As we have seen in northern Europe in recent weeks, notably in Germany, the coldest days can also be the least windy, meaning that, somewhat inconveniently, wind generation can fall embarrassingly to nothing just when you need it most.

As more wind and other intermittent renewables are added to the system, the issue of providing back-up of one sort another to address mismatches between the supply of power from renewables and the demand for that power is clearly going to become more pressing. In particular we are likely to see a growing interest in the possibilities of energy storage, indeed it may come to be viewed as a critical issue (and was recently described as such by David Clarke of the UK’s ETI, suggesting they may support future R&D in this area).

Batteries are already being used as localised support for wind farms, a notable example being Japan Wind Development’s Futamata wind project, which is equipped with a 34 MW NaS battery systems supplied by NGK Insulators. AEP in the USA also plans for extensive use of NaS batteries on its system, while in the UK (as we reported in last month’s issue, see pp 20-21) EDF is planning to trial a SAFT lithium-ion battery (combined with an ABB SVC Light system) at its Martham substation in Norfolk, to help with wind integration in that region.

Solar power can also benefit from energy storage of course and last November saw the entry into operation of what is claimed to be the world’s biggest molten salt thermal storage system, at Spain’s 50 MW Andasol 1 parabolic trough power plant.

But proven options for large scale energy storage (100 MWe or more for several hours) remain fairly limited. Hydro pumped storage, while well established, depends on the availability of suitable sites. KEMA’s 1500 MWe (20 000 MWh) Energy Island concept – currently at the feasibility study stage – is essentially pumped storage but moved offshore.

Aside from hydro, the only other bulk storage technology currently being seriously entertained would appear to be compressed air (typically stored in underground caverns). A compressed air storage system has been operating at Huntorf in Germany (320 MWe over 3h, efficiency 42%) since 1978 and another has been running at McIntosh, Alabama, USA, since 1991, able to provide 110 MWe over 26 h, with an efficiency of 54% (thanks to the use of a recuperator). For some years there have been plans to build similar facilities elsewhere in the USA, in Iowa and in Ohio.

These “first generation” systems work by supplying their compressed air to gas turbines.More recently so-called “adiabatic” systems (with storage capacities around 200-250 MWe x 5h) have been looked at in Germany. The adiabatic system doesn’t provide compressed air to a gas turbine. Instead when the air is compressed the heat of compression is conserved in a large thermal store. In the power generation phase the stored heat is used to raise the temperature of the discharging air, which is then used to drive an air turbine.

Benefits of the adiabatic system include zero emissions and high efficiency, perhaps as much as 70%. However, an EnBW project looking at the possibility of building an adiabatic facility in Lower Saxony (making use of the large salt caverns that exist there) seems to have come to nothing. Another project in Germany, this time involving RWE, with turbomachinery expertise from GE, is currently at the feasibility study stage. But indications so far suggest that, though promising, the technology – in particular the turbomachinery and the thermal store – is very challenging and needs some serious RD&D to move forward.

As governments and for that matter the EC aspire to greater percentages of renewables on the grid they should be increasingly supportive of this and other RD&D in energy storage.