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World Bank looks to renewable integration

By Dave Elliott

‘With the right combination of new policies and investments, countries can integrate unprecedented shares of variable renewable energy into their grids without compromising adequacy, reliability or affordability’. So says the World Bank in a study of renewable integration and grid balancing options, focusing on energy storage and gas fired- back up plants, but also looking at other balancing options .

The World Bank’s  new ESMAP (Energy Sector Management Assistance Program) report ‘Bringing Variable Renewable Energy Up to Scale: Options for Grid Integration Using Natural Gas and Storage’, notes that ‘making the transition to large-scale renewable energy supply requires substantial shifts in thinking and infrastructure: grid modernization, adoption of new technologies, reworked business models for utilities, and updated policy and regulatory frameworks’. And it looks at a number of new approaches to facilitate these shifts and ensure the success of this transition. They include strengthening interconnections between areas, diversifying the contribution of different renewable sources from various locations, and building up complementary generation and demand response technologies. But the main technical focus is on the complementary role of natural gas and energy storage in electricity grids that draw on high levels of solar and wind. and

Its key conclusions are that to best manage the challenge of integrating higher levels of variable renewable energy (VRE) into electricity grids, rather than just optimising individual components of the system, ‘policy, planning and regulatory interventions should be designed to minimize overall system costs subject to meeting performance targets, rather than minimizing the costs of VRE generation alone’.

Although, in many cases, ‘the flexibility of the overall power system will need to be increased as the share of VRE reaches higher levels’, it says flexibility can be provided ‘through additional interconnections to give systems operators access to a wider pool of demand and supply options; by implementing demand response measures to provide flexibility in demand; through optimizing and adding flexibility in supply, such as can be provided by NG-fired generation technologies; and/or through incorporating energy storage to act as additional demand through charging when there is excess energy, as well as additional supply through discharging when demand exceeds generation capacity, as needed.’ It says ‘the value of flexibility in the system should be recognized through policy and regulation, and remuneration mechanisms for flexible capacity should be defined’. Although it says ‘for the most part, flexibility requirements should be technology agnostic in the absence of a strong reason to use a specific technology’, it sees a ‘close link between scale-up of VRE and natural gas-fired power generation in many countries’.

That may be true for now, but it’s a bit short sighted – most current gas-fired CCGT’s (combined cycle gas turbines) are not very fast start-up systems and the other grid balancing options need support, not least since using gas still adds emissions and reserves are finite and will become more costly. Storage too is likely to be costly, whereas demand-side management and smart grid development may actually cut costs long-term by avoiding wasteful over-production. Storage can help with that by allowing excess to be used later, but it may be cheaper to shift demand. While supergrid links offer the opportunity of earning extra income from exporting any excess. So as the report recognises, there are plenty of balancing options beyond just gas and storage. All of which means that it backs the IEA’s view that ‘high shares (above 30%) of VRE can be achieved at modest additional overall electricity cost over time by explicitly planning for the best combination of VRE integration measures’.

A similar approach to optimization has been recommended for the US. Given that a new US Department of Energy report says that the US could plausibly get 35% of its electricity from wind plants by 2050, and with PV also set to expand, there is certainly a need to think about balancing these variable sources.

To that end, a new paper in the journal Energy looks at transitions to a future electricity system based primarily on wind and solar for all regions in the contiguous US. Stanford’s Mark Jacobson and his German and Danish co-authors stress the need to look at total system costs, not just individual plant costs, since judicious combinations, even including relatively high cost options, can reduce the overall balancing cost. They present optimized pathways for the build-up of wind and solar PV power for least backup energy needs as well as for least cost, using a model based on long-term high-resolution weather-determined generation data.

What the researchers found was that, in the absence of storage, ‘the pathway which achieves the best match of generation and load, thus resulting in the least backup energy requirements, generally favors a combination of both technologies, with a wind/solar PV energy mix of about 80/20 in a fully renewable scenario. The least cost development is seen to start with 100% of the technology with the lowest average generation costs first, but with increasing renewable installations, economically unfavorable excess generation pushes it toward the minimal backup pathway’.

Put simply, it is best overall to choose a supply and balancing mix that avoids producing and then wasting surplus. They say that, otherwise, surplus generation can get significant above a 30-50% variable renewable input, whereas the entailed costs ‘can be reduced significantly by combining wind and solar power, and/or absorbing excess generation, for example with storage or transmission, or by using the electricity for other purposes’ e.g. heating and synfuel production. In the latter case there would thus be a coupling across the electricity, heating and cooling, and transport sectors. In fact they conclude: ‘a high share of the surplus energy has to be used for other goals than satisfying the electricity demand to shift the LCOE-minimal mix back to where it is seen on a pure generation-cost basis.’

The heating or transport fuel markets may offer the best economic returns, but the surplus wind and PV power could be used to make storable hydrogen gas to power back-up plants later, when wind and/or PV are low, thus avoiding any emissions from balancing variable renewables. That seems an ideal solution – it turns a problem (surplus power) into a solution (reducing emissions from balancing), though it may not be a cheap option, even given the fact that the energy source is in effect free since the excess power would be dumped or production curtailed, if no other use for it was found. But this approach, along with the other uses, would reduce some of the value lost by curtailing output when demand is low.

The ‘power to gas’ idea is being tested now in Germany, including a project using an advanced PEM cell electrolyser system developed by pioneering UK company ITM Power: They recently installed a second unit for tests by RWE. They are converting some of the hydrogen to methane using captured carbon dioxide, for injection into the gas grid and are testing its role in grid balancing. Clearly a whole new approach could be opening up:


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