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Geothermal Generation Cost And Barriers

Geothermal Generation Cost And Barriers: Geothermal energy is heat derived within the sub-surface of the earth. Water and/or steam carry the geothermal energy to the earth’s surface. Depending on its characteristics, the geothermal energy can be used for heating and cooling purposes or can be harnessed to generate clean electricity.

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Geothermal power generation has higher capacity factors compared with some other renewable energy resources and is capable of supplying base-load electricity, as well as providing ancillary services for short- and long-term flexibility in some cases.

RELATED: GEOTHERMAL ENERGY POWER PLANTS

Furthermore, geothermal power generation has lower life-cycle greenhouse gas emissions than fossil fuel-based generation. Geothermal energy can be sourced from virtually everywhere.

However, the vast majority of medium- and high temperature geothermal systems, which are suitable for power generation, are located close to areas of volcanic activity.

For example, situated along plate boundaries (subduction zones, such as the majority of the Pacific “Ring of Fire”), mid-oceanic ridges (such as Iceland and the Azores) and rift valleys (such as the East African Rift) or near hot spots (such as in Hawaii) (Figure 2).

In 2016, the global geothermal installed capacity was 12.7 GW (Figure 3). In 2015, geothermal power plants generated approximately 80.9 TWh, or approximately 0.3% of global electricity generation. As shown in Table 1, the United States (2.5 GW), the Philippines (1.9 GW) and Indonesia (1.5 GW) lead in installed geothermal power capacity.

 

Global installed capacity additions in 2016 amounted to 901 megawatts (MW), the highest number in 10 years, which were installed in Kenya (518 MW), Turkey (197 MW) and Indonesia (95 MW). With the growing momentum for utilising these geothermal resources, an increasing number of countries are showing interest in developing geothermal projects.

Geothermal Power Generation

The heat content of a geothermal field will define the power generation technology to be used. Power generation from geothermal resources requires resources with high to medium heat content. Geothermal power generation currently is based on the following four technology options:

Direct dry steam plants

In this case, the conversion device is a steam turbine designed to directly use the low pressure, high-volume fluid produced in the steam field. Dry steam plants commonly use condensing turbines.

The condensate is re-injected (closed cycle) or evaporated in wet cooling towers. This type of geothermal power plant uses steam of 150 degrees Celsius (°C) or higher, and, generally, the steam entering the turbine needs to be at least 99.995% dry to avoid scaling and/or erosion of the turbine or piping components.

Direct dry steam plants range in size from 8 MW to 140 MW.

Flash plants

These are the most common type of geothermal electricity plants in operation today. They are similar to dry steam plants; however, the steam is obtained from a separation process called flashing. The steam is then directed to the turbines, and the resulting condensate is sent for re-injection or further flashing at lower pressure (Figure 5).

The temperature of the fluid drops if the pressure is lowered, so flash power plants work best with well temperatures greater than 180°C. The fluid fraction exiting the separators, as well as the steam condensate (except for condensate evaporated in a wet cooling system), are usually re-injected.

Flash plants vary in size depending on whether they are single- (0.2-80 MW), double – (2-110 MW) or triple-flash (60- 150 MW) plants.

Binary plants

These plants are usually applied to low- or medium-enthalpy geothermal fields where the resource fluid is used, via heat exchangers, to heat a process fluid in a closed loop (Figure 6).

The process fluid (e.g., ammonia/water mixtures used in Kalina cycles or hydrocarbons in organic Rankine cycles (ORC)) have boiling and condensation points that better match the geothermal resource temperature.

Typically, binary plants are used for resource temperatures between 100°C and 170°C. Although it is possible to work with temperatures lower than 100°C, the efficiency of the electricity output decreases. Binary plants range in size from less than 1 MW to 50 MW.

Combined-cycle or hybrid plants

Some geothermal plants use a combined cycle which adds a traditional Rankine cycle to produce electricity from what otherwise would become waste heat from a binary cycle (Figure 7). Using two cycles provides relatively high electric efficiency. The typical size of combined-cycle plants ranges from a few MW to 10 MWe.

Hybrid geothermal power plants use the same basics as a stand-alone geothermal power plant but combine a different heat source into the process; for example, heat from a concentrating solar power (CSP) plant. This heat is added to the geothermal brine, increasing the temperature and power output.

The Stillwater project in the US, operated by ENEL Global Renewable Energies, has launched such a hybrid system; combining CSP and solar photovoltaics with a binary system.

Two other hybrid systems being studied by ENEL include: a hybrid plant with biomass in Italy, which increases the brine temperature, similar to CSP systems.

And a hybrid plant with hydropower in Cove Fort, Utah, which uses the re-injection water flow to generate electricity, providing the additional benefit of increased control of the re-injection, thereby reducing potential damage and thus maintenance costs .

Cost of Geothermal

Geothermal power projects are capital intensive; however, they have very low and predictable operating costs.

The total installed costs of a geothermal power plant cover the exploration and resource assessment, including: exploration drilling; drilling of production and injection wells; field infrastructure, geothermal fluid collection and disposal systems, and other surface installations; the power plant and its associated costs; project development costs; and grid connection costs.

Furthermore, the cost ranges of geothermal power plants will depend largely on power plant type (flash or binary), well productivity (the number of wells) and other geothermal field characteristics.

The global total installed costs for geothermal power plants are typically between USD 1 870 per kW and USD 5 050 per kW (Figure 8); however, costs are highly site-sensitive.

For example, installing additional capacity at existing fields can be somewhat less expensive, while costs for projects with more challenging site conditions will be on the higher end of the range. Generally, costs for binary plants tend to be higher than those for direct steam and flash plants.

The European Commission (EC) forecasts the installed costs for both flash and binary plants to decrease through 2050 (Figure 9). Figure 10 presents the estimated cost breakdown for the development of two 110 MW flash geothermal power plants in Indonesia, with total installed costs of around USD 3 830 per kW.

The power plant and infrastructure costs amount to 49% of the total installed costs; drilling exploration, production and injection wells account for around 24%; while the steam field development accounts for 14%.

The EC performed a similar assessment for flash and binary plants and found that roughly 55% of total installed costs corresponds to the power plant and other infrastructure, while exploration, drilling and field development costs amount to 20% for flash plants and 35% for binary plants.

The LCOE from a geothermal power plant is generally calculated by using the installed costs, operations and maintenance (O&M) costs, economic lifetime, and weighted average cost of
capital.

Figure 11 presents the LCOE for geothermal projects assuming a 25-year economic life, O&M costs of USD 110 per kW per year, capacity factors based on project plans (or national averages if data are not available), two sets of make-up and injection wells over the 25-year life and the capital costs outlined in Figure 8.

The observed LCOE of geothermal plants ranged from USD 0.04 per kWh for second-stage development of a field to USD 0.14 per kWh for a first-of-a-kind greenfield development (Figure 11). The economics of geothermal power plants may be improved by exploiting by-products such as heat, silica or carbon dioxide.

The LCOE from a geothermal power plant is generally calculated by using the installed costs, operations and maintenance (O&M) costs, economic lifetime, and weighted average cost of capital.

Figure 11 presents the LCOE for geothermal projects assuming a 25-year economic life, O&M costs of USD 110 per kW per year, capacity factors based on project plans (or national averages if data are not available), two sets of make-up and injection wells over the 25-year life and the capital costs outlined in Figure 8.

The observed LCOE of geothermal plants ranged from USD 0.04 per kWh for second-stage development of a field to USD 0.14 per kWh for a first-of-a-kind greenfield development (Figure 11). The economics of geothermal power plants may be improved by exploiting byproducts such as heat, silica or carbon dioxide.

Potential and Barriers

The global technical potential for electricity generation from hydrothermal resources is estimated to be 240 GW, with a lower limit  of 50 GW and an upper limit between 1 000 GW and 2 000 GW, under the assumption that unidentified resources are likely five to ten times larger than currently identified resources.

According to the Geothermal Energy Association, the global geothermal industry is expected to reach about 18.4 GW by 2021. Table 2 and Figure 12 show planned capacity additions in the medium term.

Enhanced geothermal systems

A large part of the geothermal potential is heat stored at depths greater than commonly drilled. Standard hydrothermal technologies depend on permeable aquifers, which allow the flow of water through them, to produce hot water. However, at greater depths the ground becomes less porous and water flow is restricted.

Research and demonstration projects are being developed to overcome this limitation. Instead, artificial fractures are created to connect production and injection wells by hydraulic or chemical stimulation.

Stimulation is accomplished by injecting water and a small amount of chemicals at high pressure to create or reopen fractures in the deep rock (Figure 13). To prevent these fractures from closing again when the injection pressure is reduced, special materials called proppants are added.

This approach, known as enhanced geothermal (EGS), uses binary plants to produce power from the hot brine. As there is no natural flow of water, all the brine has to be re-injected into the reservoir to keep the pressure and production stable.

This helps prevent air emissions during the service life. Several pilot projects were performed in France, at Soultz-sous-Forêts and in Strasbourg as well as in the US.

Exploiting untapped resources is not the only way to increase the geothermal installed capacity. Additions also can be made through efficiency improvements, such as:

Low-temperature bottoming cycles

When dealing with high-enthalpy resources, it is common to use a flash plant configuration to exploit them. In a traditional flash plant, the steam exiting the turbine is re-injected into the ground, leaving it as waste heat.

This steam, however, frequently exits the turbine at temperatures that are suitable for power generation through a binary cycle turbine. This would increase the overall efficiency of the plant by increasing the power output.

Co-generation

Geothermal energy has many potential uses besides power generation. The water collected after separating the steam for generation is normally re-injected into the ground because the temperature is too low for power generation.

However, because it is frequently higher than 100ºC, by exchanging the heat with a different water source before injection, this newly heated water can be used for various direct-use applications such as domestic hot water supply and space heating.

Co-produced resources

The use of geothermal fluids that are a byproduct of other industrial processes also provides a great opportunity to produce electricity at low cost and with virtually no emissions.

Hot geothermal fluids which are a by-product of oil and gas operations usually are considered a nuisance, given that they need to be disposed of at a cost. Power actually can be produced from these coproduced resources, and this already has been successfully tested in the US.

Supercritical geothermal systems

These are high-temperature systems located at depths where the reservoir fluid is in supercritical state, e.g., 374ºC and 221 bar for water. These systems are the subject of ongoing research and are not yet commercial; however, they are capable of attaining higher well productivities than conventional systems given their high temperatures.

In 2009, the IDDP- 1 well in Iceland found magma and was capable of producing superheated steam at 450ºC, effectively creating the first magma-EGS system. The well, however, had to be shut down in 2012 due to a valve failure.

While such a system could prove to be more economical by exploiting the steam directly from the well, the possibility of applying a reverse procedure also has been explored. This would mean using these types of wells for injection with the objective of enhancing the performance of existing conventional systems.

The main barriers to geothermal development can be grouped into three broad categories: financial, environmental and administrative.

Financial barriers

Geothermal power plant development involves substantial capital requirements due to exploration drilling costs, for which it can be difficult to obtain bank loans. Since geothermal exploration is considered high risk, developers generally need to obtain some type of public financing.

This risk is derived from the fact that capital is required before confirmation of resource presence or exploitability, and therefore before project profitability can be determined (Figure 14). Governments can reduce this risk and the cost of capital for private developers in a number of ways.

For instance, they can create public companies that exploit geothermal resources and provide private companies (that install power plants and supply electricity to their customers) with the steam. Other risk mitigation instruments include cost-sharing for drilling and public-private risk insurance schemes.

With sufficient resource information, including seismic events/fractures and deep drilling data (which national or local governments can make available to developers), and reliable conceptual models of the underlying geothermal system and groundwater resources, risks could be reduced and financial barriers could be further eased, thereby accelerating geothermal development.

Environmental and social barriers

National regulations differ among countries; however, an environmental and social impact assessment of some type is almost always mandatory. Furthermore, apart from the assessment process, sufficient discussion with local groups may be needed before development can commence.

These issues can delay or lead to the cancellation of the geothermal power project; however, if managed in a timely and efficient manner, they do not present an obstacle.

Administrative barriers

Administrative issues such as licensing, permitting and environmental assessments are technically not barriers. However, they need to be tackled carefully by project developers, as they might impact a geothermal project by causing unnecessary delays.

On the other hand, governments should ensure that their regulations establish a transparent and straightforward process that will foster the deployment of new projects.

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