 5MW Archimede project in Sicily was the world’s first example of a combined-cycle gas plant integrated with a solar plant.
Some of the largest hybrid projects combine STEG with gas. This is a natural fit because both are thermal energy technologies and gas generation can be brought on line quickly to provide power when the sun is not shining, says Andrew Stiehl, a solar analyst at Bloomberg New Energy Finance. “To an extent, all solar thermal plants are hybrid because they all have some kind of back-up,” he adds, although many plants have a far greater gas-fired capacity than STEG capacity.
Examples include Areva’s 44MW plant at Kogan Creek in Australia, which is alongside a 750MW gas-fired plant and the 30MW Kuraymat project in Egypt, which is linked to a
150MW natural gas combined cycle power plant.
General Electric earlier this year moved to secure a slice of this market by taking a stake in eSolar that gives it an exclusive license to sell eSolar’s solar thermal technology, which it plans to combine with its FlexEfficient gas turbines that are designed to integrate gas and renewable generation. Combining the two technologies in a hybrid plant will increase the efficiency of the gas turbines to 70% from 61%, lowering fuel costs and emissions, GE says. The technologies are set to be used in a plant in Turkey that will also include wind-powered generation.
Enel won approval last month for a solar-geothermal plant in Nevada, which will add 24MW of solar capacity to its Stillwater geothermal plant. The combination of the two renewable generation technologies at the same site not only improves the electrical production profile, Pasini says, but also allows the two energy sources to share the same infrastructure, such as the interconnection power lines and operation facilities, thus reducing the environmental impact and cost.
But there are all kinds of other combinations as well. PV, for example, has been combined with wind in China and India, sometimes in conjunction with batteries or remote diesel generators.
“Generally, you want a baseload-type technology in combination with an intermittent source,” says Nathan Goode, head of energy, environment and sustainability at consultancy Grant Thornton but a combination of solar and wind can work well to smooth out seasonal generation differences in situations where there is a lot of sun in
summer and a lot of wind in winter, argues Baring-Gould. In monsoon regions, the two technologies complement each other well because there are higher winds during monsoon season and more sun during the rest of the year.
“We have seen a lot more interest in this area, particularly for renewables combined with diesel, because of the lowering of the cost of renewables and an increase in the cost of diesel,” he added. “The cost of conventional generation is not going to come down.”
Biomass is another option that can replace diesel and make projects entirely carbon-neutral, with one recent Brazilian project proposing a mix of solar and coconut shells. Even hydro power is in the mix with a number of established companies such as EdF and Tata looking to use floating arrays of panels sited on hydro reservoirs to generate extra energy. Similar combinations are available for wind.
One of the main applications of hybrid projects is in the area of distributed generation in remote areas, where renewables can offer a cost-effective alternative to diesel fuel that is
expensive and difficult to transport. “The economics make most sense in areas where there is no grid connection. The cost of building grids to remote areas can be substantial,” Fevre adds.
There is a lot of interest in hybrid projects in island communities across the Pacific and the Caribbean, Baring-Gould says, while there are also military applications for bases that need to be able to ensure security of supply independent of the national grid.
Improvements to micro-hydro and small-scale biomass technology will allow the creation of smaller-scale and more reliable all-renewable hybrid projects, he points out. The concept lends itself best to smaller-scale projects partly because as projects increase in size, economies of scale suggest focusing on one particular technology, Goode adds.
However, while the current focus is on remote applications, in time “this will start to happen even in cities with strong grids,” he says.
There will be a move to smart community grids, and while national grids will not go away, the current “hub and spoke” model will change, Baring-Gould suggests. “We are not going to get rid of large power stations, but we will build less of them. As power costs go up and the cost of renewables comes down, we will see more of a marriage of technologies,” he adds.
The main technological barrier to hybrid projects at the moment is the need to work out how to incorporate renewables and individual microgrids into traditional grid infrastructures, so the NREL is doing a lot of work on grid flow modeling, says Baring-Gould. The development of viable storage options will also play a huge role in allowing the spread of hybrid projects.
As a result, one opportunity to benefit from the hybridisation trend is to invest in utility-scale energy storage, says Jonathan Bryers, partner at CT Investment Partners, an investor in early-stage technologies. Currently, this means batteries, but in time using excess renewable energy at times of surplus supply to create hydrogen that can run fuel cells will be a viable option.
However, because many hybrid projects are quite niche and bespoke, they are likely to be more difficult to finance than programmes which bundle up a series of projects using different technologies, according to Goode. One way around this is schemes such as Enel’s Nevada project where the PV element is tacked on to an existing installation. “Such piggybacking is a relatively benign way of attracting funds to mixed projects,” Goode says,
“because it reduces risk.”
In the short run, “hybridisation is bound to make it more complex for investors and funders to assess,” he adds, “but I see it as sign that the renewables sector is maturing.”