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6 Results and Discussion
The numerical results of the six technology scenarios (four individual technologies and two mixed portfolios) and the five area scenarios are presented as three spreadsheets. The placement of devices and the division of Scotland into ten areas is shown on Maps 10 and 11.
6.1 Technology Scenarios
The numerical results from the technology scenarios are shown in Spreadsheet 1 which should be referred to throughout this section. The technology scenarios are referred to as Tech 1 to Tech 6 with suffixes a through e denoting increasing capacity in each scenario.
Figure 6.1 Example of key indicator graph (from Tech 1, onshore-wind).
A figure made up of three separate graphs is used to illustrate each of the technology scenarios. The figure above is shown here as an example. The horizontal axis used in each of the three graphs is always the same and shows increasing capacity of renewable plant. In certain cases, the maximum total capacity value shown on the graphs is greater than the corresponding figure on the Spreadsheet 1 to extend the view for trend analysis.
The left hand graph shows plant capacity factor, separated into curves for winter, summer and for the year as a total. These are all based on average values from the years 2001, 2002 and 2003.
The centre graph shows both long-term local matching and energy shortfall, as defined in Section 5.2.2. Note that the figures are not arithmetically complementary. Matching is shown relative to 100% of demand while shortfall is calculated relative to a 40% target.
The graph on the right may be used to read off a value for hourly 40% demand exceedance as follows. Choose a renewable capacity value from the horizontal axis and find its intercept with the dashed horizontal 40% line. Estimate the percentage exceedance time by interpolation from the family of lines that radiate from lower left. This means for example that 6 GW of plant would produce hourly power levels that exceed 40% of demand for around 45% of the time. A horizontal line is only drawn for the 40% case, but any other value could be used for comparison.
Spreadsheet 1 Technology scenario results.
6.1.1 Tech 1: Onshore-wind
Figure 6.2 Onshore-wind, key indicators.
For the results shown in Spreadsheet 1, up to 6 GW of onshore-wind plant was placed in four stages. The best 750 MW was placed first, followed by three doublings of capacity up to a total of 6 GW and beyond. For the graphs shown in Figure 6.2, the range was extended from 75 MW up to 9 GW. The available land area and wind climate in Scotland could produce more than this total. Experience from Denmark suggests a maximum socially acceptable density of development of 150 kW/km2. Such a level of development in Scotland would be equivalent to a maximum capacity of around 11.5 GW.
The plant capacity factors of the wind-turbines averaged over the three years 2001-2003, begin at a high of 36.3% for the first 750 MW of capacity, progressively falling to 32.7% for the entire 6 GW placement, as sites of lesser merit are included (Figure 6.2a). These capacity-factors for Scotland compare very favourably with typical European and global figures for wind turbines and not surprisingly show higher figures in winter compared with summer. The small downward slope of the curves suggests that there are many more sites suitable for economic exploitation.
The corresponding long-term local matching values start at 5.8% for 750 MW of placement and progressively increase to 41.5% of overall Scottish electrical demand for the 6 GW placement. From the 'matching' curve of Figure 6.2b it can be seen that to achieve a long-term match between only the onshore-wind resource and electricity demand, nearly 6 GW of capacity would need to be installed by 2020. The demand matching figures are very similar across the whole of each year and there is an inherent matching of onshore-wind production with Scottish demand across all seasons.
It must be emphasised that this does not imply that 6 GW of onshore-wind generating plant could supply the hour-by-hour demand at all times. There will be many hours when production is less than 40% of electricity demand. From the energy shortfall curve of Figure 6.2b it can be seen that 6 GW of onshore-wind would still leave a shortfall of 12.4% of total demand (or slightly less than a third of the 40% target). The hourly demand exceedance curves of Figure 6.2c show that 6 GW of onshore-wind plant would meet or exceed the 40% target for 44.6% of the time. For the remainder of the time, balancing energy would be required from dispatchable plant to meet the 40% target.
The results suggest that less than 6 GW of onshore-wind plant could, on average, supply 40% of the electricity demand in Scotland.
6.1.2 Tech 2: Offshore-wind
Figure 6.3 Offshore-wind, key indicators.
Up to 3 GW of offshore-wind plant was placed in three stages. The best 750 MW was placed first, followed by two doublings of capacity. Based on current technologies, the maximum water depth for installation was 40 m and the machines were sited at least 5 km offshore. Most of the suitable sites were found in east and south-west coastal areas and estuaries. There are likely to be fewer offshore-wind than onshore-wind projects, but individual offshore farms will be larger in terms of total capacity.
On Spreadsheet 1, the plant capacity factors of the offshore-wind-turbines averaged over the three years 2001 through 2003, begin at 34.1% for the best 750 MW and increase to 35.8% for the complete 3 GW placement. This small increase of capacity factor is due to higher wind resource sites in the north and west becoming economically feasible despite higher foundation and grid connection costs. Because of the differences in machines that are used onshore and offshore, these figures should not be directly compared. Nevertheless they highlight the attractiveness of the offshore resource from an energy generation point of view. The difference between summer and winter plant capacity factors is more pronounced at sea than over land.
The long-term local matching values start at 5.5% for 750 MW placement and progressively increase to 23.0% of overall Scottish electrical demand for the 3 GW placement. Offshore-wind plant with 1.5 GW capacity could on average provide 11.4% of total demand which is similar to the 11.3% from the same capacity of onshore-wind plant.
Again, this capacity of offshore-wind generating plant will not be able to supply the hour-by-hour demand at all times of the year. 3 GW of plant would leave a shortfall of 18.4% of total demand (or a little less than half of the 40% target). The exceedance curves in Figure 6.3c show that 3 GW of plant would exceed the 40% level for about 17.8% of the time.
Even though shallow-water sites are not abundant in Scotland, 3 GW of offshore-wind plant could be developed. This capacity would, on average, supply 23% of the electricity demand in Scotland.
6.1.3 Tech 3: Wave
Figure 6.4 Wave, key indicators.
For the results shown in Spreadsheet 1, up to 3 GW of wave energy plant was manually placed in three stages, starting with the best 750 MW followed by two doublings of capacity. For the graphs shown in Figure 6.4, the range was extended up to 6 GW. The overall capacity is not resource limited, but the plant totals are based on conservative estimates of the amount of plant that might be installed by 2020.
Referring to the values shown in Spreadsheet 1, the plant capacity factors averaged over the three years 2001 through 2003, begin at 33.4% for the best 750 MW and fall to 31.7% for the full placement of 3 GW, as less economic sites are added. The differences between summer and winter plant capacity factors are far more pronounced than for either onshore-wind or offshore-wind, a pattern that is consistent over the three years. The figures show that wave power plants are especially suited to supply electricity during winter months but will produce well below average during summer months.
Consequently, the long-term local matching is generally a factor of two better in winter than in summer, as shown Figure 6.4b. The long-term local matching values start at 5.4% for the 750 MW placement and progressively increase to 20.4% of overall Scottish electricity demand for the 3 GW placement.
Appraisal of the hour-by-hour matching shows that 3 GW of wave energy plant would leave a shortfall of 20.4% of total demand (or half of the 40% target). Figure 6.4c shows that with such a capacity the 40% level would be exceeded for 12.1% of the time.
The characteristics of the wave energy converters were projected from existing first generation devices. The wave power levels calculated from the resource data for the years 2001 through 2003 (and thus the calculated output of the energy converters) are believed to be below the longer term averages.
The results suggest that 3 GW of wave energy plant could, on average, supply around 20% of the electricity demand in Scotland.
6.1.4 Tech 4: Tidal-current
Figure 6.5 Tidal-current, key indicators.
For the results shown in Spreadsheet 1, 750 MW of tidal-current plant was placed manually. For the graphs of Figure 6.5, the range was extended up to 1 GW. The relatively modest tidal-current energy contribution in the study reflects the difficulty in finding sites with spring velocities of at least 2 m/s in water depths around 40 m. Further, first generation device technology was used to assess this potential, with an upper limit on channel energy extraction of about 10%. Further research may show that machines could be packed more densely in some places.
The capacity factors of 750 MW plant averaged over the three years 2001 through 2003 produce a figure of 30.0%, as shown in Figure 6.5a. The capacity factors are essentially the same in summer and winter. These are very high for the best sites in the Pentland Firth, but the steep slope of the curve in Figure 6.5a indicates that the number of "prime" sites is limited Once accurate measurements have been made, the tidal-current resource at any potential site will be almost entirely predictable. It should therefore be possible to configure optimal generating plant for any particular location.
Spreadsheet 1 and Figure 6.5b show that the long-term local matching value of the 750 MW placement is 4.8% of overall Scottish electricity demand. This number is small in the national context but regionally it could make a contribution exceeding the 40% level.
The hourly production of 750 MW of tidal-current plant would leave a shortfall of 35.2% of the total demand (or about 7/8 of the 40% target). This capacity is too small to reach the 40% demand level at any time of the year.
The tidal current resources were evaluated using machines based on first-generation shallow water devices and this has identified a relatively small number of good locations. More detailed measurements and modelling are needed to improve the accuracy of the results. While the phasing of tidal power delivery varies around the coastline, the opportunity to exploit phase differences is limited by the difficulty of finding suitably energetic sites whose patterns are complementary.
The results suggest that the completely predictable output of 750 MW of tidal-current plant could, on average, supply about 5% of the electricity demand in Scotland.
6.1.5 Tech 5: Mix with 75% Onshore-wind
Figure 6.6 75-10-10-5% mixed portfolio, key indicators.
The first mixed portfolio scenario developed renewable-generating capacity with the relative contributions of each technology held constant at 75-10-10-5%, for onshore-wind, offshore-wind, wave and tidal-current respectively. For the results summarised in Spreadsheet 1, the total capacity was increased in four stages, starting with the best 750 MW followed by three doublings of capacity up to a total of 6 GW. For the results shown graphically in Figure 6.6 the total capacity was extended up to a maximum of 9 GW to illustrate trends. Note that there is a slight deviation from the given percentages in the 750 MW case to include integer numbers of 1 km2 cells for each technology (Spreadsheet 1). Because of the chosen weighting, the simulation results in Figure 6.6 resemble those for onshore-wind alone.
In Spreadsheet 1, the plant capacity factor averaged across the plant portfolio for the three years 2001 through 2003, begins at 36.4% for the best 750 MW of mixed capacity, falling to 33.5% for the 6 GW as poorer sites are included.
The corresponding long-term local matching values start at 5.9% for 750 MW placement and progressively increase to 42.7% of overall Scottish electrical demand for the 6 GW placement. From Figure 6.6b it can be seen that to achieve a long-term local match between the mixed resource and electricity demand, about 5.5 GW of mixed capacity would need to be installed by 2020.
A mixed capacity of 6 GW would leave a shortfall of 10.4% of total demand (or one quarter of the 40% target). The 40% demand level would be exceeded for 46.4% of the time. This is a slight improvement compared with onshore-wind plant of the same capacity (Spreadsheet 1).
These findings accord with the projections of the FREDS Future Generation Group Report (Scottish Executive 2005) which identified a need for a total of 6 GW of renewable capacity to achieve the 40% target.
The results suggest that around 5.5 GW of mixed technologies plant could, on average, supply 40% of the electricity demand in Scotland. Existing and planned hydro and biomass plant will reduce the amount of capacity that would need to be installed from the four technologies considered.
6.1.6 Tech 6: Variable Mix
Figure 6.7 Variable-mix portfolio, key indicators.
Compared with the previous mixed-portfolio scenario, the combined capacity of the Tech 6 portfolios were held constant at 6 GW whilst the relative proportion that is contributed by onshore-wind was varied from 0 up to 100% (0 MW, 750 MW, 1.5 GW, 3 GW and 6 GW) so as to give it increasing prominence in the mix. The balance of the renewably generated electricity from offshore-wind, wave and tidal-current was held in a fixed 2:2:1 ratio. The maximum contributions from these sources were therefore 2.4 GW, 2.4 GW and 1.2 GW respectively.
Note that the horizontal axis of Figure 6.7 is labelled as 'Onshore wind contribution'. The left side of each graph therefore corresponds to a mix of 2.4 GW offshore-wind, 2.4 GW wave and 1.2 GW tidal-current, with no contribution from onshore-wind. The right side of each graph corresponds to 6 GW of onshore-wind with no contribution from the other technologies. Compared with the previous graphs in this section, it is important to emphasise that the total installed renewable generating capacity remains constant in Figure 6.7.
The plant capacity factor in Figure 6.7a is given for comparison with previous results. The annual values are rather constant over the whole range of onshore wind capacities. To achieve higher values in summer it is useful to have a high onshore-wind capacity. The result is similar for long-term matching. The optimum may be reached with an onshore-wind contribution of about 3 GW. The shortfall curve and the exceedance hours both suggest that the hour-by-hour matching is better with a lower contribution of onshore-wind, e.g. only 1.5 GW. Figure 6.7c shows that lower levels of demand are more often exceeded with lower onshore-wind contribution while higher demand levels are more often exceeded with higher onshore-wind contribution. For example, a demand level of 10% (on the y-axis) is exceeded for about 92% of the time with no onshore-wind in the mix and for about 81% of the time with 6 GW of only onshore-wind. A demand level of 80% (on the y-axis) is exceeded for about 6% of the time with no onshore wind and for about 16% of the time with 6 GW of onshore-wind.
The results suggest that overall performance to meet demand targets could be optimised in a balanced generation mix.
6.2 Area Scenarios
Spreadsheets 2 and 3 list the results for the area scenarios. There is one scenario for each individual technology and one scenario for a renewable plant mix. Results are listed for each area which has an exploitable resource and for the resulting total capacity across Scotland. Demand is the aggregated hourly demand within the area. For comparison the table also lists average and peak demand in the area. As explained in Section 4, the demand time series were derived from the Scottish and Southern Energy ( SSE) and the Scottish Power ( SP) area demands and not from individual grid supply points within each area. Results are rounded to whole numbers since the area scenarios are based on further assumptions compared to the technology scenarios. Otherwise the spreadsheets are organised exactly as the one for technology scenarios above.
In the technology scenarios, plant placement was determined by cost ranking across Scotland, so that the most attractive sites were always developed first. As a result, each of the four technologies was unevenly spread across the ten areas of the study. The five area scenarios provide an opportunity to compare the performance of each of the four technologies geographically by forcing machines to be assigned to areas regardless of how their economic performance in that area compares with the national averages.
The nominal capacities of plant that were placed in each area should not be taken as an indication of the regional potentials or indicative of limits.
6.2.1 Area 1: Onshore-wind
The most economic 300 MW of plant was identified separately in each area. To allow plants to connect to a grid supply point in the area, one future GSP was assumed on Shetland and one on Orkney. On the Western Isles there already exists a single high-voltage transmission line from Harris to Stornoway, but connection to the mainland is at lower voltage.
The overall plant capacity factor for Scotland is 35% which compares to 33.9% in the 3 GW technology scenario. The increase stems from the inclusion of more energetic sites on the islands, Shetland notably with 44%. In all areas with good exposure to western winds the capacity factor is in the upper thirties. The eastern areas exhibit the lowest figures although these are still high compared to central Europe. The long-term matching depends on the demand in the area. Highlands South ( SSE area) and South ( SP area) have similar demand levels. The peak demand is ten to fifteen percent higher than the installed wind capacity and the long-term matching is 50% and 41%, respectively. In the Central area the 300 MW of wind capacity contributes relatively little to satisfy the high demand for electricity. In contrast, the low demand on the islands would make strong network connections to the mainland essential. This is also indicated by the high energy export figures in Spreadsheet 2.
6.2.2 Area 2: Offshore-wind
150 MW of offshore-wind plant was placed into each of the ten areas although this is unlikely to happen in the Shetland area where the water is generally too deep 5 km offshore around the islands. Around Orkney offshore-wind power plants would not be the first choice either but there are shallow regions that could be developed. All other areas have at least one region where developments could take place.
Plant capacity factors range from 33% for less exposed sites to 48% on Shetland. As for onshore-wind the amount of matching depends on the local demand. Again, the wind resource around the islands calls for a strong interconnection to the mainland. Without these, less exposed sites in the east and south with proximity to the electricity grid are financially more attractive.
Spreadsheet 2 Area scenarios 1 - 2.
Spreadsheet 3 Area scenarios 3 - 5.
6.2.3 Area 3: Wave
Even though each of the ten areas has some coastline, the wave resource is not equally distributed. At present, the resource off the western coastline is seen as the most worthy for exploitation. Therefore wave energy converters were only placed in the four areas with broad exposure to the North Atlantic wave climate.
The overall plant capacity factor is slightly lower than in the technology scenarios because machines off Orkney and Argyll and Bute deliver less electricity. The Western Isles, with the best wave climate in Scotland, and Shetland achieve factors exceeding 30%. The chosen capacities are much higher than needed for local demand and projects will only be developed when the transmission of the electricity to load centres is resolved.
6.2.4 Area 4: Tidal-current
Good sites for tidal current exploitation exist in the north and to some extent in the south of Scotland. Further sites with small capacities like 5 MW exist in other regions such as Skye, but these were not considered in the study. There are five areas where 75 MW of capacity each was placed. The Pentland Firth, known for its energetic currents, exhibits the highest plant capacity factors and this pushes the figures for Orkney (46%) and Highlands North (40%) up. In comparison, Shetland's 25% plant capacity factor is lower. Furthermore, 75 MW of capacity may actually overexploit the resource. Whether the figure of 29% in Argyll and Bute can be realised depends on the resource west of Islay being confirmed by measurements. The South reaches only 22% but is closer to load centres than other sites. The matching figures show that tidal current power can make an important contribution to the local electricity supply.
6.2.5 Area 5: Mixed Portfolio
As with the technology scenarios, a 6 GW mix with 75% onshore wind, 10% offshore wind, 10% wave and 5% tidal current plant was developed. Since not all four resources can be found in each area, the regional split differs from the above percentages. Compared to the corresponding technology scenario Tech 5d the total plant capacity factor changes from 33.5 to 35% and the long-term local matching from 42.7% to 44%. The time when the 40% target is exceeded changes from 46.4% to 50%. This shows that inclusion of the island areas, i.e. a more geographically dispersed generation mix, could improve the matching between generation and demand for electricity. Strong electrical interconnection between areas would be necessary to make full use of this feature of renewable energy.
6.3 Power System Implications
Excess and shortfall of generation With large capacities of renewable energy generation installed there sometimes will be a need to export electricity over interconnectors to England and Northern Ireland or to curtail production. There will be many times when the variable renewable production can only satisfy a fraction of electricity demand. The remainder must then be balanced by dispatchable plant and/or imports from other areas. Figure 6.8 shows exceedance curves for production excess and shortfall for two renewable scenarios. The dashed lines are for a 6 GW onshore-wind scenario ( Tech 1 scenario) while the solid lines are for an onshore wind dominated renewable mix of the same capacity ( Tech 5 scenario). The upper two lines are for a comparison to actual (100%) demand while the lower ones are for a comparison to 40% of demand. The lower half of the diagram describes production excess, the upper half production shortfall. The vertical scale is in power units ( GW) and also in percentages of peak demand, with 100% corresponding to about 7.3 GW in 2020.
Figure 6.8 Production excess and shortfall for two scenarios.
(a) 6 GW onshore-wind only (dashed lines, Tech 1);
(b) Mixed 6 GW portfolio (solid lines, Tech 5).
Exceedance curves like the one above answer questions such as: "How many hours of the year does the shortfall (or excess) in production exceed a certain amount?" The interesting points in Figure 6.8, however, are at the extremes. The times when demand is close to peak demand and renewable generation is very low can be found in area 'A'. The scaling of the graph does not allow values in this region to be easily read, therefore the following values are taken from the numerical calculations. For 0.1% of the time (less than 9 hours in a year) the shortfall will exceed 92% (onshore-wind) or 89% (mix) of peak demand. The shortfall levels that will not be exceeded at any hour of the year are 98% for onshore-wind and 96% for the mix. Hence a mixed renewable portfolio is likely to produce more electricity at hours of high demand.
Area 'B' indicates where the curves relative to 100% of demand cross the zero line. 5% of the time onshore-wind production would actually be greater than total demand and export would be necessary. In case of the mix this time reduces to 3% of the year. Apparently there is a trade-off between the performance at both ends of the curves. From the supply point of view area 'A' is more crucial and therefore the mix performs better than the onshore-wind scenario.
Comparing production figures to 40% of the demand leads to the lower two curves. In area 'C' they cross the zero line. The time when production is greater than the 40% demand target is 44.6% for onshore wind and 46.4% for the renewable mix. The figures, which can also be found in Spreadsheet 1, suggest that the overall long-term average output of a mix of technologies is more stable than that of onshore-wind alone.
Coincident hours Area 'A' in Figure 6.8 is also described by a corner of the coincident-hours diagram discussed in Section 5.2.2. The number of hours per year when demand is higher than 90% of peak demand and generation is lower than 10% of nameplate rating is given in the 'Coincident hours' column of Spreadsheet 1 for each scenario. Comparing these worst-case values for the technology scenarios with 750 MW total capacity shows 30 hours per year for onshore-wind, 20 hours for offshore-wind, 21 hours for wave, 22 hours for tidal-current and 17 hours for the 75-10-10-5% mix. This indicates that in terms of coincident hours the mix performs better than any of the single technology scenarios.
Evaluating these coincident hours for technology scenario Tech 6 reveals that the lowest number of hours is achieved in mixes with low onshore-wind contributions. The number of worst-case coincident hours is below 9 for onshore-wind contributions up to 1.5 GW. In contrast, for a pure 6 GW onshore-wind scenario there would be 29 worst-case coincident hours per year.
As an example Figure 6.9 shows the coincident hour tables for both a 6 GW onshore-wind scenario and for a 6 GW mix. Notably the figures in the top row reduce with diversified technologies. This means it becomes more likely that at least a minimum amount of electricity is generated by the renewable generators. Given the possible dominance of onshore-wind in the renewable mix of 2020, inclusion of the other technologies reduces the risk that none of them can deliver any electricity at times of high demand.
Figure 6.9 Coincident hours of renewable generation and electricity demand.
(a) 6 GW of onshore-wind; (b) 6 GW of renewable mix with 75% onshore-wind, 10% offshore-wind, 10% wave and 5% tidal-current contribution.
Power output variability The frequency of power output changes is illustrated in Figure 6.10 for three proportions of onshore-wind in the Tech 6 scenario with 6 GW total capacity. There are traces for onshore-wind alone, for a mix with 75% onshore-wind contribution, and for a mix with no onshore-wind contribution at all.
Figure 6.10 Power variation for three scenarios with 6 GW.
(a) One hour time lag; (b) Six hour time lag.
Figure 6.10a is for a time difference of one hour. Since the original offshore-wind and wave data was interpolated from three-hourly records, conclusions must be drawn with caution. The most likely change in power output is generally zero. This could be either because the generators produce no or rated power, both at the beginning and the end of the hour, or the power output did not change. This happens for 10% of the time. Small changes in power level, both to lower and higher output, are common, large changes happen much less frequently. +10% or -10% changes are observed for around 1% of the time. This figure applies for the whole of Scotland, regionally such changes will happen much more frequently.
Figure 6.10b shows that, on average, the change of power output is greater after six hours than after one. This is to be expected. Tidal-current devices, however, may show a big change in output power after one hour and, compared to the original value, only a small change after six hours. With the smaller contribution of tidal-current to the renewable mix this influence does not impact on the graph very much. Where offshore-wind and wave devices dominate the mix, the power output changes more gradually, i.e., compared to onshore-wind, small changes occur frequently and large changes occur less frequently, potentially leaving system operators more time to dispatch balancing plant.
Power system options Diversification of energy sources and their geographical dispersion increases the hour-by-hour matching with demand. Nevertheless there will still be many hours in a year when renewable output from wind, waves and tidal currents falls below the average and some form of dispatchable plant will be needed. Examples of available options in Scotland include the following.
- Hydro-electric plant: There is about 1.3 GW of installed hydro-electric plant in Scotland with a possible extension to 1.5 GW by 2020. The actual schedule of the plant not only depends on the availability of water but also on requirements like minimum and maximum discharge and the maximum change of flow rate. Hydro-electric plant essentially provides base electricity and therefore improves hour-by-hour matching and reduces the worst-case coincident hours. Scottish and Southern Energy provided monthly production figures for about 1 GW of the existing plant covering the years 2001 through 2003 which served to estimate the impact of hydro on the scenarios. Previous scenarios were repeated including an anticipated capacity of 1.5 GW of hydro plant operating as at present. This suggested that the 40% target could be reached with an additional capacity of about 4.4 GW of onshore wind or 4.3 GW of the 75-10-10-5% renewable mix. Worst-case coincident hours naturally reduce, but more detailed data on hydro plant output would be needed to obtain robust results.
- Energy storage: There are, at present, two pumped-storage plants in Scotland. Cruachan, operated by Scottish Power, has a capacity of 400 MW and Foyers, operated by Scottish and Southern Energy, has a capacity of 300 MW. Pumped storage can be used on a daily cycle for 'peak shaving' and 'trough filling', for system balance against small changes in demand and as standby. In the future existing or additional plant could be used to smooth the output of variable renewable sources.
- Balancing plant: Nuclear and coal power plant normally provide base electricity. However, fast-starting gas turbines offer the possibility to respond quickly and operate mainly during times of peak demand. With increasing variable generation such plant could provide necessary balancing. In the future, some biomass plant may also be able to operate in this mode.
- Interconnectors: Scotland currently has interconnections with England (2.2 GW) and Northern Ireland (500 MW). The limit for imports from England is actually lower than 2.2 GW due to voltage profile and stability issues ( SP 2004). Future upgrades may further increase this capacity.
To enable any or all of the above, a fully reinforced electricity network will be required to transport energy from remote generators to load centres and to make balancing power available when and where needed.
6.4 Comments and Summary
In drawing conclusions from the study, particularly those inviting comparisons between technologies, there is a danger of comparing like with unlike. The study was strongly focussed on four variable, non-dispatchable renewable-energy generating technologies. Each of these technologies is at a different stage of development. Onshore-wind is relatively mature. Offshore-wind is new but largely based on the same technology as onshore-wind. Prototypes of deep-water wave energy devices have now been successfully deployed. Tidal-current energy on a large scale is a relatively new concept, but a prototype machine has operated for more than two years. Consequently the costs of producing electricity (or the lifetime production costs) are different for the four technologies. With the rich onshore-wind resource across Scotland, electricity from these projects is, at present, cheaper than for any project with the other three technologies. However, this situation could change with advances in technology and, for instance, with new sites for large-scale onshore-wind development becoming increasingly difficult to secure.
The nature of the resource information that was used for each technology in the study is also quite variable. The onshore-wind resource is based on measurements made at 24 stations over ten years. This was interpolated down to the scale of the 1 km2 cells by using proven techniques. The data for offshore-wind is largely based on Met Office hindcast data which was again interpolated to the 1 km2 cell level. The WAsP simulation in Scotland's rugged terrain, the necessary scaling of wind data to smooth discontinuities between areas and the use of a GIS for automatic site selection all introduce uncertainties. The overall validity of the results however is not affected. The wave data is entirely based on Met Office hindcast data, but was interpolated down to the 1 km2 cells from a fairly coarse grid of points by using elementary techniques. The primary information source for the tidal-current resource was charts and tables that are intended for mariners and not for energy assessment. The tidal-current information in these publications is fairly sparse and generally based on fairly short measuring campaigns.
The final results as presented and the remarks made in the discussion are based on the joint products of machine specifications and resource estimations. In this context it must be clearly understood that the machine specifications are somewhat speculative. However, they reflect information in the public domain regarding future technology developments. It is likely that, as wave and tidal-current technologies mature and as detailed knowledge of the resource improves, the machine designs will evolve to be appropriate to the specific resource at each location. This process would have a strong positive influence on average capacity-factors and total production capacity.
The costs of connection of onshore-wind are lower on the mainland than they will be in the Western Isles, Orkney or Shetland and so the selection of capacity in order of economic merit tends to favour mainland sites where available. This does not imply that the renewable resource is lower or poorer in the islands. On the contrary, the area scenarios show clearly that the renewable resource in the island regions is significantly higher than on or near the mainland.
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