Technology: Geothermal Heat

Geothermal Heat for District Heating

Heat from the deep underground is an important source for district heating in many countries, including Iceland and France, where geothermal provides heating for a substantial part of the heating of Paris. Currently there is a high interest in geothermal energy in many European countries and many new schemes are under development or are planned.

The use of geothermal heat depends completely on the geological formations and in particular the underground temperatures. Normally geothermal energy use requires deep drillings to get water from 500-3000 m underground and to return the cooled water. Geological layers below 3000 m are usually too dense to allow water to flow through the layers to supply the geothermal well with a continuous supply of hot water. Depending on the underground temperatures, geothermal energy can be used in the following ways:

With high underground temperatures, above 100’C, the water is in the form of steam or overheated water. The steam can be used directly for power production in a steam turbine and the overheated water can be used to produce steam for a steam turbine. After the steam turbine, the remaining heat in the now condensed water can be used for district heating. In this way the plant is a geothermal CHP plant.
With medium underground temperatures, 75-100’C, the geothermal water can be used directly for district heating via a heat exchanger.
With lower underground temperatures 40-75’C, the geothermal water can be used for district heating via a heat pump. For lower temperatures than 40’C, normally the cost of the drilling is too high to justify installations, as a simple heat pump has a better economy, but if the drilling is already made for other reasons, it might be justified to use lower temperatures.
Geothermal water is also used for public baths and spas, which is a popular use in Central European countries as Slovakia and Hungary.

A geothermal system with at least one extraction well and one injection well has a heat capacity of 5-15 MW. The wells should be some km apart, but with directional drilling, the extraction well and the injection wells can be beside each other on the surface, while being far apart the geothermal layer. For larger towns, arrays of several wells can be made to increase heat extractions.

After the geothermal water is cooled, it should be returned to the same layer where it is extracted, but in a different location, a few km from the extraction well. This ensures that the underground layer is not depleted from water and it also ensures that minerals in the geothermal water is not polluting on the surface. Often geothermal water has a high concentration of salt (NaCl) and other minerals that could pollute a river, if it was discharged into it. Often geothermal water has also dissolved a high concentration of CO2, which will be released if the water is depressurised. To avoid this CO2 emission, the geothermal water should be kept under pressure.

There are certain risks in development of geothermal heating. The main risks are:

The underground might not be as warm as expected, which in particular is a problem if the project design includes use of geothermal heat directly in district heating, not budgeting with the extra costs of a heat pump.
The underground is not porous enough to allow the hot geothermal water to flow to the well in as big a volume as expected.
The geothermal water contains very high concentrations of salt and other minerals that deposit in the heat exchanger when the water is cooled an in the injection well. This has compromised operation of two Danish geothermal heating plants, where the injection wells suffered clogging from the minerals in the geothermal water.

Even after above-ground geological surveys has concluded that a site is well suited for geothermal heat extractions, there is still a risk that one of these problems make the geothermal project less successful than expected. To mitigate this risk, some strategies are:

An insurance scheme can secure the cost of the first drilling from which it can be estimated if any of the problems are detrimental to the use of geothermal heat in the specific site. The district heating company will then pay an insurance premium of for instance 10% of the costs of the first borehole. In Denmark, the state established such an insurance scheme as a revolving fund in 2015.
Partnership with a company that has experience in drilling with risks. Oil companies has precisely this expertise. In 2022, the district heating company in Aarhus, Denmark made such an agreement with a subsidiary (Innargi) of the Danish oil and gas developer Maersk that has a long history in exploration of oil and gas in the Danish part of the North Sea.

Figure: Overview of geothermal energy potential in Ukraine.

Examples

Paris

Fed by two deep water aquifers, the greater Paris area in France has been using geothermal energy for heating since 1969, supplying today geothermal heat to 250,000 households with 50 heating networks. The geothermal water is 60-80’C from a layer 1500-2000 below ground and the geothermal water is cooled to 40’C before it is reinjected. So far, the extraction of heat has only reduced the temperature in one out of more than 50 geothermal wells, but to avoid the risk of depletion of the resource, the operators are now supplementing the existing geothermal well with drillings into a deeper layer, 2100 m below the surface.

Thisted

The town of Thisted, Denmark with 13.400 inhabitants has used geothermal heat since 1984, where a drilling showed a good source of warm water 1250 m below ground with 43’C hot water. The drilling was 3000 m deep, but the deeper layers are too compact to extract hot water. The water is filtered before and after the heat exchanger, where the geothermal water is cooled 10-12’C. The injection well is 1500 m from the extraction well and after 25 years of operation, the temperature in the geothermal water fell 0,2’C. To ensure a future, permanent supply, the district heating company is investing in new wells. Until now it has invested in a second injection well. The geothermal heat is coupled with an absorption heat pump that is driven by heat from a straw-fired boiler. The geothermal source provides 7 MW of heat while the straw boiler provides 10 MW of heat for the heat pump. Since all the heat can be used for district heating, there is no net energy use in the heat pump compared to direct use of the heat from the straw fired boiler for district heating.

Technical parameters

Sizes: 5 MW and larger
Efficiency: depends on water temperature. For systems with electric heat pumps, the net COP is 4,5 or higher including pumping of geothermal water including injection. For systems without heat pumps, the pumping energy to move the geothermal water varies from 2% to 10% of the extracted heat.
Lifetime: technical lifetime 25 years, might be longer depending on geology.
Construction time: 4-5 years, but typically longer for large systems
Size demand: 1000 m2/MW.
Emissions: In well managed systems there are no emissions, but there can be discharge of geothermal water during start-up and maintenance.

Financial parameters

Nominal investment: The drilling cost is 1800-2000 €/m.
For a 12 MW heat output geothermal system with 6 drillings each 1200 m deep and with a heat pump, the estimated costs are 2,7 mill €/MW heat output including installation costs of 0,5 mill €/MW As above with 2000 m drillings, the estimated costs are 2,88 mill. €/MW.
For a 121 MW heat output geothermal system with 12 drillings each 2000 m deep and with a heat pump, the estimated costs are 1,34 mill €/MW heat output.
An example of a 12 MW geothermal system with 1200 m deep drillings has an estimated cost of 35 mill € including electric heat pump of 10 mill €. Of the total investment, 4 mill € is for preparation and the first drilling, which is lost in case there is not found geothermal water in sufficient quality and quantity.
Fixed O&M: 22,000 €/MW heat output for 12 MW system, 18,500 €/MW heat output for 121 MW system.
Variable O&M (excluding electricity costs): 5,7 €/MWh for 12 MW system, 2,02 €/MWh for 121 MW system.

Sources for information

Costs of new and replacement district heating

Danish Energy Agency’s Technology Catalogue for Electricity and Heat Supply, online