7 MODEL SENSITIVITY AND EXAMPLE OF APPLICATION
7.1 M ODEL SENSITIVITY
7.1.1 Cost parameter variations
In this section the structure of the power generation in the cases with varied cost parameters, marked by the word ‘cost’ in the denomination, is described.
Germany is the only country in the three country network with a geothermal power and CHP potential. Geothermal power without district heating is only applied when the investment costs are at 50 % of the base case costs. The share of geothermal CHP in the total power generation is almost constant in all cases with varied cost parameters. It is hardly affected by changes of the costs of PV, concentrating solar, hydro and biomass power plants. Its share in the total power generation increases from 11 % to 16 % when the investment costs for Figure 7.1.1: Normalised total annual electric power generation in the network DE-NO-DZ; different parameter variations (see Table 7.1.1). On top: base case and variations of generation costs. At the bottom: base case and variation of annual load, transmission restrictions, storage restrictions and costs. * ‘n.i. in NO’: Annual natural inflow into pumped hydro power plants in Norway.
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bioco st80
hydrocost50 geocost120
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ocost50
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Geothermal power Geothermal CHP n. i.* in NO Run-of-river hydro (old+mod.) Run-of-river hydro (new) Reservoir hydro Biomass (steam turbine) Biomass (steam turb., CHP) Biomass (biogas CHP) Wind onshore Wind offshore Photovoltaics
CSP Residual (gas turbine) Annual p.dem. / gen. (inc. n.i.* in NO) in % Storage input in % of an. gen.
wind power are at 150 % of the base case costs. However, this cost development in the period of the coming 40 years is unlikely. In the case of onshore wind power, this would even mean an increase of the investment costs from 1160 €/kW in the year 2010 to 1350 €/kW in the year 2050. The share of geothermal CHP is strongly influenced by costs for the geothermal power plants themselves: geothermal power generation disappears completely through the cost minimisation if the costs are only 20 % higher. On the other hand, it is increased from 12 % in base case to almost 18 % when the investment costs are 80 % or 50 % of the base case costs. In these cases the potential is completely exploited. In the case
‘geocost50’ geothermal power plants without heat delivery contribute 8 % of the total power generation. The potential is then completely exploited. A relatively small variation of the investment costs, which is well in the possible range of cost developments especially of the young technology of enhanced geothermal systems, can result in it being one major contributor to the power supply or of it playing no role at all in the energy mix.
The share of biomass is almost constant and even unaffected by the reduction of biomass power plant investment costs and fuel costs to 80 % of the base case values.
The share of hydro power is rather stable in all cases apart from the hydro power investment cost variations: hydro power investment costs of 50 % of the base case costs lead to the increase of the hydro power share in the total generation from 8 % to 19 %, the additional hydro power coming from the technology category ‘old and modernised plants’ in Norway. In all other cases the Norwegian power plant mix does not contain any run-of-river hydro power.
The cost minimisation eliminates this option at the given costs assumption. In Libya there is also a small hydro power potential. This is not exploited in any of the model runs.
The wind power share is quite variable: it is highest when wind power generation replaces geothermal CHP generation because of elevated investment costs for geothermal CHP in the case ‘geocost120’. The share of onshore wind power varies strongly only when wind onshore or wind offshore costs are varied. Onshore wind power is completely replaced by offshore wind power in the case ‘windonsh_cost120’ in which the investment costs for onshore wind turbines are only 20 % higher than in the base case. In the cases with only offshore wind investment costs increased, the reduced offshore wind power generation is compensated by onshore wind power in combination with CSP, completely replacing it when the offshore wind investment costs are at 150 % of the base case investment costs.
In all cases apart from the cases with a transmission limit set to 2500 MW per transmission line, photovoltaic power plants are only built in Algeria. With the transmission limit, some PV is also built in Germany. PV only plays a major role of 27 % in the total generation if its investment costs are at 50 % of base case costs. In that case, it reduces the wind share to less than 40 % and the CSP share to around 14 %. At 80 % of the investment costs, the share amounts to 3.6 %. In all other cases, the PV share in the total generation is even lower.
Algeria is the only region in the network with a concentrating power potential. The share of CSP in the total power generation is very variable: the highest share of 51 % occurs when the investment costs for wind power are at 150 % of the base case costs. The resulting lower wind share is almost completely compensated by CSP and by some more geothermal power.
The lowest CSP share in the total power generation of 14 % occurs when the costs for PV are at 50 % of the base case costs. The increase of the CSP costs themselves to 120 % of the base case costs has little influence on the CSP share in the generation. The
configuration of the CSP plants changes in the cost variation cases as well, as can be seen in table 7.1.3: the solar multiple is between 2.6 (case ‘pvcost50’) and 3.9 (case
‘windcost150’). On average it amounts to 3.2. The storage capacity suffices for between 9.7 h (case ‘cspcosts120’) and 13.7 h (case ‘windcost150’) of turbine full load operation. On average it amounts to 12.5.
Table 7.1.3: CSP characteristics: solar multiple and relation between storage capacity and thermal turbine power input given in full load hours (flh) of turbine operation. Different parameter variations.
base windcost120 windcost150 windoffsh cost120 windoffsh cost150 windonsh cost120 pvcost80 pvcost50 cspcost120 biocost80 hydrocost50 geocost120 geocost80 geocost50
Solar multiple 3.2 3.4 3.9 3.3 3.4 3.3 3.2 2.6 2.7 3.2 3.2 3.2 3.2 3.2 Storage cap. in flh of turbine operation 12.5 12.9 13.7 12.8 12.6 12.7 12.8 13.4 9.7 12.6 11.9 12.6 12.7 12.7
load200 load150 load120 load80 load50 translim 2500 translim 16000 storcons storcons t.lim2500 storcons t.lim16000
Solar multiple 3.2 3.2 3.2 3.2 3.3 3.5 3.3 3.3 3.8 3.2 Storage cap. in flh of turbine operation 12.6 12.8 12.6 12.7 12.3 14.9 13.0 12.7 20.2 12.2
The losses due to storage, transmission and surplus vary between 4.6 % and 7.5 %, on average they amount to 6.1 % in the cost variation cases. The annual power demands are marked in the diagrams in figure 7.1.1 by black bars. The white dot with the black border in the same diagrams indicates the share of the total annual power generation that is stored before it is consumed. This share varies between 6.2 % (case ‘geocost50’) and 11.3 % (case
‘pvcost50’), and it amounts to 7.9 % on average in the cost variation cases.
Table 7.1.4: Transmission capacities in the network of Germany, Norway and Algeria (DE-NO-DZ) in GW, transmission grid length in TWkm. Different parameter variations.
base windcost120 windcost150 windoffsh cost120 windoffsh cost150 windonsh cost120 pvcost80 pvcost50 cspcost120 biocost80 hydrocost50 geocost120 geocost80 geocost50
Norway - Germany 37 35 21 35 27 38 37 36 39 37 38 44 30 22 Germany - Algeria 19 24 44 28 36 19 20 51 18 19 20 22 18 17 Transmission grid length in TWkm 117 126 151 137 143 119 119 197 117 117 121 138 102 83
load200 load150 load120 load80 load50 translim 2500 translim 16000 storcons storcons t.lim2500 storcons t.lim16000
Norway - Germany 88 55 42 26 14 2.5 16 42 2.5 16
Germany - Algeria 57 37 26 14 8.6 2.5 16 22 2.5 16
Transmission grid length in TWkm 308 196 143 84 47 11 70 133 11 70
The capacity of the transmission lines, listed in table 7.1.4, varies strongly with the assumptions about the costs of the generation technologies. The capacity of the line between Norway and Germany is 37 GW in the base case and ranges between 21 GW and 44 GW as a result of the cost parameter variations. Germany and Algeria are connected by a 19 GW line in the base case and the capacity ranges between 17 GW and 51 GW due to the
cost variations. The length of the grid, i.e. the sum of the lengths of each line multiplied by its capacity, ranges between 11 TWkm and 308 TWkm considering all parameter variations. It ranges between 83 TWkm and 197 TWkm, only considering the generation cost variations.
The share of the transmission costs in the total system costs is below 5.1 % in all regarded cases. The transmission lines are limited primarily by their function for the exchange and little by their costs. This leads to the strong variability with the energy mix in the system.