4 Energy Management Technologies
Energy management technologies aim to modify the rate of electricity consumption to suit electricity production. This is a significantly different approach to the philosophy that has driven development of the grid since its early days.
This change is reflected in a statement from the National Grid:
"We currently flex generation to meet demand, we now need to also flex demand to meet generation"
This is particularly important in conjunction with intermittent renewables. This section considers some of the potential solutions to this problem:
- Electric vehicles
- Peak demand management
- Smart Meters
- Smart Grids
- Electric Heating
4.1 Electric vehicles
Electric vehicles are often cited as one of the low carbon solutions that will be required to meet our climate change targets. Electric vehicles do not emit any direct CO 2 nor do they produce NOx, SO 2 or particulates. Hence if the source of the electricity is low CO 2 they offer a number of advantages. The level of CO 2 emissions associated with electricity will fall due to closure of coal fired power stations and increasing generation from renewable sources. Hence electric vehicles will increasingly be seen as an important low carbon technology.
From the perspective of electricity generation and grid capacity, electric vehicles raise several important issues:
- Electricity demand will increase, as vehicles switch from oil to electricity. If 100% of Scottish cars were full electric vehicles, it would require an additional 5 TWh of electrical energy per annum 8.
- Daily demand shape will change. The way in which load shape changes will be determined by the types of electric vehicle technology and recharging infrastructure that are adopted. One possible outcome is that electric vehicles add to peak electricity demand. Charging of electric vehicles will take place when the drivers/passengers are at home or at work. Hence the electricity for charging will add to electricity consumption at home or at work
Three charging options are typically considered:
- Battery swap
- Home charging
- Street/Work charging
The economics of different charging options suggests off street (home) charging is the most cost effective solution, significantly cheaper than on-street and charging in public places, workplace charging or battery exchanges ( CCC 2009).
Figure 4.1.1: Recharging infrastructure and potential contribution of charging infrastructure (Source: Element Energy, 2009)
The battery swap option would be particularly suitable in the context of intermittent generation. Battery exchanges could operate in a similar way to current petrol filling stations. This has been identified by MacKay (2009) as an especially robust solution to the grid. Battery exchanges would allow the filling station to be responsible for charging, this could be done at times of high electricity generation. This approach would also allow millions of exchangeable batteries to act as a storage buffer during periods of low generation. The main drawback identified to this approach is that standards would be required for battery design and battery mounting systems. A constraint facing Scotland is that the Scottish or even UK automotive market represents a small fraction of the global market. Any standardisation of batteries by automobile manufacturers will be dependent upon wider market changes.
In summary a battery exchange network is likely to offer some advantages in energy management:
- These locations could have highly flexible chargers designed to match grid production and demand. Surplus batteries would act as energy storage during periods of low power generation.
- Strategically located charging facilities could either assist transmission/distribution grid issues or prevent wider distribution grid upgrades to deal with individual household charging.
Car use follows a relatively predictable pattern with over 90% of vehicles being parked at home between 20:00-06:00 hours. Slow charging (c.a. 3kWh) during this period largely coincides with off peak electricity use. Home charging is relatively easy to implement within existing infrastructure and hence at a lower cost. Delay timers would represent an easy option that would ensure that residential charging does not start until off peak demand has tailed off. There would be some limitations to roll out with suburban areas with garages being the easiest solution for such charging to take place.
The limited time spent at public destinations means that slow charging will be of limited use at these sites. Street charging and work charging have been estimated by Element Energy (2009) as making up a small contribution of the potential overall recharging infrastructure, see figure above. The costs of street charging are higher than home and workplace charging. A publicly available slow charge system could cost in the region of £6,000 (currently), £1,000- £2,000 should volume sales be achieved. Fast charge prices are in the region of £50,000- £100,000 dependent upon grid reinforcement costs (Element Energy, 2009).
Charging speed fast versus slow
An important area to consider is the charging speed. This could influence the ability to deal with peaks and troughs of intermittent electricity generation. Slow charging typically takes place on single phase at low kWs over many hours. Fast charging could be done in less than 15 minutes with the chargers rated above 75kW. Fast charging would require a 3 phase grid connection and could be undertaken at recharging stations similar to present day petrol stations.
Fast charging equates to significant increase in instantaneous power consumption compared to slow charging. This is represented in the table below:
Table 4.1.1 Power demand from electric vehicle charging
Instantaneous power demand of 1 vehicle
Instantaneous power demand of 5,000 vehicles
Slow (8 hours)
Fast (20 minutes)
Very fast (10 minutes)
Electric vehicles as distributed generation
In times of low energy generation electric vehicles could potentially act as a form of distributed generation, supply stored energy back to the grid. However evidence to date suggests that this would be extremely expensive. Supplying a unit of electricity from an EV would be c.a. $0.15/kWh (just in battery costs) (Element Energy 2009). In addition to this batteries suffer much greater degradation and shortening of battery life when acting as a supply back to the grid.
The market for electric vehicles is not expected to develop rapidly until beyond 2020. By 2030 it could be expected that EVs could have an influence upon energy demand in Scotland. The CCC are due to publish a fourth report in 2010 in which they will have looked at the power system implications of widespread EV role out in the 2020s ( CCC, 2009).
In an optimistic scenario there could be 1.7 million EV's and plug in hybrids in the UK by 2020 and EVs could represent 20% of new car sales shortly after 2020, see Figure 4.1.2 below for a range of scenarios ( CCC, 2009). The capital cost of electric vehicles is dependent upon a number of performance variables, small electric vehicles designed for city use are available for around £9,000 (Independent, 2009).
Nissan announced in March 2010 that it will manufacture their first all-electric vehicle the Leaf in Sunderland, UK. The Li-ion batteries are also being manufactured in Sunderland. Total production is expected to be 60,000 vehicles per annum from 2013 ( BBC News, 2010).
Figure 4.1.2: Scenarios of electric vehicle and plug-in-hybrid cars ( CCC, 2009)
By 2030 we could see electric vehicles make an impact in Scotland. Assuming the current trajectories are replicated through to 2030 the proportion of electric vehicles could represent 10-30% of new car sales by 2030.
An example of electric vehicles in Scotland is the Glasgow Electric Car Pilot. A Scottish consortium has received £1.8 million from the Technology Strategy Board. Forty electric vehicles will be produced by Allied Vehicles, Glasgow with Dundee based Axeon Ltd supplying the batteries. Scottish Power will provide a number of recharging points in the city, Strathclyde University, Glasgow City Council and Scottish Enterprise are other consortium members involved (Scottish Government 2009b).
4.2 Peak Demand Management
Peak demand management is an element of the existing electricity market in the UK. Examples of this are:
- Triad Charges. These are charges on the licensed electricity suppliers (e.g. SSE, Scottish Power) for their load using the 3 highest periods of electricity demand. These three periods are known as the Triads, they occur during Nov to Feb each year. The Triad charges are per MW of demand at these times of peak use. In South Scotland these are £9/ MW in North Scotland these are £3.38/ MW. These charges are lower than in the rest of the UK - in London the charge is £25.9/ MW. These charges incentivise electricity suppliers to reduce customer demand. Hence suppliers include incentives in their tariffs for the largest consumers to reduce demand during the Triad half hour periods.
- National Grid Reserve Services. These are market mechanisms to encourage demand reduction or extra generation to deal with unforeseen demand increases or generation unavailability. These mechanisms include:
- Demand Management - A minimum of 25 MW of demand reduction from one or more sites and able to offer this for 2 consecutive half hour periods. National Grid encourages the role of aggregators who can manage a portfolio of sites that can offer this level of demand reduction. A Scottish company, Flextricity, is developing systems and a portfolio of clients for this market (see Smart Grids section).
- Short Term Operating Reserve ( STOR) - Must be at least 3 MW and be able to reach full output with 4 hours. Suitable generators must be able to operate for at least 2hours and be available 3 time a week.
- Fast Reserve - Rapid increase in generation within 2 minutes and by at least 25 MW/minute. A minimum size of 50 MW applies
- Fast Start - Rapid start from standstill, within 5 to 7 minutes.
- Radio Control of Heating Loads. In this system the electric heating load is controlled by radio signal. This is used by Scottish Hydro (Total Heating Total Control tariff) and Scottish Power (Comfort Plus tariff). In these cases the degree of control is limited - as the radio control acts overnight - not during the day.
In a presentation given by the National Grid in December 2009 a comparison was made between the level of grid balancing services now (3.5 GW) with the likely levels needed in 2020 (8 GW).
Figure 4.1.3 Grid Balancing Services Now and 2020
This provides valuable insights:
- The largest contributions are the Short Term Operating Reserve ( STOR) generators - which provide 70% of the services needed. STOR is a contracted Balancing Service to deliver a contracted level of power when instructed by the National Grid. The key specifications for this supply are a minimum contracted capability of 3 MW, the contracted MW must be achieved no later than 240 minutes after instruction and deliverable for 2 hours.
- Pumped storage only provides 15%.
- Demand site reduction provides 13%
In turn consumers have a range of different technical means for reducing peak demand. Only consumers with a tariff that has a peak demand element or who qualify for National Grid Reserve Services will have an incentive to act to reduce peak demand.
A wide range of technologies can be used to reduce peak demand. AEA are currently undertaking a scoping study for DECC looking at measuring peak demand in non-domestic UK buildings.
Preliminary results from the survey indicate that finance is a much greater barrier to peak demand reduction, rather than load shifting simply being impractical.
Automatic building controls and intelligent motor controls (variable speed drives) represent examples of potential peak load shifting technologies. However, the study indicates that much of the focus to date has been on reducing peak energy demand through increasing energy efficiency and there is not much evidence of widespread load shifting technologies being considered. Limited incentives in the current market to match short term (hourly) demand to supply are highlighted as a possible reason for this trend.
An alternative is the use of onsite generation to reduce demand. Two main routes are described below:
Diesel Generation. These are intended for emergency generation of electricity during grid failure. A wide range of organisations have on site diesel generation sets, including:
- Hospitals - who are required to have emergency generation
- IT Providers - who offer high levels of data security
- Water Companies - who need emergency power for water pumps
EA technology have estimated total UK capacity of emergency diesel generation at 20 GW. Hence these assets offer the potential for significant grid support. Some owners of these emergency diesel generation sets are already generating to provide income from electricity sales at times of peak prices.
This can be through their supply contract or for larger generators via payments for the Short Term Operating Reserve ( STOR), described above. An example is Wessex Water. 32 of their 550 generators are linked to a controls system for automatic operation at times of high electricity prices. This is 18 MW out of a total of 100 MW of capacity.
If this emergency diesel generation is assumed to be uniformly spread across the UK, then it is possible that up to 2 GW of this could be located in Scotland.
On site Renewable Energy: Increasing the use of small scale on site renewable energy generation is one of the routes to reduce CO 2 emissions. A number of incentives are now in place to encourage more rapid deployment of these technologies. These incentives include:
- Feed in Tariffs ( FITs): Small scale electricity generation below 5 MW are eligible for FITS, Solar PV and small scale wind are amongst the technologies supported.
- The Renewable Heat Incentive will provide a tariff per unit of renewable heat generated. All renewable heat technologies will be covered such as biomass, solar thermal and heat pumps.
- Permitted Development rights
These technologies are likely to have the following impacts on demand:
Table 4.2.1 On Site Renewable Energy Technologies and Peak Demand
Impact on Peak Demand
Generation will be greatest towards mid day in the summer months. Hence solar PV will have least impact on demand and load shape in the months of greatest demand.
Generation is dependant on wind speed which is more difficult to predict in built up areas. Will have an impact at any time of day and any day of the year.
Will significantly increase electricity demand in the winter months, including times of peak demand.
Likely to have the greatest impact on demand and load shape in the months of greatest demand.
Heat pumps are considered in more detail in Section 4.5.2
Increasing levels of on site renewable energy will therefore change peak demand and load shape in the future:
Global Status- Case study: Peak demand management in Ohio, USA.
Ohio has passed legislation to reduce energy use and peak demand. The peak demand legislation must be delivered by the utility companies with a 1% peak demand reduction in 2009 and a subsequent 0.75% each year until 2018, this totals 7.75%. This is projected to save over 840 GWh in 2011 and a summer peak reduction of 170 MW. The portfolio cost over 3 years is $180 million. A number of Demand Side Management programmes have been initiated as a result including Efficient Products, Appliance Recycling, Commercial and Industrial ( C&I) Prescriptive, C&I Custom, and C&I Self-Direct programs (Summit Blue Consulting).
The main driver for energy management is the financial incentive for either reducing demand or providing local generation. As the electricity market is a GB one the main instruments offered are available to all GB market participants. In Scotland there are a number of specific features:
- Triad incentives - Scotland has the lowest incentives in the GB market.
- National Grid Reserve Services - available across the GB, but one Scottish company is actively developing this market.
- Diesel generation - there are potential opportunities across the GB market including hospitals and other sites in Scotland. There are no accurate data for Scotland - but UK data suggests up to 2 GW of capacity.
- On site renewable energy - Scotland has very significant potential - in the case of heat pumps the impact of these small renewable systems could be to increase peak demand as they will require electrical input during the heating season, this would include early winter evenings when demand normally peaks.
4.3 Smart meters
This technology allows improved monitoring of electricity consumption. DECC announced in December 2009 that smart meters would be rolled out by utility suppliers to every home in the UK by 2020. More sophisticated examples include the ability to sell on site generation back to the grid. The wider implications of smart meters to the grid are that they enable better demand forecasting and flexible tariffs measuring consumption over certain time periods.
Smart meters are an important component of a fully implemented smart grid. In the context of Scotland, smart meters with a suitable specification will provide the potential for wider demand side response than would otherwise be the case. Increased demand side response could reduce the requirement for energy storage however as we discuss elsewhere in this report, it is likely that a wide range of solutions will be required to operate together to provide a cost effective solution to managing Scotland's electricity flows.
4.4 Smart grids
Smart grids use two way digital technology to control electronic appliances. A smart grid monitors electricity flows through the network. At times of peak demand non-essential power demands such as certain household appliances or industrial processes could be switched off or be charged a premium for energy usage. Conversely at times of surplus production such processes could be enabled.
There are a number of examples of smart grids being initiated at a sub-national level worldwide. South Korea is one of the few countries to have announced plans for a fully integrated smart grid for 2030. This smart grid will include advanced metering infrastructure, electric vehicle quick charging stations and microgrid communications. The cost of this development is estimated as $6.2 billion on technology development and $18 billion into infrastructure construction.
Work is progressing on smart grids in Scotland. Smarter Grid Solutions a spin out from Strathclyde University being one such example. They have a system already tested on the Orkney Isles where a Registered Power Zone ( RPZ) was set up. New generators will be instructed to limit their output to match the export capacity. The aim was to enable a greater capacity of wind to be connected to the grid, in this case 15 MW. SSE and Scottish Enterprise have invested a combined £300,000 into this development. Computer software is used to actively manage the electricity network so that it operates more efficiently and reliably. Under these conditions there would be more capacity for distributed generation projects to connect (Compute Scotland).
Flextricity Limited is another example of a Scottish company working in the field of energy management. They have a developed a novel approach to match electricity supply to demand. This functions by operating a 'virtual power station' comprising of small generators and electricity loads on industrial and commercial sites. The demand side management system is able to reduce loads and increase generation at times of peak grid demand.
4.5 Electric heating
Electric heating of buildings and water can provide a demand side response to take up surplus electricity generation. Electric heating of buildings and of water are mature technologies but have been limited in their use in countries that do not have supplies of cheap electricity. For an electricity system with predominantly fossil fuelled generation the efficiency of the generation plant (<50%), the losses in transmission and distribution and the associated carbon emissions all make this from of heating undesirable. However as electricity grids progressively are decarbonised and competing gas prices rise electrical heating sourced from renewable, nuclear and clean fossil fuel generation will potentially become the first choice in providing space and water heating.
4.5.1 Resistance Heating
Electric space heating through underfloor heating circuits or wall mounted storage heaters and resistance immersion heaters are the commonest ways of providing electric heating at the present time. However the use of electrically powered heat pumps to extract heat from either the ambient air or ground offer a more efficient way of providing space and water heating.
Global Status: Electric Resistance Heating
As stated in the previous section, electric resistance heating is a mature technology. The remote switching of electric heating is also a well developed technology, worldwide systems use simple time switches to allow wet systems and electrical storage heaters to take in energy when demand is generally low and store it for providing heat and hot water when electricity supply is more likely to be constrained.
Scottish Context: Electric Resistance Heating
Electric heating and its teleswitching with a radio signal to provide a simple level of demand management has been practiced by Scottish and Southern Energy for a number of years. There is significant potential to widen the spread of this type of demand management with the introduction of smart meters. The order of scale can be estimated very roughly based on 2.3 million households in Scotland and assuming that each one of these has a 3kW immersion heater in its hot water storage tank. Taking these as a potential electrical load that could be switched on and assuming that the water temperature was increased by 10°C would provide a load of up to 7,000 MW for 20 minutes. Using portions of this overall resource, along with other industrial heating loads and building heating systems could provide an economic alternative to electricity storage or constraining off excess generation.
Scotia Gas Networks indicated that in 2008 25% of Scottish homes were not connected to the gas grid 9. Assuming 50% of these use electricity for heating (rather than fuel oil, LPG or coal) and that a further 10% of the gas grid connected housing stock is also electrically heated suggests that there may be around 500,000 households with electric heating. Assuming each of these has at least one 2.5 kW (input rating) storage heater these could provide a switchable load in excess of 1,000 MW.
As the smart grid is rolled out these loads potentially become accessible to the system operator and offer a demand option that will compete with energy storage. The cost of using this latent demand could be relatively low as much of the infrastructure will be in place. The economy seven type of tariff would be replaced with a more flexible structure where energy companies determined on an hour by hour and day by day when to supply the required input energy to domestic heating and hot water systems.
It remains likely however that a wide range of both demand side and supply side measures and devices will be required to provide the most flexible, reliable and lowest cost solution to the requirement to match supply and demand across the electricity network.
4.5.2 Electric Heat Pumps
Heat pumps use the same principle as the refrigerator, the pressurisation, expansion and evaporation of a suitable fluid is used to move heat from a cool to warmer location. Heat pumps also have the potential to run backwards to provide cooling in buildings in summer.
Figure 4.5.1 Schematic of Heat Pump Circuit
A key factor for heat pumps is the coefficient of performance ( COP); this factor represents their efficiency in extracting energy from the ambient environment and transferring it to the area to be heated. Early heat pumps due to bad design or poor installation had COPs of less than 2 and could in some cases use more energy than they created.
Modern air source and ground source pumps have COPs of 3 to 3.5 (meaning they provide 100 kW of output with an electrical input of 30 to 35kW) and the state of the art technology developed in Japan 10 is delivering COPs approaching 5. These pumps can be used to heat domestic water supplies to +60°C (albeit with a lower COP for this temperature) and thus offer the possibility of significant storage capacity. Standard heat pumps will only achieve a water temperature of 45-50°C max and therefore any period of storage beyond an hour or so is likely to result in water that needs further boosting to be suitable for radiator or domestic water systems. The latter is clearly undesirable from an electricity system angle in that the boosting is likely to coincide with peak demand on the system.
Heat pumps are a relatively mature technology but are presently subject to renewed interest as their benefits in providing heat using low or zero carbon electricity are realised. As described above, work in Japan has developed heat pumps that are capable of supplying higher grade heat, which in turn offer the potential for storage of heat. One limitation could be the size and weight of the water storage tank which would have to be significantly larger (5 to 10 times) than standard household water cylinder that are sized at between 100 and 200 litres.
The difficulty for heat pumps is that compared to electric vehicle charging it is more difficult to phase the electricity input to times of low system demand. The relatively low grade heat provided by present day commercial heat pumps with co-efficients of performance in the range 3 to 3.5 means that either large amounts of water need to be stored or significant electrical boost potentially needs to be provided to the heat pump system during times of high demand (e.g. early winter evening), putting additional stress on the grid rather than relieving it.
Heat pumps with COPs in the range 3.0 to 3.5 are also only applicable in houses with good insulation. In basic terms this generally means houses that have been constructed since 1990. Unless a significant retrofit upgrading of insulation is applied to older houses, comfort levels are not achieved as the heat pump cannot provide heat faster than the rate at which it is lost from the house. A second issue with both heat pumps and electric vehicles will be the requirement for significant upgrading of local distribution networks if there is wide uptake in a given location.
While the capacity of the individual line into a property will probably be sufficient to deliver the electrical load the infrastructure at street and district level is generally designed on the assumption that while individual properties might draw up to 20kW this would not be replicated across all the properties at the same time. Heat pumps and electric vehicle charging have the potential to result in much higher continuous loads.
The heat pump limitation could be at least partly addressed by using the state of the art pumps with higher COPs and introducing a greater degree of storage of hot water - the possible limitation as referred to above, is the volume and weight of such a store.
These issues will become clearer as individual new build estates are designed and built with heat pumps as the standard heating provider and provision for electric vehicle charging.
The Scottish Government Renewable Heat Strategy (Scottish Government 2009c) forecasts that air source, ground source and water source heat pumps could be significant providers of renewable heat by 2020. The greater proportion of properties off-gas grid in Scotland means that there is greater potential for the uptake of heat pumps and it is already the case that there is greater uptake in Scotland, a number of schemes having promoted their uptake in Scotland.
Mitsubishi have established a manufacturing centre for air source heat pumps at their Livingston site. Hence there is a Scottish supply chain capability.
Heat pumps benefit in carbon terms from the accelerated decarbonisation of the electricity grid - therefore under Scotland's current proposals they will have a higher percentage of renewable heat in their output than those in England and Wales.
4.6 Timescales for Development of Solutions
The following figure highlights the estimated timescales for technologies to reach commercial deployment. Many of the technologies below such as NaS and flow batteries are currently being deployed at a limited number of sites worldwide. These early installations are acting as a learning curve for the industry with a background of wider research taking place. The dates presented below are those estimated from the background literature review of when storage or energy management technologies are likely to become widely commercially available for use in Scotland.
Figure 4.6.1 : Timescale for deployment of energy storage and energy management technologies
The diagram highlights that pumped hydro and CAES are both currently available. Of the other technologies it is unlikely that NaS batteries, Flywheels or Flow Batteries will become readily available before 2015, more likely by around 2020. A further conclusion that can be drawn is that whilst over the coming years some local smart grids will be developed and electric vehicles sold these are not likely to be widespread on the market place until around 2020s. As such two of the key energy management technologies are unlikely to help solve the increasing intermittency present before 2020.