Hybrid geothermal–fossil electricity generation from low enthalpy geothermal resources: geothermal feedwater preheating in conventional power plants

Energy 27 (2002) 329–346 www.elsevier.com/locate/energy

Hybrid geothermal–fossil electricity generation from low enthalpy geothermal resources: geothermal feedwater preheating in conventional power plants Matthias Bruhn

1,*

Geoforschungszentrum Potsdam, Telgrafenberg, 14473 Potsdam, Germany Received 30 August 1999

Abstract Hybrid steam power plants with geothermal feedwater preheating enable the conversion of geothermal energy into electricity in countries with low enthalpy geothermal resources. In order to estimate the potential of geothermal–fossil hybrid power plants with geothermal feedwater preheating, we examine the application of this concept using the examples of two modern coal fired power plants. In addition, energy output and economic efficiency calculations will be compiled for this concept utilising the thermal water data of an existing geothermal heating installation and an experimental facility for the hot dry rock technology. The process of geothermal feedwater preheating as a means of improving performance forms both an alternative and an extension to the existing electricity generation methods based on renewable energy. Photovoltaics or wind power, for example, tend to be expensive and also unreliable due to weather uncertainties. An electricity cost of around 85 EUR/MWh appears to be attainable through the geothermal preheating concept in Central Europe. In countries with the appropriate prerequisites, this concept heralds considerable benefits in terms of efficient electricity generation and environmental protection.  2002 Elsevier Science Ltd. All rights reserved.

1. Introduction In a number of countries in Europe and worldwide, there is a growing interest in so-called green pricing schemes. The term ‘green pricing’ is generally understood to describe a program in which customers volunteer to pay more than their regular electricity bill, the additional amount being spent to promote renewable energies. There are other market oriented schemes for the * Tel.: +49-30-5150-3693; fax: +49-30-5150-2605. E-mail address: [email protected] (M. Bruhn). 1 Present address: c/o VEAG Vereinigte Energiewerke AG, Abt. KBPF, Postf. 040280, 10061 Berlin, Germany.

0360-5442/02/$ - see front matter  2002 Elsevier Science Ltd. All rights reserved. PII: S 0 3 6 0 - 5 4 4 2 ( 0 1 ) 0 0 0 8 8 - 3

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Nomenclature A, B, C Expressions in Eq. (7) Eel, a Annual net electrical energy output from geothermal heat supply (in MWh/a) f Fluid consumption (in kg/kWh) k Electricity cost for additional electrical energy output (in EUR/MWh) kCO2 CO2 avoidance cost (in EUR/t) m Thermal water mass flow rate (in kg/s) ˙ Peigen Power consumption for thermal water cycle (in MW) Pel Net electric power output (in MW) Pnet, sol Net additional power output from geothermal heat supply (in MW) ˙ sol Q Geothermal heat flow (in MW) ˙V Thermal water volume flow rate (in m3/h or l/s) ˙ W Primary energy flow (in MW) z Depth (in m) b Electrical output ratio (dimensionless) ⌫el Energy-related CO2 load in conventional electricity generation (in t/MWh) ⌬pBr Share of fuel cost in conventional electricity cost (in EUR/MWh) ˙ sol Primary energy flow saved by means of geothermal heat supply (in MW) ⌬W hnet Net energetic (1st law) efficiency (dimensionless) ␬ Conversion factor (dimensionless) ␬⬘ Equivalent conversion factor (dimensionless) v Productivity of thermal water reservoir (in m3/hMPa) r Density (in kg/m3) Subscripts DE FW sol Kond R V ¨ ZU

Steam generator District heating Thermal brine or geothermal heat supply Condenser District heating: return pipe District heating: supply pipe Reheat

Superscript o

fossil only status

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promotion of renewable energies such as the introduction of quotas which may be traded (e.g. the ‘green label’ system in the Netherlands, cf. Nuon [1]). In this context, electricity gained from renewable sources is termed ‘green electricity’. The main sources for this green electricity; wind, sun and small hydropower, suffer from cost and availability problems. Geothermal energy, by its nature, has a high availability because the source is not dependent on weather conditions. The awareness of geothermal energy as a possible source of electricity, however, is limited to countries with high enthalpy geothermal sources. Some geothermal fossil hybrid systems enable a contribution of low enthalpy geothermal sources in electric power generation. This contribution would be green electricity because it would be generated from a renewable resource with a CO2-emission close to zero. However, potential green electricity consumers would need to be convinced of the advantages of the hybrid concept. Hybrid electricity generation was suggested as early as 1924 [2] and a number of studies of such systems were also published in the late seventies and early eighties, mostly in New Zealand and in the US, e.g. [3–9]. To the author’s knowledge, none of them dealt with Central Europe. More recent publications deal mostly with hybrid gas turbine combined cycles [10,11]. This article examines a geothermal fossil hybrid technology for steam power plants in the example of coal fired power plants which may be used in green electricity generation in countries with low enthalpy geothermal sources. In countries with higher enthalpy sources, this technology may be used to increase geothermal contribution to fuel savings and environmental protection. 2. Geothermal electricity generation Geothermics, or the energetic exploitation of hydrothermal resources, makes use of hot water or steam which can be found in porous or fissured rocks in the Earth’s crust. A thermal water cycle typical of geothermal heating plants in north east Germany can be seen in Fig. 1. Commercial geothermal electricity generation started in Lardarello, Tuscany, Italy in 1913 with an installed electric capacity of 250 kW [12]. This is one of the rare locations where superheated steam is available from geothermal wells. The first power plant based on geothermal hot water has been in operation in Wairakei, New Zealand since 1958 [12]. Today, the installed electric capacity amounts to some 8240 MW worldwide. The leading producers are the USA, the Philipines, Italy and Mexico. A description of conventional geothermal power generation can be found in Refs. 12–14. The usual systems work with small condensing turbines or back-pressure turbines [13]. Geothermal hot water is flashed in tanks and the steam generated in the flashing process is used for the steam turbines. Turbine operation usually requires separating solid particles from the steam and removing high portions of noncondensable gases from the condenser. Rankine cycles with organic working fluids (organic rankine cycles, ORC) and two-phase turbines are also used in geothermal electricity generation [14]. The exploitation of geothermal sources may cause a range of environmental problems depending on the location and on the technology used. Examples of which are; ground subsidence, disturbance of natural phenomena (geysers, hot springs), soil and water pollution by geothermal liquids with a high content in salts and, most interesting in terms of the climate change discussion, greenhouse gas emissions (CH4, CO2). DiPippo [15] concludes that, in spite of this, geothermal

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Fig. 1. Principle of geothermal preheating (geothermal extraction steam saving) in a steam power plant and scheme of a thermal water cycle for high salinity waters. Production well (1), downwell pump (2), transmission pipe (3), heat exchanger (4), injection well (5), filters (6), inert gas protection system (7), constant pressure system (8), slop pits (9), steam generator (boiler) (10), steam turbine (11), condenser (12), feedwater pump (13), conventional preheater (14).

installations using the appropriate technology belong to the most environmentally benign forms of electricity generation facilities. For regions which lack natural steam or hot water sources, the so-called hot dry rock technology (HDR) is under development. The idea is to generate artificial cracks in hot crystalline rock. These cracks then serve as a heat exchanger to generate hot water which may be used in a flashing process or in an ORC at the surface. The only project so far that has actually demonstrated the possibility of HDR power production is running in Soultz-sous-Foreˆ ts in Alsace, France near the German border. In an experiment, up to 90 m3/h of hot water at 142°C was circulated for about 4 months yielding a thermal output of approximately 10–11 MW [16]. Continuation of the drilling

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from the current 3900 m to 5000 m and additional fracturing of the rock is planned for the installation of a 5–6 MW ORC plant [17,18].

3. Hybrid geothermal fossil power plants A combination of geothermal energy and fossil fuels for electricity generation in so-called hybrid power plants provides significant thermodynamic advantages in comparison with a separated approach. For steam power plants, three principal concepts for hybridisation may be distinguished [19]. 1. Fossil superheating of geothermal steam [3]. Gas turbines may be used for this purpose leading to hybrid combined cycle plants [4,5,10,11]. 2. Geothermal feedwater preheating in conventional steam power plants [6,7]. 3. So-called compound geothermal fossil power plants [8]. Of these three concepts, only geothermal feedwater preheating is suitable for low enthalpy geothermal sources. It is therefore the only valid possibility for Central Europe with the possible exception of some special locations with higher temperature resources. In addition to geothermal feedwater preheating, a geothermal heat supply for district heating is also possible in combined heat and power plants. In steam power plants, the feedwater for the boiler is usually preheated with steam extracted from the turbine. As a result of this preheating process, the heat influx in the steam generator can occur at a higher temperature, which, according to the laws of thermodynamics, facilitates a higher power plant efficiency rate. This conventional preheating process may be partially replaced by geothermal feedwater preheating. An additional heat exchanger is integrated into the feed loop of an existing plant (see Fig. 1) in a bypass to one or more of the conventional preheaters. In a plant designed as a hybrid plant, some of the conventional preheaters may be reduced in size or may be left out altogether. Investment in redundant components may thus be avoided. Part of the boiler feedwater is then preheated geothermally. As a result, savings can be made in the steam flow required for feedwater preheating (extraction steam saving). The extraction steam which thus remains in the turbine leads to an increased power output in the low pressure part of the turbine. This process could contribute either to an increase in the power output (booster operation) or to combustible fuel saving at a constant power output (fuelsaver operation). The process was examined in a number of studies, some of which included complete plant design studies (cf. e.g. [9,20]). Similar systems have been discussed for other energy sources, examples of which are summarised in Refs. 21–23. To the author’s knowledge, the only hybrid power plant with geothermal preheating in commercial operation today is a 35 MW steam power plant in Honey Lake Valley, CA in the USA, which is fired by wood residues. Fossil fired plants with this concept were never built, probably due to problems finding a location suitable for both primary energy systems. Also, with decreasing oil prices in the 1980s and 1990s, there was little incentive for investment in a new system whose reliability had not been proven. Moreover, gas

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turbine combined cycle plants are not suitable for the geothermal preheat approach. This is because the steam generation is limited by the exhaust gas enthalpy available above the pinch point temperature in such systems. Below the pinch point temperature, there is abundant enthalpy in the exhaust gas for feedwater preheating.

4. Performance parameters The second law efficency of the hybrid system is superior to that of a fossil-only plant [6]. However, the power plant energetic efficiency, defined as a quotient of the electrical output and the total heat supply, decreases if geothermal heat is introduced to the system. This is because the geothermal heat supply is at a lower temperature than the heat supply in the boiler and it has a lower exergy content. In spite of this, an apparent increase in the energetic efficiency can be observed if the electricity generation is compared only to the fossil fuel-based primary energy supply. The quotient of the net power output, Pel and the primary energy flow (or fuel energy flow), ˙ , is termed the electrical output ratio b. The output ratio is similar to a first law efficiency but W it ignores both the geothermal input and any heat extraction that might occur, thus giving a measure for the fossil fuel based efficiency. Pel b⫽ ˙ W

(1)

Parameters for the two (idealised) operational concepts, booster operation and fuel saving operation, may be calculated by comparison with the initial fossil-only status marked with ‘o’ (no additional heat supply). The present study presents computer simulation results from fuel saver mode. For large, modern power plants, they equal the results for booster mode. ˙ , the (marginal) conversion In booster mode with a constant supply of primary energy, W ˙ efficiency for the geothermal heat added to the system, Qsol, is called the conversion factor ␬ (cf. [24]). ˙ sol=W ˙ °⫺W ˙ may be expressed as an equivalIn fuel-saver mode, the reduction of fuel supply ⌬W ent electrical output Pel,sol. The resulting conversion factor, ␬⬘, is called ‘equivalent conversion factor’: ˙ sol b°×(W ˙ °−W ˙) Pel,sol b°×⌬W ␬⬘⫽ ˙ ⫽ ˙ ⫽ ˙ sol Qsol Qsol Q

(2)

where b° is the electrical output ratio at the initial ‘fossil-only’ status and the index ‘sol’ refers to the thermal brine (German Sole) or to the effects of the additional heat supply. The geothermal net additional power output for the entire facility is Pnet,sol: Pnet,sol⫽Pel,sol⫺Peigen

(3)

where Peigen is the power consumed by the thermal water pump. From this, the annual electricity yield from geothermal energy, Eel,a, can be calculated using the full load hours tvh of the geother-

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mal facility. The electricity cost, k, is calculated dividing the total annual cost of the geothermal preheating installation by the annual electricity yield, Eel,a. Apart from the electricity cost, the CO2 avoidance cost, kCO2 [25], calculated according to Eq. (4), is another relevant economical figure for green electricity production. kCO2⫽

k−⌬pBr ⌫el

(4)

where ⌬pBr is the share of fuel cost in conventional electricity cost and ⌫el is the energy-related CO2 load in conventional electricity generation. Aside from looking at the efficiency of energy conversion itself, as is done using the conversion factor, the efficiency of geothermal electricity generation may be judged by looking at the specific fluid consumption f of a geothermal power plant which is defined as follows: m ˙ f⫽ Pel

(5a)

where m ˙ =V˙ ×rsol is the thermal water mass flow with V˙ and rsol representing the volume flow rate and the density of the thermal brine respectively. In the case of geothermal feedwater preheating, the net geothermal output, Pnet,sol, is taken as a basis. V˙ ×rsol f⫽ Pnet,sol

(5b)

5. Power plant performance with additional geothermal heat supply The usage of geothermal feedwater preheating in large modern power plants was investigated for a reference power plant (Fig. 2) using computer simulations of the steam cycle. In addition, a combined heat and power plant in condensing mode (pure electricity generation) was analysed. Important data on the power plants and the simulation inputs are given in Table 1. The reference power plant is a modern installation completed in the 1990s and operating in Germany. The combined heat and power plant was also used as an example by Bruhn [21]. Its basic parameters were taken from another modern installation completed in Germany in the late 1980s. The code CHP [21,26] was used for the combined heat and power plant. For validation, the calculated values mass flow, pressure and entahlpy were compared to actual values supplied by the manufacturer. The maximum relative deviation was found to be 5%, 5% and 3%, respectively. For the calculation of the conversion factor, the relevant value is the total heat flow in the conventional preheaters from condensing temperature up to a certain feedwater temperature for a given electrical output. Owing to the underlying energy and mass balances and to the simultaneous solution of the equation system, the errors in mass flows, pressures and enthalpies are partially outweighed by other errors and the relative error for the total heat flow can be expected to be lesser or equal to those of the individual values mentioned above. A maximum deviation of 3.4% was found for this value which occurred for a feedwater tem-

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Fig. 2. Simplified scheme of the reference power plant with the geothermal heat exchanger connected in a bypass to the low pressure preheaters. The various forms of the bypass for different thermal water temperatures are shown in dashed lines. 1, steam generator (boiler); 2, geothermal heat supply; 3, condenser; 4, district heat extraction.

perature of around 98°C. For the equivalent conversion factor calculated according to Eq. (2), this leads to a maximum deviation of 6.8%. The simulations for the reference power plant were done with the commercial computer code Ebsilon, version 7.01 [33] which, for most components, uses more accurate models than CHP. The code and the inputs were checked and optimised in co-operation with a utility company that co-owns the plant for accurate thermodynamic and economic calculations. The deviations are therefore expected to be lesser than those in the CHP calculations. The improvement of the electricity output ratio b (apparent increase in the efficiency) with maximal heat supply is portrayed in Table 2. The results show that a noticeable contribution from geothermal preheating in a large power plant can only be achieved by large volumes of thermal water flow. At a thermal water temperature of 70°C, the effect of geothermal preheating is so small that the geothermal system tends to become a net-consumer rather than a booster, if the thermal water pump consumes more than the power increase yielded by the additional preheat system. Preheating with water at temperatures as low as 70°C can only thus be considered in cases where no additional energy consuming processes are required, for example, in an artesian system. Fig. 3 shows the equivalent conversion factor for the reference power plant and for the combined heat and power plant plotted against the thermal water temperature. In the latter case, hot

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Table 1 ˙ FW, heat flow extracted for Simulation inputs for the reference plant and for the combined heat and power plant: Q district heating; JZU¨ , reheat temperature; pKond, pressure in condenser; JV/JR, supply- and return temperature for district heat; hnet, net efficiency; hDE, steam generator efficiency; b°, electricity output ratio at initial status Parameter

Plant data Fuel Pel (design) Pel (simulation) ˙ FW (design) Q ˙ FW (simulation) Q Live steam parameters JZU¨ Number of preheaters pKond District heat: JV/JR hnet (design) hDE (design) b° (simulation) Turbine internal efficiency Geothermal heat exchanger Feed water inlet temperature Min. temperature difference Ratio of mass flows Simulation Program used

Unit

MW MW MW MW bar/°C °C bar °C

°C K –

Reference plant

Combined plant (condensing mode)

hard coal 550 520 300 100 250/540 560 7 0,038/0,052 135/60 0.43 0.943 0.424 constant

hard coal 277 277 386 – 190/535 538 8 0,058 – 0.409 0.923 0.447 constant

28 5 1:1

36 5 1:1

Ebsilon

CHP [26]

Table 2 Increase of electricity output ratio b (i.e. apparent efficiency increase) in percentage points. Calculated for the reference power plant for a thermal water flow rate of 300 m3/h Jsol (°C) 70 135 150

Increase (percentage points) 0.05 0.3 0.4

water reservoirs at high temperatures were also evaluated using a thermal water temperature of 218°C as an example. A somewhat lower equivalent conversion factor was attained at the same temperature in the combined heat and power plant as compared with the reference power plant. This corresponds to the lower efficiency at design conditions. There is an approximately linear relation of the equivalent conversion factor to the thermal water temperature. A linear approximation was determined for the reference power plant which is given in Fig. 3. This approximation is valid for both fuel

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Fig. 3. Conversion of additional geothermal heat in modern power plants: equivalent conversion factor for the reference plant (Fig. 2) and for the combined heat and power plant plotted against the thermal water-inlet temperature. The function indicated gives the correlation for the reference power plant.

saver and booster modes for the plants investigated and it is used as a basis for the calculations of output and efficiency given below. Based on this approximation, geothermal feedwater preheating is compared to common processes for geothermal electricity generation in the lower and middle temperature ranges using the specific fluid consumption f (Fig. 4). The thermodynamic advantages of the preheating concept can be seen in the considerably lower fluid consumption.

Fig. 4. Fluid consumption f plotted over thermal water temperature (pure water, re-injection temperature: 42°C for the geothermal preheat system) for geothermal electricity generation at low to medium temperatures. References: [14,27,28].

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6. Total system: power plant with thermal water cycle An estimate of the output and the efficiency of geothermal feedwater preheating, as attainable in Central Europe, is achieved by combining the conversion factor of a modern power plant with the data of existing geothermal sites (Table 3). The annual fuel savings and output have been calculated for the thermal water conditions of Neustadt-Glewe geothermal heating plant (cf. [29,30]) and for those obtained in the circulation experiment in Soultz-sous-Foreˆ ts [16]. The function portrayed in Fig. 3 is used for the conversion factor in the reference power plant. The assumed operation of 7000 full load hours is typical of base-load plants in Germany. The geothermal preheater may be designed for a number of full load operating hours which may be higher than those for the power plant itself if only part of the preheating is done geothermally at design point. In this case, the geothermal heat supply may operate at full load even if the power Table 3 Plant parameters for a hypothetical reference power plant at Neustadt-Glewe [29] or at Soultz-sous-Foreˆ ts [16,18]. Dashes indicate that values are not known and no assumptions were necessary NeustadtGlewe Technical data Depth Thermal water temperature Thermal water reinjection temperature Equivalent conversion factor Productivity Equilibrium thermal water level Pressure loss in above ground installation Volume flow rate Pump efficiency (hydraulic to electric) Pump power consumption Annual full load hours (geothermal) Annual electricity yield Annual fuel savings

z J J⬙ ␬⬘ v Hr ⌬pV V˙ hPu Peigen tvh Ea,sol mB,a,sol

Economic data Investment cost Amortisation period Interest rate Annuity factor Annuity

I n p a

Results Electricity cost Fuel saving cost

k

CO2-savings Annual CO2 avoided CO2 avoidance cost

⌬mCO2 kCO2

2250 98 33 0.0806 100 100 1 110 0.65 0.146 7 000 3 234 1 054 6.14 20 0.06 0.0872 0.535

Soultz-sousForeˆ ts

3900 142 33 0.1334 – – – 90 – 0.250 7 000 8 965 2 922 8.7 20 0.06 0.0872 0.758

165 501

85 256

3137 157

8696 73

m °C °C – m3/hMPa m below surface MPa m3/h – MW h/a MWh/a t/a Mio EUR a – – Mio EUR EUR/MWh EUR/t t/a EUR/t

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plant output is only at partial load. To make use of this possibility, the heat exchangers and the other parts of the thermal water cycle must be sufficiently reliable even with the known dangers of scaling and corrosion. The economic efficiency is calculated over the lifetime of the plant (amortisation period, Table 3) through the unit cost of the geothermal net additional power output or alternatively through the cost per ton of combustible fuel saving. The fuel saving cost reflects the financial investment required to save a ton of hard coal by means of geothermal feedwater preheating. Annual costs for operation, maintenance etc. are thought to be included in the annuity because a relatively high investment cost was assumed. The attained unit cost of electricity (Table 3) is one point five to three times the unit cost of electricity generated by conventional methods in Germany. The cost per ton of combustible fuel savings, however, is more than six times the current price of imported coal. Thus, geothermal feedwater preheating with such high investment cost can only be financially viable in modern power plants if an increase in electrical power output is required. According to Bruhn [21] (fig. 3-10), a higher level of fuel saving can be achieved in power plants of lower efficiency than the modern steam power plants considered here. The fuel savings with geothermal feedwater preheating can thus be particularly high in simple facilities (for example, in developing countries or in smaller power plants.) For electricity generated from hard coal, the energy-related carbon dioxide load is 0.97 t/MWh [25]. For a fuel price of 41 EUR/t, which results in a share of the fuel cost ⌬pBr calculated to 13 EUR/MWh, this leads to a CO2 avoidance cost (Eq. (4)) in the order of 70 to 160 EUR/t as given in Table 3. In the case of lignite fired plants, the CO2 savings are about 10% higher and the CO2 avoidance cost is correspondingly lower. In comparison with other renewable energy sources, a pilot plant using the geothermal feedwater preheating method is expected to be in a range similar to wind, small hydropower and biomass plants both in electricity cost and in CO2 avoidance cost (cf. Table 4). In Germany, a demonstration plant with geothermal preheating cannot compete with conventional facilities at present because of moderate fuel prices and high investment cost. Geothermal feedwater preheating ranges close to other renewable energy sources in electricity cost. In some parts of Germany and in other areas in Central Europe with the appropriate geothermal conditions, a subsidy of less than 50% on the investment cost would be necessary to attain an electricity cost Table 4 Approximate investment cost and electricity cost ranges in Germany and CO2 avoidance cost calculated against electricity generated from hard coal for different power systems based on renewable energy [31] Installed capacity MW (example) Wind energy system Photovoltaic roof system Small hydropower plant Biomass (wood) fired power plant

1.5 0.005 0.5 5

Investment cost

Electricity cost

CO2 avoidance cost

EUR/kW

EUR/MWh

EUR/t (average)

970–1350 5500–7500 6150–8200 2050–3100

46–122 580–1100 77–170 72–139

63 817 104 89

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equivalent to the German minimum prices paid to producers of electricity from renewable energy sources (e.g. 91.01 EUR/MWh for wind generated electricity or 89.48 EUR/MWh for electricity generated geothermally, both of which often profit from subsidies on investment cost in addition to the favorable price regulation). The German law laying down these prices (Erneuerbare Energien Gesetz, Law on Renewable Energies) does not include hybrid plants but these prices may be used for comparison. A decisive advantage, in comparison with wind-generated electricity, the fastest growing renewable in Europe today, is the almost 100% availability of the geothermal energy. In hydropower, another major renewable energy source with high availability, a high share of the existing potential is already being exploited in many countries. Geothermal energy could be an important additional high availability source there, possibly competing with biomass where this is available. However, a geothermal installation must make use of this advantage to the maximum (7000 full load hours per year) in order to achieve the economic results shown above. Thus, the power plant equipped with the geothermal preheater must be in operation at least 7000 h/a, though it need not necessarily arrive at 7000 full load hours. For the above calculation on the reference power plant combined with Neustadt-Glewe data, the sensitivity of the results was analysed (Fig. 5). Each parameter was varied individually over a realistic range, whilst all other parameters were held constant. These parameters included the thermal water temperature J, the value of the equivalent conversion factor ␬⬘ at a given thermal water temperature, the flow rate V˙ and the amount of investment, I. 7. Possible locations From a regional point of view, the site at Neustadt-Glewe heating plant has the best conditions of all the geothermal heating plants operating in north east Germany. There are, however, natural sources with higher thermal water temperatures at other places in Central Europe. A location with a thermal water temperature, J, of 106°C is Altheim in Upper Austria, where thermal water flow rates close to 300 m3/h are obtainable [32]. The ideal technical prerequisites for the realisation of geothermal feedwater preheating, competitive even with conventional power production, would be in coal fired steam power plants

Fig. 5. Sensitivity check for the annual electricity production, Ea,sol (left) and for the electricity cost (right) for the hypothetical power plant at Neustadt-Glewe. See Table 3 for standard case (i.e. deviation factor 1).

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located in regions with favorable geothermal conditions. A possible example is Turkey where large deposits of brown coal and the appropriate power plants can be found in the west and northwestern areas of Anatoly, not far from natural hot springs. Equally promising conditions might be found in a number of other countries but they can’t be expected in too many places in the world. To realise the potential of geothermal feedwater preheating, it is necessary to make geological assessments of a large number of power plant locations. This process must also consider economic factors. The economic viability depends on the total annual cost, the additional electrical output, the power consumption for pumping and the annual time of operation. The key factors which determine these figures may be summarized in an analytical calculation according to Eqs. (6) and (7) below. I×a Pnet⫽ k×tvh −B+冑B2−4AC ˙V⫽ 2A

(6)

(7)

where: hPu A⫽⫺ v

dp B⫽(c⫻J⫹b)⫻r⫻⌬h⫺Hr⫻ ⫻hPu⫺⌬pV⫻hPu dz

C⫽⫺Pnet c×J+b is the function for ␬ or for ␬⬘, dp/dz is the pressure gradient with depth in the well, ⌬h is the specific enthalpy transfered from the thermal brine, and the other symbols are explained in Table 3. The equations may be used to calculate graphs such as shown in Fig. 6; starting from a maximum tolerable green electricity cost k defined for a given market environment. Assumptions for local values of the investment I (wells, pipes, heat exchanger etc.), the annuity factor a (repayment, interest, operation, etc.) and the annual full load operating hours tvh of the geothermal preheater result in an additional electrical output Pnet necessary for the maximum electricity cost k not to be exceeded. Eq. (7) then gives the thermal brine flow rate required to obtain the net electrical output Pnet for the given circumstances. Fig. 6 gives two examples of graphs which were generated using Eqs. (6) and (7). For example, a sandstone horizon lying at a depth of 2000 m below a power plant facility, with drilling costs typical for North East Germany (cf. Table 5) and with a thermal water temperature of around 90°C would need to deliver approximately 130 m3/h of thermal water. With flow rates lower than

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Fig. 6. Temperatures J and flow rates V˙ required to reach an electricity cost of 150 EUR/MWh (left diagram) or 50 EUR/MWh (right diagram). Depth is used as a parameter. For further assumptions see Table 5.

Table 5 Assumptions for calculating economical thermal water parameters for a given depth and a given electricity cost (cf. Fig. 6). In addition, the relation ␬⬘(J) (Fig. 3) must apply. Calculations done for pure water. For further assumptions see Table 3 Geology Productivity Thermal water reinjection temperature Economics Electricity cost (assumption) Specific drilling cost (completed well) Specific drilling cost (completed well) Investment for above ground installation

v J⬙

150 42

m3/hMPa °C

k f1 f1b

150/50 1023 1150 1.5 Mio.

EUR/MWh EUR/m EUR/m EUR

2500 m and less 3000 m and more

this, the mark of 150 EUR/MWh (which was chosen as a basis for Fig. 6, left figure), shall be exceeded. An electricity cost of 150 EUR/MWh is a realistic upper limit for green electricity to be placed in green pricing schemes. For north east Germany, this electricity cost is an ambitious target to meet with no subsidies. The right hand diagram in Fig. 6 can be utilized for a comparison with conventional electricity generation. It shows the geological pre-conditions for electricity generation at 50 EUR/MWh for German cost structure. For any other region a diagram should be drawn individually in analogy to Fig. 6, taking into account the local variations in prices. In addition to the local typical drilling cost (which is often cheaper than assumed here, cf. the investment cost for Soultz-sous-Foreˆ ts in Table 3), the type of power plant (function ␬=c×J+b) is an important variable in this calculation. Other uncertainties in such factors as the geological conditions or the mineral content in the water can result in strong deviations from the cost estimates shown here. A new research project at GeoForschungsZentrum Potsdam together with the industry aims at utilizing additional sources of thermal waters. The so called stimulation measures are to be tested and evaluated in order to use thermal water reservoirs which do not yield sufficient flow rates under natural conditions. Together with the successful HDR experiments, this project can contrib-

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ute to making thermal waters available for use in larger parts of Central Europe and in other parts of the world. 8. Conclusions The most immediate use for geothermal preheating in Rankine Cycle power plants is in places with both coal and geothermal hot water resources. If sufficient water temperatures are to be found close to steam power plants at moderate depths, a project of geothermal preheating can be successful both economically and ecologically without any subsidy. The construction of a number of new geothermal hybrid power plants would be likely to contribute to cost reduction both in the investment and in the operation and maintenance for the plant. Even under today’s conditions, further development of the concept should be considered. It is the most promising concept for arriving at an economical geothermal power production with low enthalpy sources. The system is currently expected to yield an electricity cost similar to that of other renewable energies which are subsidised in various ways today. After some pilot plants are built, the electricity cost may approach that of conventional power production. Efficiency increases and/or cost reductions can mainly be expected from geotechnical progress (drilling cost, HDR, stimulation measures...). Within green electricity generation, the geothermal preheating concept has the advantage of almost continuous availability and a relatively modest price. If included in green pricing schemes, it can run in the base load, independent of the weather conditions influencing the other renewables. If possible under the conditions in the conventional plant and in the grid, a geothermal preheat plant could even be designed to level off some of the production peaks generated by wind and photovoltaic generation. Within the HDR concept, a geothermal contribution to power generation is made possible using geothermal preheat plants requiring only moderate water temperatures. On a medium term, the concept of hybrid plants for HDR might be more economically viable than drilling much deeper and building relatively small ‘geothermal only’ power plant units. Promoting this technology is a realistic approach to developing a resource which is available in many parts of the world: the Earth’s internal heat. Acknowledgements This research was funded by the German Federal Ministry BMBF under the co-ordination of Projekttra¨ ger BEO, Ju¨ lich. The author would like to thank the East German utility company VEAG Berlin for carrying out the calculations for the reference power plant and for their support in the evaluation of the results. I thank the following people for their help in reviewing the manuscript: Prof. Rummel (Ruhruniversita¨ t Bochum), Prof. Tsatsaronis (TU Berlin), Dr. J. Baumga¨ rtner (SOCOMINE, Soultz), Dr. R. Jung (BGR Hannover), H. Menzel (Neustadt-Glewe). My warmest thanks to Mrs. Christa Tha¨ nert and Mrs. Manuela Wandel for preparing the figures and the manuscript and to all my colleagues at GFZ Potsdam for the warm welcome they gave me and for the fruitful cooperation.

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