Techno-Economic Assessment of the Supercritical Carbon Dioxide Enhanced Geothermal Systems

: Enhanced geothermal systems distinguish themselves among other technologies that utilize renewable energy sources by their possibility of the partial sequestration of carbon dioxide (CO 2 ). Thus, CO 2 in its supercritical form in such units may be considered as better working ﬂuid for heat transfer than conventionally used water. The main goal of the study was to perform the techno-economic analysis of different conﬁgurations of supercritical carbon dioxide-enhanced geothermal systems (sCO 2 -EGSs). The energy performance as well as economic evaluation including heat and power generation, capital and operational expenditures, and levelized cost of electricity and heat were investigated based on the results of mathematical modeling and process simulations. The results indicated that sCO 2 mass ﬂow rates and injection temperature have a signiﬁcant impact on energetic results and also cost estimation. In relation to ﬁnancial assessment, the highest levelized cost of electricity was obtained for the indirect sCO 2 cycle (219.5 EUR/MWh) mainly due to the lower electricity production (in comparison with systems using Organic Rankine Cycle) and high investment costs. Both energy and economic assessments in this study provide a systematic approach to compare the sCO 2 -EGS variants.


Introduction
In recent years, energy problems and global warming have become the most discussed issues by countries around the world.An economic system increasingly sensitive to the environment, the search for energy independence, and the development of an industrial sector highly dependent on electricity are just a few causes that have pushed the European Union (EU) to adopt drastic changes in European energy production and global electricity grid.The increase in the energy produced through renewable systems represents the main objective in order to be able to face the energetic and environmental requirements determined in the conference in Paris in 2020.In accordance with future goals, The European Commission is seeking to accelerate the take-up of renewables in the EU to make a decisive contribution to its ambition of reducing net greenhouse gas emissions by at least 55% by 2030 and ultimately becoming climate-neutral by 2050 [1].
The research on the extension of renewable plants also includes a considerable investment in the exploitation of geothermal resources of the various EU member states.
Thanks to the development of new systems for the energy production, district heating, and heat pumps, the exploitation of the geothermal reservoirs is predicted to increase, thus contributing to the reduction in fossil fuels use in energy applications.
Thanks to the development of new systems for the energy production, district heating, and heat pumps, the exploitation of the geothermal reservoirs is predicted to increase, thus contributing to the reduction in fossil fuels use in energy applications.
With regard to geothermal plants for electricity production, three types of geothermal power plants operate in Europe: conventional (flash and dry steam), binary, and Enhanced Geothermal Systems (EGSs) [2].The first ones are the most common, although considering the ongoing development, the rise in deployment of the binary and EGS plants is expected, as shown in Figure 1 ( based on data from [3,4]).It is presumed that advancing research, growth, and development in the field of geological formation exploration, drilling, as well as stimulation will continuously be adjusted from the oil and gas sector.Despite the visible progress in enhanced geothermal systems, the EGS technologies are still not mature enough to be commercially competitive with other expanding renewable energy sources such as solar and wind.Operating demonstration EGS plants and their performance would possibly contribute to a significant decrease in drilling costs, which represents the major share in EGS installation cost.Nevertheless, growing attention drawn by developing EGS deployment, especially spotted in countries such as the USA, Great Britain, Germany, China, ,Iceland and The Netherlands, should be transferred to actions and support from the government and other associated entities in order to provide further technology growth [5].
One of the parameters used to assess the potential power plant is Technology Readiness Level (TRL), which describes the maturity of a given technology.In the case of the enhanced geothermal system, this term includes also the readiness of fracturing, drilling, and energy carrier utilization.Due to issues related to geothermal reservoir establishment, stimulation requirements, interactions between working fluid and rock structure, as well as high costs, the technology readiness remains low.Taking into account the sCO2 cycles TRL, which is also low (around 4-5), and the fact that the sCO2-EGS concept is younger than the more developed water-based geothermal systems, the overall sCO2-EGS technology readiness level may be estimated as 4 in a technology-specific scale, which corresponds to an early stage of development [6][7][8].
The main goal of this paper is to provide an economic and energy performance assessment of supercritical carbon dioxide enhanced geothermal systems for power It is presumed that advancing research, growth, and development in the field of geological formation exploration, drilling, as well as stimulation will continuously be adjusted from the oil and gas sector.Despite the visible progress in enhanced geothermal systems, the EGS technologies are still not mature enough to be commercially competitive with other expanding renewable energy sources such as solar and wind.Operating demonstration EGS plants and their performance would possibly contribute to a significant decrease in drilling costs, which represents the major share in EGS installation cost.Nevertheless, growing attention drawn by developing EGS deployment, especially spotted in countries such as the USA, Great Britain, Germany, China, Iceland and The Netherlands, should be transferred to actions and support from the government and other associated entities in order to provide further technology growth [5].
One of the parameters used to assess the potential power plant is Technology Readiness Level (TRL), which describes the maturity of a given technology.In the case of the enhanced geothermal system, this term includes also the readiness of fracturing, drilling, and energy carrier utilization.Due to issues related to geothermal reservoir establishment, stimulation requirements, interactions between working fluid and rock structure, as well as high costs, the technology readiness remains low.Taking into account the sCO 2 cycles TRL, which is also low (around 4-5), and the fact that the sCO 2 -EGS concept is younger than the more developed water-based geothermal systems, the overall sCO 2 -EGS technology readiness level may be estimated as 4 in a technology-specific scale, which corresponds to an early stage of development [6][7][8].
The main goal of this paper is to provide an economic and energy performance assessment of supercritical carbon dioxide enhanced geothermal systems for power generation in order to compare their applicability in a practical point of view.This type of analysis allows for defining the strengths of the various types of Enhanced Geothermal Systems fed by supercritical carbon dioxide (sCO 2 -EGS) power plants from both a productivity and investment perspective, leading to the achievement of a trade-off between the needs and resources in which the system will be installed.
The following paragraphs in this paper give a broader view of the enhanced geothermal systems including a literature review and EGS assessments regarding the energetic performance of different EGS configurations as well as economic evaluation.

EGS Description
The idea of Enhanced Geothermal Systems (EGSs) is based on the concept of Hot Dry Rock (HDR) first developed in Los Alamos National Laboratory in the USA.HDR is underground bedrock that mainly consists of intact granite or other crystalline basement rock and is characterized by low permeability, low porosity, but significant geothermal potential [9].The block of hot rock creates a tank located about 5 km below the Earth's surface, whose hydraulic performance has to be artificially increased to enable the heat extraction.Enhancing the flow rate of a working fluid through such tight formations may be achieved with various approaches that have been developed.These methods refer to hydraulic fracturing, chemical stimulation, as well as thermally induced fracturing [10].The fractures complexity proceeds mainly from their geometry, which is related to different factors including in situ stress conditions, fracturing fluid, and fractures topologies, as well as wellbore direction [11].The utilization of this accumulated geothermal energy allows for generating electricity on the ground via working fluid, which circulates and collects the heat (Figure 2).Therefore, the most common working fluids used in these power plant types are water, ORC (Organic Rankine Cycle) fluid, and CO2.The possibility of using different working fluids and the chance of matching it to an ORC make EGS technology an important method of exploitation of geothermal sources, and what also characterizes such a system is the fact that no water is wasted and no gas is released during the HDR utilization [14].

Comparison of CO2 and Water
Working fluid in enhanced geothermal systems may be defined as a mixture containing dominant fluid and additives that is applied to create a network of connected frac- The concept is to use hydraulic fracturing to form an artificial geothermal reservoir by creating fractures deep underground.Applied fracturing technologies are widely used in the oil and gas industry, but in EGS systems, they mostly center on shear stimulation of pre-existing natural fractures or are adjusted to create new fractures in geothermal fields.Before EGS development, heat extraction from geothermal resources was possible only from fractures naturally found in hydrothermal reservoirs with appropriate permeability.Due to hydraulic stimulation, the fractures connect and, thus, the contact area is expanded, resulting in higher energy exchange efficiency [9].By injecting fluid into the reservoir, the heat is extracted and the hot fluid is brought to the surface to generate electricity or heat.Unlike hydrothermal, EGSs may be feasible anywhere in the world, depending on the economic limits of drill depth and the source temperature available.The choice of the working fluid used to extract the heat from the artificial well depends on the energy availability of the well itself (temperature) and on the thermodynamic properties of the fluid [12].
The first step to set-up an EGS plant is to locate a suitable reservoir with high rock temperature.The site depends on an area with hot, dry rock not on the water accumulated in hydrogeothermal reservoirs as it is conducted in conventional geothermal systems.Then, the wells are drilled and the bedrock is stimulated by hydraulic fracturing to generate a stable network of open, connected fractures that will carry the flow of injected working fluid.Afterward, the fluid circulates through the permeable pathways in the fractured zone collecting the heat and is subsequently extracted by the production well.On the surface, the heat from the fluid is used to produce electricity or electricity and heat in combined systems.EGSs work in a closed loop; thus, the working fluid is headed to the injection well to be reheated.The plant consists of facilities located above and under the ground [13].
Therefore, the most common working fluids used in these power plant types are water, ORC (Organic Rankine Cycle) fluid, and CO 2 .The possibility of using different working fluids and the chance of matching it to an ORC make EGS technology an important method of exploitation of geothermal sources, and what also characterizes such a system is the fact that no water is wasted and no gas is released during the HDR utilization [14].

Comparison of CO 2 and Water
Working fluid in enhanced geothermal systems may be defined as a mixture containing dominant fluid and additives that is applied to create a network of connected fractures.In addition to that, the desired working fluid should be marked by being environmentally friendly with no formation damage, easily available, and feasible, as well as capable of losses control, carrying specific proppants in the formation, and generating a desired net pressure [9].In a classical EGS, water is applied as a working fluid, although there are some promising gas fluids that may become more advantageous.Due to its thermodynamic properties and environmental benefits, CO 2 as a working fluid becomes an attractive option [2].Table 1 presents the differences between water and CO 2 as a working fluid in enhanced geothermal systems.The idea of a CO 2 -EGS was proposed at first by Brown in 2000 [15].It was suggested that CO 2 may be more beneficial than water in such plants.This system has an advantage of possible permanent CO 2 sequestration through fluid losses at great depths during its operations, which seems crucial in case of the need to reduce carbon emissions.CO 2 is less effective as a solvent for most rock minerals and its larger compressibility and expansiveness reflect the strong natural buoyance force that yields larger self-propelled flow velocities and less power consumption needed for the fluid circulation system.Furthermore, CO 2 is seen as a more favorable solution due to its lower viscosity, which results in higher mobility and better transport properties, and partly compensates the lower-than-water mass heat capacity by greater flows.
The advantage of EGS plants is the possibility to utilize part of the CO 2 captured from fossil-fired power plants and other emitters, preventing emissions to the atmosphere.Despite that, these systems have to face some challenges.

The Application of sCO 2 Cycles
According to the international targets on the reduction in carbon dioxide production, new low-emission power plants, more efficient renewable energy systems, and new CO 2 capture systems will be case studies in the coming years.
The sCO 2 cycle represents one of the most important ways to improve the costeffectiveness of carbon capture and storage (CCS) technologies using CO 2 captured before its permanent geological storage [8].Thermal-power cycles operating with supercritical carbon dioxide could have a significant role in future power generation systems with applications including fossil fuel, nuclear power, concentrated-solar power, and waste-heat recovery.
The use of sCO 2 as both reservoir fracturing fluid and working fluid has been initially proposed by Brown in a study [15] mainly focused on the geological perspective (the sCO 2 not being a good solvent results in a significant reduction in the scaling problems that makes sH 2 O reservoir development unfeasible).The following studies [16,17] have shown that the sCO 2 is also capable of generating a significant thermosyphon effect due to the density gradient between the injection and production wells.This allows for the direct expansion of the working fluid in a turbine, greatly simplifying the surface plant physical footprint and improving the operational flexibility, which could result in lower levelized costs of electricity compared to existing technologies [18].On the other hand, water-based systems are usually more appealing for heat-driven application (DH systems, Closed Binary Cycles) due to the higher specific heat of H 2 O compared with sCO 2 .

Working Fluids in ORC-EGS
The ORC working fluid selection is critical for the system performances, and multiple studies [19,20] have analyzed different aspects of fluid selections.Many technical, economic, and environmental aspects, often conflicting with each other, must be considered when selecting the working fluid, and the detailed guideline has been proposed by Quoilin et al. [21] and can help in the selection process.
In practice, however, only a few fluids are used by industries while developing a geothermal binary plant, for economic, environmental, and industry standardization reasons.The most common fluids are:

Case Study Selection
Depending on the heat demand type as well as possibility to obtain temperatures and pressures of the supercritical CO 2 at the outlet of the production well, three types of energy generation scenarios could be investigated: Due to the reduced thermal capacity of the geothermal region with which the modeling of the power plants was implemented, electricity generation became the primary goal.However, it was decided to introduce a specific power plant with an installation for a district heating system (DHS) in order to evaluate the exploitation of the resource in a combined power plant.
Four groups of cycles can be distinguished: The Direct sCO 2 cycle, presented in Figure 3a, represents the simplest cycle for the exploitation of the geothermal resource.This power plant foresees a direct expansion in the dedicated turbine of the sCO 2 coming from the geothermal well.After that, the sCO 2 is cooled before the injection well, and the heat released to the cooling fluid is not recovered.Due to partial CO 2 sequestration (sequestration rate around 5%), an additional CO 2 stream supplies the cycle.In the second case (Figure 3b), which shows an indirect sCO 2 cycle with the ORC, the electric power is generated only by the expansion in the turbine in the ORC.The sCO 2 in the geothermal well works in a closed loop and is used as a hot source to feed the Organic Rankine Cycle via a dedicated heat exchanger.Heat extracted by sCO 2 in the reservoir is transferred to the ORC working fluid, which circulates in the cycle containing basic elements: turbine with generator, condenser, and pump.
The next two implemented models represent two solutions where the goal is to maximize the recovery of energy that is lost from the sCO 2 cycle by cogeneration application.These two configurations are based on the already presented, basic direct sCO 2 cycle, which was extended by adding an extra heat exchanger for heat transfer to circulating water in the DHS.Both variants are presented in Figure 4 and the distinction between them relies on the location of the applied heat exchanger.
A direct supercritical CO 2 cycle with cogeneration combines electricity production with heat generation for the district heating system.In this work, two different arrangements were analyzed:

•
DHS between turbine stages with lower source temperature (Figure 4a); • DHS after outlet production well with higher source temperature (Figure 4b).The next two implemented models represent two solutions where the goal is to maximize the recovery of energy that is lost from the sCO2 cycle by cogeneration application.These two configurations are based on the already presented, basic direct sCO2 cycle, which was extended by adding an extra heat exchanger for heat transfer to circulating water in the DHS.Both variants are presented in Figure 4 and the distinction between them relies on the location of the applied heat exchanger.A direct supercritical CO2 cycle with cogeneration combines electricity production with heat generation for the district heating system.In this work, two different arrangements were analyzed: • DHS between turbine stages with lower source temperature (Figure 4a); • DHS after outlet production well with higher source temperature (Figure 4b).
Looking for the best solution for recovering the heat released in the direct sCO2 cycle,

Analytical Model Description
This subsection presents the process of mathematical modeling of the sCO2 cycles, which are intended to be applied for utilization of the heat extracted from the geothermal reservoir.On the basis of the set of configurations described in the previous section, mathematical models of the direct sCO2 Brayton cycles for electricity production or cogeneration were developed.For this purpose, the Engineer Equations Solver (EES) software was used.This tool was designed for calculating energy balances and simulating processes.
Engineer Equations Solver is a software used for solving engineering problems based on the resolution of a system with n equations and n unknowns.
For each plant configuration, a numerical model was implemented using EES with the aim of calculating the thermodynamic points of the cycle, and the mass and energy balances for each component of the plant.Moreover, through the tools of the software (parametric analysis), it was possible to determine the performance parameters of each configuration to vary the parameters of the geothermal reservoir.A model of the reservoir itself was prepared using work [24].
It is worth pointing out that all configurations have common basic components to ensure the same exploitation of the resource.Having similar configurations and the same components allowed for making a comparison between the various solutions, in addition to achieving comparable results.
As shown in the previous section, four different cases of the sCO2 cycles were proposed: Direct sCO2 cycle Due to the CO2 thermosiphon effect, no additional CO2 compressor is necessary in all configurations analyzed in this work.After the sCO2 passes through the turbine, mass flow losses are replenished in the mixer through a sCO2 feed pipeline.Then, it is cooled down in the gas cooler and flows to the injection well.The turbine outlet pressure is defined as the sum of the required pressure at the inlet of the injection well and the pressure loss in the gas cooler.
Indirect sCO2 cycle with ORC (binary cycle) Looking for the best solution for recovering the heat released in the direct sCO 2 cycle, in order to maximize electricity production and cycle efficiency, a combined power plant with a direct sCO 2 cycle and ORC was modeled.Those configurations match the direct sCO 2 expansion in the turbine as well as the heat transfer through the heat exchanger to the Organic Rankine Cycle.According to this, two different systems of combined power plant were proposed:

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Recovery heat exchanger before inlet of the injection well (Figure 5a);

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Recovery heat exchanger after outlet of the production well (Figure 5b).

Analytical Model Description
This subsection presents the process of mathematical modeling of the sCO 2 cycles, which are intended to be applied for utilization of the heat extracted from the geothermal reservoir.On the basis of the set of configurations described in the previous section, mathematical models of the direct sCO 2 Brayton cycles for electricity production or cogeneration were developed.For this purpose, the Engineer Equations Solver (EES) software was used.This tool was designed for calculating energy balances and simulating processes.
Engineer Equations Solver is a software used for solving engineering problems based on the resolution of a system with n equations and n unknowns.
For each plant configuration, a numerical model was implemented using EES with the aim of calculating the thermodynamic points of the cycle, and the mass and energy balances for each component of the plant.Moreover, through the tools of the software (parametric analysis), it was possible to determine the performance parameters of each configuration to vary the parameters of the geothermal reservoir.A model of the reservoir itself was prepared using work [24].
It is worth pointing out that all configurations have common basic components to ensure the same exploitation of the resource.Having similar configurations and the same components allowed for making a comparison between the various solutions, in addition to achieving comparable results.
As shown in the previous section, four different cases of the sCO 2 cycles were proposed: Direct sCO 2 cycle Due to the CO 2 thermosiphon effect, no additional CO 2 compressor is necessary in all configurations analyzed in this work.After the sCO 2 passes through the turbine, mass flow losses are replenished in the mixer through a sCO 2 feed pipeline.Then, it is cooled down in the gas cooler and flows to the injection well.The turbine outlet pressure is defined as the sum of the required pressure at the inlet of the injection well and the pressure loss in the gas cooler.
Indirect sCO 2 cycle with ORC (binary cycle) The sCO 2 is not directed to expansion in the turbine.The sCO 2 from the production well goes through a heat exchanger, where the heat is transferred to the working fluid in the ORC and then sCO 2 is cooled using a laminar valve, in order to obtain the required injection well's pressure and temperature.The ORC working fluid at vapor-saturated conditions passes through the turbine to be consequently cooled down until it reaches liquid-saturated conditions.
Direct supercritical CO 2 cycle with cogeneration Heat and power generation are the main products in such units.Heat is recovered with a DHS before the turbine inlet or with a DHS located between two stages of the turbine.Power generation is obtained via sCO 2 expansion in the turbine or as with the other case with the passage of the sCO 2 in the two turbine stages.After the expansion and crossing of the mixer, the carbon dioxide is cooled down but the heat released is not recovered (waste heat).
Combined direct sCO 2 with Organic Rankine Cycle Direct expansion in the sCO 2 turbine and ORC allows electricity production to be achieved.It is characterized by matching the direct sCO 2 cycle and ORC.The sCO 2 cycle works exactly as described in previous systems, but the combination with the ORC was proposed in two different ways.The first solution refers to feeding the ORC through the heat recovery released by the heat exchanger before the injection well, and the second case involves the use of a heat exchanger located after the production well outlet.The operation of the ORC is the same as that described in the binary configuration.
The working fluid used in the Organic Rankine Cycle is isobutane.This fluid was chosen due to its considerable use in the ORC and the fact that natural gas derivatives are generally cheaper.On the contrary, the use of chemical refrigerants is not recommended, as they are considered to be contaminative (e.g., R134a) or very expensive (e.g., R1233zd(e)).

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Geothermal Well For each power plant, the same geothermal well was used as an energy source for the thermodynamic cycle.The geothermal well model was implemented by defining the temperature and flow rate of CO 2 in the injection well; these two parameters represent the independent variables from which it was possible to calculate the pressure, flow, and temperature values of the production well by the use of the EES interpolation function.
According to the model, ranges of temperature and mass flow for the CO 2 injection well were set as: 20 All configurations were simulated by changing the parameters of .m inj and T inj within the fixed ranges.Therefore, it was possible to identify the parameters (mass flow, pressure, and temperature) of the geothermal wells corresponding to the maximum production of electricity.

• Pipeline
In all models implemented, the supercritical CO 2 cycle was fed by carbon dioxide from pipelines to replace the mass flow losses.The mixer after the turbine outlet allowed for matching the sCO 2 feed system with the main stream into the supercritical cycle.The origin of the mass flow losses is due to the transition of CO 2 in the geothermal well: the interaction of the carbon dioxide with chemical substances present in the subsoil leads to the oxidation of part of the CO 2 , causing a reduction in the effective outgoing mass flow from the production well.

• Main compressor
All sCO 2 cycles in each configuration include a compressor (main compressor) located between the mixer and the condenser/heat exchanger.This compressor goes into operation for maintaining the required pressure at the injection well inlet in the case of excessive pressure drop due to the components of the power plant.In Table 2, a summary of the main assumptions for system components is presented.Due to different temperatures in units with cogeneration, it was assumed that in the first case, D_sCO 2 _DHS A , where the heat exchanger for the district heating system is located between the turbines, the temperatures of water at the cold and hot side will be, respectively, 35/60 • C, which is suitable for the low-temperature DHS (LTDHS).The low-temperature system usually refers to temperatures between 50 and 60 • C and is rated as modern 4th-generation district heating [25].In the second case (D_sCO 2 _DHS B ) where the DHS heat exchanger is located after the production well, the water temperatures were assumed to be 50/80 • C, which represents typical values for the Polish district heating system (3rd generation).Different water temperature values will not have an impact on further economic evaluation, because of the exergetic allocation method used for calculations.

Economic Assessment
For the purpose of economic comparison of the analyzed EGS cases, the total system capital expenditure (CAPEX) was evaluated with the following formula: CAPEX consists of the costs of drilling the wells C well , which depends on the unit cost of drilling one well C well,unit ; the number of wells n well ; the well depth d; costs associated with one well-doublet development (including hydraulic fracturing of the EGS zone), C EGS ; the cost of installed equipment C EQP ; as well as the cost of secondary equipment (pipes, valves, civil engineering, instrumentation, and control equipment), including the cost of transportation, the land cost, civil and structure cost C direct,EQP , and indirect cost, which denotes engineering, supervision, and plant start-up costs C indirect,EQP .
The calculations were performed using the methodology presented in [26].Presented costs were updated to EUR2021 from their origin years due to EUR/USD exchange rates.
Equipment cost was obtained from the following equations applied for turbomachinery and heat exchangers separately: For turbomachinery: For heat exchangers: where factors f p , f t refer to maximum pressure and temperature, respectively, for sCO 2 installed components.The following correlations allow the influence of high pressure and temperature on the equipment materials to be taken into consideration.
The functions Equations ( 5) and ( 6) include W, which relates to the power of machinery (turbine, compressor, pump, and generator) (MW); U A, which denotes the multiplication of the overall heat transfer coefficient U and heat transfer area A (kW/K); 'a' and 'b' parameters, which depend on the component.
Further financial assumptions are presented in Table 3.  [26] 8% of (∑ C i,EQP + C direct,EQP ) All other necessary assumptions regarding equipment costs in sCO 2 cycles and Organic Rankine Cycles were taken from [27,28].
The economic evaluation also includes the performance of Levelized Cost of Electricity for all analyzed cases and Levelized Cost of Heat for combined cycles.The levelized costs enable the comparison to be made of plants in the case of their system profitability and to relate to the average electricity or heat prices that have to be incurred for energy generation during the unit lifetime.The LCOE and LCOH were calculated based on the following formulas: where OPEX refers to operational expenditures; E el is annual electricity generation, Q is annual heat production for the DHS; ε B,el and ε B,Q are total system cost multipliers, which enable specific cost allocation to electricity and heat production, respectively, obtained within the exergy allocation methodology [29]; f r is a discount factor calculated as follows: where r is the discount rate and n is years of project lifetime.

Energy Assessment
The obtained results show the potentialities of the different simulated power plants.As presented, the discussed results are based on the developed mathematical models and conducted simulations.Due to the lack of experimental data from pilot or demonstration plants, it is impossible to validate the results of the whole CO 2 -EGS analyzed, but the performance of the Bryton CO 2 cycles is within the range of results from similar studies.
In the first analysis, the net power is the main parameter with which the plants were compared.However, an exclusively developed comparison of net output power would be limiting.Each plant must be contextualized to the field of application and the necessary resources to obtain the plant power.On this basis, the analysis of the results obtained in this paper provides a comparison of all the models, with the aim of determining the best design solutions according to the varying application conditions.In Figure 6, the net power of the analyzed systems is presented.The economic evaluation also includes the performance of Levelized Cost of Electricity for all analyzed cases and Levelized Cost of Heat for combined cycles.The levelized costs enable the comparison to be made of plants in the case of their system profitability and to relate to the average electricity or heat prices that have to be incurred for energy generation during the unit lifetime.The LCOE and LCOH were calculated based on the following formulas: where  refers to operational expenditures;  is annual electricity generation, Q is annual heat production for the DHS;  , and  , are total system cost multipliers, which enable specific cost allocation to electricity and heat production, respectively, obtained within the exergy allocation methodology [29];  is a discount factor calculated as follows: where  is the discount rate and  is years of project lifetime.

Energy Assessment
The obtained results show the potentialities of the different simulated power plants.As presented, the discussed results are based on the developed mathematical models and conducted simulations.Due to the lack of experimental data from pilot or demonstration plants, it is impossible to validate the results of the whole CO2-EGS analyzed, but the performance of the Bryton CO2 cycles is within the range of results from similar studies.
In the first analysis, the net power is the main parameter with which the plants were compared.However, an exclusively developed comparison of net output power would be limiting.Each plant must be contextualized to the field of application and the necessary resources to obtain the plant power.On this basis, the analysis of the results obtained in this paper provides a comparison of all the models, with the aim of determining the best design solutions according to the varying application conditions.In Figure 6, the net power of the analyzed systems is presented.Targeting the maximum available power generation, the hybrid power plants' sCO 2 + ORC turn out to have the highest value of power generation.Furthermore, placing the heat exchanger at the inlet of the injection well leads to more power.As expected, the direct supercritical CO 2 cycle with cogeneration returns a lower power (high percentage of heat production).
The direct sCO 2 cycle generates a reduced power compared to hybrid cases, but the generated power ratio and design complexity makes it a very advantageous solution.
Simulations show that plants with a greater potential for the production of electricity have a hybrid cycle sCO 2 + ORC and binary cycle.Therefore, the comparison of these two models in terms of power production was conducted.
From the plots in Figure 7, it can be observed that in the binary model, the power is directly proportional to the flow of sCO 2 : increasing the flow yields a higher power as the supercritical cycle is detached from the power cycle (hot source).
Sustainability 2022, 14, x FOR PEER REVIEW 14 of 22 Targeting the maximum available power generation, the hybrid power plants' sCO2 + ORC turn out to have the highest value of power generation.Furthermore, placing the heat exchanger at the of the injection well leads to more power.As expected, the direct supercritical CO2 cycle with cogeneration returns a lower power (high percentage of heat production).
The direct sCO2 cycle generates a reduced power compared to hybrid cases, but the generated power ratio and design complexity makes it a very advantageous solution.
Simulations show that plants with a greater potential for the production of electricity have a hybrid cycle sCO2 + ORC and binary cycle.Therefore, the comparison of these two models in terms of power production was conducted.
From the plots in Figure 7, it can be observed that in the binary model, the power is directly proportional to the flow of sCO2: increasing the flow yields a higher power as the supercritical cycle is detached from the power cycle (hot source).On the other hand, in the hybrid models, the power generated has a maximum point corresponding to a certain mass flow of sCO2.Further increasing the mass flow is conducive to decreasing the power, as the total value of the net power is obtained from the sum of the net powers generated by the cycle ORC and sCO2.The inflection point can be explained by tracing the separate course of the two power inputs corresponding to the two cycles ORC and sCO2.In the plot in Figure 8, it can be noticed that while increasing the mass flow, the power generated by the sCO2 cycle and ORC has the opposite trend: at high flow rates, the contribution of the power ORC system is preponderant in comparison with the power of the sCO2 cycle; on the contrary, for lower mass flow rates, the supercritical cycle generates a higher power.On the other hand, in the hybrid models, the power generated has a maximum point corresponding to a certain mass flow of sCO 2 .Further increasing the mass flow is conducive to decreasing the power, as the total value of the net power is obtained from the sum of the net powers generated by the cycle ORC and sCO 2 .The inflection point can be explained by tracing the separate course of the two power inputs corresponding to the two cycles ORC and sCO 2 .In the plot in Figure 8, it can be noticed that while increasing the mass flow, the power generated by the sCO 2 cycle and ORC has the opposite trend: at high flow rates, the contribution of the power ORC system is preponderant in comparison with the power of the sCO 2 cycle; on the contrary, for lower mass flow rates, the supercritical cycle generates a higher power.
For low sCO 2 mass flow, power generation from the ORC is negligible compared to sCO 2 .Due to low mass flow and lower temperature output from the production well, the heat recovered from the ORC is limited.Therefore, the use of a sCO 2 direct expansion cycle without a parallel ORC is the best solution for power generation (improved plant power and investment costs ratio).
For high sCO 2 mass flow, the power generated in the sCO 2 cycle decreases unlike the trend of ORC net power.The use of the sCO 2 as well as a hot source in a binary cycle is the best solution for power generation in this configuration as the binary cycle has the maximum net power generated for the highest mass flow available.For low sCO2 mass flow, power generation from the ORC is negligible compared to sCO2.Due to low mass flow and lower temperature output from the production well, the heat recovered from the ORC is limited.Therefore, the use of a sCO2 direct expansion cycle without a parallel ORC is the best solution for power generation (improved plant power and investment costs ratio).
For high sCO2 mass flow, the power generated in the sCO2 cycle decreases unlike the trend of ORC net power.The use of the sCO2 as well as a hot source in a binary cycle is the best solution for power generation in this configuration as the binary cycle has the maximum net power generated for the highest mass flow available Not only is the power generated important, but also the conditions under which maximum electricity production is achieved.In this regard, the plot in Figure 9 allows the definition of the value of the well's parameters that identify the peak of the energy production at the well inlet temperature of 35 °C (temperature corresponding to maximum power values).Not only is the power generated important, but also the conditions under which maximum electricity production is achieved.In this regard, the plot in Figure 9 allows the definition of the value of the well's parameters that identify the peak of the energy production at the well inlet temperature of 35 • C (temperature corresponding to maximum power values).For the same injection temperature, the configurations may be compared in the case of unitary net power output, which is the obtained net power divided by the mass flow rate (Figure 10).This gives a different perspective on the dependence between generated power and sCO2 flow rate; nevertheless, the conducted analysis shows that the highest power was reached in direct cycles with the ORC.For the same injection temperature, the configurations may be compared in the case of unitary net power output, which is the obtained net power divided by the mass flow rate (Figure 10).This gives a different perspective on the dependence between generated power and sCO 2 flow rate; nevertheless, the conducted analysis shows that the highest power was reached in direct cycles with the ORC.
For the same injection temperature, the configurations may be compared in the case of unitary net power output, which is the obtained net power divided by the mass flow rate (Figure 10).This gives a different perspective on the dependence between generated power and sCO2 flow rate; nevertheless, the conducted analysis shows that the highest power was reached in direct cycles with the ORC.Analyzing the power plants with cogeneration, inevitably, the power generated is not comparable to other plants, but it is possible to compare the two analyzed solutions in which the location of the DHS is different (Figure 11).Analyzing the power plants with cogeneration, inevitably, the power generated is not comparable to other plants, but it is possible to compare the two analyzed solutions in which the location of the DHS is different (Figure 11).The DHS located at the outlet of the production well and before the sCO2 turbine inlet promotes the production and recovery of heat because the enthalpy of the working fluid is high.This, however, involves a reduction in the ΔH in the turbine unfavorable for the production of electricity.Instead, placing the DHS between two turbine stages allows a higher output power to be obtained but with a lower enthalpy heat source for heat generation.

Economic Evaluation
Figure 12 shows the CAPEX distribution in the analyzed cases.In all six systems, the cost of drilling was the same (the same depth and number of wells) and it represents the biggest share in CAPEX of EGS systems up to 80.3% of the total investment cost.In the The DHS located at the outlet of the production well and before the sCO 2 turbine inlet promotes the production and recovery of heat because the enthalpy of the working fluid is high.This, however, involves a reduction in the ∆H in the turbine unfavorable for the production of electricity.Instead, placing the DHS between two turbine stages allows a higher output power to be obtained but with a lower enthalpy heat source for heat generation.

Economic Evaluation
Figure 12 shows the CAPEX distribution in the analyzed cases.In all six systems, the cost of drilling was the same (the same depth and number of wells) and it represents the biggest share in CAPEX of EGS systems up to 80.3% of the total investment cost.In the direct sCO 2 case, this share is highest because of just a few components, which are associated with the lowest equipment cost.The high pressure and temperature values impact the heat exchanger operation, especially in the indirect sCO 2 cycle; thus, in this case, the cost of heat exchangers components is highest.In Figure 13, the correlation between the obtained LCOE for each variant with increasing discount rate up to 20% is presented.The graph shows a wider perspective on how the discount factor influences the costs of a project.For all cases, the growth of LCOE with the rising values of discount rate is visible; however, as shown in Table 4, the indirect cycle becomes the highest LCOE, while direct cycles integrated with the district heating system become the lowest.A summary of the economic evaluation containing CAPEX, OPEX, as well as the values of Levelized cost of electricity and heat (for combined cycles) is presented in Table 4.The highest levelized cost was obtained in the binary cycle due to the relatively high capital costs and low electricity production.The LCOH was performed for variants with cogeneration, and this parameter is slightly smaller in the case where the DHS heat exchanger is located after the production well; nevertheless, both values are within an acceptable range.
In Figure 13, the correlation between the obtained LCOE for each variant with increasing discount rate up to 20% is presented.The graph shows a wider perspective on how the discount factor influences the costs of a project.For all cases, the growth of LCOE with the rising values of discount rate is visible; however, as shown in Table 4, the indirect cycle becomes the highest LCOE, while direct cycles integrated with the district heating system become the lowest.For the direct sCO2 cycle combined with the ORC where the recovery heat exchanger is located before the injection well, the change in LCOE with the sCO2 mass flow was performed (Figure 14).With the lowest value of 20 kg/s, the LCOE reached almost 900 EUR/MWh; thus, it would be not economically viable to build a unit with such a low mass flow.For mass flows between 100 and 200 kg/s, the obtained LCOE has similar values but the net power differs; therefore, it is essential to choose the optimal solution.For the direct sCO 2 cycle combined with the ORC where the recovery heat exchanger is located before the injection well, the change in LCOE with the sCO 2 mass flow was performed (Figure 14).With the lowest value of 20 kg/s, the LCOE reached almost 900 EUR/MWh; thus, it would be not economically viable to build a unit with such a low mass flow.For mass flows between 100 and 200 kg/s, the obtained LCOE has similar values but the net power differs; therefore, it is essential to choose the optimal solution.For the direct sCO2 cycle combined with the ORC where the recovery heat exchanger is located before the injection well, the change in LCOE with the sCO2 mass flow was performed (Figure 14).With the lowest value of 20 kg/s, the LCOE reached almost 900 EUR/MWh; thus, it would be not economically viable to build a unit with such a low mass flow.For mass flows between 100 and 200 kg/s, the obtained LCOE has similar values but the net power differs; therefore, it is essential to choose the optimal solution.

Discussion
The purpose of the paper was to compare and discuss the energetic and economic performances of enhanced geothermal systems based on sCO 2 cycles.
The results show the strengths of different types of power and heat generating systems built on the geothermal reservoir.Nevertheless, there is a difficulty in identifying the best solution as the choice will depend on the useful effect obtained from the geothermal source.

•
Power generation The use of the combined direct sCO 2 with the ORC allows the power plant efficiency to be optimized by recovering part of the heat released from the sCO 2 cycle to produce additional electricity but with greater design complexities.On the other hand, the binary cycle would allow for high power outputs, but the use of sCO 2 as working fluid would limit the geothermal heat recovery.This favors the use of working fluids that would provide a higher heat recovery than sCO 2 (e.g., water).

• Cogeneration
The performance of the variants analyzed in this paper was evaluated over a wide range of sCO 2 flow rates, temperatures, and pressures.What should be stressed in these units is a beneficial impact on the wellhead pressure difference, which causes a thermosiphon effect and subsequently leads to no requirement of an additional CO 2 compressor before the injection well.However, to study the design feasibility of combined power plants, it is necessary to analyze the technological availability of turbomachinery (compressors and turbines) working with sCO 2 (design constraint).
From the economic perspective, the capital and operational expenditures were highest for the direct sCO 2 cycle with cogeneration where a heat exchanger was added between turbine stages, but similar values were obtained for the indirect cycle and, for this case, the LCOE was highest.For all analyzed cases, the LCOE varied between 118 and 220 EUR/MWh.For low mass flow rates, the sCO 2 -EGSs are not financially justified, because of high costs of electricity as well as low electricity production.Due to recent fluctuations in the energy market and associated variable electricity prices as well as low technology readiness level that influences high capital expenditures, the EGS payback period is not feasible within 25 years of project lifetime and the internal rate of return is lower than the assumed discount rate.These research findings emphasize the need of financial support for further development and deployment of enhanced geothermal systems, especially when we consider the benefit of possible CO 2 partial permanent storage.

Figure 1 .
Figure 1.Current state of global installed geothermal capacity.

Figure 1 .
Figure 1.Current state of global installed geothermal capacity.

Figure 3 .
Figure 3. Simplified schematic diagrams of (a) direct sCO 2 cycle and (b) indirect sCO 2 cycle with ORC.Sustainability 2022, 14, x FOR PEER REVIEW 8 of 22

Figure 4 .
Figure 4. Simplified schematic diagrams of direct sCO2 cycle with cogeneration; (a) DHS between turbine stages; (b) DHS after the production well.

Figure 4 .Figure 5 .
Figure 4. Simplified schematic diagrams of direct sCO 2 cycle with cogeneration; (a) DHS between turbine stages; (b) DHS after the production well.

Figure 5 .
Figure 5. Simplified schematic diagrams of direct sCO 2 cycle with ORC: (a) recovery before the injection well; (b) recovery after the production well.

Figure 6 .
Figure 6.Net power of the analyzed configurations.Figure 6.Net power of the analyzed configurations.

Figure 6 .
Figure 6.Net power of the analyzed configurations.Figure 6.Net power of the analyzed configurations.

Figure 7 .
Figure 7. Three-dimensional plots for (a) binary cycle and (b) direct sCO2 cycle with ORC (heat recovery before injection well).

Figure 7 .
Figure 7. Three-dimensional plots for (a) binary cycle and (b) direct sCO 2 cycle with ORC (heat recovery before injection well).

Figure 8 .
Figure 8.The comparison of sCO2 and ORC in the case of net power with variable mass flow rates and injection temperatures between 35 and 55 °C.

Figure 8 .
Figure 8.The comparison of sCO 2 and ORC in the case of net power with variable mass flow rates and injection temperatures between 35 and 55 • C.

Figure 9 .
Figure 9.The change in net power with variable mass flow rates for analyzed configurations and peak points (marked as red squares) obtained for maximum power generated in each system.

Figure 9 .
Figure 9.The change in net power with variable mass flow rates for analyzed configurations and peak points (marked as red squares) obtained for maximum power generated in each system.

Figure 10 .
Figure 10.The change in unitary net power with variable mass flow rates for analyzed cases.Figure 10.The change in unitary net power with variable mass flow rates for analyzed cases.

Figure 10 .
Figure 10.The change in unitary net power with variable mass flow rates for analyzed cases.Figure 10.The change in unitary net power with variable mass flow rates for analyzed cases.

Figure 11 .
Figure 11.Three-dimensional plots for sCO2 with DHS located (a) between turbine stages and (b) after the production well.

Figure 11 .
Figure 11.Three-dimensional plots for sCO 2 with DHS located (a) between turbine stages and (b) after the production well.

Figure 12 .
Figure 12.CAPEX distribution within the analyzed cases.

Figure 13 .
Figure 13.Correlation between LCOE and discount rate for analyzed cases.

Figure 14 .
Figure 14.Change in LCOE and Net Power with increasing mass flow for case.

Figure 13 .
Figure 13.Correlation between LCOE and discount rate for analyzed cases.

Figure 14 .
Figure 14.Change in LCOE and Net Power with increasing mass flow for case.

Figure 14 .
Figure 14.Change in LCOE and Net Power with increasing mass flow for case.

Table 2 .
Summary of modeling assumptions.

Table 3 .
Summary of financial assumptions.

Table 4 .
Summary of Levelized Cost of Electricity and Heat.

Table 4 .
Summary of Levelized Cost of Electricity and Heat.