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European Commission
EUR 26985 EN – Joint Research Centre – Institute for Energy and Transport

Title: 2014 JRC geothermal energy status report

Authors: Bergur Sigfusson, Andreas Uihlein

Luxembourg: Publications Offi ce of the European Union

EUROPEAN COMMISSION
Joint Research Centre
Institute for Energy and Transport

Contact information
Andreas Uihlein
Address: Joint Research Centre, P.O. Box 2, 1755 ZG Petten, The Netherlands
E-mail: andreas.uihlein@ec.europa.eu
Tel.: +31 224 56 5123

https://ec.europa.eu/jrc

LEGAL NOTICE
This publication is a Science and Policy Report by the Joint Research Centre, the European Commission’s in-house science service. It aims to provide evidence-based scientiﬁc support to the European policy-making process. The scientiﬁc output expressed does not imply a policy position of the European Commission. Neither the European Commission nor any person acting on behalf of the Commission is responsible for the use which might be made of this publication.

All images © European Union 2015, except: cover picture top right: Hickory Construction,
bottom centre: Rannveig Sigfúsdóttir, bottom right: Gretar Ívarsson

ISBN 978-92-79-44614-6 (PDF)

ISBN 978-92-79-50432-7 (EPUB)

ISSN 1831-9424

doi:10.2790/81255

Luxembourg: Publications Oﬃce of the European Union, 2016

© European Union, 2016

Reproduction is authorised provided the source is acknowledged.

Abstract

Geothermal energy resources have been used by mankind in some form for thousands of years. Depending on the temperature of the resource, it may be used for power production, supply of heat or a combination of both. This report presents the current status of the major technologies to utilize the full temperature range of geothermal resources ranging from shallow and borehole ground source heat pump systems, direct use facilities to power plants deriving their ﬂuids from volcanic systems. Power production from hydrothermal resources where natural permeability coincides with hot bedrocks is a mature technology. Power and heat production from engineered geothermal systems where permeability has to be artiﬁcially created is less mature and needs further development and support for large scale implementation. Currently, geothermal provides 0.2 % of EU ﬁnal electricity demand. Although the EU theoretical power production potential with the EGS technology is very high, public support for geothermal is limited compared to other renewable technologies. In order to expand the potential for geothermal power production, focus should be made on facilitating the deployment of the EGS technology. The understanding of successful long term EGS reservoir management has to be elevated and cheaper and more reliable drilling technologies should be developed.

LIST OF FIGURES

Fig. 1

Modelled temperature at 5 km depth in Europe

Fig. 2

Minimum levelised cost of electricity in 2020, 2030 and 2050. The economic potential for these scenarios translates to 21.2 TWh, 34 TWh and 2570 TWh within the EU

Fig. 3

A Lindal diagram of temperature of geothermal water and steam suitable for various applications

Fig. 4

Simpliﬁed ﬂow diagram for direct steam geothermal power plant

Fig. 5

Simpliﬁed ﬂow diagram for a single ﬂash (left) and a double ﬂash (right) geothermal power plant

Fig. 6

Simpliﬁed ﬂow diagram for an organic rankine cycle (left) and a kalina (right) binary geothermal power plant

Fig. 7

Casing strings and liner in a typical geothermal well (left) modiﬁed from [Dumas et al. 2013]. The widths and depths are determined by geological and thermal conditions

Fig. 8

Schematic process ﬂow diagram for a direct use system with heat exchanger

Fig. 9

Schematic process ﬂow diagram for a ground source heat pump system

Fig. 10

The phases of geothermal projects and the mechanisms of funding throughout their duration

Fig. 11

Global installed capacity for power generation, direct use and GSHP in 2010 according to continent

Fig. 12

Global installed capacity for power generation, direct use and GSHP in 2010 according to country

Fig. 13

Global installed capacity for power generation

Fig. 14

Global electricity generation between 1995 and 2012

Fig. 15

Global installed capacity for direct use from 1995 to 2010

Fig. 16

Global direct use of geothermal energy

Fig. 17

Share of global installed capacity according to direct use

Fig. 18

Global installed capacity and utilisation of ground source heat pumps

Fig. 19

Installed capacity for power generation in Europe and additions in 2013

Fig. 20

Installed capacity for power generation in Europe according to technology

Fig. 21

Net electricity generation from geothermal in Europe from 2003 to 2012

Fig. 22

Installed capacity for direct use in the European Union according to country

Fig. 23

Installed capacity and new additions in 2013 for district heating in Europe according to country

Fig. 24

Installed GSHP capacity in 2012 in Europe according to country

Fig. 25

Installed GSHP units in 2011 and sales in 2012 in Europe according to country

Fig. 26

Energy generation in Asia according to country

Fig. 27

Installed capacity for power generation in Asia according to country

Fig. 28

Power generation in Asia according to country

Fig. 29

Installed capacity for geothermal energy use in America

Fig. 30

Installed capacity for power generation in the United States and additions in 2013

Fig. 31

Installed capacity for direct use in the United States in 2013

Fig. 32

Installed power generation capacity in Mexico from 1990 to 2013

Fig. 33

Installed capacity for direct use in Africa in 2010

Fig. 34

Projections for global installed capacity and annual capacity additions 2015-2030

Fig. 35

Installed capacity for power generation and new additions in Europe according to turbine manufacturer

Fig. 36

CAPEX breakdown of a hydrothermal ﬂash power plant

Fig. 37

CAPEX breakdown of an organic rankine cycle power plant

Fig. 38

Inﬂuence of pump rate (and therefore permeability) on the CAPEX of an EGS ORC power plant. The reference case provided is that of 5.5 km deep wells, 100 kg/s pump rate and 165 °C inlet water. CAPEX numbers are those generated by the model and have not been corrected for the CAPEX brake down used

Fig. 39

Inﬂuence of well depth and pump rate on CAPEX of an ORC EGS power plant. It may be much more cost eﬀective to increase the permeability of a reservoir between injection and production wells than to drill deeper for higher reservoir temperatures

Fig. 40

LCOE of diﬀerent geothermal power plants for discount rates between 3 % and 10 %. CAPEX: reference values from [ETRI 2014] (Line: 7 %)

Fig. 41

LCOE of diﬀerent geothermal power plants for diﬀerent capital costs. CAPEX values from [ETRI 2014] , 7 % discount rate

Fig. 42

LCOE predictions of diﬀerent geothermal power plants based on learning curves between 10 % and 20 %

Fig. 43

Comparison of LCOE of diﬀerent energy technologies

LIST OF TABLES

Table 1

Overview of selected drilling methods

Table 2

Geothermal power capacity and heat production in the EU-28 in 2012 and NREAP targets in 2012 and 2020.

Table 3

Geothermal heat production with ground source heat pumps in the EU-28 (GWhth) in 2012 and NREAP targets in 2012 and 2020.

Table 4

Deep Geothermal heat production in the EU (GWhth) in 2012 and NREAP targets in 2012 and 2020. Includes district heating, industry and agriculture, balneology and other.

Table 5

Installed geothermal power generation capacity in the EU-28 (MW) in 2012 and NREAP targets in 2012 and 2020

Table 6

Overview of major European GSHP manufacturers and brands

Table 7

Overview of major vertically integrated players in the geothermal industry

Table 8

Overview of major turbine/power plant suppliers for geothermal power

Table 9

Division of CAPEX of geothermal power plants.

Table 10

Cost components included in the CAPEX estimates for geothermal power plants

Table 11

Indicators for a ﬂash power plant extracting ﬂuid from hydrothermal system at 2.5 km depth

Table 12

Indicators for a organic rankine cycle power plant from hydrothermal system

Table 13

Indicators for a organic rankine cycle power plant from an Enhanced Geothermal System

Table 14

Current LCOE in cEUR₂₀₁₃/kWh

Table 15

LCOE estimates for 2050 in cEUR₂₀₁₃/kWh

Table 16

Potential CO₂ emission savings by using geothermal resource compared to coal or natural gas as energy source. Values are in tonnes CO₂/year (% saving) and apply for 15.5 GWhe or 24 GWhth annual production. Source: JRC analysis

Table 17

Established dose-eﬀect relationships of hydrogen sulphide [WHO 2000] and limits of exposure [EC 2009b].

ACRONYMS AND ABBREVIATIONS

CAPEX

Capital expenditure or capital cost

CF

Capacity factor

CHP

Combined heat and power

COP

Coeﬃcient of performance

EEPR

European Energy Programme for Recovery

EGEC

European Geothermal Energy Council

EGS

Engineered geothermal system

EU

European Union

FIT

Feed-in-tariﬀ

FOM

Fixed operation & maintenance cost

FRP

Fibre-reinforced plastic

GSHP

Ground source heat pumps

GW

Gigawatt

HDR

Hot, dry rock

HVAC

Heating, ventilation, and air-conditioning

kW

Kilowatt

LCOE

Levelised cost of energy

LME

Large magnitude event

ML

Local magnitude of an earthquake

MW

Megawatt

NCG

Non condensable gases

NER

300 New Entrants’ Reserve 300

NREAP

National Renewable Energy Action Plan

Utilisation eﬃciency (or exergy eﬃciency) for a power plant or utilisation ratio for a heat exchanger

O&M

Operation & Maintenance

OEM

Original equipment manufacturer

OPEX

Operational expenditure

ORC

Organic rankine cycle

PDC

Polycrystalline diamond compact (bits)

ppm

Parts per million

PV

Photovoltaics

R&D

Research and development

RD&D

Research, development and demonstration

RES-E

Renewable electricity ROI Return on investment ROP Rate of penetration

TGC

Tradable Green Certiﬁcate

UTES

Underground thermal energy storage

ACKNOWLEDGEMENTS

The authors would like to thank the following internal and external experts who reviewed the draft report and contributed with their ideas to its improvement: Luigi Marini (Consultant in Applied Geochemistry), Einar Gunnlaugsson, chief geologist at Reykjavik Energy, and Evangelos Tzimas from the Joint Research Centre.

The authors would also like to thank Toni Boyd and John Lund from the Oregon Institute of Technology for providing unpublished data and for clarifying data issues.

EXECUTIVE SUMMARY

Geothermal energy is derived from the thermal energy generated and stored in the interior of the earth. This energy is accessible since groundwater transfers the heat from rocks to the surface either through boreholes or natural cracks and faults. The geothermal resource is a renewable resource because there is a constant heat ﬂow to the surface and atmosphere from the immense heat stored within the earth while the groundwater is replenished by rainfall and circulation within the crust.

A geothermal system is called hydrothermal when a natural aquifer usually with fracture permeability coincides with elevated temperatures in the crust. Hydrothermal resources have been subdivided based on the temperature of the crustal ﬂuids. Low enthalpy resources are below 100 °C at 1 km depth, whereas medium enthalpy resources are between 100-180 °C and high enthalpy resources are above 180 °C at 1 km. Waters from low enthalpy resources are directly used for example for heating and sometimes heat is extracted with the aid of ground source heat pumps. Water from medium enthalpy resources may be directly used and used for power production with the aid of binary turbines. High enthalpy resources, which have the smallest geographical distribution, are suitable for power generation and often supply heat to combined heat and power plants.

Rocks without natural permeability but displaying high temperatures may also be stimulated by physical and chemical treatments. Once an adequate stimulation has been performed, the resource is called engineered geothermal system (EGS). Production wells in hydrothermal systems are most often stimulated during the drilling process. Further, the hydrothermal reservoirs may be stimulated or aﬀected through re-injection wells by chemical additives and elevated pressures during operations. Geothermal power production from hydrothermal systems is a proven technology with a 100 year history. However, EGS are still in the development phase and have not been demonstrated under many diﬀerent geological conditions. As hot dry rocks are much more widespread than hydrothermal resources, successful EGS have the potential to produce power and or heat on much larger scale than the hydrothermal resources.

The heat from geothermal ﬂuids may be extracted through series of processes reaching from producing power, drying materials, district heating, ﬁsh farming and snow melting. Optimum heat extraction eﬃciency can be achieved and the usage can be tailor made for speciﬁc locations.

Since no fossil fuels are needed for their operation, emissions from geothermal power plants are much lower than those of coal or natural gas ﬁred power plants. Geothermal plants emit approximately 5 % of carbon dioxide, 1 % of sulphur dioxide equivalents and less than 1 % of nitrous oxide emitted by a coal power plant of equal size. Hydrogen sulphide poses the largest localised environmental threat from high enthalpy power plants. Some plants like binary plants are nearly emission free during operation but emissions are associated with drilling operations. In areas with high power and heat demand, production of heat rather than electricity using geothermal resources may be more eﬀective to reduce overall CO₂ emissions when replacing fossil fuels. The main environmental concern with EGS plants is induced seismicity during reservoir stimulation. Stimulation programs have to be well organised and properly presented to the public prior to any operations. Seismicity may also be associated with operations of hydrothermal power plants but is usually less intense.

Flash power plants associated with high enthalpy hydothermal resources are the cheapest power plants compared to binary plants from hydrothermal or binary plants associated with EGS. Drilling frequently constitutes more than 50 % of the capital expenditure (CAPEX) of geothermal power plants. Cost reductions in drilling technologies and eﬀective reservoir management scenarios have the potential to lower these costs. Although the CAPEX of geothermal plants is high compared to other renewable technologies, geothermal plants have low levelised cost of electricity (LCOE) making them a worthwhile investment opportunity.

The total installed capacity of geothermal energy amounts to about 60 GW worldwide with shares of 18 %, 26 %, and 56 % for power generation, direct use, and ground source heat pumps (GSHP), respectively. Lead markets for geothermal energy are in America, Europe and Asia.

In the EU, the installed capacity of GSHP was about 16.5 GWth while direct use capacity amounted to about 3.0 GWth. The capacity of the 51 geothermal power plants in operation is about 0.95 GWe. Sweden, Germany, and Italy are the countries with greatest installed capacity of geothermal energy in the European Union (EU). Geothermal energy provided about 0.2 % of the total EU ﬁnal electricity demand and 0.9 % of the electricity generated by renewable sources (about 660 TWh) in 2012.

The annual production of geothermal energy in the EU could reach about 49 TWh of heat from GSHP and 30 TWh from direct use in 2020. Projections for power generation assume an installed capacity of 1.6 GWe by 2020. Global hydrothermal power production capacity will increase by 0.6 GWe to 1 GWe per year in the mid-term (until 2030) and might reach 140 to 160 GWe by 2050. In comparison, general estimates, provided technological challenges are overcome, suggest between 1200 GWe to 12000 GWe could be installed applying EGS technology worldwide.

National Renewable Energy Action Plans (NREAP) lay out how the EU member states will achieve their mandatory targets of 20 % share of energy from renewable sources in overall consumption by 2020. In 2012, shallow geothermal (mainly GSHP) heat production exceeded the NREAP target by 40 %, direct heat production was 90 % of the NREAP target and installed power capacity was 11 % above the NREAP target.

Geothermal projects receive a small share of public ﬁnancial support from the EU and Member States compared to other renewable energies. Until 2012, geothermal projects had received EUR 29.4 million through FP6 and FP7 compared to EUR 1.7 billion spent to date by EU on renewables through FP6, FP7 and the European Energy Programme for Recovery (EEPR). No geothermal project has received funding from EEPR and three projects have been funded through the New Entrants’ Reserve 300 (NER 300).

The geothermal industry is still relatively small with few companies active in the supply chain. The activities in the power and direct use sectors range from exploration, drilling, engineering, to construction and plant operation. Clearly, vertical integration is one of the strategies a number of companies pursue while others are oﬀering highly specialised services (e.g. drilling). The geothermal power plant turbine market is dominated by large industrial corporations such as Mitsubishi, Ormat and Fuji. In Europe, Ansaldo-Tosi is the market leader with about 40 % of installed capacity. The European GSHP market has developed from a market with many small companies to a market dominated by major heating and air-conditioning manufacturers. The main European players are from Germany and Sweden but Asian producers from the heating, ventilation, and air-conditioning (HVAC) sector are starting to enter the market.

Due to the limited size of hydrothermal resources, the market share of geothermal power in Europe is small (0.2 %). Large scale deployment of geothermal power production requires the demonstration of successful EGS projects extracting heat from reservoirs constituting a variety of geological conditions. An adequate management of deep engineered reservoirs and highly eﬃcient thermal transfer from the rocks has to be demonstrated. The drilling technology to reach these reservoirs has to become cheaper. Then, the geological risk associated with each project will minimize, the EGS capital and operation expenditure will decrease and possibilities to enter new areas expand.

1 INTRODUCTION

This is the ﬁrst edition of an annual report with which the Institute for Energy and Transport wants to contribute to the general knowledge about the geothermal energy sector, its technology and economics with a focus on the European Union.

Geothermal energy is derived from the thermal energy generated and stored in the earth interior. The energy is accessible since groundwater transfers the heat from rocks to the surface either through bore holes or natural cracks and faults. The geothermal resource is a renewable resource because there is a constant heat ﬂow to the surface and atmosphere from the immense heat stored within the earth while the groundwater transferring the heat is replenished by rainfall and circulation within the crust. Geothermal energy is a commercially proven renewable form of energy that can provide constant power and heat. A hot rock formation with natural fractures and or porous structure where water can move is termed hydrothermal reservoir. The technology associated with hydrothermal power and heat production may be considered as mature. Conversely hot rock formations may have insuﬃcient or little natural permeability or ﬂuid saturation and need to be stimulated to allow for movement of water. Fluid is injected into the subsurface under carefully controlled conditions, which cause pre-existing fractures to re-open, creating permeability. Increased permeability allows ﬂuid to circulate throughout the now-fractured rock and to transport heat to the surface where electricity can be generated. Once stimulation has been carried out, these formations are termed EGS, a technology proven on small scale since 2007 but still in development process. To date, the large majority of geothermal energy extraction is done from hydrothermal resources and few small EGS in operation exist.

The geographical distribution of heat within the Earth’s crust is highly variable. Highest heat gradients are observed in areas associated with active tectonic plate boundaries and volcanism (Figure 1).

The geologic potential (heat in place) for geothermal power in Europe and the World is very large and exceeds the current electricity demand in many countries. However only a small portion of the heat in place can be realistically extracted for power production and the heat in place is therefore often translated to economic potential using levelised cost of energy (LCOE). The geothermal energy potential using LCOE value less than 150 EUR/ MWh in 2020 is 21.2 TWh which is considerably higher than the planned 11 TWh production in the EU member states according to their NREAP for the same year. For 2030, using LCOE of 100 EUR/ MWh, the economic potential amounts to 34 TWh or 1 % of the projected total electricity production in the EU [van Wees et al. 2013]. The same authors estimated the economic potential to grow to 2570 TWh in 2050 (as much as 50 % of the electricity produced in the EU) mainly due to economies of scale and innovative drilling concepts [van Wees et al. 2013]. However, innovative drilling concepts not relying on mechanical drilling have been in development for many years and to date, none has been demonstrated to reach the depth needed for high temperature geothermal applications and it is clear that EGS have to be demonstrated more fully before the 2030 and 2050 predictions are realised. Figure 2 displays the spatial distribution of the predicted minimum LCOE for geothermal energy in 2020, 2030 and 2050 [van Wees et al. 2013].

Fig. 1:Modelled temperature at 5 km depth in Europe (Source: Modiﬁed from GeoELEC Graphical Information System [ThermoGIS 2014])

Fig. 2:Minimum levelised cost of electricity in 2020, 2030 and 2050. The economic potential for these scenarios translates to 21.2 TWh, 34 TWh and 2570 TWh within the EU. Source: [van Wees et al. 2013]

Due to their tectonics, hydrothermal reservoirs tend to be fractured, therefore facilitating movement of water that can be extracted through production wells to the surface either to turn turbines or for direct use for heating. In addition to electricity production, the thermal capacity of the ground can provide heating or cooling with the aid of ground source heat pumps either extracting heat from shallow soils or deeper boreholes. Geothermal energy provides an opportunity to be exploited by cascade utilisation (stepwise usage at progressively lower temperatures) and therefore increase the total eﬃciency and results in economic beneﬁts. The most important cascade applications present in today’s market are power generation, district heating and cooling, industrial processing, greenhouses, ﬁsheries, de-icing, and spa bathes.

Geothermal power and heat installations draw their energy from resources of variable depths and temperatures. So far, no general consensus has been agreed on how to classify geothermal heat sources and production. In this report, when reporting on production values, the following classiﬁcation according to [Antics et al. 2013] and Directive 2009/28/EC [EC 2009a] which has been adopted by Eurostat and national statistics oﬃces, will be used:

•Power generation

•Direct use

•Ground source heat pumps

The report aims to present the overall state of the geothermal industry in Europe. Chapter 2 investigates the technological situation of geothermal technologies: state-of-the-art, research, innovations, current challenges and possible bottlenecks, and its possible future evolution. Chapter 3 investigates EU policies related to geothermal energy. Chapter 4 focuses on the geothermal market status, both globally, and in Europe; proposes some deployment scenarios and analyses industrial strategies as made public by manufacturers and developers. Chapter 5 analyses the economic aspects and implications: cost aspects focus on capital costs (CAPEX), the operational expenditure (OPEX), and the resulting cost of the energy produced. In Chapter 6, environmental impacts of geothermal energy will be discussed, with a focus on emissions and induced seismicity. Chapter 7 then provides a summary of ﬁndings.

2 TECHNOLOGY STATUS AND DEVELOPMENT

Geothermal energy is deﬁned as heat from the earth. From a practical point of view, geothermal resources may be deﬁned as thermal energy reservoirs that can be reasonably exploited at costs competitive with other forms of energy within some speciﬁed period of time. Geothermal resources have been classiﬁed according to their reservoir ﬂuid temperatures into low-, medium-and high-enthalpy ﬁelds. Additionally, the temperatures found at very shallow depths may be used to extract and store heat for heating and cooling by means of groundsource heat pumps.

In 1973, Lindal indicated the temperature range of geothermal water and steam suitable for various applications [Gudmundsson et al. 1985] (Figure 3). Conventionally, geothermal resources are hydrothermal resources that include reservoirs of hot water and/or steam, and are categorised as vapour-dominated or liquid-dominated resources. The temperature for low-enthalpy resources is below 100 °C, while medium-and high-enthalpy resources imply the temperature range of 100-180 °C and above 180 °C, respectively. Low-enthalpy, hydrothermal resources are mainly used for direct heat use, whereas medium-and high-enthalpy resources are used to generate power and in some cases also heat in cogeneration plants.

Hydrothermal resources exist at shallow to moderate depths and are the least abundant source of geothermal resource. Other geothermal resources include geo-pressured, magma and the more widespread hot, dry rock (HDR). In addition, use of supercritical unconventional resources (temperature > 374 °C and pressure > 222 bar referring to pure water) is under investigation through the Icelandic Deep Drilling Project. The process involves transferring supercritical ﬂuids to the surface and converting all the mass ﬂow (compared to 20-30 % for ﬂash power plants) into superheated steam thus increasing the overall eﬃciency of the process [Friðleifsson et al. 2014]. A detailed overview of historical developments in the geothermal industry in America between 1976 and 2006 was published in 2010 [U.S. DOE 2010a, U.S. DOE 2010b, U.S. DOE 2010c, U.S. DOE 2010d].

Fig. 3:A Lindal diagram of temperature of geothermal water and steam suitable for various applications

2.1 Current geothermal energy state-of-the-art

2.1.1 Power plant design

Geothermal power plants use steam from reservoirs of hot ﬂuids found close to the Earth’s surface or deeply buried into the crust to produce electricity. Generally, below-ground ﬂuid production systems are derived from the oil and gas industry, and aboveground conversion systems are based on traditional steam-electric power generation technology. A geothermal power plant’s annual capacity factor (CF) is generally above 90 %. Even higher values up to 97-98 % might be achieved, but with increased maintenance costs; which might be compensated by higher-priced electricity.

The eﬃciency of a geothermal power plant plays an important role when estimating the economic factors under diﬀerent conditions and the terms of reference should be established when collecting and comparing data from diﬀerent authors. The performance of a geothermal power plant can be measured using the second law of thermodynamics as the basis for the assessment of the utilisation eﬃciency (). Since geothermal plants do not operate in a cycle but instead as a series of processes, the cycle thermal eﬃciency for conventional plants does not apply (except for the closed cycle of the secondary working ﬂuid in a binary plant). The utilisation eﬃciency, also called exergy eﬃciency, measures how well a plant converts the exergy (available work) of the resource into useful output. For a geothermal plant, it is found as follows [DiPippo 2012]:

Equation 1

Where is the net electric power delivered to the grid, is the required total geoﬂuid mass ﬂow rate and is the speciﬁc energy of the geoﬂuid which is given by:

Equation 2

Where h is speciﬁc enthalpy and is speciﬁc entropy at reservoir conditions (P₁,T₁) and at the so-called dead state (P₀,T₀). The eﬃciency as described above is the eﬃciency used throughout this report.

The type and temperature of a geothermal resource determines the design of the power plant and the eﬃciency is highly dependent on the resource temperature.

The amount of non-condensable gases (NCG) generally correlates with reservoir temperatures. These gases (mainly CO₂ and H₂S) do not condense with the steam in condensers and have to be extracted by means of pumping). The existence of these gases may play an important role on the eﬃciency of the whole energy conversion process and corrosive resistant materials often have to be used, thus aﬀecting the economics of the power plants.

2.1.1.1 Direct dry steam

Dry steam is the oldest type of geothermal power plant, ﬁrst being used in 1904. Dry steam plants amount to almost a quarter of geothermal power capacity today. Dry steam technology is used in conjunction with vapour-dominated resources. An overview is provided in Figure 4. The steam from production wells (PW) with several wellhead valves (WV) is transferred through a particulate remover (PR) in steel piping (SP) towards moisture removers (MR) adjacent to the powerhouse. There, control and stop valves (CSV) adjust the ﬂow of steam into the turbine attached to the generator (T/G). The steam condenses in a condenser (C) and is then pumped (CP) towards a cooling tower (CT). The cooling water is recirculated by cooling water pumps (CWP) towards the condenser again or re-injected to the reservoir through re-injection wells (IW). Make-up water (usually less than for fossil fuel plants since the condensate is used for cooling) is required and the quantity depends on the climate and conﬁguration of the power plant. The amount of non-condensable gases (typically between 0.5 to 10 wt % of steam, sometimes higher) requires a gas extraction system to be installed. As NCG are ejected from the top of the cooling towers and gas extraction pumps work on diﬀerent eﬃciency, the cooling water may become corrosive. The pH of cooling water is therefore monitored and can be adjusted with for example caustic soda. Control of steam ﬂow at the wellheads to meet electricity demand ﬂuctuations is easier than in ﬂash steam plants.

Dry steam power plants have the highest eﬃciency among all geothermal power plants, reaching values of 50-70 % [DiPippo 2012]. They are commercially proven, simple to operate and require relatively low capital costs. However, they are only suitable for dry steam resources, of which there is little known untapped potential. Dry steam plants are not suitable for combined heat and power (CHP) applications.

Fig. 4:Simpliﬁed ﬂow diagram for direct steam geothermal power plant. See text for details. Source: [DiPippo 2012], adapted

Fig. 5:Simpliﬁed ﬂow diagram for a single ﬂash (left and a double ﬂash (right) geothermal power plant. See text for details. Source: [DiPippo 2012], adapted

2.1.1.2 Flash cycle and dual ﬂash

Flash steam power plants are the most common type of geothermal power plants, making up about two thirds of geothermal installed capacity. The ﬂash steam technology makes use of liquid-dominated hydrothermal resources with a temperature above 180 °C. In the high-temperature reservoirs, the liquid water component boils, or ‘ﬂashes’ as pressure drops (Figure 5). The ﬂuid from production wells (PW) ﬂows through cyclone separators (CS). The ﬂow path for the steam after the cyclone separators is usually the same for ﬂash plants as with dry steam power-plants after the particulate removers. The steam may be condensed in either direct contact condenser or indirect condenser. When direct contact condensers are used a higher fraction of non-condensable gases (mainly the water soluble gases CO₂ and H₂S) are partly captured into the condensate. The design of the condenser may have detrimental impact on treatment of the gases as will be discussed in Section 2.1.5. In a single ﬂash plant the separated water from the cyclone separators is pumped towards injection wells. The separated water may also be ﬂashed in a ﬂasher (F) where additional steam is generated at lower pressure than the ﬁrst ﬂash. This steam is diverted into the turbine at a lower pressure stage. During the second and third stage ﬂashing, the risk of scaling increases as the temperature of the ﬂuid is reduced and the concentration of solutes increases. The scaling risk may be decreased by diluting the separated waters with condensates prior to re-injection.

Combined-cycle ﬂash steam plants use the heat from the separated geothermal brine in binary plants (described in next section) to produce additional power before re-injection. The thermal energy of the brine may also be extracted via heat exchangers prior to re-injection. The single-ﬂash and dual-ﬂash power plants reach eﬃciencies between 30–35 % and 35–45 %, respectively when electricity is the sole product. The overall eﬃciency is greatly increased by adding heat exchangers and producing hot water since the conversion factor in a heat exchanger is far greater than converting heat to electricity. Flash power plants have a simple conﬁguration and are already proven technologically; several commercially available system suppliers are present in the market already. Single-ﬂash power plants require low capital but are typically economically competitive only when the harvested geothermal resources are at 200-240 °C or higher temperatures. Double-ﬂash power plants have an increased power output and eﬃciency (by 5-10 %) in comparison with single-ﬂash ones but require higher capital costs and higher resources temperature (> 240 °C) in order to be competitive. In both technologies, the operation and maintenance (O&M) costs increase signiﬁcantly when dealing with high mineral content brine resources. Flash power plants come in diﬀerent sizes with individual turbine units ranging from < 1 MW to > 100 MW and container modules are available on the market.

2.1.1.3 Binary

Electrical power generation units using binary cycles constitute the fastest-growing group of geothermal plants as they are able to use low-to medium-temperature resources, which are more prevalent. Today, binary plants have an 11 % share of the installed worldwide generating capacity and a 45 % share in terms of number of plants [Bertani 2012]. Binary cycle power plants, employing organic rankine cycle (ORC) or a kalina cycle, operate at lower water temperatures of about 74-180 °C using the heat from the hot water to boil a working ﬂuid, usually an organic compound with a low boiling point (Figure 6).

In ORC plants, geothermal ﬂuid is usually pumped (P) from production wells (PW). A sand remover (SR) removes debris before the ﬂuid enters an evaporator (E), and passes a pre-heater (PH) before it is pumped back into injection wells (IW). In the evaporator a preheated working ﬂuid from a pre-heater is boiled prior to entering a turbine unit (T/G). The working ﬂuid is condensed in a condenser (C) and pumped back to the pre-heater in a closed loop. Cooling water is pumped from a cooling tower (CT) towards the condenser and make-up water (M) is pumped into the cooling tower to compensate for losses by evaporation.

Fig. 6:Simpliﬁed ﬂow diagram for an organic rankine cycle (left) and a kalina (right) binary geothermal power plant. See text for details. Source: [DiPippo 2012], adapted

Kalina plants operate with a mixture of ammonia and water and the chemical composition of the working ﬂuid is adjusted to the temperature of the geothermal ﬂuid. The simplest form of a Kalina plant is displayed in Figure 6. The geothermal ﬂuid is pumped (P) from production wells (PW) into an evaporator (E) prior to being diverted back to injection wells (IW) or it can be used for district heating. The working ﬂuid is evaporated into a separator (S) from where saturated vapour rich in ammonia ﬂows to the turbine (T), thus permitting a smaller less costly turbine to be installed. The remaining water rich solution ﬂows through a preheater (PH) and is then throttled down (TV) and mixed with the ammonia rich solution. The mixture enters a recuperative preheater (RPH) prior to being fully condensed (C). Following condensation the working ﬂuid is ﬁrst heated in the recuperative preheater and then in the preheater prior to entering the evaporator. Cooling water is pumped from a cooling tower (CT) towards the condenser and make-up water (M) is pumped into the cooling tower to compensate for losses by evaporation. As with most geothermal power plant conﬁgurations, the cooling tower may be omitted by pumping cold water directly into the condenser and using the resulted heated water for district heating. This option requires more direct use of water but may be feasible option where water is not a limited resource.

In binary plants, the geothermal water and the working ﬂuid are kept separated during the whole process, so there are little or no air emissions. The binary units can be produced in very small sizes (0.1-5 MW), even as container module units allowing for a modular design.

The ORC can reach eﬃciencies between 25 % and 45 % [Emerging Energy Research 2009]. High O&M costs are present when the resource has a high salinity, which comes in direct contact with the plant. The technology suppliers are scarce, with only a few being commercially available.

The kalina cycle can, under certain design conditions, operate at higher cycle eﬃciencies of between 30 % and 65 % [Emerging Energy Research 2009]. It has an abundant, more environmentally friendly heat-transfer ﬂuid (ammonia/water). RD&D should focus on reducing the costs to make technology competitive with current ORC alternatives. Presently, kalina cycle plants are associated with high capital costs and technological complexity. The technology is not yet bankable and few plants are currently operating.

2.1.2 Drilling methods

Drilling represents 30 % to 50 % of the cost of a hydrothermal geothermal electricity project and more than half of the total cost of EGS. Lowering drilling costs is therefore a key issue for reducing the capital investment and operation costs of geothermal power plants. Geothermal drilling technology shares much of its state of the art with technology in the oil and gas industries, especially in low temperature reservoirs. Several distinctive attributes though exist such as massive losses of circulation ﬂuids, high to very high temperatures with related string and casing expansion and the prerequisite of high, full bore, production rates [Dumas et al. 2013].

The established deep drilling technique is the rotary drilling. Tri-cone rotary bits were introduced in 1909 and supplemented in the 1970s by the polycrystalline diamond bit. These are applied by diesel-electric drilling rigs to create boreholes protected by steel casings. The casings are arranged one inside another until the ﬁnal diameter is only a small fraction of the initial diameter on the surface. This arrangement is viewed by many as the biggest drawback of conventional hole-making technology [Dumas et al. 2013]. The highest CO₂ emissions from geothermal power plants are often indirect emissions resulting from drilling with diesel powered rigs. In multi-production well geothermal developments, CO₂ emissions associated with drilling might be reduced by using the power generated by modular small power plants run on steam from previous wells therefore reducing the total CO₂ emissions considerably. This setup however requires some adjustment to the existing drill rigs.

Geothermal drilling beneﬁts from on-going industry improvements. Examples are the placement of casings while drilling in the 1950s; top drive power swivels, air/foam balanced drilling, and polycrystalline diamond compact (PDC) bits in the 1970s; microdrill and coiled tubing in the 1980s; and horizontal drilling, reverse circulation cementing, logging while drilling, and environmentally safe ﬂuid formulations since the 1990s.

Despite these improvements, drilling costs continue to be high and therefore considerable emphasis has been placed on the development of new drilling technologies [Dumas et al. 2013]. A list of selected drilling technologies is provided in Table 1.

2.1.2.1 Conventional mechanical drilling methods

The classical drilling method used today with rotary drilling is crushing or scratching the rock by means of a rotating drilling bit. Two main designs exist: roller cone bits and drag bits. The roller cone bits are preferably used in hard rock formations. The roller cone bits crush the rocks while the drag bits scratch and shear the formation [Teodoriu & Cheuﬀa 2011]. These methods may be combined for example with PDC to shear the formation and rollers to crush it.

Hammer drilling is another mechanical rock drilling method. The method is not common for deep drilling activities. A combination of rotation and hammering can increase the rate of penetration (ROP) signiﬁcantly through the increase in force between bit and formation. Hammer drilling works well in hard formations but has low or no eﬃciency in soft formations.

2.1.2.2 Experimental drilling methods

The mechanical methods described above are all proven technologies and are compatible with existing surface and down-hole hardware. However these methods provide lower ROP than many other drilling methods which include: jetting (high performance/mud jet bits), thermal drilling (spallation, molten ion penetration, plasma bit), direct stream, millimetre wave, high voltage electro impulses.

Jetting or jet drilling uses the drilling mud energy to destroy the rock. The ROP can be 100 times higher compared to mechanical drilling in shallow horizontal wells [Kolle 1999]. When deep drilling is required, the total pressure losses in the system may limit the applicability of the jet drilling systems. The jet drilling technologies require high pressure/ high ﬂow rate pumps, special drill string and down hole pressure enhancer. It might become an alternative when drilling surface casings in sedimentary rocks but not yet the adequate technology for deep geothermal drilling.

Thermal drilling uses heat to destroy or melt the rock. Laser drilling is based on three common energy transfer processes between the laser and the rock: reﬂection, scattering and absorption. Some rock properties help the laser drilling process: Low thermal conductivity keeps the heat around the hole, low reﬂectivity allows for good laser-to-rock energy transfer and deep penetration that allows good volumetric absorption. Two main ways have been proposed for laser deep drilling: Rock weakening with further application of mechanical tools and direct rock destruction via ablation (ablation, fusing or vaporising). The spalling or spallation process will fragment the rock in smaller parts due to temperature gradients within the rock which can then be hydraulically moved to the surface. Spalling is less energy intensive than fusing or vaporising and is more likely to be used for deep drilling applications [Teodoriu & Cheuﬀa 2011].

Table 1: Overview of selected drilling methods

Technology

Advantages

Disadvantages

Rotary drilling,
roller cone bits

Compatible with existing hardware.

Low Rate of Penetration (ROP)

Rotary drilling,
drag bits

Compatible with existing hardware.

Low ROP

Rotary drilling,
hybrid (PDC/roller)

Compatible with existing hardware.
Up to four times faster than roller cone bits

Low ROP but faster than above.

Hammer drilling

Compatible with existing hardware. Suitable for wide shallow conductor and surface casings

Uncommon in deep formations. No eﬃciency in soft formations.

Jetting

Up to 100 times higher than diamond bits in hard formations

Large pressure losses in deep wells. Special equipment. 10-15 times higher energy demand than rotary.

Laser, ablation

Immature technology. Complicated transport of beam into deep wells.

Laser, spallation

Less energy intensive than ablation

Immature technology. Complicated transport of beam into deep wells.

Spallation

Can work in deep hydrothermal environment.

Immature technology. 10-15 times higher energy demand than rotary.

Plasma bit

Potentially 4 times faster ROP than conventional drilling.

Immature technology, pilot system exists.

Millimetre wave

Rate of penetration should be 10- 15 m h-1 and should not lower with increased depth.

Has only been demonstrated in the laboratory, energy intensive.

High voltage electro impulses

Potentially 5-10 times faster ROP than conventional drilling

Immature technology. High current and power transmission from surface to the bottom. Special insulators needed. ROP may decrease with depth.

The spallation drilling process may also be applied directly without laser melting. There, a conﬁned volume of rock is heated rapidly and the rock fragments into disk like ﬂakes. The method seems to work well in hard rocks. Fuel and oxidant are transported separately down hole where they ignite and the resulted ﬂame is capable to burn under water. The process requires a certain minimum bottom hole pressure to be initiated and controlled.

The plasma bit drilling technology is a patented non-contact device with a plasma generator where water steam is heated inside an electrical arc above 5000 K [Kocis et al. 2013]. The heated rock fragments are rapidly cooled with water in a controlled way and diverted to a mud system. The technology should eﬃciently reach depths of 10 km with constant diameter and costs are predicted to be linear. Casing while drilling is achievable where casing is formed by the disintegrated rock fragments.

Millimetre wave drilling refers to drilling done with electromagnetic frequencies higher than microwaves but lower than infrared. The waves are insensitive to small particles and smoke but are short enough to be guided as an intensive beam within the cross sections of a typical borehole. Successful melting of hard rock has been achieved but high intensities are required (≥1 kW/cm2) [Woskov et al. 2014]. A gas stream purges vaporised particles upwards into the annular space where they form a glass wall upon cooling. The technology should eﬃciently reach a depth of 10 km but is currently in the development phase.

High voltage electro impulse drilling uses high voltage electric pulses to break the rock due to local pressure pulses induced at rock interface. The technology uses rotating electrode heads and can be used as an enhancement for conventional drilling by accommodating special electrodes to the drilling bit.

2.1.3 Drilling technologies (drilling and design)

Drilling technologies may be deﬁned as the sum of all processes and equipment designed to support the drilling method [eg. Teodoriu & Cheuﬀa 2011]. A useful guide on geothermal drilling is provided by Dumas et al. [2013]. The enthalpy of geothermal ﬂuids is not high (enthalpy of dry steam is 2750 kJ/kg at 300 °C while the energy value of one litre of crude oil is approximately 35 MJ). The exergy eﬃciency of ﬂash and binary plants of converting geothermal steam/water to electricity is not high (25-50 %), therefore high mass ﬂows and hence volume ﬂow rates are required. These large ﬂow rates necessitate large diameter production casings and liners [Dumas et al. 2013]. Typical standard diameter wells utilise a standard API 9 5/8" casing as production casing and either 7” or 7 5/8" diameter slotted liner in an 8 ½" diameter open hole. Typical large diameter wells utilise a standard API 13 3/8" casing as production casing and either 9 5/8” or 10 ¾" diameter slotted liner in a 12 ¼" diameter open hole. The diameters and depths for other casings depend on geological and thermal conditions. A typical well design is shown in Figure 7 and would include [Dumas et al. 2013]:

•Conductor: 30” set a at a depth of 24 metres, either driven or drilled and set with a piling augur;

•Surface casing: 20” casing set in 26” diameter hole drilled to 80 metres depth;

•Anchor casing: 13 3/8” casing set in a 17 ½” diameter hole drilled to 270 metres depth;

•Production casing: 9 5/8” casing set in 12 ¼” diameter hole drilled to 800 metres depth;

•Open hole: 7” perforated liner set in 8 ½” diameter hole drilled to 2400 metres.

The most commonly used drilling technologies will be described in the following sections.

Fig. 7:Casing strings and liner in a typical geothermal well (left) modiﬁed from [Dumas et al. 2013]. The widths and depths are determined by geological and thermal conditions. A typical large diameter directional well from Hellisheiði, Iceland (right) [Sveinbjornsson & Thorhallsson 2014]

2.1.3.1 Casing drilling

Standard oil ﬁeld casing is used as the drill string and drilling and casing is done simultaneously. The casing is rotated from the surface with a top drive while drilling ﬂuid is circulated down the casing and up the annulus towards the surface. For casing drilling, drill collars are not needed to provide weight-on-bit unlike for conventional drilling with drill pipes. The drilling rigs used for the casing drilling process can be either specially designed to apply this technology or modiﬁed from conventional rigs. Casing drilling does not have much better ROP than conventional drilling but may be useful when problems are expected. Casing drilling is not the ﬁrst choice for deep hard rock formations and has been applied more in the oil and gas industry.

2.1.3.2 Coiled tubing drilling

The technology uses a conventional drilling assembly with a down-hole motor. Coiled tubing drilling uses higher bit speeds at lower weight-to-bit. With the technology, the coil tubing unit can either be stationary or it can revolve around the well centre [Reel 2014]. The advantages of coil tubing drilling are fast mobilisation and demobilisation, tripping times are faster than those of conventional drilling therefore lowering the overall operation duration of the drill rig. Coil tubing rigs require small footprint and enables underbalance conditions. The main disadvantages are depth limitation, the size restriction of the coil tubing and associated mechanical issues such as buckling and fatigue [Teodoriu & Cheuﬀa 2011]. Coil tubing drilling are therefore optimal for short small diameter wells as well as for re-entering or sidetracking wells. Coil tubing setup has proven eﬀective when initiating discharge of production wells that do not produce automatically when the well is opened. There, air is pumped through the coil to lift the water column with air bubbles as opposed to push water column down. The coil tubing method decreases the strain on the casings as depressurisation rates are slower during transition from hydrostatic to ﬂow conditions.

2.1.3.3 Underbalanced drilling

The drilling process intentionally keeps the wellbore ﬂuid gradient less than the natural pore pressure gradient. This protects the reservoir as drilling mud is not lost in high quantities since the well starts ﬂowing while drilling operation is still ongoing. Therefore dedicated wellhead and surface equipment is required. The ROP increases due to lower well pressure, this is especially important in hard rock formations.

2.1.3.4 Managed pressure drilling

Here the annular pressure proﬁle in the well is controlled throughout the drilling operations. The technique may either be reactive or proactive. Reactive managed pressure drilling uses a rotating control device and a choke to deal with drilling problems. Proactive managed pressure drilling includes entire well design to manage the wellbore pressure proﬁle throughout the drilling process.

2.1.3.5 Slim hole drilling

Slim hole drilling is not a special technology as such but due to its small diameter, the ROP and therefore overall costs can be reduced. The disadvantage is that production casing size is restricted and therefore slim holes may not be suitable as production wells. However, slim holes may be highly suitable for exploration and monitoring purposes.

2.1.4 Heat exchanger design

Heat exchangers play a central role in geothermal power plants but also for direct use and GSHP applications. Direct use and GSHP systems mainly deploy a liquid/liquid heat exchanger to transfer the heat from the geothermal ﬂuid or the ground to a district heating or space heating system [Huenges 2011]. In geothermal power plants, a range of heat exchangers can be installed, fulﬁlling various tasks such as pre-heating, and superheating and serving as evaporator or condenser. In power plants, not only liquid/ liquid but also liquids/liquids+gas and even liquids/ liquids+solids heat exchangers can be found.

According to [Huenges 2011], the energy balance of an ideal heat exchanger without heat losses can be described by:

Equation 3

with ṁc and ṁh referring to mass ﬂow rates, and hc and hh to the speciﬁc enthalpy. The rate of heat transferred from the hot to cold ﬂuid (without nvolving a phase change) can then be expressed as:

Equation 4

with Tc and Th referring to the temperature of the hot and cold ﬂuids and cp,c and cp,h being the constant-pressure speciﬁc heat capacities. Given a maximum usable heat of ,o at the ambient temperature T₀, the utilisation ratio is:

Equation 5

For a plant using a geothermal resource at 150 °C down to 70 °C, the utilisation ratio at an ambient temperature of 20 °C is 62 % [Huenges 2011].

When designing a heat exchanger, the dimensioning of the heat transfer area A is key aspect and can be derived by:

Equation 6

with △Tm being the mean temperature diﬀerence, and U beling the overall heat transfer coeﬃcient [DiPippo 2012, Huenges 2011]. Depending on the available knowledge on inlet and outlet temperatures, the mean temperature diﬀerence △Tm can be derived or calculated by diﬀerent methods. The overall heat transfer coeﬃcient is inﬂuenced by ﬂuid, ﬂow conditions, shape of heat transfer area, and heat transfer regime (e.g. boiling, no phase change).

The design and layout of a heat exchanger has to take into account several parameters. As said before, the heat transfer rate is deﬁned by the design of the geothermal energy plant and is used to calculate the required heat transfer surface area. Fluids can ﬂow in parallel, in opposite (counter-ﬂow), or in perpendicular (cross-ﬂow) directions and the ﬂow type inﬂuence temperature proﬁles and heat transfer characteristics [Huenges 2011]. Two basic types of heat exchangers are typically used in geothermal applications: shell-and-tube heat exchangers and plate heat exchangers. Plate heat exchangers show high surface-to-volume ratios and high heat transfer coeﬃcients [Madhawa Hettiarachchi et al. 2007]. Thus, they are usually very compact and they can easily be expanded when the capacity needs to be increased [Zhu & Zhang 2004]. Shell-and-tube heat exchangers are very reliable and ﬂexible and they can be used in almost all geothermal applications [Huenges 2011]. However, they are more susceptible to fouling and have lower surface-to-volume ratios compared to plate heat exchangers. They are usually used for evaporators and condensers.

2.1.5 Emission abatement systems

Gases that do not condense with the steam in the power plant’s condensers are referred to as non-condensable gases (NCG). The main NCG species in geothermal steam are carbon dioxide (CO₂) and hydrogen sulphide (H₂S). Ammonia (NH₄) is often absent but may be up to 10 vol % in the steam. Smaller amounts of H₂, N₂, Ar, CH₄, CO and Hg may exist in the emitted gases.

Of these gases, H₂S is the gas of highest concern due to its toxic nature and therefore emphasis will be made on H₂S abatement systems. Depending on site speciﬁc factors, a speciﬁc process may have to be incorporated into the plant process to remove H₂S from the emissions stream. The location of the power plant has large impact on technology selected. Local emission regulations diﬀer; the distance to resource materials (chemicals feeds and water) for the cleaning process as well as distance to markets for potential products may become detrimental. Finally, the design of the H₂S removal system has to take into account condenser type after the turbines. Therefore when choosing a H₂S removal technology, a combined technical, environmental and economic study needs to be carried out.

The geothermal gases have diﬀerent solubility in water which will determine to some extent their behaviour in the condensers as well as in the gas removal process. Hydrogen gas may in extreme cases be up to 50-60 vol % of the emitted gas mixtures and as it is highly ﬂammable may interfere with known H2S removal technologies developed in the oil and gas industry. Ammonia may exist in smaller proportions and when NH₃ concentrations are high the choice of condensers design becomes important factor on the H₂S removal system design. Due to acid-base interactions between NH₃ and H₂S, partition of H₂S to the condensate in direct contact condensers may become signiﬁcant and secondary treatment can be necessary [Mamrosh et al. 2012].

Many technologies exist for removing H₂S from gases and the selection of technology depends on gas amount and composition and the level of H₂S removal required. These include liquid redox sulphur recovery processes (e.g. Stretford, LO-CAT), the modiﬁed Claus process (gas phase oxidation), burn/ scrub processes, burn/vent processes, amines and physical solvents, scrubbing H₂S with caustic soda, scrubbing with other alkaline earth minerals, wet sulphuric acid process (WSA), AMIS (Mercury and H₂S removal), direct acid gas injection, Paques/thiopac, ThioSolv, Biox and water adsorption and injection. These technologies are of diﬀerent maturity, some have been developed for other industries and modiﬁed for the geothermal industry and others are developed within the geothermal industry. Below is a description of selected H₂S removal process.

2.1.5.1 Liquid redox sulphur recovery processes

The Stretford process is a vanadium based aqueous liquid redox process primarily used in older geothermal plants built before 1990 and is most suitable with indirect contact condensers. More recently the vanadium based technology has been replaced by iron based process due to concerns associated with V content in the waste sulphur and solutions. Brieﬂy, H₂S is removed from NCG by contacting the NCG with the Stretford solution in a venturi scrubber and packed tower. In a reaction tank, alkali vanadates convert bisulphide (HS-) to elemental sulphur and V⁺⁵ converts to V⁺⁴. The V⁺⁴ is then regenerated to V⁺⁵ in oxidation tanks sparged with air using anthraquinone disulphonic acid (ADA) as an oxygen carrier. There, sulphur is also separated from the solution by ﬂotation. The main chemicals used are vanadium, ADA and caustic soda. A newer version of the Stretford process (LO-CAT, SulFerox) uses chelated iron (Fe), thus allowing high concentrations of Fe in solution. Iron chelates react with H₂S in the gas contactor quickly forming solid elemental sulphur particles with high removal eﬃciency. Iron chelates are regenerated with oxygen from air and sulphur particles are removed by settling and ﬁltration. When H₂ concentrations in the NCG are low enough, adsorption of H₂S, reduction and oxidation of Fe chelates can all occur in the same reaction vessel therefore signiﬁcantly simplifying the process (less equipment and fewer side reactions) (LO-CAT Autocirc). The main chemicals used are Fe chelates, surfactants, caustic soda and sometimes chelant degradation inhibitors and biocides. Main problems associated with these processes are solution foaming, plugging of vessels and pipes by sulphur and high chemical make-up rates [Mamrosh et al. 2012].

2.1.5.2 Modiﬁed Claus process

The Claus process is the standard technology used for handling large amounts of H₂S at natural gas processing plants and oil reﬁneries. There H₂S is converted to elemental sulphur. The NCG stream is burned where air is only enough to burn one third of the H₂S to SO₂ and to completely burn H₂ and CH₄. The SO₂ is then reacted with a solid catalyser at elevated temperatures with the remaining H₂S to form elemental sulphur. The elemental sulphur is condensed to molten sulphur. Hydrogen in the NCG may aﬀect the H₂S conversion process in the Claus unit and an incinerator may be needed to remove additional H₂S from the tail gas [Mamrosh et al. 2012]. The Claus process is not common in the geothermal sector but a variety of the process, called Selectox where elemental sulphur production is carried out at lower temperature is operated in Japan.

2.1.5.3 Burn scrub process

In a burn/scrub process the NCG stream is incinerated oxidizing H₂S to SO₂. The H₂ and CH₄ are also combusted. The incinerator may be equipped with a heat recovery system where water is converted to steam which is then diverted to the turbine generator. The incinerated NCG is then routed through a quench vessel to cool the gas and scrubbers to remove the SO₂ [Mamrosh et al. 2012]. The burn/scrub process is most often integrated into the cooling towers or is operated as a standalone system. When the process is integrated into the cooling towers, the SO₂ scrubbers are operated at pH 6-8 and require approximately two parts caustic soda per equivalent of SO₂ to form Na₂SO₃ and water. Standalone units may be operated at lower pH (as low as pH 4 for adequate adsorption eﬃciency) due to the relatively low dissociation constant (pKa1 = 1.9) of H₂SO₃. Therefore lower amounts of caustic soda may be required, however this is not normal mode of operation and is not widely applied [Mamrosh et al. 2012].

2.1.5.4 Amines and physical solvents

A process involving amines or physical solvents includes adsorption of a selected gas from the gas stream in a solvent and venting other gases (ﬂue gases or natural gas) from the adsorption tower. This process is the most common CO₂ capture process in the carbon capture and storage/ utilisation industries. For geothermal applications, the H₂S is separated from the NCG in an adsorption tower containing solvent, the solvent is then diverted to a heater where H₂S is boiled from the solvent resulting in a more or less pure stream of H₂S that may be treated further, re-injected as a gas to the reservoir or dissolved in water prior to re-injection. A double system may be applied where H₂S from the NCG is dissolved in the ﬁrst step. The resulting CO₂ rich gas may then be diverted to a second step where CO₂ is removed and the resulting gases, primarily H₂ may be incinerated or used further.

2.1.5.5 Water absorption and injection

Water is not typically used as H₂S absorbent as there are many sorbents that have much higher aﬃnity to H₂S. The solubility of H₂S in water at high pressures can though be substantial. Brieﬂy the technology includes compression of the NCG stream up to selected pressure. The gas enters an absorption column and water is pumped into the column from above. H₂S and CO₂ are dissolved in the water and other gases (H₂, CH₄ and others) are vented oﬀ. The H₂S loaded water is then pumped into the subsurface where pressure conditions are higher than the partial pressures of the dissolved gases to prevent degassing.

Where ample amount of water is available, water adsorption may be feasible to prevent release of chemical absorbents from the H₂S capture process. The water used to dissolve H₂S may be fresh ground waters, condensates or separated waters. Since the H₂S loaded ﬂuid becomes acid (pH 3-5, depending on the partial pressure of H₂S and CO₂ in the water) corrosive resistant materials need to be used for all handling. Furthermore, prevention of air entering the condenser and therefore the NCG stream is critical to prevent oxidation of H₂S to sulphuric acid. An operation of this technology requires understanding of the reservoir conditions as well as the capture process itself. H₂S migration processes have to be understood. This technology is not widely adopted in the geothermal sector although it is known at some installations in the oil and gas industry [Mamrosh et al. 2012]. Currently, this type of system is operated as a demonstration plant attached to the Hellisheiði geothermal plant in Iceland [Aradottir et al. 2014]. There the NCG gas stream is compressed into an absorption tower where condensate waters dissolve the H₂S and CO₂. The mixture is then pumped to an re-injection well cased down to the high temperature reservoir [Aradottir et al. 2014]. In the reservoir the corrosive water is predicted to react with the host rocks and producing sulphides therefore minimizing the risk of the H₂S being transported to the surface again.

2.1.5.6 The AMIS system

Enel in Italy developed the AMIS system which is a technology for simultaneous removal of H₂S and mercury from the power plants emissions. The technology was developed as the NCG content is mainly CO₂ (< 95 % by weight) and therefore combustion would require additions of substantial amounts of fuel. The ﬁrst commercial installation was started up in 2002 after developments since the early 1990s. Due to high NCG content all the condensers of Enel are direct contact condensers and NCG are extracted with centrifugal compressors. The process consists of three stages [Sabatelli et al. 2009]:

•Removal of mercury by chemical absorption;

•Selective catalytic oxidation of H₂S to SO₂;

•SO₂ scrubbing by a side stream of cooling water.

The technology has been proven to be successful and the majority of Enel power plants are equipped with it treating more than 80 % of the total H₂S emissions and they are available > 90 % of the time. Most problems rise from machinery problems. The rated values of eﬃciency for the technology are up to 90 % for H₂S and 95 % for Hg [Pertot et al. 2013]. The AMIS technology has also been simpliﬁed for H₂S treatment only in the Lardarello area [Sabatelli et al. 2009].

2.1.6 Engineered Geothermal Systems

Engineered geothermal systems (EGS) provide geothermal power by tapping into the Earth’s deep geothermal resources that are otherwise not exploitable due to lack of water and fractures, location or rock type. EGS technologies have the potential to cost-eﬀectively produce large amounts of electricity almost anywhere in the world. At the moment, several pilot projects are being conducted in Australia, Europe, Japan and the US. The basic concept is to drill two wells into a hot dry rock with limited permeability and ﬂuid content at a depth of 5–10 km. High temperature reservoirs (200 °C) have though been found as shallow as 3 km, where the temperature gradient is high (60–65 °C/km).

The EGS technology creates permeability in the rock by hydro-fracturing the reservoir with cold water pumped into the ﬁrst well (the injection well) at high pressure. The second well (the production well) intersects the stimulated fracture system and returns the hot water to the surface where electricity can be generated. Additional production wells may be drilled in order to meet power generation requirements.

Adoption of ﬂash or binary technologies may be used with EGS depending on the temperature of geothermal ﬂuid extracted from the artiﬁcial reservoir created by hydraulic stimulation.

Current practice for geothermal conversion systems shows that exergy eﬃciencies typically range from 25–50 %. Future engineering practice would like to increase these to 60 % or more, which requires further investments in research, development and demonstration (RD&D) to improve heat transfer, and improving mechanical eﬃciencies of converters such as turbines, turbo-expanders and pumps.

There is a strong need for EGS demonstrations to be scaled up. With wells extending up to 5 km in many cases, drilling poses a signiﬁcant challenge for EGS developers. The cost reduction of injection and production wells is the next big technological issue facing the commercialisation of EGS technology. A signiﬁcant technological hurdle is to control these deep-rooted fractures (exceeding 5 km) in order to create a large area for heat transfer and ensure suﬃcient mass ﬂow between wells. Before reaching large-scale commercialisation, it still requires significant improvements to lower the costs.

2.1.7 Re-injection

Geothermal energy is regarded a renewable resource. However, the resource may be overexploited if there is no balance between production and inﬂow into the resource. The optimum level of long-term sustainable production depends on the resource characteristics. The production and re-injection may have to be amended during the production history and new wells (both production and re-injection wells) are often drilled in strategic locations as better understanding is gained on the geothermal resource behaviour. The production and re-injection rate is then controlled to prevent the adverse eﬀects of premature pressure and temperature declines. The resource behaviour should therefore be monitored by the operators. The resource is frequently monitored by geochemical tracers, seismicity, reservoir pressure and temperature, micro-gravity. Results from these monitoring tools are then fed into reservoir simulation models which aid in planning the exploitation of the resource and predicting its behaviour in the future.

Re-injection wells may be as important as production wells for successful long-term production from a geothermal resource. The role and position of the re-injection wells is increasingly important as the reservoir permeability decreases. A hydrothermal resource with abundant fracture permeability may be operated without signiﬁcant pressure drop for decades without any re-injection. An EGS however will not be operated without at least one re-injection well. Re-injection wells further serve the purpose of allowing for disposal spent geothermal ﬂuids back into the ground, preventing the release of potential contaminants and heat into surface and shallow ground waters.

Successful re-injection of spent geothermal ﬂuids relies heavily on maintaining the permeability of the feed zones intersected by the re-injection wells. Oversaturation of secondary minerals should therefore be prevented or their precipitation rates at least be slowed down if possible. In ﬂash systems, this oversaturation may be decreased by dilution with condensate waters. Lowering scaling rates by various chemical methods such as pH adjustment, inhibitors have is a common practice to facilitate suﬃcient re-injection [Gallup 2011]. Re-injection of separated water into a fractured reservoir was greatly facilitated by mixing it with cooler condensate water prior to re-injection [Gunnarsson et al. 2015]. There the widening of fractures due to thermal contraction of the reservoir rocks were large enough to compensate for decreased viscosity of the ﬂuid and the operation of the re-injection zones takes these eﬀects into account. Prior to dilution of spent geothermal ﬂuids during re-injection a thorough geochemical study should be carried out to predict if undesirable reactions may take place leading to scaling in re-injection wells or the feed zones. Furthermore dilution of spent ﬂuids with cold water may not be desirable in a matrix dominated as the cooling front may reach the production wells faster than desired.

2.1.8 Direct use

Direct use is the oldest form of geothermal energy exploitation by mankind [Gudmundsson 1985]. Diﬀerent categories of direct use exist, for example: space and district heating, greenhouse heating, aquaculture pond heating, agricultural drying, industrial uses, cooling, snow melting, bathing and swimming [Lund 2011]and updates the previous survey carried out in 2005. We also compare data from 1995 and 2000 presented at World Geothermal Congresses in Italy and Japan, respectively (WGC95 and WGC2000). The main applications worldwide are bathing & swimming and space/district heating (Section 4.1.2). Usually, direct use is working with temperatures below 150 °C [Blanco Ilzarbe et al. 2013]. Advantages of direct use are a widespread resource available at economic drilling depths and the use of conventional well drilling, heating and cooling equipment [Lund 2009].

A basic direct use system often applied in low permeability reservoirs is shown in Figure 8. Usually, heat exchangers are used in order to have a clean secondary ﬂuid circulating through the user side of the system as the geothermal ﬂuid usually is unsuitable for direct use due to ﬂuid chemistry [Karlsson & Ragnarsson 1995]. The main components of a direct use system are the down hole and circulation pumps, pipelines, and the heat extraction and exchange parts [Lund 1998].

Fig. 8:Schematic process ﬂow diagram for a direct use system with heat exchanger. Source: [Lund 1998], adapted

The downhole pumps used in direct use applications are lineshaft pumps or submersible pumps. Lineshaft pumps are less expensive and have successfully been used since long. However, for depths greater than about 250-350 m, submersible pumps are needed [Lund 1998].

Piping for transmission and distribution are usually made from carbon steel, especially when temperatures above 100 °C are involved. Also ﬁbre-reinforced plastic (FRP) and polyvinyl chloride can be used. Pre-insulated pipelines are common nowadays [Yildirim et al. 2010]. Pipelines can be installed aboveground or underground. Aboveground installation allows for easy maintenance, however, damage from accidents or vandalism can be more probable. In addition, several issues might prevent aboveground pipelines, including diﬃculties with road crossings, expansion provisions, and insulation protection [Yildirim et al. 2010]. If pipelines are installed below ground, a protection by coatings or wrappings is needed. In some district heating systems, concrete tunnels have been used which is an expensive option but allows easier maintenance, future expansion, and also the possibility for co-utilisation with other users such as domestic water, electricity, telecommunication [Lund 1998, Yildirim et al. 2010]. A cheaper underground solution is to directly bury the pipelines.

Three diﬀerent types of heat exchangers are suitable for direct use of geothermal energy: plate, shell-and-tube, and downhole heat exchangers [Lund 1998]. Plate heat exchangers are very common in geothermal applications due to small size, and fewer costs compared to other types of heat exchangers. In addition, plate heat exchangers can easily be increased or reduced in size if needed by adding or removing plates from the stack. In special applications, downhole heat exchangers are used.

Many geothermal direct use systems are equipped with a peaking system or a back-up plant for maximum load. Often, it is more economically to adapt the geothermal system to the base load and cover peak demand with a conventional boiler or other sources [Huenges 2011].

Concerning the development of the technology, already in 1984, Gudmundsson stated ”the technology of direct applications is available and should not be a barrier to further developments” [Gudmundsson 1985]. Standard equipment is being used for direct use projects. Recently, [Blanco Ilzarbe et al. 2013] found that there are not many new patents in the area of direct use besides some developments in the area of integration of geothermal energy use in buildings. In the following sections we will focus on recent advances in the most important area of direct use, namely space and district heating.

The most common basic direct use systems, for example in Iceland, are composed of downhole and circulation pumps, transmission and distribution pipelines, peaking or back-up plants, and various forms of heat extraction equipment. Fluid is often disposed of at the surface [Lund 1998]. Doublet systems, with one production and one injection well were initially developed in the 1960s and became common in the 1980s [GEODH 2013]. Distance between wells is set in a way so that resource extraction for at least 20 years is guaranteed before the production wells start to cool down [EGEC 2007]. Wells can reach depths of about 2000 to 3500 m. To avoid corrosion of steel casings, ﬁbreglass lined production wells, introduced in the 1990s are often used [EGEC 2007].

At the moment, district heating systems is the geothermal sector with the most dynamic development [EGEC 2013a]. Newer developments include concepts to extend lifetime of doublet design projects by drilling a third production well and converting the former two wells into injection wells (triplet system). This concept, mainly applied in France, can allow for 30 additional years of use of the geothermal resource [EGEC 2013a]. Concerning new space/district heating systems, more and more triplet systems are installed. Also smaller systems are becoming more common with shallower resources, sometimes used in combination with large heat pump systems [EGEC 2013a]. More recently, geothermal resources of low to medium temperature are now used for combined heat and power production with a binary cycle power plant ﬁrst and subsequent direct use, which also improves the economics of geothermal projects [Lund 2011]and updates the previous survey carried out in 2005. We also compare data from 1995 and 2000 presented at World Geothermal Congresses in Italy and Japan, respectively (WGC95 and WGC2000).

2.1.9 Ground source heat pumps

Ground source heat pumps (GSHP) use shallow geothermal energy which is available almost everywhere. They convert the low temperature geothermal energy to thermal energy at a higher temperature which can be used for space or water heating [Ochsner 2008]. Usually, a refrigerant is used as the working ﬂuid in a closed cycle [Self et al. 2013]. An antifreeze solution is circulated inside a closed coil and exchanges heat with the heat source/sink through the ground heat exchanger (Figure 9). While in Europe, water-to-water systems are common, mainly water-to-air systems are used in the US.

Fig. 9:Schematic process ﬂow diagram for a ground source heat pump system

Electric energy is used to drive the compressor and the eﬃciency of the performance of a heat pump is measured by calculating the ratio of delivered to used energy which is the coeﬃcient of performance (COP) [Ochsner 2008, Vellei 2014]:

Equation 7

The COP depends on the temperature diﬀerence between heat source and heat sink. The smaller the temperature diﬀerence, the more eﬃcient the heat pump will be. GSHP usually have a COP in the range of 3-4 but can reach even up to 6 when well-designed [Carlsson et al. 2013, Goldstein et al. 2011, Puttagunta & Shapiro 2012].

The ground collector of a GSHP mainly takes the form of horizontal loops or vertical loops made of polyethylene or polypropylene tubes [Gazo & Lind 2010, Self et al. 2013]. Horizontal loops are the most common type of system since they oﬀer the lowest costs. They oﬀer a high ﬂexibility with regards to installation options but need large areas. In contrast, vertical loop systems can be used when access to land is restricted. Due to higher drilling costs, vertical loop systems are more expensive than horizontal loops [Gazo & Lind 2010]. Another system uses direct exchange loops (often called single loops). These allow heat transfer between the ground and the refrigerant as closed (copper) loops are buried directly in the ground. Direct exchange systems have higher thermal eﬃciency and can be smaller. However, they are sensitive to damage on tubing and there is the risk of refrigerant leakage to the soil.

More recent innovations include the use of underground thermal energy storage (UTES). With UTES, heat is stored during the summer period and used in winter. Thermal energy can be stored in aquifers or in spaced boreholes. Also solar thermal collectors can be added to GSHP systems. They can be directly added to the GSHP’s ground loop and to increase effi ciency of the system while reducing the demand for land area.

The installed capacity of GSHP has seen a dramatic increase with annual growth rates of 10 % since 1994 with a main focus on Europe and the United States [Self et al. 2013]. Shallow geothermal energy use is much greater than geothermal energy direct use of electricity production both with respect to installed capacity, and energy production [EGEC 2013a]. Despite the successes in the past and continuous growth, RD&D in GSHP is focussing on further increasing the eﬃciency of GSHP systems and reducing costs [Angelone & Labini 2014a]. The main development areas include ease of maintenance and repair, improved control systems, more eﬃcient working ﬂuids, and increased eﬃciency of auxiliaries such as pumps and fans [Angelone & Labini 2014a]. Ground collectors should be improved by optimisation of design and grouting material [RHC 2014]. In the long term, the aim is to develop better materials for the ground collector. Currently mainly plastics tubes are used which oﬀer low cost and corrosion resistance but show low thermal conductivity [Angelone & Labini 2014b]. The Geothermal Energy Roadmap of the European Technology Platform on Renewable Heating & Cooling recommends the development of new antifreeze ﬂuids that are environmentally benign, and oﬀer better thermal characteristics than current ﬂuids [RHC 2014].

2.1.10 Materials in the geothermal sector

An important parameter in power plant design and operation is the selection of suitable materials during the construction process. Similarly strategic location of sampling points to collect steam, gases and ﬂuids from the processes is important to allow for preventive measures to be taken prior to costly damage to equipment.

2.1.10.1 Corrosion

Geothermal ﬂuids are often characterised by high salt concentrations, high temperature and pressure and the presence of dissolved gases such as H₂S. This may cause substantial corrosion to metal components of geothermal energy plants which leads to quicker wear of materials and eventually to higher maintenance and repair costs, and downtime [Milles 2012]. Corrosion is a great concern for geothermal power plant operators [Mundhenk et al. 2013]. It can occur at various components of geothermal power plants including liners and well casings, well heads, turbines, heat exchangers, and pipes. As condensers operate under vacuum conditions there is always a risk of leaking of atmosphere into the unit and resulting in both formation of elemental sulphur that can clog components and sulphuric acid. The atmosphere may also enter the condenser with gland steam if a turbine doesn’t have speciﬁc extraction system to eject the gland steam. Liners and well casings are most aﬀected when the deep ﬂuid is acidic and/or saline while corrosion in heat exchangers is commonly due to stress corrosion cracking [Fridriksson & Thórhallsson 2006].

Material selection can prevent corrosion, however, may lead to increased costs [Fridriksson & Thórhallsson 2006, Gunnlaugsson et al. 2014, Mundhenk et al. 2013]. It is recommended not using high yield-strength steel for casing and liners, and to use chromium steel for the upper parts of casings. High-temperature cement should be used to ﬁx casings [Fridriksson & Thórhallsson 2006]. Turbine components in geothermal power plants have to be made of materials that can resist corrosion which is mainly due to gases such as H₂S present in geothermal steam. In general, 12 % chromium steel has been successfully used [DiPippo 2012]. The selection of the most suitable alloy depends on the speciﬁc component and environment it will be used. Alloys that have been used include titanium, nickel, chromium, molybdenum, cobalt, zirconium, tantalum, and aluminium [Kaya & Hoshan 2005]. Under high H₂S concentrations indirect steam condensers are sometimes constructed with titanium pipes to prevent corrosion.

Besides careful material selection, research and development of new materials is proposed to mitigate the eﬀects of corrosion on the economic performance of geothermal energy plants. [Angelone & Labini 2014a] mention new components from polymers or plastics, optimised coating, and the utilisation of aluminium. Fibre-reinforced plastics and concrete-polymer mixtures have seen increasing use in the past [Kaya & Hoshan 2005]. Another strategy proposed is to accept corrosion-related replacement of parts while using low-cost materials.

2.1.10.2 Scaling

Scaling is a phenomenon that can occur frequently in geothermal power plants. Solids are formed within a solution by chemical reactions or precipitation by oversaturation [Huenges 2011]. Often, scaling is due to pressure drops, temperature or pH changes, increased levels of oxygen and/or corrosion [Mundhenk et al. 2013]. In principle scaling can occur in production wells, the surface equipment, and reinjection wells [Fridriksson & Thórhallsson 2006]. The solids can form on the surfaces of e.g. heat exchanger, or pipes and can clog them. Once scaling has commenced on piping surfaces, the course surface promotes further crystal growth towards the water ﬂow direction as turbulence is increased adjacent to the scale surface. The solid particles formed on pipe walls and heat exchangers can fall oﬀ the walls (for example during pipe expansion and shrinkage during heating and cooling) and ending up in pump heads causing mechanical erosion. A considerable scaling can occur during mixing of diﬀerent water types, for example when cold oxygen rich water is drawn into a hotter oxygen poor reservoir.

Many ways to combat scaling exist, chieﬂy depending on the type of scaling (silica and sulphides in high temperature systems, carbonates in low and medium temperature systems and other types). They include preventing turbulent ﬂow in pipes, reducing temperature changes and avoiding large pressure drops across valves. However, reduction of temperature decrease and pressure drop has to be studied in conjunction with the desired eﬃciency of the energy conversion process. Since the eﬃciency of the conversion process is directly related to the temperature diﬀerence through the process considerable eﬀort has been placed into adjusting the pH of separated waters to prevent scaling [Gallup 2011, Sigfusson & Gunnarsson 2011]. Scaling inhibitors can also be applied and scale can also be removed mechanically or with acids [Huenges 2011]. Another approaches to prevent scaling is the application of coatings with anti-adhesive properties [Mundhenk et al. 2014]. Finally silica polymerisation has been proven to be successful to prevent silica scaling from separated waters prior to re-injection [Gunnarsson et al. 2010].

The knowledge of the chemical composition of the ﬂuids and gases is important to understand potential scaling and corrosion problems during preparation, installation and operation of any geothermal installation. An eﬀort should be made to sample and characterise ﬂuids and gases likely to be involved in the processes. Based on these analyses, geochemical modelling may be carried out to predict scaling and corrosion problems. However, the thermodynamic and kinetic datasets used to predict mineral saturation state and rate of chemical reactions occurring in geothermal systems and power plants are not complete and the geochemical modelling therefore may have considerable margin of error. Therefore, laboratory experiments often need to be conducted to validate and compliment the modelled results. Although laboratory experiments take time and can bear some cost, the understanding gained on the process by accurately characterising each process can lead to signiﬁcant cost savings during the design, construction and operation of the geothermal installations.

2.1.10.3 Saturated vapour in turbines

According to [DiPippo 2012], in liquid-dominated geothermal systems, steam is used as saturated vapour which leads to moisture being present in steam paths. As a consequence, droplets can form at the end of the lower pressure stages of turbines and strike the blade edges leading to erosion pits. To prevent this, turbine blades can be reinforced with appropriate alloys, for example, cobalt-rich alloys. Moisture separators are usually located directly in front of the turbine unit to remove moisture condensed in the pipelines leading from steam/ water separators to the turbines. Methods applied to monitor moisture entering the turbines include a regular monitoring of sodium in the steam. There, a small portion of the steam is condensed prior to being analysed either by a Na-selective electrode or with other analytical methods (atomic adsorption, ion chromatography). As Na only exists in the separated water, the measurement of Na in the steam gives a useful indication of the separated water portion in the steam and therefore the eﬃciency of steam / water separators. In vapour-dominated geothermal systems, the transition from superheated to saturated steam may lead to corrosion if hydrochloric acid is present in the superheated steam. Droplets in the steam may also be measured by laser absorption methods that are currently under development.

2.1.10.4 Shallow geothermal

In the shallow geothermal sector, research and development (R&D) has a key focus on improving materials used for borehole heat exchangers and ground loops. The main goal is to allow for a better energy transfer and to reduce costs by keeping lifespan similar to the materials currently used [RHC 2014].

2.2 Current challenges and possible bottlenecks

The key issue the geothermal power sector faces is the deployment of EGS technology. To date, the technology has been demonstrated on small scale in few locations. However, for an adequate proof of concept the technology needs to be demonstrated under diﬀerent geological conditions where permeability can be produced and maintained without having to rely on pre-existing fractures in the reservoirs. Operators need to demonstrate the ability to adequately control reservoirs in diﬀerent settings, both in terms of heat extraction and from chemical stimulants and seismic point of view. In the process of providing widely applicable proof of concept of EGS, drilling technologies as well as reservoir management and monitoring technologies should be developed extensively.

2.2.1 Estimate of resource potential

It is well known that the heat stored in the Earth’s crust is very high. However, the estimation of heat in place would beneﬁt from more direct measurements. An extensive drilling campaign has been proposed by the European Geothermal Energy Council (EGEC) and would bring beneﬁts to the geothermal sector in two ways: ﬁrst, it would facilitate a more accu rate estimate of the resource potential in Europe by establishing temperature gradients and heat ﬂows in the crust and provide a better picture of the geology in the area. Second, due to increased drilling activities in the sector, knowledge and expe rience would be accumulated quicker.

2.2.2 Drilling risks and costs

Today, drilling costs often constitute more than half of the cost associated with construction and commissioning of a geothermal power plant. Drilling into hydrothermal reservoirs includes drilling into highly heterogeneous materials where hard rocks may alternate with fractures where complete loss of circulation and collapsing geological formations may be experienced. Loss of circulation can lead to extensive losses of drill muds and cements. Collapsing formations may prevent movement of casings and in worst cases lead to the necessity of cutting the drill string causing the bottom hole assembly, collars and parts of the drill string to be left in the well [Sveinbjornsson & Thorhallsson 2014]. An intensive drilling campaign as mentioned in the chapter above provides the opportunity to develop and test novel drilling technologies in a reasonably short period of time and better direct resource potential and drilling development projects are therefore highly complementary.

2.2.3 Stimulation

Today, natural permeability of geothermal reser voirs determines the productivity of geothermal wells. Some eﬀort has been put into geothermal reservoir stimulation but the knowledge gathered to date appears fragmented. Existing stimulation methods need to be reﬁned to increase the rate of success, to improve predictability of results, to remove well and formation damage, to develop and prop fracture networks, and to reduce environ mental hazard (pollution of aquifer, induced seis micity). Research should focus on understanding the underlying processes leading to improved permea bility and develop concepts to minimise unwanted side eﬀects. The reservoir stimulation research would complement the overall goal of proving the EGS concept under diﬀerent geological conditions.

3 EU AND MEMBER STATE POLICIES RELATED TO GEOTHERMAL ENERGY

There are several EU directives aﬀecting the geothermal sector the most important one being the Directive on the promotion of the use of energy from renewable sources adopted on 23 April 2009 [EC 2009a]. In the following sections, a summary of polices related to geothermal is given.

3.1 National Renewable Energy Action Plans (NREAP)

The Directive 2009/28/EC introduces National Renewable Energy Action Plans (NREAP) that each Member State must adopt [EC 2009a]. The NREAP lay out how the Member State will achieve the mandatory target of 20 % share of energy from renewable sources in total energy consumption by 2020. The NREAP include the use of geothermal for power production as well as heating and cooling. The Commission Decision 2009/548/EC establishes a template for the NREAP [Commission Decision 2009]. Nineteen of European countries have adopted one or more categories of geothermal into their NREAP. Table 3 provides a summary of the NREAP targets for geothermal energy in EU member states for the years 2012 and 2020 and reported values of geothermal energy use for the year 2012.

In 2012, the combined geothermal power capacity in EU28 was 934 MWe compared to NREAP 2020 targets of 1612 MWe. Heat production from direct sources was 9400 GWhth with NREAP 2020target at 30589 GWhth. Finally, shallow geothermal heat production was 27080 GWhth in 2012 with NREAP 2020target at 49340 GWhth.

Table 2 displays that in 2012, the installation of geothermal power plants and the heat production from GSHP exceeded EU28 NREAP targets of 2012. However the EU28 2012 targets for direct heat production were slightly missed.

Table 2:Geothermal power capacity and heat production in the EU28 in 2012 and NREAP targets in 2012 and 2020

Type

Reported values¹ 2012

NREAP
target 2012

NREAP
target 2020

Shallow geothermal (mainly GSHP)

GWhth

27080

18946

49340

Deep geothermal resources (direct heat)

GWhth

9404

10440

30589

Geothermal power capacity

MWe

876

787

1612

1) Source: [Antics et al. 2013]

The NREAP predicted values for 2012 are compared to reported data from the Member States that have included the respective technologies into their plans in Table 3, Table 4 and Table 5. Furthermore the 2020 target values are reported.

On the whole, the installation of GSHP has been faster than anticipated in Europe. Austria, Romania and Sweden have the highest proportional gain compared to their NREAP while Denmark, France, Italy, Netherlands, Slovenia and UK were furthest from reaching their 2012 NREAP targets.

For deep geothermal resources for direct use, the commissioning rate of new installations was low leading to heat production of 9404 GWhth compared to the NREAP targets of 10440 GWhth in 2012 (Table 4). Greece, Hungary and Lithuania have the highest proportional gain compared to their NREAP while Belgium and Netherlands are proportionally furthest from reaching their 2012 NREAP targets.

For geothermal power plants, the installed capacity in 2012 (876 GW) exceeded the NREAP targets of 787 GW (Table 5). The main reason is due to the commission of Italian power plants not anticipated in the NREAP. France and Germany are far from reaching their geothermal power targets. In France, no geothermal power development has occurred for the last 10 years except the EGS of Soultzsous Forets and targets will not be reached. In Germany, projects under construction promise 60 to 70 MWe until the end of 2015.

Table 3:Geothermal heat production with ground source heat pumps in the EU28 (GWhth) in 2012 and NREAP targets in 2012 and 2020

Country

2012

2020

NREAP target

Reported values¹

Diﬀerence

% diﬀerence

NREAP target

GWhth

GWhth

GWhth

GWhth

AT

128

1440

1312

1026

302

BE

442

335

107

24

1710

DE

3710

4200

490

13

6059

DK

1570

695

875

56

2314

EL

105

135

30

29

582

ES

187

210

23

12

471

FR

3954

2775

1179

30

6629

HU

70

110

40

58

1244

IT

779

472

307

39

6071

NL

1372

880

492

36

2814

RO

12

32

20

175

93

SE

4431

15200

10769

243

9478

SI

151

96

55

37

442

SK

12

12

100

47

UK

2024

500

1524

75

11083

Total

18947

27080

8133

49340

1) Source: [Antics et al. 2013]

Table 4:Deep Geothermal heat production in the EU (GWhth) in 2012 and NREAP targets in 2012 and 2020. Includes district heating, industry and agriculture, balneology and other

Country

2012

2020

NREAP target

Reported values¹

Diﬀerence

% diﬀerence

NREAP target

GWhth

GWhth

GWhth

GWhth

AT

256

184

72

28

465

BE

41

18

23

56

66

BG

28

16

12

44

105

CZ

0

25

25

0

174

DE

1326

729

597

45

7978

EL

244

504

260

106

593

ES

44

0

110

FR

2268

1316

952

42

5815

HU

1396

2849

1453

104

4152

IT

2780

2368

412

15

3489

LT

35

93

58

167

58

NL

872

202

670

77

3012

PL

337

187

151

45

2070

PT

163

96

67

41

291

RO

407

362

45

11

930

SE

270

270

0

SI

209

164

45

22

233

SK

35

0

1047

UK

21

21

0

Total

10440

9404

958

30589

1) Source: [Antics et al. 2013]

Table 5:Installed geothermal power generation capacity in the EU28 (MW) in 2012 and NREAP targets in 2012 and 2020

Country

2012

2020

NREAP target

Reported values¹

Diﬀerence

% diﬀerence

target

MW

MW

MW

MW

AT

1

1.4

0.4

40

1

BE

0

0

0

3.5

CZ

0

0

0

4.4

DE

27

11.9

15.1

56

298

EL

0

0

0

120

ES

0

0

0

50

FR

37

17

20

54

80

HU

0

0

0

57

IT

787

875.5

88.5

11

920

PT

25

28.5

3.5

14

75

RO

0

0.05

0.05

0

0

SK

4

4

100

4

Total

881

934

53

0

1613

1) Source: [Antics et al. 2013]

3.2 EU and Member State policies and ﬁnancing

Geothermal project development has high upfront cost and can take as little as 3 years but average development time is about ﬁve to seven years. Figure 10 shows the individual phases of a geothermal project and presents the ﬁnancial instruments needed in each of these steps [EGEC 2013b]. EU legislation on renewable electricity requires that dispatch priority is given to renewable electricity insofar as the operation of the national electricity system permits [EC 2009a]. There exists a number of support schemes within the EU and they diﬀer between the Member States. Below follows a short description of main mechanisms available for funding from the EU and Member states.

Fig. 10:The phases of geothermal projects and the mechanisms of funding throughout their duration. Reproduced from [EGEC 2013b]

3.2.1 Research, development and deployment

In the last 10 years, Member States have spent EUR 4.5 billion on renewable R&D. In the same period, the EU has spent EUR 1.7 billion from the Sixth (FP6) and Seventh Framework Programme (FP7), and the European Energy Programme for Recovery (EEPR). Until 2012, EUR 29.4 million were allocated from FP6 and FP7 to geothermal projects. Moreover, to date, the geothermal sector is the only one (with biomass) to have experienced a proportional reduc tion in FP7 funding (from EUR 17.3 million in FP6 to EUR 12.1 million). No geothermal project has been ﬁnanced by the EUR 4.5 billion EEPR programme that commenced in 2009.

3.2.2 NER 300 programme

The New Entrants’ Reserve 300 (NER 300) programme is another ﬁnancing instrument at EU level used to subsidise installations of innovative renewable energy technology and CCS. In December 2012, the European Commission, in the ﬁrst call for proposals, awarded about EUR 39 million to the Geothermal South Hungarian EGS Demonstration Project [Commission Decision 2012]. A second call was launched in 2013 and another 2 EGS proj ects have been awarded funding: the Croatian Geothermae project (about EUR 14.7 million) and the French Geostras project (about EUR 16.8 million) [Commission Decision 2014].

All the geothermal projects funded are EGS projects with a nominal capacity greater than 5 MWe. The Hungarian EGS Demonstration project is a project falling under the subcategory “EGS in compressional stress ﬁelds” while the other two projects are of the subcategory “EGS in areas with deep compact sedimentary and granite rocks and other crystalline structures”. Maximum funding rates for the projects are between about 21 EUR/MWh to 57 EUR/MWh.

3.2.3 Risk insurance funds

Risks associated with geothermal project develop ment include short term risks such as the risk not ﬁnding an adequate resource and long term risks (e.g. decline of resource over time due to production). The resource is conﬁrmed only after the exploration and drilling is ﬁnished; these two processes often repre sent most of the costs associated with the develop ment of a geothermal project. The average period for developing geothermal power projects to commercial deployment is ﬁve to seven years. However, once the feasibility of a resource has been established, the probability of project success is higher than 80 %. Risk insurance funds for the geological risks associ ated with geothermal projects exist in three Member States as well as in Iceland and Switzerland [EGEC 2013b]. Geothermal developers struggle to ﬁnd insurance (public or private) schemes with aﬀord able terms and conditions for the resource risk. This is due to a relatively limited number of geothermal electricity operations in the EU and the diﬃculties met while assessing the probability of success. The European Geothermal Energy Council (EGEC) has proposed a European Geothermal Risk Insurance Fund (EGRIF) that aims at alleviating the shortage of insurance policies for the resource risk and easing investments in geothermal electricity projects.

3.2.4 Feed-in-tariﬀs

A feed-in-tariﬀ (FIT) is a ﬁxed and guaranteed price paid to the eligible producers of electricity from renewable energy sources. In 2014, this policy instru ment was available in 23 EU Member States. Of these, Germany, France, Slovenia, Slovakia, Spain, Austria, Czech Republic, Greece, Portugal (Azores only) and Hungary have dedicated FIT for geothermal energy. The most attractive schemes are found in Germany (25 c EUR/kWh for all projects and additional 5 c EUR for EGS) and France (20 c EUR/kWh with an energy eﬃciency bonus of up to 8 c EUR/kWh) [Angelone & Labini 2014b]. In 2011, feed-in-tariﬀ schemes were the most signiﬁcant form of operating support for renewable energies [EC 2011]. Analyses on the eﬀect of feed-in-tariﬀs in the geothermal sector remain few and more emphasis has been laid on their eﬀect on for example photovoltaics (PV) and wind. For PV and onshore wind in Europe, [Jenner et al. 2013] concluded that feed-in-tariﬀ policies had driven PV development in Europe since 1992 via their expected return on investment (ROI) faced by investors. They did not ﬁnd clear evidence that feed-in-tariﬀ policies had driven wind power development except when combined with tendering schemes. Similarly, [Jenner et al. 2013] showed that policy design, electricity price and electricity production cost were more important determinants of renewable electricity development than policy enactment alone.

A study on the combination of deployment instru ments (feed-in-tariﬀs, investment subsidies and soft loans) did not result in lower policy costs [MirAtrigues and del Río 2014]. However, combina tions of support schemes may lead to intertemporal distributions of the same amount of policy costs. This redistribution of costs may aﬀect social accept ability and political feasibility of renewable energy support [MirAtrigues and del Río 2014]. The timing of costs is of particular relevant for geothermal projects as the costs tend to occur over long times, for example, it typically takes seven to eight years from initiation of exploration until entry into opera tion for a geothermal power plant.

3.2.5 Feed-in-premiums

Feed-in-premiums grant a payment per kWh on top of the electricity wholesalemarket price. Estonia, the Netherlands, Slovenia and Italy promote geothermal power generation by means of feed in premiums [Angelone & Labini 2014b].

3.2.6 Tradable Green Certiﬁcates

Tradable green certiﬁcate (TGC) programmes establish requirements to produce/deliver a certain percentage of electricity using renewable and other ‘green’ sources. Therefore technologies that qualify as green thus produce two distinct commodities, (1) electricity, which is sold in the normal electricity market and (2) green certiﬁcates, which are traded in a green certiﬁcate market. The income of selling the green certiﬁcates to producers or distributors of electricity from other sources covers the gap between the marginal cost of renewable electricity generation and the price of electricity. In 2014, six EU countries applied TGC schemes [MirAtrigues and del Río 2014] and Belgium (Flanders), Romania, and the UK apply the scheme for geothermal [Angelone & Labini 2014b].

3.2.7 Tendering

Tendering involves governments inviting renewable electricity (RES-E) generators to compete for either certain ﬁnancial budget or a certain RES-E generation capacity. Cheapest bids per kWh are awarded contracts and receive the subsidy. In 2014, nine countries employ tendering schemes.

3.2.8 Soft loans

Soft loans are usually provided by governments with rates below market interest rates and can in some cases signiﬁcantly lower capital costs. Furthermore, the repayment periods may be longer and interest holidays included.

4 GEOTHERMAL ENERGY MARKET STATUS

4.1 Global market status

As mentioned above, the following classiﬁcation according to [Antics et al. 2013] and Directive 2009/28/EC [EC 2009a] is used to deﬁne the diﬀerent markets within the geothermal industry:

•Power generation

•Direct use

•Ground source heat pumps

An overview over global installed capacity for power generation, direct use and GSHP in 2010 is shown in Figure 11. In general, lead markets for geothermal energy are in America, Europe and Asia. Installed capacity for GSHP is greatest, followed by direct use and power generation.

Fig. 11:Global installed capacity for power generation, direct use and GSHP in 2010 according to continent. Sources: [Boyd & Lund 2014, IGA 2014]

Some countries show signifi cant shares for GSHP while others dominate power generation (Figure 12). Highest total installed capacity of geothermal energy is in the United States, followed by China, and Sweden. The top 10 countries have about 75 % and the top 15 countries about 84 % of total installed capacity worldwide .

4.1.1 Power generation

In 2013, global installed capacity for geothermal power generation reached about 11.8 GWe [GEA 2013, IGA 2014]. The new installed capacity in 2013 amounted to 530 MWe [GEA 2014, REN21 2014], which is a new record in annual installations. Of this, 145 MWe were installed in Europe, 107 MWe in New Zealand, 85 MWe in the US and 36 MWe in Kenya [EGEC 2013a, GEA 2014, Mugo 2013, NZGA 2014]. The growth of global cumulative installed capacity was about 4 % in 2013 and higher than in the previous years when 3 % was reached for 2011 and 2012 [REN21 2014].

Fig. 12:Global installed capacity for power generation, direct use and GSHP in 2010 according to country Sources: [Boyd & Lund 2014, IGA 2014]

Asia is leading the cumulative installed capacity with 3.8 GWe, dominated by the Philippines (1.8 GWe) and Indonesia (1.3 GWe), followed by the US with 3.4 GWe (Figure 13). Total installed capacity in Europe amounts to about 1.7 GWe. Concerning the rest of the world, Mexico deserves to be mentioned with an installed capacity of about 1 GWe.

Fig. 13:Global installed capacity for power generation. Source: [IGA 2014]

Geothermal electricity generation has continuously increased and in 2012, more than 70 TWh have been produced (Figure 14). In 2012, geothermal electricity generation accounted for about 1.5 % of global renewable and 0.3 % of total global elec tricity production [Observ’ER 2013a].

Fig. 14:Global electricity generation between 1995 and 2012 Sources: Own calculations, based on [IEA-GIA 2013, Observ’ER 2013a, OECD/IEA 2013]

4.1.2 Direct use

The direct use of geothermal resources in this report means the direct thermal extraction for heating and cooling excluding heat pumps (for heat pumps, see Section 4.1.3). Possible direct uses are: space and district heating, heating of public baths and swimming pools, heating of greenhouses, industrial process heat, and agricultural drying.

Information on installed capacity for direct use is diffi cult to fi nd and o_ en, statistical data are missing [EGEC 2013a]. Global installed capacity of direct use (without heat pumps) is estimated between 19 GWth and 26 GWth [REN21 2014]. Countries with largest direct use (without heat pumps) include China (about 3.7 GWth), Turkey (about 2.7 GWth), Iceland (about 2.2 GWth), and Japan with about 2.1 GWth of installed capacity [REN21 2014].

In 2013, installed capacity for direct use of geothermal energy increased. However, it was difficult to find precise information on new installations. According to [REN21 2014], capacity grew in Europe (Hungary, Italy, Germany). Unfortunately, data on historical development of capacity for direct use (without heat pumps) according to country could not be found [Boyd & Lund 2014].

Data on the past development of installed capacity according to use shows a steady increase and capacity in 2010 was about 2.5 times the installed capacity in 1995 (Figure 15). The greatest increases in absolute terms have been achieved for bathing and swimming and industrial uses, followed by space/district heating. Direct utilisation of thermal resources in terms of heat followed a similar trend than installed capacity.

The share of the individual users diﬀers consider ably between countries, and regions. In Iceland, for example, space/district heating and snow melting dominates direct use while in Japan, bathing and Industrial uses Agricultureal drying Aguaculture pond heating Greenhouse heating Space/district heating swimming accounts for more than 80 % if direct use [Lund et al. 2010].

Fig. 15:Global installed capacity for direct use from 1995 to 2010 Sources: [IEA-GIA 2012, IEA-GIA 2013]

Production of geothermal heat by direct users amounted to about 225 PJ in 2010 (Figure 16). China shows highest use of geothermal heat, with estimated use of about 46 PJ in 2009 [Lund et al. 2010, OECD/IEA 2011]. In the past, total global growth followed to a great extent the trend of worldwide installed capacity.

Fig. 16:Global direct use of geothermal energy Sources: [IEA-GIA 2012, IEA-GIA 2013]

In 2010, the largest direct uses globally (excluding heat pumps) are bathing and swimming (44 %), space/district heating (35 %), and the heating of greenhouses (10 %). Other direct uses such as agri cultural drying or pond heating are of minor importance, only.

Fig. 17:Share of global installed capacity according to direct use Sources: [IEA-GIA 2012, IEA-GIA 2013]

4.1.3 Ground source heat pumps

Installed capacity for ground source heat pumps by far exceeds installed capacity for power generation and direct use. However, statistical data often do not report the use of ground source heat pumps (shallow geothermal energy). Sometimes, they are subsumed under direct use. Data for global installed capacity and utilisation of heat pumps could be obtained from [IEA-GIA 2013] for 1995 to 2010. However, newer data was not available.

Both global installed capacity and use show a dramatic increase. In 2010, installed capacity was more than two times higher than 2005 about 18 times higher compared to 1995 and utilisation increased by 1200 % between 1995 and 2010.

Fig. 18:Global installed capacity and utilisation of ground source heat pumps. Source: [IEA-GIA 2013]

4.2 Europe

4.2.1 Power generation

The installed capacity of the 68 power plants in operation in Europe was about 1850 MWe at the end of 2013, producing about 11.7 TWh of electricity [EGEC 2013a]. The 51 geothermal power plants in the EU28 account for about 946 MWe and 5.56 TWh of electricity produced (Figure 19).

In 2013, 8 power plants have entered into operation with a capacity of about 145 MWe. In the EU28, new plants have been added in Germany (16 MWe), Romania (0.05 MWe), and Italy (1 MWe). Other new installations took place in Turkey (128 MWe).

Fig. 19:Installed capacity for power generation in Europe and additions in 2013. Source: [EGEC 2013a]

In terms of power plant technology, dry steam and single ﬂash technology dominate the European market, with shares of 48 % and 34 %, respec tively [EGEC 2013a]. New installations in 2013 were mainly binaryORC but one 80 MWe project in the Turkey deployed triple ﬂash (Figure 20).

Fig. 20:Installed capacity for power generation in Europe according to technology. Source: [EGEC 2013a]

Production of electricity in Europe reached 11.7 TWh in 2012 and 5.6 TWh in the EU according to [EGEC 2013a]. Information from Eurostat gives slightly lower results with 5.4 TWh of generation in 2012 which is mainly due to the fact that the new plants in Germany have apparently not been accounted for by [Eurostat 2014]. Figure 21 shows that electricity production from geothermal energy in the EU28 has been relatively stable during the past ten years.

In 2012, geothermal energy provided about 0.2 % of the total ﬁnal electricity demand (about 2800 TWh) and 0.9 % of the electricity generated by renewable sources (about 660 TWh) in the EU28. The capacity factor of the geothermal power plants in Europe was about 76 % in 2012, due to decommissioning and some plants had to be repaired and where only available from some days [EGEC 2013a].

Fig. 21:Net electricity generation from geothermal in Europe from 2003 to 2012. Source: [Eurostat 2014]

4.2.2 Direct use

The installed capacity for direct use of geothermal energy for heat in the European Union was about 3.0 GWth in 2012 (Figure 22). The countries that show greatest direct use are Italy, Hungary, and France. Direct use increased by almost 25 % between 2011 and 2012. However, an improved methodology to calculate direct use was introduced between 2011 and 2012, which leads to higher capacity, especially for balneology in Italy [Observ’ER 2013b]. Main direct uses in the EU are heating networks (about 50 % of direct use) and balneology (about 20 % of direct use). Currently, geothermal district heating has a share of about 0.5 % of the total district heating market [Euroheat 2014].

Fig. 22:Installed capacity for direct use in the European Union according to country. Source: [Observ’ER 2013b]

In total, about 27630 TJ of heat have been produced in 2012, which is an increase of 10 % compared to 2011 [Observ’ER 2013b].

Looking beyond the EU and considering Europe, only data for district heating could be found in [EGEC 2013a]. Total installed capacity in 2013 was estimated to be about 4.3 GWth with a production of about 46 300 TJ (Figure 23). Main players are Iceland with about 50 % (2.2 GWth) and Turkey with about 20 % (0.8 GWth) of the installed capacity in Europe [EGEC 2013a].

Fig. 23:Installed capacity and new additions in 2013 for district heating in Europe according to country. Source: [EGEC 2013a]

New major additions of capacity occurred in France, Hungary and Italy. In Hungary, a district heating plant was opened in 2013 in Miskolc which might reach a capacity of 60 to 70 MWth [PannErgy 2014, REN21 2014]. Another major inauguration took place in Italy where the Monteverdi Marittimo 6 MWth district heating plant was opened [REN21 2014]. In future, the installed capacity will grow mainly in Germany, France, and Hungary [EGEC 2013a].

4.2.3 Ground source heat pumps

Installed GSHP capacity in Europe amounted to about 16.5 GWth in Europe and 14.9 GWth in the EU [EGEC 2013a]. Main markets for GSHP in the EU are Sweden, Germany, France, and Austria (Figure 24). The total number of units installed was estimated to be about 1.34 million units in Europe (1.21 million in the EU) in 2013.

Fig. 24:Installed GSHP capacity in 2012 in Europe according to country. Source: [EGEC 2013a]

Major markets in the EU in 2012 were Sweden and Germany with 25 % and 21 % of market share, respectively (Figure 25). Total sales of geothermal heat pumps in 2012 were 6 % of installed units in 2011. European GSHP market has been shrinking in the recent years because the market is very much dependent on the new building market and since the construction sector still shrinks and fewer houses are built, also fewer GSHP units are sold [Observ’ER 2013b]. It is expected that the market will recover in the next coming years.

Fig. 25:Installed GSHP units in 2011 and sales in 2012 in Europe according to country. Source: [Observ’ER 2013b]

4.3 Asia

Figure 26 shows geothermal energy generation in 4000 Asia according to countries and use. In some countries, direct use & GSHP clearly dominates energy production, while in other countries, power gener ation (e.g. Indonesia, Philippines) has signiﬁcantly greater shares. In Asia, China is the country leading in geothermal energy use. According to [REN21 2014], however, uncertainties for direct use are high and the estimates for China range between 13 to 45 TWh for direct use excluding GSHP. [Zhao & Wan 2014] have estimated total production at 12.8 TWh for direct use and about 8 TWh for GSHP.

Fig. 26:Energy generation in Asia according to country. Source: [IGA 2014, OECD/IEA 2013], own calculations

The installed capacity for geothermal power gener ation increased signiﬁcantly in Asia between 1990 and 2010. Since then, growth has been slower (Figure 27). In the Philippines, degradation of some geothermal ﬁelds occurred [Menzies 2013]. In contrast, electricity generation has not increased at the same rate (Figure 28).

Fig. 27:Installed capacity for power generation in Asia according to country. Source: [IGA 2014]

Fig. 28:Power generation in Asia according to country. Source: [OECD/IEA 2013]

Recent new installation of power generation capacity include the 20 MW Maibarara geothermal power plant in the Philippines that was opened in February 2014 [MGI 2014]. In addition, the Bacman plant resumed operations in 2014 for two units at 55 MWe each [Business World 2014].

4.4 America

In America, only the United States, Canada and Mexico use geothermal energy to a greater extent (Figure 29). In the following, we will thus focus on those three countries only.

Fig. 29:Installed capacity for geothermal energy use in America. Source: [Boyd & Lund 2014]

4.4.1 United States

In the United States, about 3440 MW of power gener ation capacity were installed at the end of 2013 [GEA 2014]. In total, 85 MW have been installed during 2013 in Utah, California, Nevada and New Mexico (Figure 30). According to [GEA 2014], capacity additions have decreased by 40 % compared to 2012, 1250 mainly due to political barriers such as low prices for fossil fuels, and grid integration issues. In addition, it has to be noted that for many power plants, actual capacity is much lower than the initial capacity which is not reﬂected in statistics since often nameplate capacity is accounted for. The power plants at the Geysers geothermal ﬁeld have now a capacity of about 950 MWe while the nameplate capacity or the initial capacity of these plants was about 1550 MWe.

Fig. 30:Installed capacity for power generation in the United States and additions in 2013. Source: [GEA 2014]

GHSP account for about 12000 MW of installed capacity in the US and almost equals the installed capacity in Europe (Section 4.2.3). Market growth was about 10 % annually in the past [Trenchless 2010]. The largest manufacturers in the US are ClimateMaster and WaterFurnace [BNEF 2009].

Installed capacity for direct use in the United States is small compared to GSHP and electricity. Direct use in the United States takes many forms. It is dominated by space heating, aquaculture, bathing and swimming, and district heating (Figure 31) .

Fig. 31:Installed capacity for direct use in the United States in 2013. Source: [Boyd & Lund 2014]

4.4.2 Mexico

Mexico uses geothermal resources almost exclu sively for power generation with about 1 GWe of installed capacity (Figure 32). Since 2012 no new capacity has been installed. Electricity production has grown from 193 GWh in 1973 to about 5400 GWh today [QuijanoLeón & GutiérrezNegrín 2003].

Fig. 32:Installed power generation capacity in Mexico from 1990 to 2013. Sources: [IGA 2014, QuijanoLeón & Gutiérrez Negrín 2003], own calculations

4.4.3 Canada

In Canada, geothermal energy is used almost only for GSHP (about 1100 MW installed capacity in 2010). The GSHP market experiences considerable growth between 2003 and 2010 (e.g. more than 60 % annual growth in 2006, 2007, and 2008) but declined in 2010 and has stabilised since. In 2011, more than 12000 GSHP units have been installed [Canadian GeoExchange Coalition 2012].

Total installed capacity for direct use was 26 MWth in 2013, with 15 MWth for bathing and swimming and [CanGEA 2013]. Geothermal energy is currently not being used for power production despite a potential of about 5000 MWe [Thompson et al. 2013].

4.5 Rest of the world

4.5.1 Oceania

4.5.1.1 New Zealand

Currently, 13 geothermal power plants with an installed capacity of about 780 MWe are in opera tion in New Zealand. In 2013, 107 MW were newly installed (25 MWe at TOPP1, Norkse Skog Tasman and 82 MWe at Ngatakariki, Mighty River Power). In 2014, the Te Mihi plant has been handed over from the construction contractor to the owner and oper ator and should reach full production (166 MWe) at the end of the year. It is expected that the Wairakei plant will be phased out gradually from now on.

In New Zealand, geothermal power plants already provide 13 % of the countrys electricity demand [NZGA 2014]. Direct use in 2010 amounted to about 10 PJ with 55 % of it being used in industrial applications such as timber drying and paper processing [Climo et al. 2014]. GSHP market is in its very early days in New Zealand, with only few installations so far.

4.5.1.2 Australia

In Australia, geothermal energy is mainly used directly. According to [Lund et al. 2010], total installed capacity is about 33 MWth, mainly for bathing and swimming. Installed GSHP capacity amounts to about 24 MWth. The only power generating plant is a small 80 kW unit in Birdsville [Ergon Energy 2013].

4.5.2 Africa

In Africa, geothermal energy for power generation is currently being used mainly in Kenya (about 270 MWe installed capacity). In 2013, 36 MWe have been added to the 2nd unit of the Olkaria III plant and in 2014, unit 3 of Olkaria III was opened, increasing total capacity of the project by 26 MWe.

Geothermal energy is directly used in several coun tries, including Algeria, Tunisia, Kenya, South Africa, and Morocco [Lund et al. 2010]. The type of direct use diﬀers between individual countries, however, in general, the heating of greenhouses and bathing and swimming are the two applications showing the highest shares of installed capacity (Figure 33).

Fig. 33:Installed capacity for direct use in Africa in 2010. Source: [Lund et al. 2010]

4.6 Analysis and projections

Since only few sources were available concerning projections of direct use and GSHP, we will focus on power generation in this section. Current shortterm projections for future growth in power generation capacity from [BNEF 2013] are shown in Figure 34. For the midterm development, [BNEF 2013] esti mates 1016 GWe net additions by 2030 and an average growth of about 600 to 950 MWe per year. In the long term, the vision of [OECD/IEA 2011] is a worldwide installed capacity of 200 GWe in 2050 while [Goldstein et al. 2011] expect a capacity of 140 to 160 GWe by 2050.

According to [BNEF 2013], the total project pipe line encompasses 13.2 GWe in about 30 projects, with Indonesia leading (about 3.2 GW). The top 10 countries account for 80 % of the projects in the pipeline. The most common project type is a ﬂash cycle greenﬁeld project and the top ranked developer is Ormat with about 1 GW in the pipe line [BNEF 2013]. Estimates from [GEA 2014] are slightly lower, stating a global project pipeline of about 12 GWe with 1.9 GWe already being under construction. According to [GEA 2014], the cumu lative installed capacity could reach 13.5 GWe in 2017.

Fig. 34:Projections for global installed capacity and annual capacity additions 20152030. Source: [BNEF 2013]

In Europe, currently 74 projects are under development and 144 are being explored [EGEC 2013a]. Capacity will grow to 2760 MWe in 2017. A major increase of installed capacity is expected in Turkey. In the EU28, expected capacity will be about 1.6 GWe according to the National Renewable Energy Action Plans (NREAP) in 2020 [Observ’ER 2013b].

In Africa, Ethiopia deserves to be mentioned with 450675 MWe planned capacity by 2020 in six diﬀerent projects [Kebede 2012]. Plans in Kenya include 790 MWe of additional capacity by 2016 [Mugo 2013].

The current project pipeline in the Philippines includes additional capacity of about 1160 MWe between 2016 and 2020 [Ogena & Fronda 2013]. In Indonesia, two ﬁelds of 275 MWe are currently under construction and project of about 2400 MWe are in the pipeline [Samyanugraha & Lestari 2011].

Planned capacity additions in the United States amounted to 1000 MWe in 2013 and 3100 MWe of geothermal resources are under development [GEA 2014]. The geothermal project pipeline in the United States has decreased in 2013 compared to previous years, mainly due to lower demand in the U.S. for new geothermal power projects. It seems that major barriers are weak demand, inadequate transmission systems, permitting delays and a lack of coherent policy support. Thus, projects at an early stage of development are cancelled [GEA 2014]. Still, “the ratio of projects in later stages of development versus earlier stage projects has stayed roughly the same” [GEA 2014].

4.7 Power turbine manufacturer’s market

Globally, three major manufacturers (Mitsubishi, Ormat, Fuji) dominate the market in geothermal power, accounting for about 75 % of the installed capacity [EGEC 2013a]. In Europe, AnsaldoTosi is the market leader with about 40 % of installed capacity. Other prominent players in Europe are Mitsubishi, Fuji, and General Electric/Nuovo Pignone (Figure 35). Industrial growth strategies and proﬁles of individual companies are discussed in Section 4.9.

Fig. 35:Installed capacity for power generation and new additions in Europe according to turbine manufacturer. Source: [EGEC 2013a]

4.8 Ground source heat pump market

Table 6:Overview of major European GSHP manufacturers and brands

Company

Brand(s)

Country

Capacity

Comments

BDR Thermea

De Dietrich

France

717kW

12 300 heat pumps sold in 2013

Baxi

UK

420 kW

Brötje

Germany

621 kW

Sofath

France

632 kW

In total 50 000 heat pumps sold so far

Bosch
Thermotechnik

Junkers

Germany

617 kW

Buderus

Germany

770 kW

IVT Industrier

Sweden

616 kW

Swanlabelled GSHP

Danfoss

Thermia Värme

Sweden

445 kW

Nibe

Alpha-InnoTec

Germany

6160 kW

Belongs to Schulthess (daughter company of Nibe)

Nibe Energy Systems

Sweden

517 kW

Largest European manufacturer of domestic heating products

KNV

Austria

478 kW

Acquired in 2008. 13 000 heat pumps sold so far

Vaillant

Vaillant

Germany

646 kW

Second largest HVAC manufacturer

Viessmann

Viessmann

Germany

2117 kW

Satag Thermotechnik

Switzerland

319 kW

Acquired in 2004

KWT

Switzerland

62000 kW

One of the pioneers in GSHP

Ochsner

Ochsner

Austria

561 kW

110 000 heat pumps installed so far

Stiebel Eltron

Stiebel Eltron

Germany

613 kW

Acquired 35 % of share capital of Ochsner

Sources: Own research, [EHPA 2013, Observ’ER 2013c]

The European heat pump and also the GSHP market has developed from a market with many small local companies to a market dominated by major heating and airconditioning manufacturers [EHPA 2013]. For GSHP, the main European players are listed in Table 6. Countries of origin of manu facturers very much mirror the main markets for GSHP with many big producers being from Germany and Sweden.

Asian manufacturers which have been focussing on air/air heat pumps and air conditioning in the past are now more active on the European GSHP market. For example, Daikin recently launched a GSHP for residential usages while Mitsubishi’s Ecodan GSHP systems target medium to large commercial instal lations [Daikin 2014, Mitsubishi 2014]. Other manu facturers such as Samsung, LG, Panasonic and Hitachi seem not to have GSHP in their portfolio yet.

4.9 Industrial strategies

The geothermal industry is small with few compa nies active in the supply chain. The activities in the power and direct use sectors range from exploration, drilling, engineering, to construction and plant oper ation. Clearly, vertical integration is one of the strat egies a number of companies pursue, meaning that they are active in many or all stages of a geothermal project [REN21 2014]. Table 7 gives an overview over some of the major vertically integrated companies in the geothermal power sector. Most of the integrated companies play a strong role in the geothermal sector of a certain region or country and are now aiming at expand their footprint globally.

Other companies in the geothermal sector pursue a diﬀerent approach by oﬀering highly special ised services. Examples of drilling ﬁrms are Thermasource from the US or Iceland Drilling [Goldstein & Braccio 2014]. Examples for companies specialised in geothermal engineering are Mannvit and Verkis from Iceland and Power Engineers from the US [Goldstein & Braccio 2014, REN21 2014]. Only few companies are dealing with the cold end of large geothermal power plants with most turbine manufacturers being supplied by only one company, BalckeDürr [Gunnlaugsson 2014].

Table 7:Overview of major vertically integrated players in the geothermal industry

Company

Chevron

Enel Green Power

Ormat

Company
proﬁle

Multinational energy company. Active in oil, gas, and geothermal energy, including exploration, production, reﬁning, chemicals manufacturing, power generation.

Active in all kinds of renewables (wind, solar, hydroelectric, geothermal and biomass). More than 750 plants in operation or under construction in 16 countries.

Subsidiary of Enel, Italy’s largest power company and Europe’s second listed utility

World leader in geothermal and recovered energy generation.

Develops, builds, owns and operates geothermal power plants but also manufactures and sells equipment

Plants from 250 kW to 130 MW

Geothermal
power plants
in operation

647 MW in Indonesia (2 ﬁelds)

692 MW in Philippinesa) (2 ﬁelds)

769 MW in Italy (34 plants)

194 MW in El Salvadorb) (1 plant) 33 MW in the US (1 plant)

Direct use in Italy: Provision of heat to 8 700 customers and 25 hectares of greenhouses

626 MW owned and operated worldwide

1750 MW supplied worldwide

Strategy

•Leverage woruzldwide technical and operational capabilities to enable investment in domestic, utilityscale geothermal projects

•Assess further prospects in Indonesia and Philippines

•Strategically grow Chevron’s geothermal footprint (e.g. US, Hudson Ranch investment)

•Strengthen role in the global scenario, with new initiatives to be enacted abroad (focus on Central and South America and US)

•Direct attention to markets with abundant renewable resources, stable regulatory frameworks and strong economic growth

•Continue eﬀorts to rationalize operating expenses by operating plants more directly and with greater eﬃciency

•Continue to seek economies of scale, especially in procurement

•Use knowledge gained from own operations to increase competitiveness (eﬃcient maintenance and response to operational issues)

•Generate growth by securing leases, expanding exploration and developing highperformance projects

•Current exploration in 39 sites (US, South America, Indonesia, New Zealand)

•Established Geodrill, a drilling company executing exploration and drilling plans

•Build a geographically balanced portfolio of geothermal and REG

a) through a 40 % interest in Philippines Geothermal Production Company b) in partnership with national electric company

Sources: [Chevron 2014, Enel Green Power 2013, Enel Green Power 2014, Ormat 2012a, Ormat 2012b, Ormat 2014]

When it comes to turbine suppliers, some compa nies oﬀer speciﬁc expertise and proprietary tech nology. Ormat, for example, is specialised in binary (ORC) power plants and their components [REN21 2014]. The Italian company Exergy produces highly eﬃcient ORC plants using its newly developed radial outﬂow turbine concept [Exergy 2014]. Another example is Turboden, which is specialised in binary turbinegenerators [Turboden 2014].

Despite the existence of highly specialised smaller companies, the geothermal power plant turbine market is dominated by big industrial corporations such as Mitsubishi Heavy Industries, Toshiba, Fuji Electric, Ansaldo, GE/Nuovo Pignone, and Alstom that are also active in other energy sectors (Table 8). Some of those companies such as Ansaldo or Alstom not only supply turbines but also oﬀer additional services ranging from civil and mechanical design to installation and commissioning of whole plants.

So far, companies active in geothermal power generation or direct use are not active in the ground source heat pumps market (Section 4.8) or vice versa except for Mitsubishi that oﬀers also a large GSHP system for commercial applications. Manufacturers of GSHP systems are mainly based in the HVAC sector or in consumer & household appliances.

Table 8: Overview of major turbine/power plant suppliers for geothermal power

Company

Company proﬁle

MW
supplied

Strategy

Alstom

Multinational company active in power generation, power transmission and rail infrastructure

Geothermal power (50 years experience) is a key component of Alstom’s clean power oﬀering

Product range covers medium size range (2535 MW) and doubleﬂow turbine (3560+ MW) range

Besides steam turbine and generators, Alstom oﬀers condensers, hotwell pumps, instrumentation and control systems

350 MWe

•Maximise beneﬁts achieved through integration of Alstom produced components

•Build on track record in project ﬁelds to further develop and adapt the oﬀering to market requirements globally

•Tailormade packages to exactly suit customer’s plant and business strategy

•Other oﬀers include parts, repairs, ﬁeld service, technical expertise and operational support, service contracts and original equipment manufacturer (OEM) services

Ansaldo

Italy’s largest supplier, installer and service provider for power generation plants and components.

Experience with geothermal power plants since 1913 (ﬁrst turbinegenerator unit at Larderello)

2000 MWe
130 units

•Provide optimized solutions for geothermal power plants (20 to 150 MW)

•Provide not only steam turbine or generator sets, but also complete integrated package ( including e.g. civil, electrical design, installation, commissioning)

•Provide services for both OEM and non OEM plants (turbines, generators, repairs, replacement parts, control systems

Fuji
Electric

Manufacturer of thermal and electric energy technology

Engaged in thermal power plant business since 1959 (planning, design, procurement, construction, commissioning and after sales service)

Leading manufacturer of geothermal steam turbines and generators

Delivered more than 34000 MW (545 units) of steam turbines and generators worldwide

2630 MWe
67 units

•Japan: advance into the domestic geothermal market

•Overseas: target increased orders from growing markets of Central and South America as well as Africa

•US: expand operations

GE/Nuovo Pignone

Multinational company active in Energy, technology Infrastructure, consumer and industrial appliances

GE Power & Water provides a broad array of power generation, energy delivery, and water process technologies

Geothermal turbines oﬀered from 5100 MWe

533 MWe

•Highly reliable geothermal steam turbine generator sets allowing for longterm, reliable operation

•Modular component structure to achieve the cost and reliability

Mitsubishi Heavy Industries

Multinational engineering, electrical equipment and electronics company

Leading manufacturer of geothermal steam turbines and generators

3000 MWe
100 units

•Pushes forward with continued growth and business expansion

•Bought Pratt & Whitney Power Systems, including Turboden, creating a much stronger player

Toshiba

Toshiba Power Systems Company is a leading manufacturer of heavy electrical equipment. Delivered 1700 steam turbine units, 240 hydraulic turbine units, 300 hydraulic generator units and 32 nuclear reactor units so far

Leading manufacturer of geothermal steam turbines and generators

•Still global leader in installed geothermal capacity

•Focused on improvements and upgrades of existing plants in the past

•Now again more active in supplying steam turbines for new projects

Sources: [Alstom 2013, Alstom 2014, Nuovo Pignone 2005, ThinkGeoEnergy 2011, Ansaldo 2011, Ansaldo 2014a, Ansaldo 2014b, Bertani 2012, Estabrook & Leger 2000, Fuji Electric 2013a, Fuji Electric 2013b, Fuji Electric 2014]

5 TECHNOECONOMIC ASSESSMENT OF GEOTHERMAL POWER PLANTS

The cost of building and operating a geothermal power plant varies widely and depends on such factors as [DiPippo 1999]:

•Resource type (steam or hot water) and depth;

•Resource temperature;

•Reservoir productivity;

•Power plant size;

•Power plant type;

•Environmental regulations;

•Cost of capital;

•Cost of labour

The ﬁrst three factors inﬂuence the number of wells that must be drilled and are furthermore related to the size of the desired power plant. The resource type mainly inﬂuences the power plant type. Dry resources are suitable for dry steam plants that are the simplest type of geothermal power plants. Hot water resources may be suitable for either ﬂash or binary power plants. Flash power plants typically extract from resource temperatures above 180 °C and as temperatures exceed 240 °C double (or even triple) stage ﬂash power plants become economically feasible. ORC power plants are usually constructed when resource tempera tures are below 180 °C. Combined heat and power plants are only constructed from hot water type resources. The depth of the resource directly inﬂu ences the cost of drilling. The depth also inﬂuences the complexity of the reservoir management such as maintenance of permeability. Finally, the cost of monitoring activities in production and injec tion wells is dependent on the resource depth. Power plant size is entirely dependent on the size of the resource and can often not be decided on until some exploration and testing of the reservoir has been carried out. Environmental regulations vary between regions but often limit the emission allowances from power plants. For geothermal, the primary emissions of concern are H₂S and mercury. The chemical compositions of the geothermal ﬂuids are highly variable and depend on the resource temperature and the supply of mobile compo nents, primarily chloride, CO₂ and H₂S all of which tend to increase near active volcanism zones. Due to the corrosive nature of H₂S, its treatment may constitute high proportion of the construction costs where strict environmental regulations are in place. The high variability of these factors makes a cost estimation of geothermal power plant devel opment and construction rather complex as site speciﬁc factors related to the resource may have detrimental eﬀect on costs.

5.1 Cost and performance characteristics of geothermal installations

The performance characteristics of power plants for the time period 2010 to 2050 were evaluated based on the methodology of [EIA 2013] and is the same as applied in a JRC report that discusses the evaluation method in more detail [ETRI 2014]. A recently published software [Dauenhauer 2014] was used to calculate the CAPEX of a binary power plant with and without EGS for comparison to other literature. In geothermal power plants, drilling and reservoir engineering often constitutes more than 50 % of the CAPEX in conventional hydrothermal plants and even higher in EGS that rely on heat from even deeper sources than hydrothermal. This speciﬁc cost is highly dependent on the geology and depth of the reservoir. In conventional hydrothermal systems, ﬂuids are frequently extracted from 22.5 km depths. Engineered Geothermal Systems may extract heat from as deep as 5.5 km and predictions assume 10 km wells in the future.

Historically, geothermal energy has mainly been harnessed where bedrock permeability and heat gradients are high. Recently, increased eﬀort has been put into the concept of EGS where heat is extracted from deep reservoirs that may need stimulation due to low permeability. Therefore when addressing the CAPEX of geothermal power plant construction, it is logical to separate the cost of equipment on the surface on one hand and drilling and reservoir stimulation on the other.

The expenditure categories were classiﬁed according to Table 9. This report presents perfor mance characteristics of selected geothermal power production technologies for the time period from 2010 to 2050. The data for each technology refer to sizes and conﬁgurations which are typical of average geographic locations within the European Union. The most relevant types of each technology were selected for presentation in this report. The CAPEX is reported as overnight capital expenditure which means the cost of delivery of a plant as if no interest was incurred during construction i.e. as if the project was completed and delivered “overnight”. EUR 2013 values. Neither taxes nor subsidies were incorporated in the economic estimations presented in this report.

The CAPEX is given as a reference value with a lower and higher bound. All cost data were converted to EUR 2013 values. Neither taxes nor subsidies were incorporated in the economic estimations presented in this report.

Table 9: Division of CAPEX of geothermal power plants.

Item

Description

Remark

Civil and structural costs

allowance for site preparation (excluding the costs of infrastructure connections i.e. electricity, fuel and water connections):

•clearing, drainage, etc.

•installation of underground utilities

•structural steel supplfy and installation

•construction of buildings and roads on the site

Mechanical Equipment
supply and Installation,
Major Equipment, Surface

Power Plant buildings, Fluid delivery/reinjection system and surface pumps, heat exchangers turbine generators, condensers, cooling towers, desulfurization system, fresh water supply.

•Speciﬁc cost to ORC hydrothermal and EGS are heat exchangers to boil the working ﬂuid.

•EGS operate with higher pump capacity than hydrothermal system althoughreinjection pumps may be needed for hydrothermal systems

•Speciﬁc cost to ﬂash hydrothermal plants can be desulfurization system.

Mechanical Equipment supply and Installation costs, Subsurface Surface

Production and reinjection wells, submersed pumps, reservoir stimulation

•A hydrothermal reservoir may be stimulated in conjunction with well drilling.

•A EGS reservoir always needs to be stimulated to enhance permeability between production and reinjection well.

Electrical and I&C supply and installation

All electrics except generator inside the power plant.

Project indirect costs

Planning, consulting, project management

Owner costs, Development costs

Geological, geochemical and geophysical exploration of the reservoir is included here.

Owner costs, Interconnection costs

Grid connection

Owner costs, Insurance costs

Insurance costs.

Three reference power plant types are provided in this report:

•A Flash power plant extracting ﬂuid from a hydro thermal system at 2.5 km depth;

•An ORC power plant extracting ﬂuid from a hydro thermal system at 2.5 km Depth;

•An ORC power plant extracting 165 °C ﬂuid at 100 kg s⁻¹ from EGS at 5.5 km depth. CAPEX values are also provided for 150 °C and 180 °C ﬂuids at 50–150 kg s⁻¹ and at 3 and 4 km depths.

The CAPEX of these plants may then be adjusted based on the depth of the main feed zones of the production and reinjection wells and in the case of EGS the pump rate of the circulation ﬂuid. The low/high margins are dependent on cost with EGS stimulation (EUR 48 million for each system) and the drilling cost is assumed to ﬂuctuate +/ 10 %. In Table 10, the cost components included in the CAPEX estimates are shown.

5.1.1 Flash power plants from a hydrothermal reservoir

The CAPEX breakdown for a ﬂash power plant is given in Figure 36. Mechanical equipment costs represent more than 51 % of CAPEX, followed by owner’s cost (mainly development costs) and project indirect costs.

Fig. 36:CAPEX breakdown of a hydrothermal ﬂash power plant

Table 10:Cost components included in the CAPEX estimates for geothermal power plants

Cost component

Flash power plants from a hydrothermal reservoir

Organic Rankine Cycle from a hydrothermal system

Organic Rankine Cycle from an Enhanced Geothermal System

Civil and structural costs

Civil and structural costs

X

X

Mechanical equipment costs

Major equipment costs

X

X

X

Balance of plant costs

X

X

X

Electrical and I&C costs

Electrical and I&C supply and installation

X

X

Project indirect costs

Project indirect costs

X

X

Owner’s costs

Development costs

X

X

X

Interconnection costs

X

X

X

Insurance costs

X

X

Table 11 summarises the economic indicators for the ﬂash power plant. The upper CAPEX range assumes that the production and injection wells are 3.5 km deep instead of 2.5 km.

Table 11:Indicators for a ﬂash power plant extracting ﬂuid from hydrothermal system at 2.5 km depth

Parameter

Unit

2010

2020

2030

2040

2050

Net electrical power

MW

45

45

45

45

47

Gross electrical power

MW

47

47

47

47

47

Thermal power

MW

196

191

188

184

189

Net eﬃciency

%

23

23.5

23.9

24.4

24.9

Max. capacity factor

%

95

95

95

95

95

Avg. capacity factor

%

95

95

95

95

95

Technical lifetime

years

30

30

30

30

30

CAPEX ref

€₂₀₁₃/kWe

5530

4970

4470

4020

3610

CAPEX low

€₂₀₁₃/kWe

2500

2500

2500

2500

2500

CAPEX high

€₂₀₁₃/kWe

5930

5370

4870

4420

4010

CAPEX ﬂoor

€₂₀₁₃/kWe

2000

2000

2000

2000

2000

Quality of CAPEX estimate

medium

CAPEX learning rate

%

FOM

% of CAPEX ref.

1.4

1.6

1.8

2.0

2.2

5.1.2 Organic Rankine Cycle from a hydrothermal system

The CAPEX breakdown for an ORC plant is given in Figure 37. Similar to ﬂash power plants, the mechan ical equipment costs represent the greatest share of CAPEX (about 50 %), followed by project indirect costs and owner’s cost (mainly development costs).

Table 12 summarises the economic indicators for the ORC power plant.

Fig. 37:CAPEX breakdown of an organic rankine cycle power plant

5.1.3 Organic Rankine Cycle from an Enhanced Geothermal System

A detailed CAPEX breakdown for an ORCEGS plant could not be derived due to data limitations. Table 13 summarises the economic indicators for the ORC power plant.

Table 12:Indicators for a organic rankine cycle power plant from hydrothermal system

Parameter

Unit

2010

2020

2030

2040

2050

Net electrical power

MW

7.3

7.5

7.7

8.0

8.2

Gross electrical power

MW

9.0

Thermal power

MW

54

54

54

54

54

Net eﬃciency

%

13.3

13.8

14.2

14.7

15.1

Max. capacity factor

%

95

95

95

95

95

Avg. capacity factor

%

95

95

95

95

95

Technical lifetime

years

30

30

30

30

30

CAPEX ref

€₂₀₁₃/kWe

6970

6600

6240

5870

5510

CAPEX low

€₂₀₁₃/kWe

6470

6100

5740

5370

5010

CAPEX high

€₂₀₁₃/kWe

7470

7100

6740

6370

6010

CAPEX ﬂoor

€₂₀₁₃/kWe

Quality of CAPEX estimate

low

CAPEX learning rate

%

FOM

% of CAPEX ref.

2.1

2.2

2.3

2.5

2.7

Table 13:Indicators for a organic rankine cycle power plant from an Enhanced Geothermal System

Parameter

Unit

2010

2020

2030

2040

2050

Net electrical power

MW

4.4

4.6

4.8

5.1

5.3

Gross electrical power

MW

4.9

5.1

5.4

5.6

5.9

Thermal power

MW

41

41

41

41

41

Net eﬃciency

%

10.6

11.2

11.8

12.3

12.9

Max. capacity factor

%

95

95

95

95

95

Avg. capacity factor

%

95

95

95

95

95

Technical lifetime

years

30

30

30

30

30

CAPEX ref

€2013/kWe

12600

10300

9000

8600

8200

CAPEX low

€2013/kWe

11700

9600

8400

8000

7600

CAPEX high

€2013/kWe

13400

11000

9600

9100

8700

CAPEX ﬂoor

€2013/kWe

Quality of CAPEX estimate

medium

CAPEX learning rate

%

FOM

% of CAPEX ref.

1.8

1.8

1.9

1.9

1.9

5.2 Approaches to reducing the cost of energy

As mentioned above, the CAPEX of geothermal power plants is dependent on several factors and in particular the resource conditions at the power plant site. Cost analyses have been carried out by changing well depth, production ﬂuid tempera ture and ﬂuid ﬂow rate from reservoir to power plant. The price of the turbine was kept constant at 4000 EUR/kWe. Figure 38 shows the eﬀect of pump rate and well depth on CAPEX. The highest gain of increasing pump rate is observed between 5075 kg s1 but lowers as pump rate is increased towards 150 kg s1. Assuming the thermal transfer from reservoir rocks to the circulating geothermal ﬂuid is suﬃcient; the ﬁgure also shows that for 4 km deep wells, slightly higher ﬁnancial beneﬁt may be expected by increasing pump rate from 75100 kg s1 than by extracting from 180 °C compared to 165 °C. Therefore, creation and maintenance of adequate fracture network in the reservoir is paramount. Similarly, Figure 39 high lights the importance of maintaining high ﬂow through the reservoir. In all modelled scenarios, the CAPEX with 100 kg/s ﬂow is lower than the CAPEX with 50 kg/s.

Further cost reducing factors include:

•Cheaper drilling technology through advances in the state of the art of drilling;

•Increased eﬃciency of the energy conversion process;

•Cheaper corrosion resistant materials;

•Cheaper scaling mitigation methods;

•More reliable resource potential prediction minimizing the number of abandoned projects;

•Improved exploration techniques minimizing the number of abandoned projects far into development.

Fig. 38:Inﬂuence of pump rate (and therefore permeability) on the CAPEX of an EGS ORC power plant. The reference case provided is that of 5.5 km deep wells, 100 kg/s pump rate and 165°C inlet water. CAPEX numbers are those generated by the model and have not been corrected for the CAPEX brake down used. Source: JRC own analysis with GeoELEC software [Dauenhauer 2014].

Fig. 39:Inﬂuence of well depth and pump rate on CAPEX of an ORC EGS power plant. It may be much more cost eﬀective to increase the permeability of a reservoir between injection and production wells than to drill deeper for higher reservoir temperatures.

Source:JRC own analysis with GeoELEC software [Dauenhauer 2014]

5.3 Integration in the electricity system

Geothermal power plants can produce base load electricity with a high capacity factor (about 9095 %). They can be very ﬂexible since they can operate in partial load and allow for a fast rampup of 56 hours from cold to full output compared to 9 hours and 50 hours for lignite power and nuclear power plants, respectively [Eggeling et al. 2012]. Considering the ﬂexible output of ﬂash geothermal plants though, one needs to take into account the increased demand this kind of operation has on man power requirements (to oversee successful operation of the production wells and steam deliv ering system). Variable power output may lead to elevated wear and tear in equipment and one has to bear in mind that turbine units are not designed for highly variable operation.

No technical barriers prevent the integration of geothermal power to the European electricity grid. In general, small geothermal power plants will feed electricity into the middlevoltage system by the means of a transfer station which will lead to minor local eﬀects only [Auer et al. 2004, Eggeling et al. 2012]. In the future, we will see a clear trend towards distributed generation in Europe with increasing shares of volatile producers (e.g. wind, PV) which will require adaptations of the current electricity network [Reitenbach 2014]. Baseload geothermal electricity could play an important role in stabilising the grid and reducing the needs for and costs of grid infrastructure changes [Eggeling et al. 2012].

The costs of the grid connection of a geothermal power plant diﬀer according to local grid structure and site speciﬁc conditions. Usually, the grid connection includes ﬁxed costs for a transfer station, estimated at about 8000085000 EUR for a small 1 MWe plant [Eggeling et al. 2012]. In addition, costs depending on the distance to the location of grid connection assigned by the grid operator occur. Grid connec tion costs have to be considered in the early plan ning phase of geothermal power plants since often a tradeoﬀ between the quality of a hydrothermal resource and the distance to the grid connection point exists; a fact that has to be taken into account from an economic point of view [Huenges 2011].

5.4 Cost of Energy

The levelised cost of energy (LCOE), a common indi cator for assessing energy costs, has been calcu lated for diﬀerent types of geothermal power plants based on the ﬁgures given in section 5.1 for CAPEX and OPEX applying diﬀerent discount rates and CAPEX assumptions. Figure 40 shows the results for varying discount rates with using the reference values for capital costs and Figure 41 shows the LCOE for varying CAPEX predictions at a discount rate of 7 %.

Fig. 40:LCOE of diﬀerent geothermal power plants for discount rates between 3 % and 10 %. CAPEX: reference values from [ETRI 2014] (Line: 7 %)

Fig. 41:LCOE of diﬀerent geothermal power plants for diﬀerent capital costs. CAPEX values from [ETRI 2014] 7 % discount rate.

From the literature, current LCOE estimates could be retrieved (Table 14). These LCOE calculations are comparable with values from [Goldstein et al. 2011, OECD/IEA 2011].

Table 14:Current LCOE in cEUR₂₀₁₃/kWh

Reference

Flash power plant

ORC

power plant

ORC EGS
power plant

Comment

This report, based on

5.8

7.9

13.8

7 % discount rate

[ETRI 2014]

(4.17.2)

(5.79.6)

(9.917.0)

3 %10 % discount rate

[Goldstein et al. 2011]*

4.56.6

4.98.5

n.a.

Current LCOE, CF 74 %, 7 % discount rate

[Goldstein et al. 2011]*

2.912.0

3.015.7

n.a.

Current LCOE, CF & discount rate ranges

[OECD/IEA 2011] **

4.06.3

4.78.7

7.915.0 (US)

19.823.7 (EU)

CF 85 %, 35 years

* Conversion from USD₂₀₀₅ to EUR₂₀₀₅ with 1 USD = 0.8453 EUR, from EUR₂₀₀₅ to EUR₂₀₁₃ by applying GDP deﬂator values from Eurostat

** Conversion from USD to EUR with 1 USD = 0.79 EUR

In addition, to the calculation of LCOE based on [ETRI 2014], we have also applied learning rates using the global capacity projections from [Goldstein et al. 2011]. According to [Jamasb & Kohler 2007], learning rates can range between 3 % to over 35 %. Often, a learning rate of 20 % has been applied for energy generation technologies in the past. For our calculations, learning rates of 10 % and 20 % have been assumed (Figure 42).

Fig. 42:LCOE predictions of diﬀerent geothermal power plants based on learning curves between 10 % and 20 %

Table 15:LCOE estimates for 2050 in cEUR2013/kWh

Reference

Flash power plant

ORC power plant

ORC EGS power plant

Comment

This report, based on [ETRI

4.1

6.6

9.1

7 % discount rate

2014]

(3.05.0)

(4.98.0)

(6.611.1)

3 %10 % discount rate

This report, based on learning curves and capacity forecast from [Goldstein et al. 2011]

3.44.5

4.66.0

8.110.6

Learning rate between 10 % and 20 % assumed

[DLR 2010]

n.a.

n.a.

10.0

Depending on region and

(7.120.0)

reservoir characteristics

* Conversion from USD₂₀₀₅ to EUR₂₀₀₅ with 1 USD = 0.8453 EUR, from EUR₂₀₀₅ to EUR₂₀₁₃ by applying GDP deﬂator values from Eurostat

** Conversion from USD to EUR with 1 USD = 0.79 EUR

A comparison of the LCOE of geothermal power plants with other energy technologies is shown in Figure 43. LCOE is in the range of other renew able energy technologies and higher compared to advanced fossil fuels and nuclear power. When comparing geothermal power plants with other renewables, it has to be kept in mind that geothermal power plants deliver baseload elec tricity, also reﬂected by a high capacity factor which many other renewables are not (e.g. wind, PV). The LCOE does not take into account the eﬀects of ﬂuctuating supply (and demand).

Fig. 43:Comparison of LCOE of diﬀerent energy technologies. Calculations based on [ETRI 2014]. Solid bars: current LCOE (lowhigh CAPEX). Shaded: Possible LCOE reductions until 2050

6 ENVIRONMENTAL IMPACTS OF GEOTHERMAL ENERGY

Environmental impacts of geothermal activities may occur during construction of geothermal facil ities or during the operation. The environmental impact of geothermal facilities has been classiﬁed as [Mannvit hf 2013]:

•Surface disturbances (access roads, pipe and power lines, plant associated land use);

•Physical eﬀects (eﬀect of ﬂuid withdrawal on surface manifestations, land subsidence, induced seismicity, visual eﬀects due to structures);

•Noise (during drilling, construction and operation);

•Thermal pollution (hot liquids and steam released from discharging boreholes and the power plant;

•Chemical pollution (disposal of liquids and solid waste, gaseous emissions, natural radioactivity);

•Impact on protected faunas and ﬂoras.

The location and type of facility determines the envi ronmental impacts associated with daily operation.

•Flash and direct steam plants exploiting high enthalpy resources release steam and gases to the atmosphere and ﬂuids either at the surface or into deeper reservoirs. Induced seismicity is primarily associated with reinjection of ﬂuids and can vary from virtually nonexistent to generation of > M3 earthquakes in extreme cases. However distinction between induced seismicity and natural seismicity is not easy in hydrothermal ﬁelds.

•Binary plants exploiting medium enthalpy resources with natural permeability can operate in closed systems without considerable release of steam or gases to the atmosphere. Induced seis micity may be associated with their operation.

•Enhanced geothermal systems rely on heat extraction from reservoirs that have been created or improved artiﬁcially. The power plant associated with the EGS will usually be binary so emissions are limited. The most signiﬁcant environmental impact is induced seismicity associated with the fracturing of the reservoir and earthquakes up to M 3.4 were detected in Basel [Deichmann and Giardini 2009, Zang et al. 2014]

•Direct use facilities release heat to the environ ment after use but the eﬀects are usually very local. The geoﬂuids may contain elevated concen trations of toxic elements but direct CO₂ emissions are typically negligible

•The CO₂ emissions from GSHP systems depend on the energy source used to power the pumps. Otherwise the main environmental threat from closed loop GSHP systems is the accidental release of antifreeze into the environment.

The reader is referred to other comprehensive studies for further discussion on the environmental eﬀects of geothermal utilisation [Clark et al. 2012, GEA 2012, Mannvit hf 2013].

6.1 Emissions to air and ground waters during power production

Carbon dioxide (CO₂) is the main gas species emitted by geothermal operations. Hydrogen sulphide (H₂S) is often the second most important species. Other gases include hydrogen (H₂), methane (CH₄), ammonia (NH₃) and nitrogen (N₂). All of these do not condense with the steam in the power plant’s condensers and they are therefore termed as noncondensable gases (NCG) Generally the concentration of the gas species increases with increased resource temperature. Mercury, arsenic, radon and boron may also be present. The amount of these gas species released is highly sitespeciﬁc and depends on the geological conditions such as resource rock type and temperature. In addition, the technology used for energy production inﬂu ences atmospheric emissions. Flash and direct steam power plants direct the geothermal ﬂuids through the turbines and gases are extracted from condensers. Conversely, binary power plants direct the geothermal ﬂuids in a closed loop through heat exchangers prior to reinjection therefore facili tating nearly emission free operation.

6.1.1 CO₂ emissions

CO₂ is mainly emitted from power plants after being extracted from condensers but may also be released from two phase heat exchangers. On average, CO₂ constitutes 90 % of the NCG. CO₂ emission rates range between 4740 kg CO₂/MWh from geothermal power plants with an average of 122 kg CO₂/MWh [Bertani and Thain 2002]. Direct use CO₂ emissions tend to be on the order of 01 kg CO₂/MWh [Fridleifsson et al. 2008]. CO₂ emis sions from GSHP depend on the eﬃciency of the equipment used as well as the fuel mix and the eﬃciency of electricity generation needed to run the heat pumps. The average CO₂ emissions associated with generation of electricity in Europe has been estimated to be 550 kg CO₂/MWh. A GSHP run on electricity may emit 45 % less CO₂ than an oil boiler and 33 % less than a gas boiler. If the GSHP is run on renewable electricity, CO₂ savings can be higher [Fridleifsson et al. 2008]. The total CO₂ reduction potential of heat pumps has been estimated to be 1.2 billion tonnes per year or about 6 % of global emissions [ISEO 2014].

When estimating potential CO₂ emission savings by utilising geothermal energy the question on whether to produce electricity or heat is more eﬀective arises. To compare potential CO₂ emission savings, a small geothermal plant was assumed that produces either only electricity or only heat. For simplicity, cogeneration was not used. The plant is fed by a single production well with a pump delivering 50 kg/s of 150 °C water. For electricity production, an ORC plant is assumed returning 60 °C water. The net capacity is 1863 kW and the plant is able to produce 15.5 GWhe assuming an capacity factor of 0.95. For heat only plant, the utilisation ratio of a heat exchanger may be estimated as shown in equation 5. Assuming the same geothermal ﬂuid of 150 °C, return temperature of 60 °C and ambient temperature of 20 °C, the utilisation ratio is 0.69. The net capacity is therefore 2887 kWth and the plant is able to produce 24 GWhth using the same amount of ﬂuid as the ORC plant.

The direct and indirect CO₂ emissions from an ORC power plant are 96 kg CO₂/MWhe [ETRI 2014]. The same ﬂuid is used for the heat plant. Therefore the direct and indirect CO₂ emissions for heat production are 62 kg CO₂/MWhth since the heat plant capacity is higher than for the electricity plant. Direct and indirect emissions from steam turbine coal supercritical CHP are 456 kg CO₂/MWhe and 323 kg CO₂/MWhe from combined cycle gas turbine CHP [ETRI 2014]. Direct and indirect emissions producing heat with hard coal are 414 kg CO₂/MWhth and 227 kg CO₂/MWhth from natural gas [Biomass Energy Centre 2014].

Using the geothermal ﬂuid, the production of 15.5 GWhe of electricity emits 1488 tons CO₂ annually. Using the same geothermal ﬂuid, the production of 24.0 GWhth of heat emits 1488 tons CO₂ annually. Potential savings producing electricity or heat with geothermal as compared with either coal or natural gas may therefore be estimated (Table 16).

In all cases, high CO₂ savings can be achieved by producing electricity or heat by geothermal compared to coal and gas. Higher CO₂ savings may be expected by using low and medium temperature geothermal resources for heat production than for power production but this diﬀerence is only three percent when comparing geothermal to gas as an energy source. However, it must be stressed that frequently there is lack of infrastructure and poten tial buyers of this heat and from economical point of view for the developer, electricity production may be a better option.

6.1.2 H₂S emissions

Of the gases emitted from high temperature power plants, H₂S is of primary concern due to its toxicity and because it may constitute a large share of emis sion (up to 2035 vol % of NCG). At low tempera tures, H₂S concentrations usually do not exceed few tens parts per million (ppm). Power plants may emit between 0.05 g/kWh to 9800 g/kWh [Carlsson et al. 2013]. Low levels of H₂S may be tolerated as the human body has enzymes capable of detoxifying H₂S to sulphate but this capability is limited to low levels of H₂S. Shortterm high level exposure may lead to loss of breathing and high probability of death. Table 17 shows the eﬀects of diﬀerent levels of H₂S exposure on the human body and various limits of exposure.

H₂S is soluble in water but it primarily partitions to the gas phase in the condensers. Therefore depending on the H₂S fraction in the geoﬂuid and local regu lations, the gas extracted from the condensers may have to be treated to prevent HyS emissions to the atmosphere. H₂S treatment methods are described in chapter 2.1.5.

6.1.3 Mercury emissions

Mercury (Hg) is not present in every geothermal resource. However, if Hg is present, it may be emitted during power production from that resource. As with other gases, Hg is not emitted from closed binary plants as the geothermal ﬂuid is simply passed through a heat exchanger prior to being reinjected. Mercury is emitted from geothermal power plants both in gaseous and in particulate form. Gaseous Hg is more reactive than particulate Hg and is more soluble in water. It remains in the atmosphere for 110 days and can be deposited locally and region ally. Particulate Hg binds to drift water droplets and is mainly deposited locally. The gaseous Hg has higher bioavailability than the particulate form [Pertot et al. 2013]. The main identiﬁed Hg occur rence in geothermal resources in Europe is in the LardarelloTravaleRadicondoli geothermal area in Tuscany, Italy. There, annual emissions decreased from 0.21 μg/kWh to 0.16 μg/kWh between 2003 2007 when the local operator installed dedicated H₂S and mercury removal systems, known as AMIS [Pertot et al. 2013]. The AMIS has a tested eﬃciency of 95 % Hg removal. The overall Hg emission reduction from the area was lower than 95 % as in 2007, 10 out of 27 power plants with combined capacity of 720 MW were equipped with the AMIS system. The AMIS system and those used in the Geysers area in USA utilize activated carbon to absorb mercury from the gas stream prior to converting sulphur from its gaseous form to solid form. Therefore the hazardous waste produced during power produc tion is reduced by thousands of tons annually [GEA 2007].

Table 16:Potential CO₂ emission savings by using geothermal resource compared to coal or natural gas as energy source. Values are in tonnes CO₂/year (% saving) and apply for 15.5 GWhe or 24 GWhth annual production supplied by a single geothermal well at 50 kg/s and 150 °C. Source: JRC analysis

Heat production

Power generation

Steam turbine coal supercritical

8460 (85 %)

5581(79 %)

Combined cycle gas turbine

6274 (73 %)

3519 (70 %)

Table 17:Established doseeﬀect relationships of hydrogen sulphide [WHO 2000] and limits of exposure [EC 2009b]

Lower value

Limit value

Upper value

Eﬀects, limits

mg/m³ (ppm in brackets)

0.001 (0.0007)

0.190 (0.13)

Human recognition threshold. Human sensitivity to the smell is variable

0.150 (0.1)

Maximum timeweighted average (24 hours) according to WHO

7 (5)

8 hour exposure limit

14 (10)

Shortterm exposure limit (STEL) where exposure should not exceed 15 minutes

15 (10)

30 (20)

Threshold for eye irritation

70 (50)

140 (100)

Serious eye damage

210 (150)

350 (250)

Loss of olfactory sense

450 (320)

750 (530)

Pulmonary oedema with risk of death

450 (320)

1400 (1000)

Strong stimulation of the central nervous system followed by respiratory arrest

1400 (1000)

2800 (2000)

Immediate collapse with paralysis of respiration

6.2 Induced seismicity

Earthquakes are the primary process to release stress built up in the Earth’s crust. Earthquakes occur when stresses on preexisting planes of weakness exceed their stress. Although damages to buildings associated with shallow geothermal activities and GSHP are not common [Grimm et al. 2014], induced seismicity related to deep geothermal applications has been known for long time. Induced seismicity has received increased attention with the introduction of the EGS concept. Although the exact mechanisms triggering earthquakes during geothermal applica tions is not understood, earthquakes occur primarily during reinjection and maximum observed earth quakes in a given reservoir are dependent on the injected volume [Zang et al. 2014]. Rock properties, injection pressure, and temperature all inﬂuence the nature of the failure that occurs. For today’s EGS developed between 25 km of depth, there is no relationship between the number of recorded events or the maximum magnitude and reservoir depth [Evans et al. 2012]. Induced seismicity is not as prevalent and often not recognised with the surface monitoring system in place when no reinjection is carried out. As EGS are often located near densely populated areas, borehole sensors may need to be installed to increase signaltonoise ratios and therefore achieve a better picture of the reservoir response to production and reinjection. Installation of sensors at depth increases the sensitivity of the seismic monitoring network thereby increasing the resolution of the reservoir models.

The goal of an engineered or enhanced geothermal system operation is to locate or safely create permeability through fractures and voids in high temperature rock such that water and steam can circulate through these pathways and transfer heat to the surface. An engineered system is one where natural fractures do not occur and have to be created or existing ones need to be reactivated. An enhanced system, the natural rock permeability is increased by massive water injection (up to 100 kg s1 in extended open hole sections. The ﬂuids are pumped under high pressure to enhance permea bility through hydraulic fracturing (mode I crack), hydro shearing (mode II crack), a combination of both or acidizing [Zang et al. 2014].

Most commonly, earthquakes occur during or slightly after stimulation of geothermal systems. These earthquakes are predominantly under a local magni tude (ML) 2 and below the threshold to be felt [Evans et al. 2012]. The geothermal sites near Basel, Landau and SoultzsousForêts in the upper Rhine valley have experienced up to ML 3.4 event due to EGS activities causing public concern [Zang et al. 2014].

Prior to drilling, obtaining a Pwave and Swave model of the reservoir is recommended as it is necessary to accurately pinpoint the origin of earth quakes during stimulation and operation [Zang et al. 2014]. The spatiotemporal distribution of seis micity is often a gradual migration from the vicinity of the borehole to distances farther from the bore hole as ﬂuid injection is progressing. The change in ratio of Pwave to Swave velocities has further been observed to correlate with the progression of injected ﬂuids. Hence the 3D model of the reservoir has to incorporate temporal aspects of Pwave and Swave velocities. Prestimulation seismic moni toring might be useful to identify buried faults. The stimulation and operation of an EGS should be designed as to prevent large magnitude events (LME). These LME may not only cause damage on the surface but can also lower the eﬃciency of the geothermal system by creating high permeability pathways preventing suﬃcient heat exchange. LME have mainly been reported after long term ﬂuid injections or as a result of reservoir impoundment both of which can bring preexisting fractures in the shallow crust closer to failure. EGS stimulations generally show higher propensity to produce LME compared to hydraulic fracturing in the oil and gas industry and seismogenic indices were higher for stimulations in crystalline rocks than in sedimentary rocks. During the early stimulation phase, pore pres sures are high in the vicinity of the injection well and many small events, often on faults with low applied shear stress are induced. As the injected water migrates away from the injection point and the pore pressure far from the injection well decreases, the shear stress necessary to trigger an event must increase. This increases the probability of the often observed larger magnitude events at the periphery of the stimulated volume and at the later stages of the stimulation [Zang et al. 2014].

7 KEY FINDINGS AND CONCLUSIONS

This report aims at presenting the overall state of play of geothermal energy in Europe in 2014. Geothermal energy is a renewable source of energy that can provide constant power and heat. The technologies to exploit its potential are commer cially proven today apart from EGS. In Europe, the geologic or theoretical potential is very large and exceeds current electricity demand in some coun tries. However, distribution of geothermal heat is highly variable and only a small part of the theo retical potential can actually be exploited due to technical and economic barriers.

Three forms of geothermal energy use can be diﬀer entiated: power generation, direct use, and ground source heat pumps. In Europe and worldwide, installed capacity for GSHP is greatest, followed by direct use and power generation.

Ground source heat pumps (GSHP)

GSHP use geothermal energy from shallow depths, which is available almost everywhere. They convert the low temperature geothermal energy to thermal energy at a higher temperature which can be used for space or water heating and cooling.

The installed capacity of GSHP has seen a dramatic increase with annual growth rates of 10 % since the mid1990s with a main focus on Europe and the United States. The installed GSHP capacity in the EU reached to about 14900 MWth (1.2 million units). The main markets for GSHP in the EU are Sweden, Germany, France, and Austria. The European GSHP market has been shrinking because of its depen dence on the new building market which has decreased in the recent years. A market recovery is expected in the coming years.

•To increase overall system eﬃciency, eﬀorts should be made to optimize all components of borehole heat exchangers with emphasis on pipe materials and better thermal transfer ﬂuids.

Direct use

Being the oldest form of geothermal energy exploitation, direct use works with higher resource temperatures than GSHP but still below 150 °C. Examples of direct use include space and district heating, heating of swimming pools, spas, and greenhouses, but also industrial uses and snow melting. Direct use beneﬁts from a widespread resource available at economic drilling depths and the use of conventional equipment.

The installed capacity in the EU was about 3 GWth and about 27600 TJ of heat are produced annually. The major markets for direct use are Italy, Hungary, and France. The main direct uses in the EU are district heating and bathing. District heating is currently the geothermal sector with the most dynamic develop ment. Installed capacity is expected to grow mainly in Germany, France, and Hungary.

•Geothermal direct use and GSHP for heating and cooling is best integrated in a regional approach to reduce cost and increase secu rity of supply. Solutions to integrate the refurbishment of old buildings to district heating networks are key to lower the overall energy consumption and CO₂ emissions for heating and cooling in the short term.

Power generation

For power generation, the type and temperature of the geothermal resource determines power plant design and eﬃciency. Dry steam plants and ﬂash plants use reservoirs with a temperature above 180 °C. They account for the majority of geothermal power generation capacity today and are commer cially available. Binary plants derive their ﬂuids from cooler resources (about 75180 °C). They represent about 10 % of the installed global geothermal power generating capacity and 45 % in terms of number of plants but they are the fastestgrowing group since they use more prevalent resources. However, only few technology suppliers are available for binary plants and only a limited number of – potentially highly eﬃcient – kalina type binary plants exist.

The installed capacity of power generation in the EU was about 0.9 GWe and 2013 electricity produc tion was about 5.6 TWh. In 2013, the new installed capacity worldwide amounted to 0.5 GWe, a new record in annual installations. Of these, 145 MWe were installed in Europe (including Turkey and Iceland) and about 17 MWe in the EU. A moderate growth is expected during the next years in the EU, with the installed capacity in 2020 to be about 1.6 GWe.

•Lowering drilling costs is a key issue for lowering CAPEX and OPEX of power plants. Heat exchangers play a central role in geothermal binary power plants but also for direct use and GSHP applications.

•Design and layout of heat exchanger heavily inﬂuence both CAPEX and OPEX and R&D eﬀorts are focussing on reducing heat exchanger costs.

A key issue to expand the resource potential of the geothermal power sector is the deployment of EGS technology. EGS has been demonstrated on small scale in few locations so far.

•For an adequate proof of concept, the EGS technology needs to be demonstrated under diﬀerent geological conditions.

Operators of EGS need to demonstrate the ability to adequately control reservoirs in diﬀerent settings, both in terms of heat extraction and from chemical stimulants and seismic point of view.

EU targets and policies

Geothermal project development has high upfront cost and it might take 36 years to realise a project. EU legislation on renewable electricity requires that dispatch priority is given to renewable electricity insofar as the operation of the national electricity system permits. A number of support schemes for geothermal energy within the EU exist but they diﬀer between Member States.

Risks of geothermal project development include the short term risk of not ﬁnding an adequate resource and the long term risk that the resource declines over time due to production. The resource is conﬁrmed only after exploration and drilling, and these two processes often are responsible for the majority of the costs associated with the develop ment of a geothermal project.

•The most important market push instrument is the implementation of a risk insurance fund which exists in 3 Member States.

EGEC has proposed a European Geothermal Risk Insurance Fund aiming at alleviating the shortage of insurance policies for the resource risk and easing investments in geothermal electricity projects.

Today, geothermal energy is a proven technology with a long history. Due to the limited size of hydrothermal resources, the market share of geothermal energy in Europe is still small. Large scale deployment of geothermal power production requires the demonstration of successful EGS proj ects extracting heat from reservoirs constituting a variety of geological conditions and drilling technology has to become cheaper. Future deploy ment of GSHP and direct use resources for district heating is very much linked to the recovery of the building sector.

•During refurbishment, heating and cooling systems of existing buildings should be integrated to district heating and developers of new buildings and infrastructures should be made aware of the ﬂexibility and beneﬁts of geothermal resources.

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