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Techno-Economic Assessment of a Combined Heat and Power Plant Integrated with Carbon Dioxide Removal Technology: A Case Study for Central Poland

Techno-Economic Assessment of a Combined Heat and Power Plant Integrated with Carbon Dioxide... energies Article Techno-Economic Assessment of a Combined Heat and Power Plant Integrated with Carbon Dioxide Removal Technology: A Case Study for Central Poland 1 , 2 3 4 Paweł Gładysz * , Anna Sowizd ˙ zał ˙ , Maciej Miecznik , Maciej Hacaga and Leszek Pajak ˛ Faculty of Energy and Fuels, AGH University of Science and Technology, 30-059 Kraków, Poland Faculty of Geology, Geophysics and Environmental Protection, AGH University of Science and Technology, 30-059 Kraków, Poland; ansow@agh.edu.pl (A.S.); pajakl@agh.edu.pl (L.P.) Department of Renewable Energy and Environmental Research, Mineral and Energy Economy Research Institute of the Polish Academy of Sciences, 31-261 Kraków, Poland; miecznik@min-pan.krakow.pl Faculty of National Security, War Studies University, 00-910 Warszawa, Poland; m.hacaga@akademia.mil.pl * Correspondence: pawel.gladysz@agh.edu.pl Received: 5 April 2020; Accepted: 1 June 2020; Published: 3 June 2020 Abstract: The objective of this study is to assess the techno-economic potential of the proposed novel energy system, which allows for negative emissions of carbon dioxide (CO ). The analyzed system comprises four main subsystems: a biomass-fired combined heat and power plant integrated with a CO capture and compression unit, a CO transport pipeline, a CO -enhanced geothermal system, 2 2 2 and a supercritical CO Brayton power cycle. For the purpose of the comprehensive techno-economic assessment, the results for the reference biomass-fired combined heat and power plant without CO capture are also presented. Based on the proposed framework for energy and economic assessment, the energy eciencies, the specific primary energy consumption of CO avoidance, the cost of CO 2 2 avoidance, and negative CO emissions are evaluated based on the results of process simulations. In addition, an overview of the relevant elements of the whole system is provided, taking into account technological progress and technology readiness levels. The specific primary energy consumption per unit of CO avoided in the analyzed system is equal to 2.17 MJ /kg CO for biomass only 2 LHV 2 (and 6.22 MJ /kg CO when geothermal energy is included) and 3.41 MJ /kg CO excluding the LHV 2 LHV 2 CO utilization in the enhanced geothermal system. Regarding the economic performance of the analyzed system, the levelized cost of electricity and heat are almost two times higher than those of the reference system (239.0 to 127.5 EUR/MWh and 9.4 to 5.0 EUR/GJ), which leads to negative values of the Net Present Value in all analyzed scenarios. The CO avoided cost and CO negative cost in the 2 2 business as usual economic scenario are equal to 63.0 and 48.2 EUR/t CO , respectively, and drop to 27.3 and 20 EUR/t CO in the technological development scenario. The analysis proves the economic feasibility of the proposed CO utilization and storage option in the enhanced geothermal system integrated with the sCO cycle when the cost of CO transport and storage is above 10 EUR/t CO 2 2 2 (at a transport distance of 50 km). The technology readiness level of the proposed technology was assessed as TRL4 (technological development), mainly due to the early stage of the CO -enhanced geothermal systems development. Keywords: CO capture; utilization and storage; combined heat and power; CO enhanced geothermal 2 2 systems; supercritical CO power cycles; biomass; negative emission technologies Energies 2020, 13, 2841; doi:10.3390/en13112841 www.mdpi.com/journal/energies Energies 2020, 13, 2841 2 of 34 Energies 2020, 13, x FOR PEER REVIEW 2 of 34 1. Introduction 1. Introduction Over the last two decades, deep changes have influenced the energy sector from both the point of Over the last two decades, deep changes have influenced the energy sector from both the point view of energy sources and that of technologies in use. The main factors behind these changes are the of view of energy sources and that of technologies in use. The main factors behind these changes are pursuit of more sustainable electricity generation, and economic and energy security considerations. the pursuit of more sustainable electricity generation, and economic and energy security Europe is one of the most vivid examples. Some of the European Union member states—for example, considerations. Europe is one of the most vivid examples. Some of the European Union member Germany—make e orts to be leaders in introducing changes in the energy sector. Human-induced states—for example, Germany— make efforts to be leaders in introducing changes in the energy climate change (mainly GHG emissions from various industry sectors) is pushing the pursuit of sector. Human-induced climate change (mainly GHG emissions from various industry sectors) is more sustainable and environmentally friendly electricity generation. There are di erent pathways, pushing the pursuit of more sustainable and environmentally friendly electricity generation. There depending on the states’ energy and climate policies and conditions to meet this objective. However, are different pathways, depending on the states’ energy and climate policies and conditions to meet some technologies and policy actions are included in all of them, viz. renewable energy sources, energy this objective. However, some technologies and policy actions are included in all of them, viz. renewable e eciency, and nergy decarbonisation. sources, energy In Polish efficiency, ocial documents and decarboni concerning sation. In enerPoli gy policy sh off[i1ci ]al and docu pathways ments for the country’s development [2], these mechanisms are also included. The concept analyzed within concerning energy policy [1] and pathways for the country’s development [2], these mechanisms are a the lso i paper ncluded. The concept a is coherent with all thr na eelyz points, ed wias thiitn the pa emphasizes per is coherent wi the usage of renewable th all three poi energy sour nts, a cess(by it means of biomass and geothermal energy), the increase in energy utilization eciency (by means of emphasizes the usage of renewable energy sources (by means of biomass and geothermal energy), t the he incre cogeneration ase in energ of heat y utand ilizat electricity), ion efficiena cy nd (b the y m decarbonisation eans of the cogen (by erat means ion of of he CO at and captur elect e,rutilisation, icity), and and storage) of the energy sector (Figure 1). All of them combined lead to the possibility of obtaining the decarbonisation (by means of CO2 capture, utilisation, and storage) of the energy sector (Figure 1) so-called . All of t“negat hem combined l ive” CO emissions ead to the possib and incr ilit easing y of obeconomic taining so- pr ca ofitability lled “negat as ive a ” result CO2 emis of the sions and synergy between those three pillars. increasing economic profitability as a result of the synergy between those three pillars. Figure 1. Three pillars of new energy systems. Figure 1. Three pillars of new energy systems. The main goal of this paper is to give a wide overview of the important aspects regarding the The main goal of this paper is to give a wide overview of the important aspects regarding the proposed system, both from technological and economic points of view. A location in Central Poland proposed system, both from technological and economic points of view. A location in Central Poland was used as a base for a case study, but the presented results can be applied to other locations. However, was used as a base for a case study, but the presented results can be applied to other locations. it should be kept in mind that, e.g., enhanced geothermal system performance is strictly associated However, it should be kept in mind that, e.g., enhanced geothermal system performance is strictly with available geological formations. Additionally, the biomass-fired combined heat and power (CHP) associated with available geological formations. Additionally, the biomass-fired combined heat and plants operating in di erent countries have di erent designs depending on the heat demand over the power (CHP) plants operating in different countries have different designs depending on the heat year. In Nordic countries, designs with back-pressure steam turbines are widely used, whereas in demand over the year. In Nordic countries, designs with back-pressure steam turbines are widely other countries (like Poland), extraction-condensing turbines are used more often, and back-pressure used, whereas in other countries (like Poland), extraction-condensing turbines are used more often, turbines are only used at industrial sites with constant heat demand. All of those aspects should be and back-pressure turbines are only used at industrial sites with constant heat demand. All of those kept in mind when applying the results of this study to other locations and countries. Therefore, aspects should be kept in mind when applying the results of this study to other locations and we provide a detailed method description for crucial parts of the analysis—carbon dioxide-enhanced countries. Therefore, we provide a detailed method description for crucial parts of the analysis— geothermal system (CO -EGS) operation and economic assessment—to allow others to implement the carbon dioxide-enhanced geothermal system (CO2-EGS) operation and economic assessment—to presented concept for their case studies. allow others to implement the presented concept for their case studies. 1.1. CO2 Capture, Utilization, and Storage (CCUS) As many countries are failing to meet the Paris agreement climate goals, it becomes more and more obvious that all available technologies must be used to curb emissions. After a period of Energies 2020, 13, 2841 3 of 34 1.1. CO Capture, Utilization, and Storage (CCUS) As many countries are failing to meet the Paris agreement climate goals, it becomes more and more obvious that all available technologies must be used to curb emissions. After a period of inattention, government interest in Carbon Capture and Storage (CCS) technology has been rising since 2018 [3]. Its global progress has been monitored on a regular basis by the Global CCS Institute through the Carbon Capture and Storage (CCS) Readiness Index (CCS-RI). It comprises four sub-indicators that track all the necessary aspects of technological development: inherent interest, policy issues, regulatory and legal frameworks, and storage development [4]. Within the group of the high-scoring states, one finds the most developed states, namely Australia, Canada, Norway, the United Kingdom, and the United States. China, Denmark, Germany, Japan, and the Netherlands are well-advanced and progressing in introducing CCS [4]. The third group—moderately performing—consists of predominantly European countries. Poland scored 42 points out of 100 and was therefore added to this group [4] (Table 1). Table 1. Top 10 emissions countries versus top 10 Carbon Capture and Storage (CCS)-ready countries [4,5]. Emissions (Mt CO ) Score in the CCS Readiness Index China 9839 Canada 71 United States of America 5270 USA 70 India 2467 Norway 67 Russian Federation 1693 United Kingdom 65 Japan 1205 Australia 62 Germany 799 Netherlands 54 Iran 672 China 53 Saudi Arabia 635 Denmark 52 South Korea 616 Germany 50 Canada 573 Japan 50 Poland (21st position) 327 Poland (15th position) 42 Since the 2015 assessment, Poland’s overall score has improved. However, it still continues to remain at an average level. A closer look reveals that an increased score in the storage sub-indicator is responsible for the advance. However, Poland belongs to the group where “most of the storage potential is considered only as prospective resources”, and the country’s experience is limited [6]. Moreover, no change was noted in the policy and regulatory areas. Poland is especially ill-prepared within the former, achieving a score eight times lower than the leader of the policy indicator index, Norway (7 and 56, respectively) [7]. When the regulatory area is considered, Poland belongs to the middle of Band B, the group of countries where only some laws applicable to the CCS project cycle were introduced. The unchanged position of Poland since 2015 indicates limited legislative activity and policy development [8] (Table 2). Table 2. Poland versus Canada (the leading state) performance comparison. Poland’s Position Change Indicator Canada Poland since the 2015 Study Total 2018 score (CCS-RI) 71 42 Up CCS Storage Indicator 98 68 Up (CCS-SI) CCS Policy Indicator 40 7 No change (CCS-PI) CCS Legal and Regulatory Indicator 65.5 45 No change (CCS-LRI) CCS Inherent Interest 88 68 No change Indicator (CCS-CI) Energies 2020, 13, 2841 4 of 34 According to the most recent reports [9], the global CCS fleet consists of 51 large-scale facilities, with 19 in operation, 4 in construction, 10 in advanced development, and 18 in early development. Geographically, the majority of them are concentrated in North America (47%), followed by China (16%, majority in early development) and the UK (12%, all in early development). Current storage capacity is around 39 million tonnes of CO annually, which equals slightly more than 0.1% of global emissions. Although the overall survivability rate of CCS projects is 37%, the number of projects entering the pipeline has increased recently and exceeded the number of those exiting. It has been stressed that the pace of CCS adoption is well below of what is required to meet the Paris Agreement goal of a 2 C increase. While the building rate should reach the level of 70–100 facilities per year, the actual progress has been only one facility annually in the last decade. The report stresses that technologies for CCS are generally well-established. Therefore, there are policy changes on a monumental scale that are necessary for the successful wide-scale deployment of CCS. These include increasing the number of projects entering the pipeline and their survivability rate, as well as protecting them from short-term political changes. To stop the process of global warming and simultaneously meet climate goals, global society needs to reach and sustain net zero global anthropogenic carbon dioxide emissions. Moreover, even if the process of warming would be halted, negative emission technologies (NETs), also known as carbon dioxide removal (CDR) technologies, may still be essential to prevent further warming [10]. However, meeting the 2 C goal is practically impossible without using one of the most crucial NETs—bioenergy with carbon capture and storage (BECCS) [11]. Its crucial role comes from the fact that it allows for the double capture of carbon dioxide. Because of using biomass, which captures CO in the process of growth, BECSS seems indispensable, as CO is captured for the second time when energy is released. Afterwards, emissions are stored underground. Hence, it can mitigate emissions from other sources as well as those emissions that have already occurred [12]. Three categories of biomass input were analyzed—energy crops, forestry residues, and agricultural residues—for two major applications: large scale electricity generation and biofuel production. Technologically, the highest potential for emission reduction was found in biomass integrated gasification combined cycles (BIGCCs) and a circulating fluidized bed (CFB) [13]. However, economically, the potential of a CFB is 20 times less than that of BIGCCs [13]. Even if burned along with fossil fuels, BECCS ensures a low emission profile [12]. With direct air carbon capture and storage (DACCS), BECSS consists of two NETs with the largest overall CO removal potentials, albeit at high cost [11]. The amount of biomass that can be sustainably produced and global storage capacity can also limit the spread of BECCS [13]. Coal’s domination in the energy mix inspired Poland’s attempts to develop CCS installations. Post-combustion carbon capture was planned for the PGE Bełchatów demonstration project, which was supposed to be run in the 858 MW unit, launched in 2011. The Polish CCS project in Bełchatów, despite receiving a positive assessment from the European Investment Bank and European Commission in the first round of recruitment for the EU’s NER 300 program, was withdrawn from the competition in 2011 and canceled in 2013. Although the project could have been built with European funds, it was necessary to involve national funds to run it on an everyday basis, which was not politically feasible [14,15]. Other factors that influenced the project closure decision were high costs, insucient public acceptance, and the incomplete implementation of the CCS Directive [16]. Not much has changed since then. Although extensive performance assessments were conducted in Poland that showed the suitability of geologic settings, from a legal point of view, storage sites can only be located o shore [17]. The recent governmental assessment was that CCS installations can be competitive only when CO emission allowances will exceed EUR 50 per ton [18]. One of the main research concerns regarding BECCS is the assessment of the net negative emission status of the technology. The authors of a review paper on Integrated Assessment Models [19] addressed the main criticism regarding their application for the assessment of bioenergy with CCS. The main finding of the paper was the importance of using other models and analytical approaches to enhance the Integrated Assessment Models’ role in mitigation pathway analysis. Similarly, in [20], Energies 2020, 13, 2841 5 of 34 the authors addressed the topic of BECCS and identified research priorities and the assessment needed to accelerate the deployment of this technology. Among already widely discussed assessment priorities such as the potential of biomass supply, the authors pointed out the importance of alga biomass studies in terms of economic viability, environmental sustainability, and their inclusion in the value chain of biomass for BECCS. Regarding techno-economic studies of the BECCS, a few studies can be found that deal with an evaluation of bioenergy with CCS in di erent sectors. In [21], the authors performed such an analysis for a sugarcane mill located in Brazil. They concluded that CO capture at the analyzed plant is technically feasible and that the cost of avoided CO emissions was 62 EUR/t CO , with the 2 2 potential to decrease to 48 EUR/t CO in the case of larger plants and more ecient technologies. Authors often propose merging novel CO capture with the BECCS concept. In [22], the results of the techno-economic evaluation of BECCS via chemical looping combustion were presented. The cost of CO avoidance was estimated at 150 US$/t CO , compared with BECCS with post-combustion CO 2 2 2 capture, at around 200 US$/t CO . A similar conclusion regarding the superiority of novel CO capture 2 2 technologies (in this case, calcium looping) with BECCS over conventional absorption CO removal were also reported in [23]. 1.2. District Heating Systems in Poland In 2017, there were more than 400 heating and heating distribution companies operating in Poland [24]. The total installed capacity of heat production reaches almost 55 GW with around 240 th thousand TJ delivered to the consumers connected to a district heating system (DHS) in Poland. th Almost 54% of all heating companies operate in a DHS smaller than 50 MW . The average share of th heat produced in cogeneration is around 61%, but it should be noted that it comes mainly from large heat sources in bigger cities. Coal is a dominant fuel in the production mix for heat in Poland (72%), followed by biomass (7.4%) and natural gas (6.8%) [24]. The average price of heat in Poland is around 9 EUR/GJ and varies depending on whether the fuel is in heat-only boilers or a CHP plant (from lignite, 6.3 EUR/GJ, to coal, 8.8 EUR/GJ, and from biomass, 9.8 EUR/GJ, to light fuel oil, 15.6 EUR/GJ). In recent years, the Polish heating sector has been struggling with several obstacles of a legislative and economic nature. When large DHSs are concerned, most of them manage the upcoming challenges in an e ective and economically feasible manner. Most small DHSs (up to 50 MW ) are facing serious th challenges, both from economic and environmental points of view. About 80% of DHSs, especially small ones (from 1 to about 100 MW ), are inecient according to the Energy Eciency Directive [25], th which might result in a lack of public aid in the near future. In addition, environmental-driven investments are needed, mainly due to the Medium Combustion Plants (MCP) Directive [26], which is setting emission standards for sulphur dioxide (SO ), nitrogen oxides (NO ), and particulate matter (PM) for combustion plants with a rated thermal input of 1 to 50 MW . A change in fuel structure is th also needed, as sources with a thermal input above 20 MW participate in EU-ETS, and after 2030, th the free allowances will be gradually reduced. On the other hand, the demand for heat is decreasing as a result of the thermal modernization of buildings connected to DHSs. All of these points have led to an increase in heat production costs, which might result in the disconnection of consumers from the network and switching to individual heat sources (at the level of building complexes, single buildings, or individual apartments). Several studies have been published in the last three years regarding the challenges of small DHSs and cooperating heat sources [25–28]. As stressed in most of them, the main chances for the successful transformation of a small DHS lies in cogeneration (which could provide an additional 2–4 GW of el electricity production capacity in the system), the popularization of biomass as a fuel in heat-only boilers and CHP plants, and increases in the energy eciency of buildings (together with an increased usage of district heating for hot tap water preparation). Energies 2020, 13, 2841 6 of 34 1.3. Enhanced Geothermal Systems Classical geothermal systems are based on mature and well-known technology, enabling the exploitation of water accumulated in hydrogeothermal reservoirs. However, huge geothermal potential is present in bedrock with low permeability, low porosity, and low to medium enthalpy. Enhanced Geothermal Systems (EGSs) are unconventional geothermal systems that make it possible to utilize the geothermal energy accumulated in hot rocks characterized by insucient or little natural permeability or fluid saturation. This kind of system assumes heat extraction from underground hot dry rock (HDR) Energies 2020, 13, x FOR PEER REVIEW 6 of 34 by an artificial increase in the hydraulic performance of a geothermal reservoir and then the circulation of a working fluid into it and bringing the heated working fluid to a power plant to generate electricity geothermal reservoir and then the circulation of a working fluid into it and bringing the heated (Figure 2) [29,30]. working fluid to a power plant to generate electricity (Figure 2) [29,30]. Figure 2. Schematic of a conceptual two-well Enhanced Geothermal System (EGS) in hot dry rock Figure 2. Schematic of a conceptual two-well Enhanced Geothermal System (EGS) in hot dry rock (based (based on [31]) on [31]).. Conventionally, the only working fluid applied to EGS is water [32]. However, EGS with CO as a Conventionally, the only working fluid applied to EGS is water [32]. However, EGS with CO2 as working fluid is a very attractive option, which results from both energy and environmental benefits. a working fluid is a very attractive option, which results from both energy and environmental The advantages of this type of solution are due to the more favorable thermodynamic properties of benefits. The advantages of this type of solution are due to the more favorable thermodynamic CO compared with water, which in turn result in higher production flow rates and reduced carbon properties o 2 f CO2 compared with water, which in turn result in higher production flow rates and emissions into the atmosphere [33–35]. In this case, as the permeability and heat exchange area of the reduced carbon emissions into the atmosphere [33–35]. In this case, as the permeability and heat surrounding formation increases, the amount of CO sequestration increases too, while the rate of heat exchange area of the surrounding formation incre 2ases, the amount of CO2 sequestration increases extraction decreases slowly, which shows that the permeability of the surrounding formation has a too, while the rate of heat extraction decreases slowly, which shows that the permeability of the significant impact on CO sequestration and the heat extraction rate [36,37]. surrounding formation has 2 a significant impact on CO2 sequestration and the heat extraction rate The concept of CO -EGS was described for the first time by Brown [38]. This solution appeared as [36,37]. a response to the emerging needs to reduce carbon dioxide emissions in the world. Since then, research The concept of CO2-EGS was described for the first time by Brown [38]. This solution appeared has shown a number of advantages of this technology, the basis for which is the possibility of the as a response to the emerging needs to reduce carbon dioxide emissions in the world. Since then, geological storage of CO due to the losses of the working fluid at great depths. However, attention is research has shown a num 2 ber of advantages of this technology, the basis for which is the possibility also paid to other aspects of this solution, including high expansiveness and compressibility, low salt of the geological storage of CO2 due to the losses of the working fluid at great depths. However, solubility, favorable transport properties, and—due to strong buoyancy—low chemical activity and attention is also paid to other aspects of this solution, including high expansiveness and compressibility, low salt solubility, favorable transport properties, and—due to strong buoyancy— low chemical activity and self-propelled high flow rates [34,39–41]. For the first time in the world, the EGS has been tested in New Mexico (Fenton Hill). Research conducted since 1974 confirms that such unconventional geothermal systems can work effectively. Since that time, 18 EGS sites have been created around the world, including projects in Australia, Japan, South Korea, German, Sweden, France, Swiss, the UK, and the USA [42]. All current EGS projects use water as a working fluid. An attempt to use CO2 as a working fluid was undertaken in the Ogachi EGS site (1989–2001). The lithological reservoir was granodiorite-characterized by a temperature of more than 230 °C at a 1000 m depth. The large loss of circulating fluid was a limitation to the commercial operation of the system [42]. Currently no EGS-CO2 installation is available. The development of such projects is only at the Energies 2020, 13, 2841 7 of 34 self-propelled high flow rates [34,39–41]. For the first time in the world, the EGS has been tested in New Mexico (Fenton Hill). Research conducted since 1974 confirms that such unconventional geothermal systems can work e ectively. Since that time, 18 EGS sites have been created around the world, including projects in Australia, Japan, South Korea, German, Sweden, France, Swiss, the UK, and the USA [42]. All current EGS projects use water as a working fluid. An attempt to use CO as a working fluid was undertaken in the Ogachi EGS site (1989–2001). The lithological reservoir was granodiorite-characterized by a temperature of more than 230 C at a 1000 m depth. The large loss of circulating fluid was a limitation to the commercial operation of the system [42]. Currently no EGS-CO installation is available. The development of such projects is only at the stage of numerical simulations and laboratory tests [43–45]. However, the results of the conducted research are very promising. For a comprehensive assessment point of view, the enhanced geothermal systems face some challenges. In [29], the authors proposed a multiple-criteria decision-making approach, which takes technical, geological, economic, environmental, and social impacts into consideration. Proposed within the paper tool is a good example of actions for the support of the wider deployment of the EGS system. The selection methods for power generation in the case of a water-based EGS system have also been discussed in [46], where the authors performed an optimization analysis of single- and double-flash systems, a flash-organic Rankine cycle system, and a double-flash-organic Rankine cycle system. The main findings of the paper indicate that double-flash systems might be a better option for temperatures above 170 C, whereas a flash-organic Rankine cycle system performs better at lower temperatures. The authors of another study on this subject [30] found similar results regarding the performance of flash systems. In addition, the analyzed expansion-type system proved to have significantly higher geofluid e ectiveness than flash-type plants. 1.4. Supercritical CO Cycles The supercritical carbon dioxide (hereinafter referred to as sCO ) cycle was firstly proposed in 1950 [47] and developed in 1967. High thermal eciency and better temperature glide matching between the heat source and the working fluid are advantages of using CO in the supercritical state. It is a machine-friendly (non-corrosive and non-toxic), environmentally friendly, a ordable, and accessible working fluid that requires only moderate critical pressure [48]. Amongst the purely practical advantages are the small size of these systems and the wide application possibilities, including in the nuclear, solar, and coal-fired energy industries [47]. The sCO cycles receive much interest for applications with waste heat, where a medium to high temperature range is concerned. In [49], the conceptual designs of sCO power cycles for such applications were presented. The proposed single flow split with a dual expansion design could provide more than 40% more power compared with a baseline single recuperated cycle. In [50], the authors applied the sCO Brayton cycle at a natural gas compression station and compared the selected eciency indicators with organic Rankine cycles. In addition, as stressed by the authors, when waste heat management is concerned, it is essential to maintain the maximum levels of internal heat recovery and cost-e ectiveness. 2. Methods 2.1. Case Study Selection Within the project, for which presented analysis is part of, three scenarios of the modernization of heat sources for small (up to 50 MW ) DHSs are considered: th A reference biomass-fired CHP plant with an extraction-condensing or back-pressure turbine; A biomass-fired CHP plant with post-combustion CO capture using monoethanolamine (MEA) or calcium-looping processes and storage in saline formations; A biomass-fired CHP plant with post-combustion CO capture and CO utilization via CO -enhanced 2 2 2 geothermal systems. Energies 2020, 13, 2841 8 of 34 In this paper, the last option is investigated, viz. a biomass-fired CHP plant with an extraction- condensing turbine, MEA CO capture installation, and CO -EGS utilization. Based on the Polish 2 2 geological structure analysis and a review of small DHSs, the location in Central Poland was chosen. For the calculation of specific energy consumption for CO avoided and CO avoided cost (CAC), 2 2 the results for the reference biomass-fired CHP plant with extraction condensing and without CO capture are presented. The design of the reference plant was assumed to provide the same net electrical and heat output as the entire analyzed system. 2.1.1. District Heating System Selection The demand for heat in municipal district heating systems for the purpose of heating, ventilation, and air-conditioning varies depending on atmospheric conditions. The demand for heat calculations are based on the duration curve of the external temperature in the heating season and the heat demand for hot tap water. The analyzed DHS plant’s main parameters are taken from the available energy plan of the Koło city council [51] and other sources [52,53] and are summarized in Table 3. The analysis within the paper heating network assumes qualitative-quantitative regulations that apply to most of the municipal district heating systems in the world. Table 3. Main parameters of the Koło district heating system (DHS). Parameter Value Climatic zone (in Poland) II Lowest external temperature characteristic for given 18 C climatic zone External temperature when the heating season starts 12 C Duration of the heating season 200 days Maximum heat flux in the DHS 35,704.4 kW th Maximum heat demand for heating and ventilation 35,150 kW th in the DHS Hot tap water heat demand in the DHS 554.4 kW th Temperature of the DHS water output 150 C (at maximum heat demand) Temperature of the DHS water input 70 C (at maximum heat demand) Temperature of the DHS water 70 C/35 C (beside heating season, for hot tap water only) As presented in Table 3, the share of hot tap water in the DHS is very low. The temperatures are also rather high. All those aspects have been raised in the energy plan of the city [51], and suggestions for DHS development over the next years indicate a significant increase in the share of hot tap water in the total heat demand and lowering the DHS temperatures. Taking into account the following remarks, the theoretical DHS was proposed, with a maximum heat demand of 37 MW . For the calculations, th the DHS was divided into six zones, where the heat demand and temperatures are presented in Figure 3. The thermal load of a CHP plant meeting the needs of municipal consumers through the district heating system is characterized by a large degree of irregularity. This is denoted by a considerable ratio of the maximum to the minimum loads (for example, in Poland, the maximum/minimum ratio can reach up to 5:1). The power rating of the turbine (maximum heat production) in a CHP unit must be chosen according to the optimal coecient of the share of cogeneration, which defines the ratio of the maximum heat flux from the steam turbine (cogeneration) to the maximum demand for heat in the DHS. Based on previous research [52,54,55], an optimal coecient of the share of cogeneration of 0.6 was assumed in this analysis. Energies 2020, 13, x FOR PEER REVIEW 8 of 34 The demand for heat in municipal district heating systems for the purpose of heating, ventilation, and air-conditioning varies depending on atmospheric conditions. The demand for heat calculations are based on the duration curve of the external temperature in the heating season and the heat demand for hot tap water. The analyzed DHS plant’s main parameters are taken from the available energy plan of the Koło city council [51] and other sources [52,53] and are summarized in Table 3. The analysis within the paper heating network assumes qualitative-quantitative regulations that apply to most of the municipal district heating systems in the world. Table 3. Main parameters of the Koło district heating system (DHS). Parameter Value Climatic zone (in Poland) II Lowest external temperature characteristic for given climatic zone −18 °C External temperature when the heating season starts 12 °C Duration of the heating season 200 days Maximum heat flux in the DHS 35,704.4 kW th Maximum heat demand for heating and ventilation in the DHS 35,150 kW th Hot tap water heat demand in the DHS 554.4 kW th Temperature of the DHS water output (at maximum heat demand) 150 °C Temperature of the DHS water input (at maximum heat demand) 70 °C Temperature of the DHS water (beside heating season, for hot tap water only) 70 °C/35 °C As presented in Table 3, the share of hot tap water in the DHS is very low. The temperatures are also rather high. All those aspects have been raised in the energy plan of the city [51], and suggestions for DHS development over the next years indicate a significant increase in the share of hot tap water in the total heat demand and lowering the DHS temperatures. Taking into account the following remarks, the theoretical DHS was proposed, with a maximum heat demand of 37 MWth. For the calculations, the DHS was divided into six zones, where the heat demand and temperatures are Energies 2020, 13, 2841 9 of 34 presented in Figure 3. Figure 3. Heat demand curve in the analyzed DHS. Figure 3. Heat demand curve in the analyzed DHS. Figure 3 presents the duration curve of the demand for heat in the DHS with the area of the The thermal load of a CHP plant meeting the needs of municipal consumers through the district operation of the CHP plant and peak boilers. As the gas-fired peak boiler has a minimum operation heating system is characterized by a large degree of irregularity. This is denoted by a considerable load of 20%, the decrease in CHP load had to be taken into account. As the availability factor of the ratio of the maximum to the minimum loads (for example, in Poland, the maximum/minimum ratio CHP plant is assumed at 80%, part of the hot tap water demand (in summer months) is also covered by gas-fired boilers. 2.1.2. Geological Structure Selection The selection of the geological structure is the first and basic element of creating a CO -EGS system. So far, there is no significant experience in developing such systems, which is reflected in the diculty of defining the criteria that should be met by a selected geological structure. Sites prospective for the potential application of an EGS with CO as the working fluid (CO -EGS) 2 2 should meet the geological and hydrogeothermal conditions suitable for building EGS systems while taking into account the possibilities of the concurrent underground storage of CO . Sedimentary basins located in tectonically stable areas, with no contemporary volcanism or earthquakes, are best for this purpose [56]. The geological structure designated for underground CO storage should form a structural or stratigraphic trap, most favourably in the form of an anticline, characterized by considerable capacity. Reservoir rocks should have an appropriate porosity and permeability to ensure suitable storage capacity, should be tight, should be covered with impermeable rocks with suitable thickness, and should be located at a suitable depth so as to ensure the required pressure and capacity of the CO being injected. Rock formations designated for CO storage should be located far below any 2 2 utilized aquifers. They should be separated from them by one or several layers of impermeable insulation rocks, preventing gas from migration to potable water levels that are higher. A degree of isolation of the formations to be used for storage should be considered in relation to the system of hydrodynamic conditions in a given geological structure, trying to control CO distribution. A big role is played by the strength of insulating layers, including layer plasticity. They should be thick enough to prevent the phenomenon of fracturing and, in consequence, layer puncture as a result of excessive injection pressure. It is necessary to analyze in detail overlaying sealing beds, which requires detailed studies, tests, and trials. Geological tightness is particularly important, since storage in such structures usually requires higher pressures than hydrostatic pressure. A lack of geological tightness can occur, for instance, in tectonically involved aquifers, which eliminates a given structure for the purposes of carbon dioxide storage [57]. Currently, there is a technological possibility of drilling wells even at depths exceeding 4 km as well as fracturing technology in order to achieve the hydraulic connection between injection and Energies 2020, 13, 2841 10 of 34 production boreholes [58]. Therefore, the most suitable rock for EGSs should be characterized by low porosity and permeability values and possibly a high heat flow reflected in a high reservoir temperature. Reservoir rock parameters and sealing rock parameters are both important. In this case, high permeability values may cause an uncontrolled escape of the injected fluid. Poland is located within three main European geostructural units: the Precambrian East European Platform in the east, which is a large and flat area covered by sediments; the Paleozoic Platform, which comprises the southwestern half of the Polish territory; and the Carpathians, which is a part of the Alpine–Himalayan system in the south. This geostructural position influences the development of the thermal and geological conditions. Most of Poland is covered by sedimentary rocks (Polish Lowlands, Carpathians, and Carpathian Foredeep). The only exception is the Sudetes region (SW part of Poland), where crystalline rocks occur [59]. Energies 2020, 13, x FOR PEER REVIEW 10 of 34 Geothermal installations currently operating in the area of the Polish Lowlands utilize successfully a key premise to treat these reservoirs only as geothermal reservoirs. The situation is different in the waters from the Lower Cretaceous and Lower Jurassic reservoirs [60] (Figure 4). It is thus a key premise case of a Lower Triassic reservoir. All studies conducted so far [61,62] point out the rather poor water to treat these reservoirs only as geothermal reservoirs. The situation is di erent in the case of a Lower content in this reservoir and the low potential for building conventional geothermal installations. Triassic reservoir. All studies conducted so far [61,62] point out the rather poor water content in this Although a EGS geothermal system with a location in a zone of sedimentary rock occurrence shows reservoir and the low potential for building conventional geothermal installations. Although a EGS slightly poorer thermal parameters than systems in crystalline or magma rocks, from the point of geothermal system with a location in a zone of sedimentary rock occurrence shows slightly poorer thermal view of CO2 sequestration, the best solution is to select sedimentation basins located in tectonically parameters than systems in crystalline or magma rocks, from the point of view of CO sequestration, stable areas, which is proven by the above-shown criteria. Due to the depth and expected thermal the best solution is to select sedimentation basins located in tectonically stable areas, which is proven by and petrophysical parameters of Lower Triassic formations, the Krośniewice-Kutno area (Central the above-shown criteria. Due to the depth and expected thermal and petrophysical parameters of Lower Poland) was chosen as an optimum location (Figure 4). In this area, the most prospective horizon for Triassic formations, the Kros ´niewice-Kutno area (Central Poland) was chosen as an optimum location an EGS location is the clastic deposits of the Lower Triassic. The top of the reservoir of more than (Figure 4). In this area, the most prospective horizon for an EGS location is the clastic deposits of the 1000 m thick is behind at depths 5000–5500 m below sea level, and the temperature within the Lower Triassic. The top of the reservoir of more than 1000 m thick is behind at depths 5000–5500 m reservoir is in the range 165–195 °C. The porosity of the reservoir rocks is approximately 2.5%, while below sea level, and the temperature within the reservoir is in the range 165–195 C. The porosity of the permeability is about 0.1 mD [61,63–66]. the reservoir rocks is approximately 2.5%, while the permeability is about 0.1 mD [61,63–66]. Figure 4. Location of the research area together with the predicted geological profile of Krośniewice Figure 4. Location of the research area together with the predicted geological profile of Krosniewice ´ IG-1. IG-1. The estimation of the amount of CO2 that will be permanently bound in the geological structure is a very challenging task. Nevertheless, it can be assumed that this amount will depend on parameters such as the area of major flow paths and the contact area between the fluid and the fractures, the shape of the fractures and their hydraulic connectivity, the porosity and permeability of the geological formation, the reservoir pressure and background pore pressure, the reservoir temperature, the degree of pore saturation with individual fluids, pore fluid phases, and time [62]. The mineralogical composition of the reservoir rocks and the chemical composition of the primary pore fluid will also play important roles in the context of solubility and mineral trapping. It is estimated that, for the long-term operation of EGS installations with CO2 as a working medium, the amount of stored CO2 is in the order of 5% [34]. However, for different reservoir conditions, the amount of CO2 stored may be different, such as in the case of the geothermal field in Habanero (Australia), where this value seems to be much overestimated [63]. A more precise and site-specific estimation of the amount of CO2 to be stored in the enhanced geothermal reservoir can Energies 2020, 13, 2841 11 of 34 The estimation of the amount of CO that will be permanently bound in the geological structure is a very challenging task. Nevertheless, it can be assumed that this amount will depend on parameters such as the area of major flow paths and the contact area between the fluid and the fractures, the shape of the fractures and their hydraulic connectivity, the porosity and permeability of the geological formation, the reservoir pressure and background pore pressure, the reservoir temperature, the degree of pore saturation with individual fluids, pore fluid phases, and time [62]. The mineralogical composition of the reservoir rocks and the chemical composition of the primary pore fluid will also play important roles in the context of solubility and mineral trapping. It is estimated that, for the long-term operation of EGS installations with CO as a working medium, the amount of stored CO is in the order of 5% [34]. However, for di erent reservoir conditions, the amount of CO stored may be di erent, such as in the case of the geothermal field in Habanero (Australia), where this value seems to be much overestimated [63]. A more precise and site-specific estimation of the amount of CO to be stored in the enhanced geothermal reservoir can be achieved with the aid of a numerical simulator coupling heat and mass transport with the reactive Energies 2020, 13, x FOR PEER REVIEW 11 of 34 geochemistry of fluid–rock interactions [63]. be achieved with the aid of a numerical simulator coupling heat and mass transport with the reactive 2.2. Process geochemistry of Synthesis and fluid Design –rock interactions [63]. The goal of this paper was to model (including the o -design operation) and analyze the full 2.2. Process Synthesis and Design chain of the proposed technology. Thus, the mathematical models of the CO -EGS (developed in The goal of this paper was to model (including the off-design operation) and analyze the full VBA Excel) and the integrated biomass-fired CHP plant with CO capture (developed in IPSE Pro) chain of the proposed technology. Thus, the mathematical models of the CO2-EGS (developed in VBA Excel) and the integrated biomass-fired CHP plant with CO2 capture (developed in IPSE Pro) were were developed and combined through PSE Excel (a dedicated tool for Excel and IPSE Pro model developed and combined through PSE Excel (a dedicated tool for Excel and IPSE Pro model combinations). A simplified diagram of the analyzed system is presented in Figure 5. combinations). A simplified diagram of the analyzed system is presented in Figure 5. Figure 5. Simplified diagram of a CHP unit with an extraction-condensing turbine, a CO2 capture and Figure 5. Simplified diagram of a CHP unit with an extraction-condensing turbine, a CO capture and compression unit, and a CO2-enhanced geothermal system with a supercritical CO2 (sCO2) Brayton compression unit, and a CO -enhanced geothermal system with a supercritical CO (sCO ) Brayton cycle 2 2 2 cycle (T: turbine; GC: gas cooler; AF: air fan; G: generator; COM: compressor; REB: reboiler; STR: (T: turbine; stripper; AB GC: gas S: cooler; absorber; ES AF: air P: electrostatic pr fan; G: generator; ecipitatorCOM: ; BHE: bcompr ase heat e essor; xchang REB: er; RHrE eboiler; : regeneraSTR: tive stripper; heat exchanger; FCT: force-draft cooling tower; CON: condenser; DEA: deaerator; PB: peak boiler; ABS: absorber; ESP: electrostatic precipitator; BHE: base heat exchanger; RHE: regenerative heat SNCR: elective non-catalytic reduction). exchanger; FCT: force-draft cooling tower; CON: condenser; DEA: deaerator; PB: peak boiler; SNCR: elective non-catalytic reduction). In general, the analyzed system can be divided into four main subsystems: (i) a biomass-fired combined heat and power plant integrated with (ii) a CO2 capture and compression unit, (iii) a CO2 transport pipeline, and (iv) a CO2-enhanced geothermal system comprising a geological reservoir and an sCO2 Brayton power cycle. The heat demand in the DHS is covered by the steam extracted from the turbine and the waste heat coming from the CO2 capture and compression unit (mainly the interstage cooling of the CO2 compressors). The cooling duty for the steam condenser in the CHP plant and the CO2 capture and compression unit is achieved by the forced-draft cooling tower. The flue gases after conditioning are directed to the absorber, where CO2 is captured in an amine solution and then released in the stripper. The MEA regeneration is done in the reboiler, where the heat is provided from the steam turbine bleeding. Captured CO2 is then compressed and transported via the Energies 2020, 13, 2841 12 of 34 In general, the analyzed system can be divided into four main subsystems: (i) a biomass-fired combined heat and power plant integrated with (ii) a CO capture and compression unit, (iii) a CO 2 2 transport pipeline, and (iv) a CO -enhanced geothermal system comprising a geological reservoir and an sCO Brayton power cycle. The heat demand in the DHS is covered by the steam extracted from the turbine and the waste heat coming from the CO capture and compression unit (mainly the interstage cooling of the CO compressors). The cooling duty for the steam condenser in the CHP plant and the CO capture and compression unit is achieved by the forced-draft cooling tower. The flue gases after conditioning are directed to the absorber, where CO is captured in an amine solution and then released in the stripper. The MEA regeneration is done in the reboiler, where the heat is provided from the steam turbine bleeding. Captured CO is then compressed and transported via the CO pipeline 2 2 to the storage (utilization) site. Due to the small range of the CO transport (50 km), the rebooster station is not included. The CO stream at the EGS site coming from the pipeline is mixed with the circulating stream of sCO and injected into the fractured EGS zone, where it heats up. Part of the injected CO is sequestrated in the EGS zone (5%), and the rest is directed to the sCO turbine. After the 2 2 turbine, the CO is cooled in the gas cooler to the desired temperature. Due to the thermosiphon e ect, no additional CO compression is needed, as the pressure outlet from the turbine is chosen to utilize the positive pressure di erence between the injection and production wells. The amount of CO coming from the CO capture unit is assumed to be the same as the amount of CO sequestered, 2 2 2 allowing the system to operate constantly. 2.2.1. Analytical Model of the CO -Fed Enhanced Geothermal System (CO -EGS) in the Krosniewice- ´ 2 2 Kutno Area Analytical models can be an alternative to detailed 3D numerical models when it is necessary to quickly estimate geothermal reservoir exploitation parameters. As some authors have pointed out [67–69], the 1D and 2D analytical models can often provide a good approximation for more detailed 3D models. Using this approach, a steady-state analytical model of single-channel flow in the EGS reservoir was developed. The model simulates the injection of sCO into the fractured zone of the originally low-permeable rock formation, the 1D flow between the injection and production boreholes, and the CO extraction using the production well (Figure 6). The assumptions of this model also include laminar (Darcy) flow in the reservoir and turbulent flow in both wells. The temperature of the injected fluid is assumed to linearly increase from the injection zone, to reach a natural reservoir temperature at the feed zone of the production well. The extraction of CO , the carrier of geothermal heat, can be accomplished either using down-hole pumps or spontaneously, thanks to the thermosiphon e ect (similar to the artesian outflow in water wells). Contrary to models developed earlier [66,68,69], the one used here accounts for the heat transfer between CO , the wells’ casings, and the surrounding rocks. A list of the governing equations in this model is given in Appendix A. The simulation of the CO injection into the Lower Triassic sandstones in the Krosniewice-Kutno ´ area was performed for hundreds of di erent scenarios, in which the thermosiphon e ect usually occurs. The two factors that a ect the pressure di erence between the production and injection wellheads (thermosiphon) the most are the fractured zone permeability and the working fluid (CO ) mass flow rate. For a given mass flow rate and with other parameters kept constant, permeability controls the pressure distribution in the reservoir, a ecting the value of thermosiphon (Figure 7). At a certain value of EGS reservoir permeability, a break-even point is reached, and a further increase in permeability does not significantly a ect the pressure di erence between the production and injection borehole wellheads. What is worth noticing is the fact that, at high reservoir permeability, the thermosiphon process approaches a certain value, regardless of the mass flow rate. As the model couples reservoir and wellbore processes, these results imply that a reservoir pressure drop has a more profound e ect than a pressure drop in the wellbore. Energies 2020, 13, x FOR PEER REVIEW 12 of 34 CO2 pipeline to the storage (utilization) site. Due to the small range of the CO2 transport (50 km), the rebooster station is not included. The CO2 stream at the EGS site coming from the pipeline is mixed with the circulating stream of sCO2 and injected into the fractured EGS zone, where it heats up. Part of the injected CO2 is sequestrated in the EGS zone (5%), and the rest is directed to the sCO2 turbine. After the turbine, the CO2 is cooled in the gas cooler to the desired temperature. Due to the thermosiphon effect, no additional CO2 compression is needed, as the pressure outlet from the turbine is chosen to utilize the positive pressure difference between the injection and production wells. The amount of CO2 coming from the CO2 capture unit is assumed to be the same as the amount of CO2 sequestered, allowing the system to operate constantly. 2.2.1. Analytical Model of the CO2-Fed Enhanced Geothermal System (CO2-EGS) in the Krośniewice-Kutno Area Analytical models can be an alternative to detailed 3D numerical models when it is necessary to quickly estimate geothermal reservoir exploitation parameters. As some authors have pointed out [67–69], the 1D and 2D analytical models can often provide a good approximation for more detailed 3D models. Using this approach, a steady-state analytical model of single-channel flow in the EGS reservoir was developed. The model simulates the injection of sCO2 into the fractured zone of the originally low-permeable rock formation, the 1D flow between the injection and production boreholes, and the CO2 extraction using the production well (Figure 6). The assumptions of this model also include laminar (Darcy) flow in the reservoir and turbulent flow in both wells. The temperature of the injected fluid is assumed to linearly increase from the injection zone, to reach a natural reservoir temperature at the feed zone of the production well. The extraction of CO2, the carrier of geothermal heat, can be accomplished either using down-hole pumps or spontaneously, thanks to the thermosiphon effect (similar to the artesian outflow in water wells). Contrary to models developed earlier [66,68,69], the one used here accounts for the heat transfer between CO2, the wells’ casings, Energies 2020, 13, 2841 13 of 34 and the surrounding rocks. A list of the governing equations in this model is given in Appendix A. Energies 2020, 13, x FOR PEER REVIEW 13 of 34 a certain value of EGS reservoir permeability, a break-even point is reached, and a further increase in permeability does not significantly affect the pressure difference between the production and injection borehole wellheads. What is worth noticing is the fact that, at high reservoir permeability, the thermosiphon process approaches a certain value, regardless of the mass flow rate. As the model couples reservoir and wellbore processes, these results imply that a reservoir pressure drop has a more profound effect than a pressure drop in the wellbore. Figure Figure 6. 6. Schematic Schematic drawing drawing of of the thesingle-ch single-channel annel EG EGS S momodel. del. The simulation of the CO2 injection into the Lower Triassic sandstones in the Krośniewice-Kutno area was performed for hundreds of different scenarios, in which the thermosiphon effect usually occurs. The two factors that affect the pressure difference between the production and injection wellheads (thermosiphon) the most are the fractured zone permeability and the working fluid (CO2) mass flow rate. For a given mass flow rate and with other parameters kept constant, permeability controls the pressure distribution in the reservoir, affecting the value of thermosiphon (Figure 7). At Figure 7. The impact of fractured zone permeability on the thermosiphon e ect for simulated operating Figure 7. The impact of fractured zone permeability on the thermosiphon effect for simulated conditions operating in t conditions he Krosniewice–Kutn ´ in the Krośo niewice– area (rKutno area (reservoir eservoir temperature: temp 170erature: 170 °C; reinjection C; reinjection temperature: temperature: 35 °C; well depth: 5600 m b.g.l.; wells’ separation distance: 600 m; wells casing 35 C; well depth: 5600 m b.g.l.; wells’ separation distance: 600 m; wells casing roughness: 0.04 mm; roughness: 0.04 mm; CO2 sequestration rate: 5%). CO sequestration rate: 5%). 2.2.2. 2. The 2.2. The CHP CPlant HP Plwith ant wiCO th CO Captur 2 Capture and sCO e and sCO 2 Br Brayton ayton Cycle Cycle 2 2 Based on the analyses concerning the optimal coefficient of the share of cogeneration in DHSs Based on the analyses concerning the optimal coecient of the share of cogeneration in DHSs [54] [54] and available data concerning Polish DHSs [24], the coefficient of the share of cogeneration for and available data concerning Polish DHSs [24], the coecient of the share of cogeneration for the the analyzed referenced biomass-fired CHP plant is assumed as 0.60, which corresponds to the analyzed referenced biomass-fired CHP plant is assumed as 0.60, which corresponds to the maximum maximum heat flux for the CHP plant equal to ca. 22.2 MWth. In order to meet the maximum heat heat flux for the CHP plant equal to ca. 22.2 MW . In order to meet the maximum heat demand, th demand, the peak boilers have to be taken into account (gas-fired units are assumed). The analyzed the peak boilers have to be taken into account (gas-fired units are assumed). The analyzed plant plant uses a stoker-fired boiler, which burns wood chips with a high moisture content (the LHVar was uses a stoker-fired boiler, which burns wood chips with a high moisture content (the LHV was ar around 9534 kJ/kg). Primary steam (53 bar/480 °C) is generated in the boiler and then enters the steam around 9534 kJ/kg). Primary steam (53 bar/480 C) is generated in the boiler and then enters the steam turbine. Steam is extracted at low pressure supplying the regeneration system, which consists of a regenerative heat exchanger preheating the condensate prior to feeding it to the deaerator. turbine. Steam is extracted at low pressure supplying the regeneration system, which consists of a Feedwater, after removing oxygen and other dissolved gasses, is pumped into the boiler to repeat the regenerative heat exchanger preheating the condensate prior to feeding it to the deaerator. Feedwater, cycle. The outlet steam (0.04 bar) goes to the heat condenser. Base heat exchangers cover the basic after removing oxygen and other dissolved gasses, is pumped into the boiler to repeat the cycle. heat demand, resulting from the characteristics of the district heating network, and are supplied with the steam extracted at intermediate pressure (1.9 bar). Part of the heat for the DHS is supplied from the interstage cooling of the CO2 compressors. The same heat extraction from the steam turbine is also used to feed the deaerator after the pressure-reduction valve. The peak heat demand is covered by the gas-fired boilers. The CHP is equipped with the forced draft cooling tower that provides the cooling duty for the condenser, CO2 capture installation, and the interstage cooling of the CO2 compressors. Flue gases from the pulverized biomass boiler are fed into the flue gas conditioning system with selective non-catalytic reduction and an electrostatic precipitator. Due to the low sulphur content in the fuel, the desulphurization system is neglected. Energies 2020, 13, 2841 14 of 34 The outlet steam (0.04 bar) goes to the heat condenser. Base heat exchangers cover the basic heat demand, resulting from the characteristics of the district heating network, and are supplied with the steam extracted at intermediate pressure (1.9 bar). Part of the heat for the DHS is supplied from the interstage cooling of the CO compressors. The same heat extraction from the steam turbine is also used to feed the deaerator after the pressure-reduction valve. The peak heat demand is covered by the gas-fired boilers. The CHP is equipped with the forced draft cooling tower that provides the cooling duty for the condenser, CO capture installation, and the interstage cooling of the CO compressors. 2 2 Flue gases from the pulverized biomass boiler are fed into the flue gas conditioning system with selective non-catalytic reduction and an electrostatic precipitator. Due to the low sulphur content in the fuel, the desulphurization system is neglected. Furthermore, the flue gases are directed to the MEA CO capture installation, where the CO is 2 2 captured from flue gases. A CO capture eciency of 90% and a high purity (99.5%) are assumed. The unit heat consumption is calculated based on the approach presented in [70] and is around 3.36 MJ/kg CO . The saturated steam for the regeneration of the solvent is provided by the extraction of the steam turbine (2.75 bar). Furthermore, the captured CO is directed to the CO compression train, 2 2 which comprises five CO compressors with interstage cooling (to 30 C) and a pump that compresses the CO to 130 bar. The CO is transported via a pipeline for 50 km to the utilization site, where it is 2 2 compressed to the required pressure of the injection well. It was assumed that 5% of the circulating CO is sequestrated, which results in ca. 150 kg/s of CO being constantly injected into the geological 2 2 reservoir. Due to the e ect of CO thermosiphon, there is no need to add the sCO compressor for the 2 2 remaining mass flow. After the turbine, the sCO is cooled down in a gas cooler and is directed to the mixer and then to the injection well. The turbine pressure outlet is determined by the required pressure at the inlet of the injection well plus the pressure loss in the gas cooler [66]. The detailed results regarding the energy performance of the CHP plant, CO capture installation, the geological reservoir, and the sCO cycle can be found in the previous papers of the authors [55,66,71]. 2.3. Thermodynamic Assessment For the purpose of the analysis, the gross and net biomass energy utilization factors (BEUFs) and electrical eciencies (BEEEs) have been defined as follows, respectively: E + Q el DHS = (1) BEUF ch,bio el = (2) BEEE ch,bio where E is the annual electricity production of the system, Q is the annual heat production for the el DHS DHS, and E is the annual chemical energy of the biomass. ch,bio As presented in Equations (1) and (2), the geothermal energy coming from the hot dry rocks is neglected, as the utilization of the geothermal energy is a by-product of the CO storage. On the other hand, the electricity production in the sCO cycle is included in the annual electricity production. The same approach was applied for the calculations of specific energy consumption for CO avoided (SPECCA), where only the biomass chemical energy is considered. 2.4. Economic Assessment Within the economic assessment of the proposed system, both the Levelized Cost of Electricity (LCOE) and that of Heat (LCOH) are calculated. In addition, the Net Present Value (NPV) analysis is performed, including the Break-Even Points (BEP) of negative CO emission credits, electricity, and heat. Both the LCOE and LCOH are aggregated indicators of the costs of the whole process during the system’s assumed lifetime. They comprised total investment costs, operational costs (both fixed Energies 2020, 13, 2841 15 of 34 and variable), and the obtained electricity or heat production. In this study, the LCOE and LCOH are defined as follows: "  (TSC f + OPEX ) B,el a i i LCOE = (3) el ( ) "  TSC f + OPEX B,Q a i LCOH = (4) where TSC is the Total System Cost (EUR), f is the discount factor, and OPEX is the sum of the variable and fixed operational costs. " and " are the total system cost multipliers, which B,el B,Q in accordance with the assumed exergy allocation methodology [72] allow the specific costs to be assigned to electricity and heat production. The calculation of the total system cost multipliers relies on the exergy allocation methodology, which takes into account the exergy of useful products in multi-generation processes. For the analyzed system, they take the values of 0.89 and 0.11 for electricity and heat, respectively, and are calculated as follows: el " =   (5) B,el T T 7008 m,i 0 E + Q el DHS,i i=1 T m,i where T is the logarithmic mean temperature di erence in the DHS, T is the reference temperature, m 0 and " can be calculated as 1 " . B,Q B,el Furthermore, within the economic assessment of the proposed systems, the NPV was proposed to incorporate all the sources of potential income (e.g., the negative CO emission credits). The NPV is calculated based on the following formula: CF NPV = TSC (6) (1 + r) =0 where for  1, the cash flow (CF ) is defined as CF = E  c + Q c + G  c OPEX TAX (7) el el DHS CO2 CO2,NEC i where c , c , and c are the prices of electricity, district heat, and negative CO emission el DHS CO2,NEC 2 credits; r is the discount rate; and TAX is the income tax. The CAC is calculated using the “net present value” method [73], due to the multiple products of the analyzed system (heat and electricity). Necessary assumptions for the validity of the method have been considered, viz. the same net electricity and heat production for the analyzed system with CCS and the reference one. Thus, the CAC is calculated as follows [73]: NPV NPV CCS re f CAC = (8) P G P n CO2,re f n CO2,CCS =0 =0 (1+r) (1+r) where G is the annual CO emissions into the atmosphere. CO2 2 In addition to the CAC, the CO negative emission cost (CNC) is proposed, which is defined as follows: NPV NPV CCS re f CNC = (9) CO2,neg =0 (1+r) where G is the annual negative CO emissions in the analyzed CCS system. CO2,neg 2 Energies 2020, 13, 2841 16 of 34 2.4.1. Methodology for Investment Cost Estimation For each component of the analyzed system, the cost was estimated according to a bottom-up approach where the plants’ (the CHP plant, the CO capture and compression unit, and the sCO 2 2 power plant) costs were broken down. This allowed for an estimation of the Total System Cost (TSC), which is the sum of the total cost of the subsystems. Each subsystem’s total cost was calculated as the Total Equipment Cost (TEC) of the included components and the direct and indirect costs (labor, engineering, integration, etc.). Thus, the TSC of the analyzed system can be defined as follows: 8 9 2 3 > > > > X X 6  7 > > 6 7 < = 6 7 6 7 TSC = > 1 + i + i  1 + i  TEC > + TSC + TSC (10) LC, j E&PC, j 6 P&C, j i, j7 EGS pipeline > > 4 5 > > : ; j i where i is the labor cost indicator, i is the engineering and project cost indicator, and i is the LC E&PC P&C piping and integration cost indicator. The methodology of the TEC calculations for the machinery and equipment, as well as the TSC for the CO transport pipeline and the enhanced geothermal system, is presented in Appendix B. The TEC of the CHP plant components was estimated based on [74]. The TEC estimation of the CO capture and compression unit follows the guidelines presented in [70] and the reference values obtained from [75]. The TEC of the sCO cycle components was estimated based on [76], and the auxiliary equipment’s TEC was estimated based on [77]. For the CO pipeline, the total subsystem cost was taken from [78], and the data regarding Polish geological locations, for the development of the EGS system, were assumed based on [79]. The formulas presented in Appendix B were adopted, by means of the Chemical Engineering Cost Index [80] and the EUR/USD exchange rates, to EUR in 2017 from their origin years and currencies. In Table 4, a list of all the equipment that was part of the Total Equipment Cost assessment is presented, taking into account the proposed methods and division into subsystems (Figure 5). The methods for cost calculations are presented in Appendix B. Table 4. List of equipment considered in the investment cost assessment (MEA: monoethanolamine; sCO : supercritical CO ). 2 2 Subsystem Equipment and Costs biomass receiving and preparation infrastructure biomass grate boiler extraction-condensing steam turbine condenser main heat exchanger (for DHS) regenerative heat exchangers Biomass-fired CHP plant deaerator air fan and flue gas blower with electric motor pumps with electric motor electrical generator force-draft cooling tower steam extraction (for MEA regeneration) direct contact cooler absorber and regenerator (stripper) rich/lean regenerative heat exchanger reboiler CO capture and compression unit MEA reclaimer solvent processing area flue gas blower with electric motor CO drying and compression unit (as whole) 2 Energies 2020, 13, 2841 17 of 34 Table 4. Cont. Subsystem Equipment and Costs 50 km CO pipeline (as whole) CO transport 2 sCO turbine sCO heat exchanger (gas cooler) air fan with electric motor CO -enhanced geothermal system electrical generator wells and casting well drilling and EGS zone stimulation 2.4.2. Financial Assumptions and Scenario Definition Three scenarios were proposed for analysis within the economic assessment: Business as usual, based on the current market in Poland; The investment subsidy scenario, where 50% of the investment cost is subsidized by the state (which is a common practice in relation to biomass CHP plants and geothermal installations [79]); Technological development, where a 30% decrease in the total systems cost occurs (e.g., due to the technological development in the field of CO capture or sCO cycle construction—first of a kind 2 2 vs. nth of a kind). In Table 5, a summary of financial assumptions is presented for all three analyzed scenarios. In addition, a tax rate of 19% is assumed, together with a 5% depreciation charge for equipment and machinery. The year-by-year changes in heat demand or the parameters of CO -EGS were neglected in the study. Table 5. Summary of financial assumptions. Technological Parameter/Scenario Business as Usual Investment Subsidy Scenario Development Location basis Central Poland Cost year basis 2017 Base currency used EUR (Euro) Investment lifetime 30 years Capacity factor 80% (7008 h per year) Discount rate 10% 8% 8% Investment cost according to Equation (3) 30% Subsidies (state grant) 0% 50% 0% Fuel (biomass) cost 6 EUR/GJ OPEX cost: Biomass-fired CHP plant 3.2% of CAPEX CO capture and compression unit 2.5% of CAPEX CO transport pipeline 0.1% of CAPEX EGS wells 0.1% of CAPEX sCO power plant 3.0% of CAPEX Electricity price 100 EUR/MWh 50 EUR/MWh 100 EUR/MWh Heat price 10 EUR/GJ CO credit (negative emission credit) * 20 EUR/t CO 2 2 * CO credit for negative emissions was assumed as the equivalent of the EU-ETS emission allowance. Regarding the assumption in each scenario (Table 4), the discount rate decrease by 2 percentage points in the subsidy and technological development scenario is mainly due to a lower project risk. The electricity price in the subsidy scenario decreases to average market prices in Poland, as state support for the investment cost is assumed. In other scenarios, the RES support scheme deployed in Poland was taken into account, which predicts a maximum price of 440 PLN/MWh (ca. 105 EUR/MWh) Energies 2020, 13, 2841 18 of 34 for the biomass-based and geothermal electricity production. In the current legal system in Poland, a feed-in tari for electricity and subsidy grants for investment costs exclude each other to a large degree due to the legal regulations that state that if an investment grant is higher than the total feed-in tari subsidy (over 15 years) for electricity, then further state support cannot be granted. 3. Results 3.1. Energy Balance In Table 6, a summary of results regarding the annual operation of the analyzed system is presented. Table 6. Summary of the energy and environmental analysis. Parameter Analyzed System * Reference CHP Plant Gross electricity production: in a steam turbine generator 130,157.1 MWh/a 121,372.8 MWh/a in an sCO Brayton turbine generator 23,102.8 MWh/a - Electricity own consumption: in a CHP plant 6157.3 MWh/a 4758.2 MWh/a in a CO capture and compression unit 27,470.3 MWh/a - in an sCO Brayton cycle 3017.7 MWh/a - Net Electricity Production of the System 116,614.6 MWh/a Heat Production to DHS (Total), incl.: 371.3 TJ /a th steam turbine extraction 283.6 TJ /a 371.3 TJ /a th th interstage cooling of CO compressors 87.7 TJ /a - 2 th Heat production for MEA regeneration 697.6 TJ /a - th Energy input, incl.: chemical energy of biomass 2124.6 TJ /a 1674.8 TJ /a LHV LHV heat extracted from geological reservoir 838.7 TJ/a - CO Sequestrated (Removed) 207,276.9 t CO /a 0 t CO /a 2 2 2 Biomass energy utilization factor (Equation (1)): gross (annual average) 43.45% 48.26% net (annual average) 37.24% 47.24% Electrical eciency (Equation (2)): gross (annual average) 25.97% 26.09% net (annual average) 19.76% 25.07% Gross power to heat ratio of the CHP plant 0.48 1.18 * including a biomass-fired CHP plant, CO capture and compression installation, and a CO -enhanced geothermal 2 2 system with an sCO Brayton power cycle. In Table 6, the presented results indicate that the average biomass energy eciency (BEUF) is rather low, which is the result of the significant heat demand in the CO capture installation. For the BEUF net eciency, the decrease in comparison with the reference plant for this study is of 10 percentage points. The electrical eciencies of the analyzed system are also lower than those in the literature (e.g., a 28.2% net annual average in [81] for medium—80 MW feed—wood chip CHP with a power-to-heat ratio of ch 1), but the decrease in the net electricity eciency in comparison with the reference CHP plant without CO capture and utilization in this study is only 5.3 percentage points. It should also be noted that, to keep the same heat and net electrical production, the power-to-heat ratio of the CHP plant changes significantly (from 1.18 in the reference case to 0.48 in the analyzed system), which also strongly a ects the technical design of the steam cycle. If geothermal energy would be included in the eciency calculations, then the net energy utilization factor would be 26.7% and the net electrical eciency would be 14.2%. The negative CO emissions of 97.56 t CO /TJ are similar to those obtained in the 2 2 ch case of CHP plants with a calcium-looping CO capture [23]. In Figure 8, the annual electricity balance of the analyzed system is presented. It should be noted that the sCO cycle net electricity generation compensates around 73% of the electricity consumption 2 Energies 2020, 13, 2841 19 of 34 Energies 2020, 13, x FOR PEER REVIEW 19 of 34 in the CO capture and compression unit. Thus, from the energy point of view, the CO utilization in 2 2 EGS instead of conventional storage in saline formations (which would actually require additional electricity, e.g., for brine management [82]) is more favorable. Energies 2020, 13, x FOR PEER REVIEW 19 of 34 Figure 8. Annual electricity balance of the analyzed system. Figure 8. Annual electricity balance of the analyzed system. Figure 8. Annual electricity balance of the analyzed system. The SPECCA for the analyzed system, compared to that for the reference CHP plant (biomass- The SPECCA for the analyzed system, compared to that for the reference CHP plant (biomass- fired without CCS), is 2.17 MJLHV/kg CO2. When the specific energy consumption for CO2 avoided The SPECCA for the analyzed system, compared to that for the reference CHP plant (biomass-fired fired without CCS), is 2.17 MJLHV/kg CO2. When the specific energy consumption for CO2 avoided includes the geothermal energy, the value increases significantly to 6.22 MJ/kg CO2. The obtained without CCS), is 2.17 MJ /kg CO . When the specific energy consumption for CO avoided includes LHV 2 2 includes the geothermal energy, the value increases significantly to 6.22 MJ/kg CO2. The obtained values of SPECCA, which takes into account only the chemical energy of biomass, can be considered the geothermal energy, the value increases significantly to 6.22 MJ/kg CO . The obtained values of SPECCA, values of SPECCA, which takes into account only the chemical energy of biomass, can be considered as very low, compared to those for other CO2 capture technologies (e.g., for MEA, the base case is as very low, compared to those for other CO2 capture technologies (e.g., for MEA, the base case is which takes into account only the chemical energy of biomass, can be considered as very low, compared to 3.34 MJLHV/kg CO2 in [3]). This is a direct result of the heat integration between the CO2 capture and 3.34 MJLHV/kg CO2 in [3]). This is a direct result of the heat integration between the CO2 capture and those for other CO capture technologies (e.g., for MEA, the base case is 3.34 MJ /kg CO in [3]). This is a 2 LHV 2 compression unit and the DHS, as well as the partial compensation of the electricity consumption for compression unit and the DHS, as well as the partial compensation of the electricity consumption for direct result of the heat integration between the CO capture and compression unit and the DHS, as well CO2 compression in the sCO2 power cycle. The system that excludes the CO2-EGS and assumes CO2 compression in the sCO2 power cycle. The system that excludes the CO2-EGS and assumes as the partial compensation of the electricity consumption for CO compression in the sCO power cycle. conventional CO2 storage, the SPECCA is equal to 3.41 MJLHV/kg CO2, and is comparable with the 2 2 conventional CO2 storage, the SPECCA is equal to 3.41 MJLHV/kg CO2, and is comparable with the values from [83] for analyzed CO2 capture technology. The system that excludes the CO -EGS and assumes conventional CO storage, the SPECCA is equal to 2 2 values from [83] for analyzed CO2 capture technology. In Figure 9, the energy balance of the analyzed system is presented, showing the main heat losses 3.41 MJ /kg CO , and is comparable with the values from [83] for analyzed CO capture technology. LHV 2 2 In Figure (cooling 9, the ener duty), the he gy b at lo alance of the ad (both for th an e DH alyzed S and sy M stem EA r e is pr gener esented, ation proce showing ss heat), the and el main ectricit heat y losses In Figure 9, the energy balance of the analyzed system is presented, showing the main heat losses production and consumption. As shown, the main cooling duty is associated with the sCO2 cycle, (cooling duty), the heat load (both for the DHS and MEA regeneration process heat), and electricity (cooling duty), the heat load (both for the DHS and MEA regeneration process heat), and electricity where the excess heat is rejected to the environment. It should be noted that rejected heat in the sCO2 production and consumption. As shown, the main cooling duty is associated with the sCO2 cycle, cycle has high parameters (around 110 °C), which means that it could be utilized if possible. It can be production and consumption. As shown, the main cooling duty is associated with the sCO cycle, where where the excess heat is rejected to the environment. It should be noted that rejected heat in the sCO2 also noted that a significant amount of heat is used for MEA regeneration in the CO2 capture unit, the excess heat is rejected to the environment. It should be noted that rejected heat in the sCO cycle has cycle has high parameters (around 110 °C), which means that it could be utilized if possible. It can be which leads to almost a triplication of the overall heat production in the system compared with the high parameters (around 110 C), which means that it could be utilized if possible. It can be also noted also noted that a significant amount of heat is used for MEA regeneration in the CO2 capture unit, reference plant. that a significant amount of heat is used for MEA regeneration in the CO capture unit, which leads to which leads to almost a triplication of the overall heat production in the system compared with the almost a triplication of the overall heat production in the system compared with the reference plant. reference plant. Figure 9. Simplified schematic of the analyzed system with the main components of the mass and energy balance. Figure 9. Simplified schematic of the analyzed system with the main components of the mass and Figure 9. Simplified schematic of the analyzed system with the main components of the mass and energy balance. energy balance. Energies 2020, 13, 2841 20 of 34 Energies 2020, 13, x FOR PEER REVIEW 20 of 34 3.2. Economic Evaluation 3.2. Economic Evaluation The TSC of the analyzed system was estimated based on Equation (3) and Appendix B at The TSC of the analyzed system was estimated based on Equation (3) and Appendix B at 153.38 153.38 MEUR . In Figure 10, the share of the TSC for the CHP plant, the CO capture and storage 2017 2 MEUR2017. In Figure 10, the share of the TSC for the CHP plant, the CO2 capture and storage unit, the unit, the CO transport pipeline, the CO -EGS, and the sCO power plant is presented. As can be seen, 2 2 2 CO2 transport pipeline, the CO2-EGS, and the sCO2 power plant is presented. As can be seen, the cost the cost of the CO capture and compression plant is nearly double the investment cost of the plant of the CO2 capture and compression plant is nearly double the investment cost of the plant side. The side. The CO transport and utilization (through CO -EGS and the sCO power plant) comprise 20.5% 2 2 2 CO2 transport and utilization (through CO2-EGS and the sCO2 power plant) comprise 20.5% of the of the TSC, where the development (drilling and fracturing) of the CO -EGS system is dominant. TSC, where the development (drilling and fracturing) of the CO2-EGS system is 2 dominant. Figure 10. The share of system costs for parts of the analyzed system with respect to the total system Figure 10. The share of system costs for parts of the analyzed system with respect to the total system cost. cost. The specific unit investment cost was derived from the total subsystem costs, for which the values The specific unit investment cost was derived from the total subsystem costs, for which the are as follows: values are as follows: The biomass-fired CHP plant: 3073 EUR/kW (gross electric power in full-condensation mode); el • The biomass-fired CHP plant: 3073 EUR/kWel (gross electric power in full-condensation mode); The MEA unit and the CO compression train: 277.5 EUR/tpa; • The MEA unit and the CO2 compression train: 277.5 EUR/tpa; The sCO power plant and CO -EGS: 7090 EUR/kW (gross electric power of the turbine). • The sCO2 power plant and CO2-EGS: 7090 EUR/kWel (gross electric power of the turbine). 2 2 el In the case of the biomass-fired CHP plant, the values are within the range of medium-size CHP In the case of the biomass-fired CHP plant, the values are within the range of medium-size CHP plants fired with wood in the European market, whereas they were 2817 EUR/kWel in the reference plants fired with wood in the European market, whereas they were 2817 EUR/kW in the reference el case. For the enhanced geothermal plants, the TSC is almost 100% higher [84] compared with the case. For the enhanced geothermal plants, the TSC is almost 100% higher [84] compared with the conventional geothermal plants. For the CO2 capture and compression unit, the unit investment costs conventional geothermal plants. For the CO capture and compression unit, the unit investment costs are also higher (by 30%–50%) when compared with some industrial applications [85], mainly due to are also higher (by 30%–50%) when compared with some industrial applications [85], mainly due to the small scale. Nevertheless, the presented results for the cost estimations will be further used in the the small scale. Nevertheless, the presented results for the cost estimations will be further used in the economic assessment of the whole system, including in technological development scenarios. Within economic assessment of the whole system, including in technological development scenarios. Within the analysis, three years of construction time is assumed. the analysis, three years of construction time is assumed. For the analyzed system, in the business as usual scenario, the LCOE is equal to 239.0 EUR/MWh and the LCOH is equal to 9.4 EUR/GJ. When the LCOH is still within an acceptable range, the LCOE For the analyzed system, in the business as usual scenario, the LCOE is equal to 239.0 EUR/MWh is significantly higher than it is in other RES schemes [84]. However, it should be noted here that none and the LCOH is equal to 9.4 EUR/GJ. When the LCOH is still within an acceptable range, the LCOE of the other RES schemes analyzed in [84] have been able to provide negative CO2 emissions, which is significantly higher than it is in other RES schemes [84]. However, it should be noted here that none is one of the main goals of the proposed system. When the reference CHP plant is considered, the of the other RES schemes analyzed in [84] have been able to provide negative CO emissions, which is LCOE is 127.5 EUR/MWh and the LCOH is 5.0 EUR/GJ. In Table 7, the results of the NPV and BEP one of the main goals of the proposed system. When the reference CHP plant is considered, the LCOE is for all three analyzed scenarios are presented. In all cases, the NPV is below 0, but what is worth 127.5 EUR/MWh and the LCOH is 5.0 EUR/GJ. In Table 7, the results of the NPV and BEP for all three mentioning regarding the subsidy scenario (Figure 11a) is that negative cash flow could be analyzed scenarios are presented. In all cases, the NPV is below 0, but what is worth mentioning regarding observed—the same comment can be made for the reference CHP plant (Figure 11b). This means that the subsidy scenario (Figure 11a) is that negative cash flow could be observed—the same comment can the subsidy for investment cost, without support for operational costs (e.g., through a feed-in tariff be made for the reference CHP plant (Figure 11b). This means that the subsidy for investment cost, without support for operational costs (e.g., through a feed-in tari for electricity), does not achieve its purpose. As already mentioned, in the current support system in Poland, a feed-in tari for electricity Energies 2020, 13, 2841 21 of 34 and subsidy grants for investment in RES schemes exclude each other to a large degree. In both cases for the analyzed system, the total state subsidy (resulting from a feed-in tari and investment grants) is around 80 million EUR. As presented in Table 7, in the investment subsidy scenario, the current feed-in tari of ca. 100 EUR/MWh would need to be increased by 30% to meet the BEP, which would only allow one to obtain NPV = 0 (and this is still not attractive for potential investors). Table 7. Summary of the economic assessment. Investment Subsidy Technological Parameter/Scenario Business as Usual Scenario Development Net Present Value (NPV)—Analyzed 127,862,030 EUR 98,362,265 EUR 66,782,545 EUR System, with: Break-Even Point (BEP) for: price of electricity 243.5 EUR/MWh 131.6 EUR/MWh 162.8 EUR/MWh price of heat 55.1 EUR/GJ 35.6 EUR/GJ 29.7 EUR/GJ price of CO credits 100.7 EUR/t CO 65.9 EUR/t CO 55.3 EUR/t CO 2 2 2 2 Energies 2020, 13, x FOR PEER REVIEW 21 of 34 Net Present Value (NPV)—Reference 23,751,231 EUR 45,244,659 EUR 2,136,259 EUR Biomass-Fired CHP Plant, with: for e Brleak-Even ectricityPoint ), do(BEP) es nofor: t achieve its purpose. As already mentioned, in the current support system in price of electricity 126.7 EUR/MWh 86.9 EUR/MWh 98.00 EUR/MWh Poland, a feed-in tariff for electricity and subsidy grants for investment in RES schemes exclude each price of heat 18.4 EUR/GJ 21.6 EUR/GJ 9.37 EUR/GJ other to a large degree. In both cases for the analyzed system, the total state subsidy (resulting from price of fuel 4.2 EUR/GJ 3.4 EUR/GJ 6.1 EUR/GJ a feed-in tariff and investment grants) is around 80 million EUR. As presented in Table 7, in the CO Avoidance Cost (CAC), 63.0 EUR/t CO 27.3 EUR/t CO 35.5 EUR/t CO 2 2 2 investment subsid calculated based ony Equation scenario, the cur (8) rent feed-in tariff of ca. 100 EUR/MWh would need to be increased by 30% to meet the BEP, which would only allow one to obtain NPV = 0 (and this is still CO negative emission cost (CNC), 48.2 EUR/t CO 20.9 EUR/t CO 27.1 EUR/t CO 2 2 2 calculated based on Equation (9) not attractive for potential investors). Figure 11. The Net Present Value (NPV) for different scenarios in (a) the analyzed system and (b) the Figure 11. The Net Present Value (NPV) for different scenarios in (a) the analyzed system and (b) the reference biomass-fired CHP plant, and for the business as usual scenario impact of different (c) negative reference biomass-fired CHP plant, and for the business as usual scenario impact of different (c) CO emission credits in the analyzed system and (d) prices of fuel in the reference biomass-fired CHP plant. negative CO2 emission credits in the analyzed system and (d) prices of fuel in the reference biomass- fired CHP plant. Table 7. Summary of the economic assessment. Investment Technological Parameter/Scenario Business as Usual Subsidy Development Scenario Net Present Value (NPV)—Analyzed System, −127,862,030 EUR −98,362,265 EUR −66,782,545 EUR with: Break-Even Point (BEP) for: price of electricity 243.5 EUR/MWh 131.6 EUR/MWh 162.8 EUR/MWh price of heat 55.1 EUR/GJ 35.6 EUR/GJ 29.7 EUR/GJ price of CO2 credits 100.7 EUR/t CO2 65.9 EUR/t CO2 55.3 EUR/t CO2 Net Present Value (NPV)—Reference −23,751,231 EUR −45,244,659 EUR 2,136,259 EUR Biomass-Fired CHP Plant, with: Break-Even Point (BEP) for: price of electricity 126.7 EUR/MWh 86.9 EUR/MWh 98.00 EUR/MWh price of heat 18.4 EUR/GJ 21.6 EUR/GJ 9.37 EUR/GJ Energies 2020, 13, 2841 22 of 34 In Figure 11c, the impact of the negative CO emission credit on the NPV for the analyzed system in the business as usual scenario is presented. As there is currently a lack of dedicated schemes to support the negative CO emissions, in the analysis, the corresponding EU-ETS CO emission allowance price 2 2 was assumed (20 EUR/t CO ). For the current technological development and economic support mechanism, the price of the negative CO emission credits would need to be five times higher to provide economic justification for investment in the analyzed system. For the reference biomass-fired CHP plant, the impact of the fuel cost on the NPV in the same business as usual scenario has been presented in Figure 11d. As can be observed, the cost of fuel significantly impacts the economic profitability of the reference CHP plant, and prices below 4 EUR/GJ would be needed to provide ch economic justification for such units. In Table 7, beside the NPV for the analyzed system and reference CHP plant, the results for the BEP price of CO credits, CO avoided cost, and CO negative emission cost are presented. Taking 2 2 2 into account their definitions, as expected, the BEP of CO credit is higher than CAC or CNC, as it refers to the overall economic performance of the analyzed system expressed by the NPV. The CAC is higher than CNC, as it refers to the avoided CO emissions, which takes into account the di erence in direct CO emissions resulting from fuel combustion in the analyzed system and reference plant. Finally, the CNC refers only to obtained negative emissions, which correspond directly to the amount of CO capture in the analyzed system, as the reference CHP plant CO emission (coming from biomass 2 2 combustion) is considered to be zero. As the annual net production of electricity and heat in the analyzed system and reference CHP plant are the same (Table 6), the lowest CAC was obtained for the investment subsidy scenario, in which the investment cost decreases by 50% (through subsidies), followed by the technology development scenario, where the investment cost decreases by 30% (Table 5). Thus, the impact of the investment cost on the CAC can be observed. Taking into account the main goal of the proposed system, which is to obtain negative CO emissions, the CNC is a more valuable indicator that quantifies the cost of providing those negative emissions, taking into account the same production levels (in this analysis, electricity and heat) in the energy system. Based on the presented results, it can be stated that the direct cost of negative CO emissions coming from the investment in the proposed CO capture and 2 2 utilization (and storage) is around 50 EUR/t CO , but the economic justification for the development of the analyzed system is two times higher (around 100 EUR/t CO ) in the business as usual scenario. In Figure 12, the discounted cash flow (CF) for the analyzed system is presented. It can be observed that incomes from electricity and heat barely surpass the operational expenditures (fixed and variable ope Energies ration2020 al co , 13 st,s x FO ). TR P huEER s, th RE e N VIEW PV values (e.g., for the business as usual scenario) correspond to 23 of the 34 TSC. Figure 12. Discounted CF in the business as usual scenario in the analyzed system. Figure 12. Discounted CF in the business as usual scenario in the analyzed system. For the performed economic assessment, sensitivity analysis was performed, and the results are presented in Figure 13. As expected, the price of electricity and fuel (biomass) has the highest impact on the NPV. The impact of the price of heat and price of negative CO2 emission credit has a similar effect, although it should be pointed out that the heat price is strictly regulated in Poland, so significant changes in the price of heat should not be expected. Moreover, a dedicated support scheme for heat production operational costs from renewable energy sources is also lacking. Figure 13. Sensitivity analysis in the business as usual scenario in the analyzed system. In Figure 14, the NPV in the function of the cost of fuel and the price of negative CO2 emission credit is presented for the business as usual and the technological development scenarios. It is clear that, with an increase of the price of biomass (fuel), a lower NPV can be obtained. On the other hand, the increase in the CO2 credits helps to increase the profitability of the project. With a decrease in the costs of fuel to 4 EUR/GJ (which is a closer price range in, e.g., the USA) and the technological development of the system components (which is possible, taking into account, e.g. the decrease in the investment cost for other renewable energy source technologies and CO2 capture technology Energies 2020, 13, x FOR PEER REVIEW 23 of 34 Energies 2020, 13, 2841 23 of 34 Figure 12. Discounted CF in the business as usual scenario in the analyzed system. For the performed economic assessment, sensitivity analysis was performed, and the results are For the performed economic assessment, sensitivity analysis was performed, and the results are presented in Figure 13. As expected, the price of electricity and fuel (biomass) has the highest impact presented in Figure 13. As expected, the price of electricity and fuel (biomass) has the highest impact on the NPV. The impact of the price of heat and price of negative CO emission credit has a similar on the NPV. The impact of the price of heat and price of negative CO2 emission credit has a similar e ect, although it should be pointed out that the heat price is strictly regulated in Poland, so significant effect, although it should be pointed out that the heat price is strictly regulated in Poland, so changes in the price of heat should not be expected. Moreover, a dedicated support scheme for heat significant changes in the price of heat should not be expected. Moreover, a dedicated support scheme production operational costs from renewable energy sources is also lacking. for heat production operational costs from renewable energy sources is also lacking. Figure Figure 13. 13. Sensitivity Sensitivity analysis analysis in in the bu the business siness as u as usual sual scenar scenario io in the analy in the analyzed zed systsystem. em. In Figur In Figure e 14, the 14, the NPV i NPV in the n the functi function on of of the the c cost ost of fu of fuel el aand nd the pr the price ice of ne of negati gative CO ve 2CO emission emission credit is presented for the business as usual and the technological development scenarios. It is clear credit is presented for the business as usual and the technological development scenarios. It is clear that, with an increase of the price of biomass (fuel), a lower NPV can be obtained. On the other hand, that, with an increase of the price of biomass (fuel), a lower NPV can be obtained. On the other hand, the increase in the CO2 credits helps to increase the profitability of the project. With a decrease in the the increase in the CO credits helps to increase the profitability of the project. With a decrease in costs of fuel to 4 EUR/GJ (which is a closer price range in, e.g., the USA) and the technological the costs of fuel to 4 EUR/GJ (which is a closer price range in, e.g., the USA) and the technological development of the system components (which is possible, taking into account, e.g. the decrease in Energies development 2020, 13, x FO of the R Psystem EER REVIEW components (which is possible, taking into account, e.g., the decrease 24 of 34 in the investment cost for other renewable energy source technologies and CO2 capture technology the investment cost for other renewable energy source technologies and CO capture technology itself), itself), the BEP of the negative CO2 emission credit is around 35 EUR/t CO2, which is a very promising the BEP of the negative CO emission credit is around 35 EUR/t CO , which is a very promising option 2 2 option for heat and electricity supply together with carbon dioxide removal from the atmosphere. for heat and electricity supply together with carbon dioxide removal from the atmosphere. Figure 14. NPV in the function of negative CO emission credits and the cost of fuel in (a) the business Figure 14. NPV in the function of negative CO2 emission credits and the cost of fuel in (a) the business as usual scenario and (b) the technological development scenario. as usual scenario and (b) the technological development scenario. Within the analyzed system, the TSC includes the costs associated with CO2 utilization—the CO2 transport pipeline, CO2-EGS system development (drilling and fracturing), and the sCO2 power plant. This approach might not correspond to current trends in CCUS technologies, while dedicated operators are proposed for CO2 transport and CO2 utilization or storage. In Figure 15, the impact including the proposed CCUS chain associated with CO2 transport and utilization on the NPV is presented. The black lines correspond to the currently analyzed option for two CO2 transport distances (50 and 100 km). The coloured lines indicate the impact on the NPV when the costs of CO2 transport and storage (T&S) are given. As can be seen, the proposed option (for a 50 km CO2 transport pipeline) is competitive when the CO2 transport and storage costs are above 10 EUR/t CO2 (which is the case for Poland [82]). This proves that the proposed design of CO2 transport and utilization (including storage) is an economically favorable option, and that the electricity production from renewable energy sources (geothermal energy) can be increased. Figure 15. ΔNPV resulting from different options for capture CO2 utilization and storage. Energies 2020, 13, x FOR PEER REVIEW 24 of 34 itself), the BEP of the negative CO2 emission credit is around 35 EUR/t CO2, which is a very promising option for heat and electricity supply together with carbon dioxide removal from the atmosphere. Energies 2020, 13, 2841 24 of 34 Figure 14. NPV in the function of negative CO2 emission credits and the cost of fuel in (a) the business as usual scenario and (b) the technological development scenario. Within the analyzed system, the TSC includes the costs associated with CO utilization—the CO transport pipeline, CO -EGS system development (drilling and fracturing), and the sCO power 2 2 2 Within the analyzed system, the TSC includes the costs associated with CO2 utilization—the CO2 plant. This approach might not correspond to current trends in CCUS technologies, while dedicated transport pipeline, CO2-EGS system development (drilling and fracturing), and the sCO2 power plant. operators are proposed for CO transport and CO utilization or storage. This approach might not correspond 2 to current 2 trends in CCUS technologies, while dedicated In Figure 15, the impact including the proposed CCUS chain associated with CO transport and operators are proposed for CO2 transport and CO2 utilization or storage. In Figure 15, the impact including the proposed CCUS chain associated with CO2 transport and utilization on the NPV is presented. The black lines correspond to the currently analyzed option for utilization on the NPV is presented. The black lines correspond to the currently analyzed option for two CO transport distances (50 and 100 km). The coloured lines indicate the impact on the NPV two CO2 transport distances (50 and 100 km). The coloured lines indicate the impact on the NPV when the costs of CO transport and storage (T&S) are given. As can be seen, the proposed option when the costs of CO2 transport and storage (T&S) are given. As can be seen, the proposed option (for a 50 km CO transport pipeline) is competitive when the CO transport and storage costs are 2 2 (for a 50 km CO2 transport pipeline) is competitive when the CO2 transport and storage costs are above 10 EUR/t CO (which is the case for Poland [82]). This proves that the proposed design of above 10 EUR/t CO2 (which is the case for Poland [82]). This proves that the proposed design of CO2 CO transport and utilization (including storage) is an economically favorable option, and that the transport and utilization (including storage) is an economically favorable option, and that the electricity production from renewable energy sources (geothermal energy) can be increased. electricity production from renewable energy sources (geothermal energy) can be increased. Figure 15. ΔNPV resulting from different options for capture CO2 utilization and storage. Figure 15. DNPV resulting from di erent options for capture CO utilization and storage. 3.3. Technology Readiness Level of the Analyzed Concept The concept of the Technology Readiness Level (TRL) is used to estimate the maturity level of a technology, which is necessary to achieve a low-carbon economy but not yet available at a commercial scale. One of them is CCS, including BECCS. However, there are factors that can put important limitations on its global spread. These include a lower eciency compared to other combustion methods and a weak infrastructure for CO transport and storage. On the combustion side, a lower energy density and less ash deposition can be problematic [86]. However, the key prerequisites for large-scale BECCS are the availability of biomass feedstock and land for production. The challenges for the former include competition between di erent sectors of the economy for feedstock and competition with other ecosystem services, for example food production. The seasonal availability of certain crops can also be a limitation. A related issue is land availability for biomass feedstock production. BECCS is one of the CCS technologies that have reached (or are close to reaching) the commercial phase of development. What is underlined by researchers is that BECCS’ spread relies on a mature CCS industry. In 2019, five BECCS plants were operating worldwide. By 2100, this could provide more than 5% of total global primary energy [87]. However, if other negative emission technologies are to be quickly developed, this could potentially lead to a slower and lower uptake of BECCS. This can only be realized if they are to be cost-competitive in comparison to BECCS [87]. Energies 2020, 13, 2841 25 of 34 There were four EGS sites in the US in 2017, operating at around a 2 MW capacity. Some of them el are planned to reach 5 MW by 2020. However, the small project size can be misleading, as the target el is the development of (low- and medium-temperature) geothermal systems in the range of hundreds of kWe to an MWe for electricity in remote towns as well as the utilization of coproduced thermal power generation that results from the by-products of existing oil and gas wells. Only afterwards is the development of larger systems planned [42]. There have been attempts to develop an EGS in Asia as well. Japan developed two, but they are now closed. South Korea, China, and Taiwan are currently experimenting with the technology [42,88]. It has also been recently argued that, despite promising initial ideas on applying unconventional oil and gas technologies, there are shortcomings that make EGSs uneconomical [89]. Research has indicated that an adequate mass flow rate, of 80 kg/s at 200 C, is required for the proper functioning of an EGS plant. However, the systems currently in operation do not even reach 25 kg/s [90]. Moreover, the costs of deep wells remain highly uncertain [90]. The key challenge that remains addressed is how to establish and maintain a suitable reservoir. Furthermore, its change over time is insuciently understood. Finally, knowledge on the long-term interaction between working fluids and rock structure is incomplete [91]. To sum up, EGSs are heavily subsidized and are more expensive than other energy sources, which makes them not economically feasible. Therefore, governments should focus on reducing costs to 2030 to a competitive level [88]. This is assuming remarks that refer to a water-based EGS, while the TRL level of a CO -based EGS is around 3–4. There are five research institutes in the US and one each in Japan and South Korea that have indicated experimentation with sCO since 2009 [48,92]. According to the energetic rule of thumb that thermal eciency rises with the size of the system, sCO eciency is expected to rise. However, all test facilities operate at small scales; therefore, the development of a large-scale (>10 MW) prototype sCO system is necessary [92], and some of the most recent research points out that scaling up remains an issue [47,48]. Better designs of heat exchangers, bearings, and seals are necessary [47]. Two experiments of the application of the sCO power cycle in geothermal energy have shown that (1) the relationship between the mass flow rate of sCO and the power capacity is nonlinear and that (2) the cycle eciency was around 18% [47]. Thus, the overall TRL is also rather low, around 4–5. Thus, taking into account all of the aforementioned considerations, the overall TRL of the proposed concept can be assessed as TRL4 (technological development), mainly due to the early stage of the CO -enhanced geothermal system development. 4. Discussion Based on the presented results, it can be concluded that, in the current energy market in Poland, the proposed option is not economically feasible. The break-even price of the negative CO emission credit (the CO emission allowance price) should be approximately 100 EUR/t CO , which, even with the latest 2 2 rapid increase in EU ETS prices, could be expected by 2050. Within the analyzed scenarios, the government investment subsidies could improve the economic profitability of the system, but this is still not enough to provide economic justification at present without further support for the operational costs (e.g., through a feed-in tari for electricity or additional negative CO emission credits). Thus, further technological advances should be pursued to lower the investment costs of system components, mainly of the CHP plant, post-combustion CO capture, and CO -EGS system development (the cost of wells 2 2 drilling). In the first case, the potential is already visible when comparing the investment costs around the world—e.g., in China and India, the unit investment costs for biomass-fired CHP plants are almost two times lower than in Europe [84]. Additionally, a decrease in the CO capture installation investment cost should also be expected due to the development and maturity, as well as the redesign, of the units for smaller capacities. In addition, there is still small room for improved energy performance, as a decrease in the energy consumption in CO capture units can be observed. Where operational costs are concerned, fuel cost is of great significance; the assumed paper price of 6 EUR/GJ for waste wood biomass in Poland seems higher than in other parts of the world—e.g., in the USA, the prices are up to 2.5 USD/GJ [93]—but if the transport to Europe and other costs are Energies 2020, 13, 2841 26 of 34 included, in the end, the prices of biomass are even higher (up to 10 USD/GJ). The prices of wood biomass are expected to grow over the next several years in Poland, so only a locally specific source of cheap biomass could positively influence the economic profitability of the system. From an economic point of view, CO utilization instead of conventional storage in saline formations proved to be more economically justified, as the sequestration during the operation of the CO -EGS system could generate additional income per unit of CO stored. The low electrical eciency 2 2 of the CO -EGS power plant can be significantly improved when additional ORC is added or there is a local demand for heat at the site. Those options should be analyzed in further studies to estimate the potential economic benefits resulting from the change in system design. In [94], the cost of BECCS was estimated between 15 and 400 USD/ton of CO removed. It was also stated that BECCS was the best solution for providing negative CO emissions in most climate change scenarios. It should be noted that BECCS also has several drawbacks—mainly increased water and land use [94]. Where the maturity of the analyzed technological design is concerned, the conventional BECCS components are usually mature technologies. In the analyzed system, the CO -EGS system was included, which would decrease the TRL of the technology. However, as stated in the introduction, Poland still has much to do in the field of regulations and laws for CCS deployment, and probably even more where CCUS is concerned. Nevertheless, despite rather negative results coming from the study, research should be continued in terms of whole system energy and economic optimization, as well as more detailed investment cost estimations. Taking into account the importance of negative CO emissions for meeting climate goals [10], there might not be a better alternative than the wide deployment of BECCS technologies. 5. Conclusions The obtained results indicate that, in the current energy market in Poland, the proposed system is not economically feasible. The main obstacles, from an economic point of view, are associated with the high investment cost of the CO capture and compression unit, as well as a lack of dedicated comprehensive governmental incentives to pursue negative CO emissions in the energy sector. The latter is associated with the general lack of interest on behalf of the Polish government in CO capture and storage technologies, despite their general increased technological maturity over the last few years. Author Contributions: Conceptualization, P.G.; methodology, P.G. and M.M.; software, P.G. and M.M.; validation, P.G., A.S. and M.M.; formal analysis, P.G. and M.M.; investigation, P.G., M.M. and M.H.; resources, P.G., A.S. and L.P.; data curation, P.G., M.M. and A.S.; writing—original draft preparation, P.G., A.S., M.M., L.P. and M.H.; writing—review & editing, P.G., A.S., M.M. and M.H.; visualization, P.G. and A.S.; supervision, P.G.; project administration, P.G.; funding acquisition, P.G. All authors have read and agreed to the published version of the manuscript. Funding: This research was funded by the National Science Centre, Poland, grant number 2017/24/C/ST8/00204. Conflicts of Interest: The authors declare that there is no conflict of interest. Appendix A Governing equations for steady-state, single-channel flow and heat exchange in the reservoir–wellbore coupled model are presented in Appendix A. From the law of energy conservation and assuming a Darcy flow of constant cross-sectional area in the reservoir, the following set of equations is used to estimate the necessary injection pressure to be maintained at the wellhead: P = P + DP + DP gDz (A1) inj res f, well res Dz V Dzm DP = f  = 8f (A2) f, well D 2 D Energies 2020, 13, 2841 27 of 34 6.9 f = 1.8 log + (A3) Re 3.7D VD 4 m Re = = (A4) m DL DP = (A5) res KA For the production well, the following relationship is valid: P = P DP gDz (A6) prod res f, well where P and P are the pressures at the wellheads of the injection and production wells, respectively; inj prod DP represents the frictional pressure loses in the wellbore; DP represents the reservoir pressure f, well res losses due to laminar (Darcy) flow; V is the fluid velocity; m is the mass flow rate;  is the fluid density;  is the fluid dynamic viscosity; Re is the Reynolds number; g is the standard gravity; D is the pipe inner diameter;  is the pipe roughness; K is the average permeability of the reservoir zone; DL and Dz are the incremental reservoir and well intervals (lengths), respectively; and A is the cross-sectional swept area of the fluid flow in the reservoir. The temperature of the working fluid (e.g., water and CO ) at the bottom of the injection well and at the production wellhead can be estimated using the approximate solution of the line-source heat equation. The solution of Equation (A7) allows for the determination of the unit heat transfer rate between the borehole and flowing well. " ! # 4 t q = 4 (T T ) ln (A7) a w 1 r c r r where q is the unit heat transfer rate;  is the apparent thermal conductivity of the wellbore, casings, and surrounding rock formation; c is the specific heat of rock formation;  is the density of the rock formation; T is the temperature of the fluid in the analyzed interval; T is the natural temperature of w 1 the rock formation in the analyzed interval, undisturbed by the drilling of the fluid flow; t is the time; r is the well diameter; and is the Euler constant (  0.577216). Equation (A7) is valid only when r c w r u =  1 (A8) 4 t The determination of the unit heat transfer rate requires the use of an apparent thermal conductivity coecient, which takes into account the thermal conductivity of the casings, grouts, and rock formation, at a distance from the well axis to the distance at which the impact of the well operation on the natural temperature of the rock formation is negligible. The apparent thermal conductivity coecient for cylindrical layers can be determined using Equation (A9): i=1 = (A9) s D i mz i=1 i mi where s is the thickness of the ith layer,  is the thermal conductivity of the ith layer, D is the i i mz equivalent logarithmic mean of the extreme diameters, and D is the logarithmic mean of the outer mi and inner diameters of the ith cylindrical layer (m). D = 4 t (A10) mz where is the thermal di usivity of rock formation, and t is the time of the simulation period (1 year). Energies 2020, 13, 2841 28 of 34 The formula for the logarithmic mean of the pipe diameters is D D out inn D = (A11) out ln inn where D and D are the pipe’s outer and inner diameters, respectively. out inn The temperature at the outlet of each borehole’s interval can be calculated using the following equation: q z I,i T = T (A12) out, i inn, i V c where T and T are the temperatures at the outlet and inlet of the ith section, respectively; l is out, i inn, i i the length of the ith section; V is the volumetric flow rate; c is the specific heat; and % is the density of the injected/pumped fluid (kg/m ). Appendix B All total equipment cost (TEC) values are given in EUR (2017). The TECs were given as “power functions” for the following components: The biomass receiving and preparation infrastructure: 0.4096 TEC = 332, 786 G (A13) RPI bio where G (ton/day) is the biomass mass flow (as received); bio The biomass grate boiler: . . 0.1195 TEC = m  274 352 m  C  C (A14) GB st p,GB t,GB st where C and C stand for the pressure and superheated steam multipliers: p,GB t,GB > C = 1 p  2.0 MPa > p ,GB st > C = 0.0278  p + 0.5348  p + 0.0044 for 2.0 MPa < P < 6.0 MPa (A15) p,GB st st > st C = 2.21 P  6.0 Mpa p,GB st 6 2 C = 0.910  DT + 0.0043 DT + 1.0051 (A16) T,GB st st where and m (kg/s) is the boiler steam mass flow, p (MPa) is the boiler steam pressure, and DT (K) st st st is the di erence between the steam temperature from the boiler and saturation temperature; The extraction-condensing steam turbine: 0.287 TEC = 4008.22 P  P (A17) EC,ST ST,con ST,con where P (kW ) is the electrical power of the turbine in full-condensation mode; ST,con el The water/steam heat exchangers: . . 0.18 TEC = 313 Q  Q (A18) WS,HX HX HX where Q (kW ) is the heat transfer in the heat exchanger; HX th The air fans: Energies 2020, 13, 2841 29 of 34 0.67 AF TEC = 103, 193 (A19) AF where P (kW ) is the electrical power of the air fan motor; AF el The electrical generator: 0.95 TEC = 85.4 P (A20) GEN GEN where P (kW ) is the electrical power of the generator; GEN el The cooling tower: TEC = 32.2 Q (A21) CT CT where Q (kW ) is the cooling tower heat duty; th CT The supercritical CO turbine: 0.8 TEC = 168, 840 P  C  C (A22) CO2,ST p,CO2 t,CO2 ST where P (MW ) is the e ective power of the turbine, and C and C stand for the pressure el p,CO2 t,CO2 ST and temperature multipliers for the sCO machinery: C = 1 if p < 10 MPa max p,CO2 (A23) C = 0.8 + 0.02 p if p  10 MPa p,CO2 max max C = 1 if t < 400 t,CO2 max (A24) C = 5.32 0.0238 t + 0.00003 t if t  400 t,CO2 max max max where and p (bar) is the maximal pressure, and t ( C) is the maximal temperature at which the max max machinery is operated; The supercritical CO chiller: TEC = 168 UA  C  C (A25) CO2,HX p,CO2 t,CO2 HX where UA (kW/K) is the overall heat transfer coecient U multiplied by the heat transfer area A of HX the heat exchanger. For the CO capture and compression equipment, the total equipment cost was estimated as 0.6 TEC = TEC  (A26) re f re f where X is the scaling parameter. For the components of the CO capture and compression equipment, the scaling parameters are presented in Table A1. Energies 2020, 13, 2841 30 of 34 Table A1. Scaling parameters for the CO capture and compression equipment. Equipment Scaling Parameter, X Direct contact cooler V T f g f g Flue gas blower f g,re f f g,re f Absorber Rich/lean cross heat exchanger solv Regenerator V solv,re f f g G st . . Reboiler V G f g,re f st,re f st Steam extractor . st,re f DMEA MEA reclaimer DMEA,re f solv Solvent processing area solv,re f CO2 CO drying and compression unit CO2,re f where V is the flue gas volumetric flow; T is the flue gas temperature at the inlet to given f g f g . . . machinery; V is the solvent volumetric flow; G is the steam mass flow; G is the make-up solv st DMEA solvent mass flow; and G is the compressed CO mass flow. 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Review of supercritical CO2 power cycle technology and current status of research and development. Nucl. Eng. Technol. 2015, 47, 647–661. [CrossRef] 93. International Renewable Energy Agency. Biomass for power generation. In Renewable Energy Technologies: Cost Analysis Series; IRENA: Abu Dhabi, UAE, 2012; Volume 1. 94. Consoli, C. Perspective. Bioenergy and Carbon Capture and Storage; Global CCS Institute: Melbourne, Australia, 2018. © 2020 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (http://creativecommons.org/licenses/by/4.0/). http://www.deepdyve.com/assets/images/DeepDyve-Logo-lg.png Energies Multidisciplinary Digital Publishing Institute

Techno-Economic Assessment of a Combined Heat and Power Plant Integrated with Carbon Dioxide Removal Technology: A Case Study for Central Poland

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energies Article Techno-Economic Assessment of a Combined Heat and Power Plant Integrated with Carbon Dioxide Removal Technology: A Case Study for Central Poland 1 , 2 3 4 Paweł Gładysz * , Anna Sowizd ˙ zał ˙ , Maciej Miecznik , Maciej Hacaga and Leszek Pajak ˛ Faculty of Energy and Fuels, AGH University of Science and Technology, 30-059 Kraków, Poland Faculty of Geology, Geophysics and Environmental Protection, AGH University of Science and Technology, 30-059 Kraków, Poland; ansow@agh.edu.pl (A.S.); pajakl@agh.edu.pl (L.P.) Department of Renewable Energy and Environmental Research, Mineral and Energy Economy Research Institute of the Polish Academy of Sciences, 31-261 Kraków, Poland; miecznik@min-pan.krakow.pl Faculty of National Security, War Studies University, 00-910 Warszawa, Poland; m.hacaga@akademia.mil.pl * Correspondence: pawel.gladysz@agh.edu.pl Received: 5 April 2020; Accepted: 1 June 2020; Published: 3 June 2020 Abstract: The objective of this study is to assess the techno-economic potential of the proposed novel energy system, which allows for negative emissions of carbon dioxide (CO ). The analyzed system comprises four main subsystems: a biomass-fired combined heat and power plant integrated with a CO capture and compression unit, a CO transport pipeline, a CO -enhanced geothermal system, 2 2 2 and a supercritical CO Brayton power cycle. For the purpose of the comprehensive techno-economic assessment, the results for the reference biomass-fired combined heat and power plant without CO capture are also presented. Based on the proposed framework for energy and economic assessment, the energy eciencies, the specific primary energy consumption of CO avoidance, the cost of CO 2 2 avoidance, and negative CO emissions are evaluated based on the results of process simulations. In addition, an overview of the relevant elements of the whole system is provided, taking into account technological progress and technology readiness levels. The specific primary energy consumption per unit of CO avoided in the analyzed system is equal to 2.17 MJ /kg CO for biomass only 2 LHV 2 (and 6.22 MJ /kg CO when geothermal energy is included) and 3.41 MJ /kg CO excluding the LHV 2 LHV 2 CO utilization in the enhanced geothermal system. Regarding the economic performance of the analyzed system, the levelized cost of electricity and heat are almost two times higher than those of the reference system (239.0 to 127.5 EUR/MWh and 9.4 to 5.0 EUR/GJ), which leads to negative values of the Net Present Value in all analyzed scenarios. The CO avoided cost and CO negative cost in the 2 2 business as usual economic scenario are equal to 63.0 and 48.2 EUR/t CO , respectively, and drop to 27.3 and 20 EUR/t CO in the technological development scenario. The analysis proves the economic feasibility of the proposed CO utilization and storage option in the enhanced geothermal system integrated with the sCO cycle when the cost of CO transport and storage is above 10 EUR/t CO 2 2 2 (at a transport distance of 50 km). The technology readiness level of the proposed technology was assessed as TRL4 (technological development), mainly due to the early stage of the CO -enhanced geothermal systems development. Keywords: CO capture; utilization and storage; combined heat and power; CO enhanced geothermal 2 2 systems; supercritical CO power cycles; biomass; negative emission technologies Energies 2020, 13, 2841; doi:10.3390/en13112841 www.mdpi.com/journal/energies Energies 2020, 13, 2841 2 of 34 Energies 2020, 13, x FOR PEER REVIEW 2 of 34 1. Introduction 1. Introduction Over the last two decades, deep changes have influenced the energy sector from both the point of Over the last two decades, deep changes have influenced the energy sector from both the point view of energy sources and that of technologies in use. The main factors behind these changes are the of view of energy sources and that of technologies in use. The main factors behind these changes are pursuit of more sustainable electricity generation, and economic and energy security considerations. the pursuit of more sustainable electricity generation, and economic and energy security Europe is one of the most vivid examples. Some of the European Union member states—for example, considerations. Europe is one of the most vivid examples. Some of the European Union member Germany—make e orts to be leaders in introducing changes in the energy sector. Human-induced states—for example, Germany— make efforts to be leaders in introducing changes in the energy climate change (mainly GHG emissions from various industry sectors) is pushing the pursuit of sector. Human-induced climate change (mainly GHG emissions from various industry sectors) is more sustainable and environmentally friendly electricity generation. There are di erent pathways, pushing the pursuit of more sustainable and environmentally friendly electricity generation. There depending on the states’ energy and climate policies and conditions to meet this objective. However, are different pathways, depending on the states’ energy and climate policies and conditions to meet some technologies and policy actions are included in all of them, viz. renewable energy sources, energy this objective. However, some technologies and policy actions are included in all of them, viz. renewable e eciency, and nergy decarbonisation. sources, energy In Polish efficiency, ocial documents and decarboni concerning sation. In enerPoli gy policy sh off[i1ci ]al and docu pathways ments for the country’s development [2], these mechanisms are also included. The concept analyzed within concerning energy policy [1] and pathways for the country’s development [2], these mechanisms are a the lso i paper ncluded. The concept a is coherent with all thr na eelyz points, ed wias thiitn the pa emphasizes per is coherent wi the usage of renewable th all three poi energy sour nts, a cess(by it means of biomass and geothermal energy), the increase in energy utilization eciency (by means of emphasizes the usage of renewable energy sources (by means of biomass and geothermal energy), t the he incre cogeneration ase in energ of heat y utand ilizat electricity), ion efficiena cy nd (b the y m decarbonisation eans of the cogen (by erat means ion of of he CO at and captur elect e,rutilisation, icity), and and storage) of the energy sector (Figure 1). All of them combined lead to the possibility of obtaining the decarbonisation (by means of CO2 capture, utilisation, and storage) of the energy sector (Figure 1) so-called . All of t“negat hem combined l ive” CO emissions ead to the possib and incr ilit easing y of obeconomic taining so- pr ca ofitability lled “negat as ive a ” result CO2 emis of the sions and synergy between those three pillars. increasing economic profitability as a result of the synergy between those three pillars. Figure 1. Three pillars of new energy systems. Figure 1. Three pillars of new energy systems. The main goal of this paper is to give a wide overview of the important aspects regarding the The main goal of this paper is to give a wide overview of the important aspects regarding the proposed system, both from technological and economic points of view. A location in Central Poland proposed system, both from technological and economic points of view. A location in Central Poland was used as a base for a case study, but the presented results can be applied to other locations. However, was used as a base for a case study, but the presented results can be applied to other locations. it should be kept in mind that, e.g., enhanced geothermal system performance is strictly associated However, it should be kept in mind that, e.g., enhanced geothermal system performance is strictly with available geological formations. Additionally, the biomass-fired combined heat and power (CHP) associated with available geological formations. Additionally, the biomass-fired combined heat and plants operating in di erent countries have di erent designs depending on the heat demand over the power (CHP) plants operating in different countries have different designs depending on the heat year. In Nordic countries, designs with back-pressure steam turbines are widely used, whereas in demand over the year. In Nordic countries, designs with back-pressure steam turbines are widely other countries (like Poland), extraction-condensing turbines are used more often, and back-pressure used, whereas in other countries (like Poland), extraction-condensing turbines are used more often, turbines are only used at industrial sites with constant heat demand. All of those aspects should be and back-pressure turbines are only used at industrial sites with constant heat demand. All of those kept in mind when applying the results of this study to other locations and countries. Therefore, aspects should be kept in mind when applying the results of this study to other locations and we provide a detailed method description for crucial parts of the analysis—carbon dioxide-enhanced countries. Therefore, we provide a detailed method description for crucial parts of the analysis— geothermal system (CO -EGS) operation and economic assessment—to allow others to implement the carbon dioxide-enhanced geothermal system (CO2-EGS) operation and economic assessment—to presented concept for their case studies. allow others to implement the presented concept for their case studies. 1.1. CO2 Capture, Utilization, and Storage (CCUS) As many countries are failing to meet the Paris agreement climate goals, it becomes more and more obvious that all available technologies must be used to curb emissions. After a period of Energies 2020, 13, 2841 3 of 34 1.1. CO Capture, Utilization, and Storage (CCUS) As many countries are failing to meet the Paris agreement climate goals, it becomes more and more obvious that all available technologies must be used to curb emissions. After a period of inattention, government interest in Carbon Capture and Storage (CCS) technology has been rising since 2018 [3]. Its global progress has been monitored on a regular basis by the Global CCS Institute through the Carbon Capture and Storage (CCS) Readiness Index (CCS-RI). It comprises four sub-indicators that track all the necessary aspects of technological development: inherent interest, policy issues, regulatory and legal frameworks, and storage development [4]. Within the group of the high-scoring states, one finds the most developed states, namely Australia, Canada, Norway, the United Kingdom, and the United States. China, Denmark, Germany, Japan, and the Netherlands are well-advanced and progressing in introducing CCS [4]. The third group—moderately performing—consists of predominantly European countries. Poland scored 42 points out of 100 and was therefore added to this group [4] (Table 1). Table 1. Top 10 emissions countries versus top 10 Carbon Capture and Storage (CCS)-ready countries [4,5]. Emissions (Mt CO ) Score in the CCS Readiness Index China 9839 Canada 71 United States of America 5270 USA 70 India 2467 Norway 67 Russian Federation 1693 United Kingdom 65 Japan 1205 Australia 62 Germany 799 Netherlands 54 Iran 672 China 53 Saudi Arabia 635 Denmark 52 South Korea 616 Germany 50 Canada 573 Japan 50 Poland (21st position) 327 Poland (15th position) 42 Since the 2015 assessment, Poland’s overall score has improved. However, it still continues to remain at an average level. A closer look reveals that an increased score in the storage sub-indicator is responsible for the advance. However, Poland belongs to the group where “most of the storage potential is considered only as prospective resources”, and the country’s experience is limited [6]. Moreover, no change was noted in the policy and regulatory areas. Poland is especially ill-prepared within the former, achieving a score eight times lower than the leader of the policy indicator index, Norway (7 and 56, respectively) [7]. When the regulatory area is considered, Poland belongs to the middle of Band B, the group of countries where only some laws applicable to the CCS project cycle were introduced. The unchanged position of Poland since 2015 indicates limited legislative activity and policy development [8] (Table 2). Table 2. Poland versus Canada (the leading state) performance comparison. Poland’s Position Change Indicator Canada Poland since the 2015 Study Total 2018 score (CCS-RI) 71 42 Up CCS Storage Indicator 98 68 Up (CCS-SI) CCS Policy Indicator 40 7 No change (CCS-PI) CCS Legal and Regulatory Indicator 65.5 45 No change (CCS-LRI) CCS Inherent Interest 88 68 No change Indicator (CCS-CI) Energies 2020, 13, 2841 4 of 34 According to the most recent reports [9], the global CCS fleet consists of 51 large-scale facilities, with 19 in operation, 4 in construction, 10 in advanced development, and 18 in early development. Geographically, the majority of them are concentrated in North America (47%), followed by China (16%, majority in early development) and the UK (12%, all in early development). Current storage capacity is around 39 million tonnes of CO annually, which equals slightly more than 0.1% of global emissions. Although the overall survivability rate of CCS projects is 37%, the number of projects entering the pipeline has increased recently and exceeded the number of those exiting. It has been stressed that the pace of CCS adoption is well below of what is required to meet the Paris Agreement goal of a 2 C increase. While the building rate should reach the level of 70–100 facilities per year, the actual progress has been only one facility annually in the last decade. The report stresses that technologies for CCS are generally well-established. Therefore, there are policy changes on a monumental scale that are necessary for the successful wide-scale deployment of CCS. These include increasing the number of projects entering the pipeline and their survivability rate, as well as protecting them from short-term political changes. To stop the process of global warming and simultaneously meet climate goals, global society needs to reach and sustain net zero global anthropogenic carbon dioxide emissions. Moreover, even if the process of warming would be halted, negative emission technologies (NETs), also known as carbon dioxide removal (CDR) technologies, may still be essential to prevent further warming [10]. However, meeting the 2 C goal is practically impossible without using one of the most crucial NETs—bioenergy with carbon capture and storage (BECCS) [11]. Its crucial role comes from the fact that it allows for the double capture of carbon dioxide. Because of using biomass, which captures CO in the process of growth, BECSS seems indispensable, as CO is captured for the second time when energy is released. Afterwards, emissions are stored underground. Hence, it can mitigate emissions from other sources as well as those emissions that have already occurred [12]. Three categories of biomass input were analyzed—energy crops, forestry residues, and agricultural residues—for two major applications: large scale electricity generation and biofuel production. Technologically, the highest potential for emission reduction was found in biomass integrated gasification combined cycles (BIGCCs) and a circulating fluidized bed (CFB) [13]. However, economically, the potential of a CFB is 20 times less than that of BIGCCs [13]. Even if burned along with fossil fuels, BECCS ensures a low emission profile [12]. With direct air carbon capture and storage (DACCS), BECSS consists of two NETs with the largest overall CO removal potentials, albeit at high cost [11]. The amount of biomass that can be sustainably produced and global storage capacity can also limit the spread of BECCS [13]. Coal’s domination in the energy mix inspired Poland’s attempts to develop CCS installations. Post-combustion carbon capture was planned for the PGE Bełchatów demonstration project, which was supposed to be run in the 858 MW unit, launched in 2011. The Polish CCS project in Bełchatów, despite receiving a positive assessment from the European Investment Bank and European Commission in the first round of recruitment for the EU’s NER 300 program, was withdrawn from the competition in 2011 and canceled in 2013. Although the project could have been built with European funds, it was necessary to involve national funds to run it on an everyday basis, which was not politically feasible [14,15]. Other factors that influenced the project closure decision were high costs, insucient public acceptance, and the incomplete implementation of the CCS Directive [16]. Not much has changed since then. Although extensive performance assessments were conducted in Poland that showed the suitability of geologic settings, from a legal point of view, storage sites can only be located o shore [17]. The recent governmental assessment was that CCS installations can be competitive only when CO emission allowances will exceed EUR 50 per ton [18]. One of the main research concerns regarding BECCS is the assessment of the net negative emission status of the technology. The authors of a review paper on Integrated Assessment Models [19] addressed the main criticism regarding their application for the assessment of bioenergy with CCS. The main finding of the paper was the importance of using other models and analytical approaches to enhance the Integrated Assessment Models’ role in mitigation pathway analysis. Similarly, in [20], Energies 2020, 13, 2841 5 of 34 the authors addressed the topic of BECCS and identified research priorities and the assessment needed to accelerate the deployment of this technology. Among already widely discussed assessment priorities such as the potential of biomass supply, the authors pointed out the importance of alga biomass studies in terms of economic viability, environmental sustainability, and their inclusion in the value chain of biomass for BECCS. Regarding techno-economic studies of the BECCS, a few studies can be found that deal with an evaluation of bioenergy with CCS in di erent sectors. In [21], the authors performed such an analysis for a sugarcane mill located in Brazil. They concluded that CO capture at the analyzed plant is technically feasible and that the cost of avoided CO emissions was 62 EUR/t CO , with the 2 2 potential to decrease to 48 EUR/t CO in the case of larger plants and more ecient technologies. Authors often propose merging novel CO capture with the BECCS concept. In [22], the results of the techno-economic evaluation of BECCS via chemical looping combustion were presented. The cost of CO avoidance was estimated at 150 US$/t CO , compared with BECCS with post-combustion CO 2 2 2 capture, at around 200 US$/t CO . A similar conclusion regarding the superiority of novel CO capture 2 2 technologies (in this case, calcium looping) with BECCS over conventional absorption CO removal were also reported in [23]. 1.2. District Heating Systems in Poland In 2017, there were more than 400 heating and heating distribution companies operating in Poland [24]. The total installed capacity of heat production reaches almost 55 GW with around 240 th thousand TJ delivered to the consumers connected to a district heating system (DHS) in Poland. th Almost 54% of all heating companies operate in a DHS smaller than 50 MW . The average share of th heat produced in cogeneration is around 61%, but it should be noted that it comes mainly from large heat sources in bigger cities. Coal is a dominant fuel in the production mix for heat in Poland (72%), followed by biomass (7.4%) and natural gas (6.8%) [24]. The average price of heat in Poland is around 9 EUR/GJ and varies depending on whether the fuel is in heat-only boilers or a CHP plant (from lignite, 6.3 EUR/GJ, to coal, 8.8 EUR/GJ, and from biomass, 9.8 EUR/GJ, to light fuel oil, 15.6 EUR/GJ). In recent years, the Polish heating sector has been struggling with several obstacles of a legislative and economic nature. When large DHSs are concerned, most of them manage the upcoming challenges in an e ective and economically feasible manner. Most small DHSs (up to 50 MW ) are facing serious th challenges, both from economic and environmental points of view. About 80% of DHSs, especially small ones (from 1 to about 100 MW ), are inecient according to the Energy Eciency Directive [25], th which might result in a lack of public aid in the near future. In addition, environmental-driven investments are needed, mainly due to the Medium Combustion Plants (MCP) Directive [26], which is setting emission standards for sulphur dioxide (SO ), nitrogen oxides (NO ), and particulate matter (PM) for combustion plants with a rated thermal input of 1 to 50 MW . A change in fuel structure is th also needed, as sources with a thermal input above 20 MW participate in EU-ETS, and after 2030, th the free allowances will be gradually reduced. On the other hand, the demand for heat is decreasing as a result of the thermal modernization of buildings connected to DHSs. All of these points have led to an increase in heat production costs, which might result in the disconnection of consumers from the network and switching to individual heat sources (at the level of building complexes, single buildings, or individual apartments). Several studies have been published in the last three years regarding the challenges of small DHSs and cooperating heat sources [25–28]. As stressed in most of them, the main chances for the successful transformation of a small DHS lies in cogeneration (which could provide an additional 2–4 GW of el electricity production capacity in the system), the popularization of biomass as a fuel in heat-only boilers and CHP plants, and increases in the energy eciency of buildings (together with an increased usage of district heating for hot tap water preparation). Energies 2020, 13, 2841 6 of 34 1.3. Enhanced Geothermal Systems Classical geothermal systems are based on mature and well-known technology, enabling the exploitation of water accumulated in hydrogeothermal reservoirs. However, huge geothermal potential is present in bedrock with low permeability, low porosity, and low to medium enthalpy. Enhanced Geothermal Systems (EGSs) are unconventional geothermal systems that make it possible to utilize the geothermal energy accumulated in hot rocks characterized by insucient or little natural permeability or fluid saturation. This kind of system assumes heat extraction from underground hot dry rock (HDR) Energies 2020, 13, x FOR PEER REVIEW 6 of 34 by an artificial increase in the hydraulic performance of a geothermal reservoir and then the circulation of a working fluid into it and bringing the heated working fluid to a power plant to generate electricity geothermal reservoir and then the circulation of a working fluid into it and bringing the heated (Figure 2) [29,30]. working fluid to a power plant to generate electricity (Figure 2) [29,30]. Figure 2. Schematic of a conceptual two-well Enhanced Geothermal System (EGS) in hot dry rock Figure 2. Schematic of a conceptual two-well Enhanced Geothermal System (EGS) in hot dry rock (based (based on [31]) on [31]).. Conventionally, the only working fluid applied to EGS is water [32]. However, EGS with CO as a Conventionally, the only working fluid applied to EGS is water [32]. However, EGS with CO2 as working fluid is a very attractive option, which results from both energy and environmental benefits. a working fluid is a very attractive option, which results from both energy and environmental The advantages of this type of solution are due to the more favorable thermodynamic properties of benefits. The advantages of this type of solution are due to the more favorable thermodynamic CO compared with water, which in turn result in higher production flow rates and reduced carbon properties o 2 f CO2 compared with water, which in turn result in higher production flow rates and emissions into the atmosphere [33–35]. In this case, as the permeability and heat exchange area of the reduced carbon emissions into the atmosphere [33–35]. In this case, as the permeability and heat surrounding formation increases, the amount of CO sequestration increases too, while the rate of heat exchange area of the surrounding formation incre 2ases, the amount of CO2 sequestration increases extraction decreases slowly, which shows that the permeability of the surrounding formation has a too, while the rate of heat extraction decreases slowly, which shows that the permeability of the significant impact on CO sequestration and the heat extraction rate [36,37]. surrounding formation has 2 a significant impact on CO2 sequestration and the heat extraction rate The concept of CO -EGS was described for the first time by Brown [38]. This solution appeared as [36,37]. a response to the emerging needs to reduce carbon dioxide emissions in the world. Since then, research The concept of CO2-EGS was described for the first time by Brown [38]. This solution appeared has shown a number of advantages of this technology, the basis for which is the possibility of the as a response to the emerging needs to reduce carbon dioxide emissions in the world. Since then, geological storage of CO due to the losses of the working fluid at great depths. However, attention is research has shown a num 2 ber of advantages of this technology, the basis for which is the possibility also paid to other aspects of this solution, including high expansiveness and compressibility, low salt of the geological storage of CO2 due to the losses of the working fluid at great depths. However, solubility, favorable transport properties, and—due to strong buoyancy—low chemical activity and attention is also paid to other aspects of this solution, including high expansiveness and compressibility, low salt solubility, favorable transport properties, and—due to strong buoyancy— low chemical activity and self-propelled high flow rates [34,39–41]. For the first time in the world, the EGS has been tested in New Mexico (Fenton Hill). Research conducted since 1974 confirms that such unconventional geothermal systems can work effectively. Since that time, 18 EGS sites have been created around the world, including projects in Australia, Japan, South Korea, German, Sweden, France, Swiss, the UK, and the USA [42]. All current EGS projects use water as a working fluid. An attempt to use CO2 as a working fluid was undertaken in the Ogachi EGS site (1989–2001). The lithological reservoir was granodiorite-characterized by a temperature of more than 230 °C at a 1000 m depth. The large loss of circulating fluid was a limitation to the commercial operation of the system [42]. Currently no EGS-CO2 installation is available. The development of such projects is only at the Energies 2020, 13, 2841 7 of 34 self-propelled high flow rates [34,39–41]. For the first time in the world, the EGS has been tested in New Mexico (Fenton Hill). Research conducted since 1974 confirms that such unconventional geothermal systems can work e ectively. Since that time, 18 EGS sites have been created around the world, including projects in Australia, Japan, South Korea, German, Sweden, France, Swiss, the UK, and the USA [42]. All current EGS projects use water as a working fluid. An attempt to use CO as a working fluid was undertaken in the Ogachi EGS site (1989–2001). The lithological reservoir was granodiorite-characterized by a temperature of more than 230 C at a 1000 m depth. The large loss of circulating fluid was a limitation to the commercial operation of the system [42]. Currently no EGS-CO installation is available. The development of such projects is only at the stage of numerical simulations and laboratory tests [43–45]. However, the results of the conducted research are very promising. For a comprehensive assessment point of view, the enhanced geothermal systems face some challenges. In [29], the authors proposed a multiple-criteria decision-making approach, which takes technical, geological, economic, environmental, and social impacts into consideration. Proposed within the paper tool is a good example of actions for the support of the wider deployment of the EGS system. The selection methods for power generation in the case of a water-based EGS system have also been discussed in [46], where the authors performed an optimization analysis of single- and double-flash systems, a flash-organic Rankine cycle system, and a double-flash-organic Rankine cycle system. The main findings of the paper indicate that double-flash systems might be a better option for temperatures above 170 C, whereas a flash-organic Rankine cycle system performs better at lower temperatures. The authors of another study on this subject [30] found similar results regarding the performance of flash systems. In addition, the analyzed expansion-type system proved to have significantly higher geofluid e ectiveness than flash-type plants. 1.4. Supercritical CO Cycles The supercritical carbon dioxide (hereinafter referred to as sCO ) cycle was firstly proposed in 1950 [47] and developed in 1967. High thermal eciency and better temperature glide matching between the heat source and the working fluid are advantages of using CO in the supercritical state. It is a machine-friendly (non-corrosive and non-toxic), environmentally friendly, a ordable, and accessible working fluid that requires only moderate critical pressure [48]. Amongst the purely practical advantages are the small size of these systems and the wide application possibilities, including in the nuclear, solar, and coal-fired energy industries [47]. The sCO cycles receive much interest for applications with waste heat, where a medium to high temperature range is concerned. In [49], the conceptual designs of sCO power cycles for such applications were presented. The proposed single flow split with a dual expansion design could provide more than 40% more power compared with a baseline single recuperated cycle. In [50], the authors applied the sCO Brayton cycle at a natural gas compression station and compared the selected eciency indicators with organic Rankine cycles. In addition, as stressed by the authors, when waste heat management is concerned, it is essential to maintain the maximum levels of internal heat recovery and cost-e ectiveness. 2. Methods 2.1. Case Study Selection Within the project, for which presented analysis is part of, three scenarios of the modernization of heat sources for small (up to 50 MW ) DHSs are considered: th A reference biomass-fired CHP plant with an extraction-condensing or back-pressure turbine; A biomass-fired CHP plant with post-combustion CO capture using monoethanolamine (MEA) or calcium-looping processes and storage in saline formations; A biomass-fired CHP plant with post-combustion CO capture and CO utilization via CO -enhanced 2 2 2 geothermal systems. Energies 2020, 13, 2841 8 of 34 In this paper, the last option is investigated, viz. a biomass-fired CHP plant with an extraction- condensing turbine, MEA CO capture installation, and CO -EGS utilization. Based on the Polish 2 2 geological structure analysis and a review of small DHSs, the location in Central Poland was chosen. For the calculation of specific energy consumption for CO avoided and CO avoided cost (CAC), 2 2 the results for the reference biomass-fired CHP plant with extraction condensing and without CO capture are presented. The design of the reference plant was assumed to provide the same net electrical and heat output as the entire analyzed system. 2.1.1. District Heating System Selection The demand for heat in municipal district heating systems for the purpose of heating, ventilation, and air-conditioning varies depending on atmospheric conditions. The demand for heat calculations are based on the duration curve of the external temperature in the heating season and the heat demand for hot tap water. The analyzed DHS plant’s main parameters are taken from the available energy plan of the Koło city council [51] and other sources [52,53] and are summarized in Table 3. The analysis within the paper heating network assumes qualitative-quantitative regulations that apply to most of the municipal district heating systems in the world. Table 3. Main parameters of the Koło district heating system (DHS). Parameter Value Climatic zone (in Poland) II Lowest external temperature characteristic for given 18 C climatic zone External temperature when the heating season starts 12 C Duration of the heating season 200 days Maximum heat flux in the DHS 35,704.4 kW th Maximum heat demand for heating and ventilation 35,150 kW th in the DHS Hot tap water heat demand in the DHS 554.4 kW th Temperature of the DHS water output 150 C (at maximum heat demand) Temperature of the DHS water input 70 C (at maximum heat demand) Temperature of the DHS water 70 C/35 C (beside heating season, for hot tap water only) As presented in Table 3, the share of hot tap water in the DHS is very low. The temperatures are also rather high. All those aspects have been raised in the energy plan of the city [51], and suggestions for DHS development over the next years indicate a significant increase in the share of hot tap water in the total heat demand and lowering the DHS temperatures. Taking into account the following remarks, the theoretical DHS was proposed, with a maximum heat demand of 37 MW . For the calculations, th the DHS was divided into six zones, where the heat demand and temperatures are presented in Figure 3. The thermal load of a CHP plant meeting the needs of municipal consumers through the district heating system is characterized by a large degree of irregularity. This is denoted by a considerable ratio of the maximum to the minimum loads (for example, in Poland, the maximum/minimum ratio can reach up to 5:1). The power rating of the turbine (maximum heat production) in a CHP unit must be chosen according to the optimal coecient of the share of cogeneration, which defines the ratio of the maximum heat flux from the steam turbine (cogeneration) to the maximum demand for heat in the DHS. Based on previous research [52,54,55], an optimal coecient of the share of cogeneration of 0.6 was assumed in this analysis. Energies 2020, 13, x FOR PEER REVIEW 8 of 34 The demand for heat in municipal district heating systems for the purpose of heating, ventilation, and air-conditioning varies depending on atmospheric conditions. The demand for heat calculations are based on the duration curve of the external temperature in the heating season and the heat demand for hot tap water. The analyzed DHS plant’s main parameters are taken from the available energy plan of the Koło city council [51] and other sources [52,53] and are summarized in Table 3. The analysis within the paper heating network assumes qualitative-quantitative regulations that apply to most of the municipal district heating systems in the world. Table 3. Main parameters of the Koło district heating system (DHS). Parameter Value Climatic zone (in Poland) II Lowest external temperature characteristic for given climatic zone −18 °C External temperature when the heating season starts 12 °C Duration of the heating season 200 days Maximum heat flux in the DHS 35,704.4 kW th Maximum heat demand for heating and ventilation in the DHS 35,150 kW th Hot tap water heat demand in the DHS 554.4 kW th Temperature of the DHS water output (at maximum heat demand) 150 °C Temperature of the DHS water input (at maximum heat demand) 70 °C Temperature of the DHS water (beside heating season, for hot tap water only) 70 °C/35 °C As presented in Table 3, the share of hot tap water in the DHS is very low. The temperatures are also rather high. All those aspects have been raised in the energy plan of the city [51], and suggestions for DHS development over the next years indicate a significant increase in the share of hot tap water in the total heat demand and lowering the DHS temperatures. Taking into account the following remarks, the theoretical DHS was proposed, with a maximum heat demand of 37 MWth. For the calculations, the DHS was divided into six zones, where the heat demand and temperatures are Energies 2020, 13, 2841 9 of 34 presented in Figure 3. Figure 3. Heat demand curve in the analyzed DHS. Figure 3. Heat demand curve in the analyzed DHS. Figure 3 presents the duration curve of the demand for heat in the DHS with the area of the The thermal load of a CHP plant meeting the needs of municipal consumers through the district operation of the CHP plant and peak boilers. As the gas-fired peak boiler has a minimum operation heating system is characterized by a large degree of irregularity. This is denoted by a considerable load of 20%, the decrease in CHP load had to be taken into account. As the availability factor of the ratio of the maximum to the minimum loads (for example, in Poland, the maximum/minimum ratio CHP plant is assumed at 80%, part of the hot tap water demand (in summer months) is also covered by gas-fired boilers. 2.1.2. Geological Structure Selection The selection of the geological structure is the first and basic element of creating a CO -EGS system. So far, there is no significant experience in developing such systems, which is reflected in the diculty of defining the criteria that should be met by a selected geological structure. Sites prospective for the potential application of an EGS with CO as the working fluid (CO -EGS) 2 2 should meet the geological and hydrogeothermal conditions suitable for building EGS systems while taking into account the possibilities of the concurrent underground storage of CO . Sedimentary basins located in tectonically stable areas, with no contemporary volcanism or earthquakes, are best for this purpose [56]. The geological structure designated for underground CO storage should form a structural or stratigraphic trap, most favourably in the form of an anticline, characterized by considerable capacity. Reservoir rocks should have an appropriate porosity and permeability to ensure suitable storage capacity, should be tight, should be covered with impermeable rocks with suitable thickness, and should be located at a suitable depth so as to ensure the required pressure and capacity of the CO being injected. Rock formations designated for CO storage should be located far below any 2 2 utilized aquifers. They should be separated from them by one or several layers of impermeable insulation rocks, preventing gas from migration to potable water levels that are higher. A degree of isolation of the formations to be used for storage should be considered in relation to the system of hydrodynamic conditions in a given geological structure, trying to control CO distribution. A big role is played by the strength of insulating layers, including layer plasticity. They should be thick enough to prevent the phenomenon of fracturing and, in consequence, layer puncture as a result of excessive injection pressure. It is necessary to analyze in detail overlaying sealing beds, which requires detailed studies, tests, and trials. Geological tightness is particularly important, since storage in such structures usually requires higher pressures than hydrostatic pressure. A lack of geological tightness can occur, for instance, in tectonically involved aquifers, which eliminates a given structure for the purposes of carbon dioxide storage [57]. Currently, there is a technological possibility of drilling wells even at depths exceeding 4 km as well as fracturing technology in order to achieve the hydraulic connection between injection and Energies 2020, 13, 2841 10 of 34 production boreholes [58]. Therefore, the most suitable rock for EGSs should be characterized by low porosity and permeability values and possibly a high heat flow reflected in a high reservoir temperature. Reservoir rock parameters and sealing rock parameters are both important. In this case, high permeability values may cause an uncontrolled escape of the injected fluid. Poland is located within three main European geostructural units: the Precambrian East European Platform in the east, which is a large and flat area covered by sediments; the Paleozoic Platform, which comprises the southwestern half of the Polish territory; and the Carpathians, which is a part of the Alpine–Himalayan system in the south. This geostructural position influences the development of the thermal and geological conditions. Most of Poland is covered by sedimentary rocks (Polish Lowlands, Carpathians, and Carpathian Foredeep). The only exception is the Sudetes region (SW part of Poland), where crystalline rocks occur [59]. Energies 2020, 13, x FOR PEER REVIEW 10 of 34 Geothermal installations currently operating in the area of the Polish Lowlands utilize successfully a key premise to treat these reservoirs only as geothermal reservoirs. The situation is different in the waters from the Lower Cretaceous and Lower Jurassic reservoirs [60] (Figure 4). It is thus a key premise case of a Lower Triassic reservoir. All studies conducted so far [61,62] point out the rather poor water to treat these reservoirs only as geothermal reservoirs. The situation is di erent in the case of a Lower content in this reservoir and the low potential for building conventional geothermal installations. Triassic reservoir. All studies conducted so far [61,62] point out the rather poor water content in this Although a EGS geothermal system with a location in a zone of sedimentary rock occurrence shows reservoir and the low potential for building conventional geothermal installations. Although a EGS slightly poorer thermal parameters than systems in crystalline or magma rocks, from the point of geothermal system with a location in a zone of sedimentary rock occurrence shows slightly poorer thermal view of CO2 sequestration, the best solution is to select sedimentation basins located in tectonically parameters than systems in crystalline or magma rocks, from the point of view of CO sequestration, stable areas, which is proven by the above-shown criteria. Due to the depth and expected thermal the best solution is to select sedimentation basins located in tectonically stable areas, which is proven by and petrophysical parameters of Lower Triassic formations, the Krośniewice-Kutno area (Central the above-shown criteria. Due to the depth and expected thermal and petrophysical parameters of Lower Poland) was chosen as an optimum location (Figure 4). In this area, the most prospective horizon for Triassic formations, the Kros ´niewice-Kutno area (Central Poland) was chosen as an optimum location an EGS location is the clastic deposits of the Lower Triassic. The top of the reservoir of more than (Figure 4). In this area, the most prospective horizon for an EGS location is the clastic deposits of the 1000 m thick is behind at depths 5000–5500 m below sea level, and the temperature within the Lower Triassic. The top of the reservoir of more than 1000 m thick is behind at depths 5000–5500 m reservoir is in the range 165–195 °C. The porosity of the reservoir rocks is approximately 2.5%, while below sea level, and the temperature within the reservoir is in the range 165–195 C. The porosity of the permeability is about 0.1 mD [61,63–66]. the reservoir rocks is approximately 2.5%, while the permeability is about 0.1 mD [61,63–66]. Figure 4. Location of the research area together with the predicted geological profile of Krośniewice Figure 4. Location of the research area together with the predicted geological profile of Krosniewice ´ IG-1. IG-1. The estimation of the amount of CO2 that will be permanently bound in the geological structure is a very challenging task. Nevertheless, it can be assumed that this amount will depend on parameters such as the area of major flow paths and the contact area between the fluid and the fractures, the shape of the fractures and their hydraulic connectivity, the porosity and permeability of the geological formation, the reservoir pressure and background pore pressure, the reservoir temperature, the degree of pore saturation with individual fluids, pore fluid phases, and time [62]. The mineralogical composition of the reservoir rocks and the chemical composition of the primary pore fluid will also play important roles in the context of solubility and mineral trapping. It is estimated that, for the long-term operation of EGS installations with CO2 as a working medium, the amount of stored CO2 is in the order of 5% [34]. However, for different reservoir conditions, the amount of CO2 stored may be different, such as in the case of the geothermal field in Habanero (Australia), where this value seems to be much overestimated [63]. A more precise and site-specific estimation of the amount of CO2 to be stored in the enhanced geothermal reservoir can Energies 2020, 13, 2841 11 of 34 The estimation of the amount of CO that will be permanently bound in the geological structure is a very challenging task. Nevertheless, it can be assumed that this amount will depend on parameters such as the area of major flow paths and the contact area between the fluid and the fractures, the shape of the fractures and their hydraulic connectivity, the porosity and permeability of the geological formation, the reservoir pressure and background pore pressure, the reservoir temperature, the degree of pore saturation with individual fluids, pore fluid phases, and time [62]. The mineralogical composition of the reservoir rocks and the chemical composition of the primary pore fluid will also play important roles in the context of solubility and mineral trapping. It is estimated that, for the long-term operation of EGS installations with CO as a working medium, the amount of stored CO is in the order of 5% [34]. However, for di erent reservoir conditions, the amount of CO stored may be di erent, such as in the case of the geothermal field in Habanero (Australia), where this value seems to be much overestimated [63]. A more precise and site-specific estimation of the amount of CO to be stored in the enhanced geothermal reservoir can be achieved with the aid of a numerical simulator coupling heat and mass transport with the reactive Energies 2020, 13, x FOR PEER REVIEW 11 of 34 geochemistry of fluid–rock interactions [63]. be achieved with the aid of a numerical simulator coupling heat and mass transport with the reactive 2.2. Process geochemistry of Synthesis and fluid Design –rock interactions [63]. The goal of this paper was to model (including the o -design operation) and analyze the full 2.2. Process Synthesis and Design chain of the proposed technology. Thus, the mathematical models of the CO -EGS (developed in The goal of this paper was to model (including the off-design operation) and analyze the full VBA Excel) and the integrated biomass-fired CHP plant with CO capture (developed in IPSE Pro) chain of the proposed technology. Thus, the mathematical models of the CO2-EGS (developed in VBA Excel) and the integrated biomass-fired CHP plant with CO2 capture (developed in IPSE Pro) were were developed and combined through PSE Excel (a dedicated tool for Excel and IPSE Pro model developed and combined through PSE Excel (a dedicated tool for Excel and IPSE Pro model combinations). A simplified diagram of the analyzed system is presented in Figure 5. combinations). A simplified diagram of the analyzed system is presented in Figure 5. Figure 5. Simplified diagram of a CHP unit with an extraction-condensing turbine, a CO2 capture and Figure 5. Simplified diagram of a CHP unit with an extraction-condensing turbine, a CO capture and compression unit, and a CO2-enhanced geothermal system with a supercritical CO2 (sCO2) Brayton compression unit, and a CO -enhanced geothermal system with a supercritical CO (sCO ) Brayton cycle 2 2 2 cycle (T: turbine; GC: gas cooler; AF: air fan; G: generator; COM: compressor; REB: reboiler; STR: (T: turbine; stripper; AB GC: gas S: cooler; absorber; ES AF: air P: electrostatic pr fan; G: generator; ecipitatorCOM: ; BHE: bcompr ase heat e essor; xchang REB: er; RHrE eboiler; : regeneraSTR: tive stripper; heat exchanger; FCT: force-draft cooling tower; CON: condenser; DEA: deaerator; PB: peak boiler; ABS: absorber; ESP: electrostatic precipitator; BHE: base heat exchanger; RHE: regenerative heat SNCR: elective non-catalytic reduction). exchanger; FCT: force-draft cooling tower; CON: condenser; DEA: deaerator; PB: peak boiler; SNCR: elective non-catalytic reduction). In general, the analyzed system can be divided into four main subsystems: (i) a biomass-fired combined heat and power plant integrated with (ii) a CO2 capture and compression unit, (iii) a CO2 transport pipeline, and (iv) a CO2-enhanced geothermal system comprising a geological reservoir and an sCO2 Brayton power cycle. The heat demand in the DHS is covered by the steam extracted from the turbine and the waste heat coming from the CO2 capture and compression unit (mainly the interstage cooling of the CO2 compressors). The cooling duty for the steam condenser in the CHP plant and the CO2 capture and compression unit is achieved by the forced-draft cooling tower. The flue gases after conditioning are directed to the absorber, where CO2 is captured in an amine solution and then released in the stripper. The MEA regeneration is done in the reboiler, where the heat is provided from the steam turbine bleeding. Captured CO2 is then compressed and transported via the Energies 2020, 13, 2841 12 of 34 In general, the analyzed system can be divided into four main subsystems: (i) a biomass-fired combined heat and power plant integrated with (ii) a CO capture and compression unit, (iii) a CO 2 2 transport pipeline, and (iv) a CO -enhanced geothermal system comprising a geological reservoir and an sCO Brayton power cycle. The heat demand in the DHS is covered by the steam extracted from the turbine and the waste heat coming from the CO capture and compression unit (mainly the interstage cooling of the CO compressors). The cooling duty for the steam condenser in the CHP plant and the CO capture and compression unit is achieved by the forced-draft cooling tower. The flue gases after conditioning are directed to the absorber, where CO is captured in an amine solution and then released in the stripper. The MEA regeneration is done in the reboiler, where the heat is provided from the steam turbine bleeding. Captured CO is then compressed and transported via the CO pipeline 2 2 to the storage (utilization) site. Due to the small range of the CO transport (50 km), the rebooster station is not included. The CO stream at the EGS site coming from the pipeline is mixed with the circulating stream of sCO and injected into the fractured EGS zone, where it heats up. Part of the injected CO is sequestrated in the EGS zone (5%), and the rest is directed to the sCO turbine. After the 2 2 turbine, the CO is cooled in the gas cooler to the desired temperature. Due to the thermosiphon e ect, no additional CO compression is needed, as the pressure outlet from the turbine is chosen to utilize the positive pressure di erence between the injection and production wells. The amount of CO coming from the CO capture unit is assumed to be the same as the amount of CO sequestered, 2 2 2 allowing the system to operate constantly. 2.2.1. Analytical Model of the CO -Fed Enhanced Geothermal System (CO -EGS) in the Krosniewice- ´ 2 2 Kutno Area Analytical models can be an alternative to detailed 3D numerical models when it is necessary to quickly estimate geothermal reservoir exploitation parameters. As some authors have pointed out [67–69], the 1D and 2D analytical models can often provide a good approximation for more detailed 3D models. Using this approach, a steady-state analytical model of single-channel flow in the EGS reservoir was developed. The model simulates the injection of sCO into the fractured zone of the originally low-permeable rock formation, the 1D flow between the injection and production boreholes, and the CO extraction using the production well (Figure 6). The assumptions of this model also include laminar (Darcy) flow in the reservoir and turbulent flow in both wells. The temperature of the injected fluid is assumed to linearly increase from the injection zone, to reach a natural reservoir temperature at the feed zone of the production well. The extraction of CO , the carrier of geothermal heat, can be accomplished either using down-hole pumps or spontaneously, thanks to the thermosiphon e ect (similar to the artesian outflow in water wells). Contrary to models developed earlier [66,68,69], the one used here accounts for the heat transfer between CO , the wells’ casings, and the surrounding rocks. A list of the governing equations in this model is given in Appendix A. The simulation of the CO injection into the Lower Triassic sandstones in the Krosniewice-Kutno ´ area was performed for hundreds of di erent scenarios, in which the thermosiphon e ect usually occurs. The two factors that a ect the pressure di erence between the production and injection wellheads (thermosiphon) the most are the fractured zone permeability and the working fluid (CO ) mass flow rate. For a given mass flow rate and with other parameters kept constant, permeability controls the pressure distribution in the reservoir, a ecting the value of thermosiphon (Figure 7). At a certain value of EGS reservoir permeability, a break-even point is reached, and a further increase in permeability does not significantly a ect the pressure di erence between the production and injection borehole wellheads. What is worth noticing is the fact that, at high reservoir permeability, the thermosiphon process approaches a certain value, regardless of the mass flow rate. As the model couples reservoir and wellbore processes, these results imply that a reservoir pressure drop has a more profound e ect than a pressure drop in the wellbore. Energies 2020, 13, x FOR PEER REVIEW 12 of 34 CO2 pipeline to the storage (utilization) site. Due to the small range of the CO2 transport (50 km), the rebooster station is not included. The CO2 stream at the EGS site coming from the pipeline is mixed with the circulating stream of sCO2 and injected into the fractured EGS zone, where it heats up. Part of the injected CO2 is sequestrated in the EGS zone (5%), and the rest is directed to the sCO2 turbine. After the turbine, the CO2 is cooled in the gas cooler to the desired temperature. Due to the thermosiphon effect, no additional CO2 compression is needed, as the pressure outlet from the turbine is chosen to utilize the positive pressure difference between the injection and production wells. The amount of CO2 coming from the CO2 capture unit is assumed to be the same as the amount of CO2 sequestered, allowing the system to operate constantly. 2.2.1. Analytical Model of the CO2-Fed Enhanced Geothermal System (CO2-EGS) in the Krośniewice-Kutno Area Analytical models can be an alternative to detailed 3D numerical models when it is necessary to quickly estimate geothermal reservoir exploitation parameters. As some authors have pointed out [67–69], the 1D and 2D analytical models can often provide a good approximation for more detailed 3D models. Using this approach, a steady-state analytical model of single-channel flow in the EGS reservoir was developed. The model simulates the injection of sCO2 into the fractured zone of the originally low-permeable rock formation, the 1D flow between the injection and production boreholes, and the CO2 extraction using the production well (Figure 6). The assumptions of this model also include laminar (Darcy) flow in the reservoir and turbulent flow in both wells. The temperature of the injected fluid is assumed to linearly increase from the injection zone, to reach a natural reservoir temperature at the feed zone of the production well. The extraction of CO2, the carrier of geothermal heat, can be accomplished either using down-hole pumps or spontaneously, thanks to the thermosiphon effect (similar to the artesian outflow in water wells). Contrary to models developed earlier [66,68,69], the one used here accounts for the heat transfer between CO2, the wells’ casings, Energies 2020, 13, 2841 13 of 34 and the surrounding rocks. A list of the governing equations in this model is given in Appendix A. Energies 2020, 13, x FOR PEER REVIEW 13 of 34 a certain value of EGS reservoir permeability, a break-even point is reached, and a further increase in permeability does not significantly affect the pressure difference between the production and injection borehole wellheads. What is worth noticing is the fact that, at high reservoir permeability, the thermosiphon process approaches a certain value, regardless of the mass flow rate. As the model couples reservoir and wellbore processes, these results imply that a reservoir pressure drop has a more profound effect than a pressure drop in the wellbore. Figure Figure 6. 6. Schematic Schematic drawing drawing of of the thesingle-ch single-channel annel EG EGS S momodel. del. The simulation of the CO2 injection into the Lower Triassic sandstones in the Krośniewice-Kutno area was performed for hundreds of different scenarios, in which the thermosiphon effect usually occurs. The two factors that affect the pressure difference between the production and injection wellheads (thermosiphon) the most are the fractured zone permeability and the working fluid (CO2) mass flow rate. For a given mass flow rate and with other parameters kept constant, permeability controls the pressure distribution in the reservoir, affecting the value of thermosiphon (Figure 7). At Figure 7. The impact of fractured zone permeability on the thermosiphon e ect for simulated operating Figure 7. The impact of fractured zone permeability on the thermosiphon effect for simulated conditions operating in t conditions he Krosniewice–Kutn ´ in the Krośo niewice– area (rKutno area (reservoir eservoir temperature: temp 170erature: 170 °C; reinjection C; reinjection temperature: temperature: 35 °C; well depth: 5600 m b.g.l.; wells’ separation distance: 600 m; wells casing 35 C; well depth: 5600 m b.g.l.; wells’ separation distance: 600 m; wells casing roughness: 0.04 mm; roughness: 0.04 mm; CO2 sequestration rate: 5%). CO sequestration rate: 5%). 2.2.2. 2. The 2.2. The CHP CPlant HP Plwith ant wiCO th CO Captur 2 Capture and sCO e and sCO 2 Br Brayton ayton Cycle Cycle 2 2 Based on the analyses concerning the optimal coefficient of the share of cogeneration in DHSs Based on the analyses concerning the optimal coecient of the share of cogeneration in DHSs [54] [54] and available data concerning Polish DHSs [24], the coefficient of the share of cogeneration for and available data concerning Polish DHSs [24], the coecient of the share of cogeneration for the the analyzed referenced biomass-fired CHP plant is assumed as 0.60, which corresponds to the analyzed referenced biomass-fired CHP plant is assumed as 0.60, which corresponds to the maximum maximum heat flux for the CHP plant equal to ca. 22.2 MWth. In order to meet the maximum heat heat flux for the CHP plant equal to ca. 22.2 MW . In order to meet the maximum heat demand, th demand, the peak boilers have to be taken into account (gas-fired units are assumed). The analyzed the peak boilers have to be taken into account (gas-fired units are assumed). The analyzed plant plant uses a stoker-fired boiler, which burns wood chips with a high moisture content (the LHVar was uses a stoker-fired boiler, which burns wood chips with a high moisture content (the LHV was ar around 9534 kJ/kg). Primary steam (53 bar/480 °C) is generated in the boiler and then enters the steam around 9534 kJ/kg). Primary steam (53 bar/480 C) is generated in the boiler and then enters the steam turbine. Steam is extracted at low pressure supplying the regeneration system, which consists of a regenerative heat exchanger preheating the condensate prior to feeding it to the deaerator. turbine. Steam is extracted at low pressure supplying the regeneration system, which consists of a Feedwater, after removing oxygen and other dissolved gasses, is pumped into the boiler to repeat the regenerative heat exchanger preheating the condensate prior to feeding it to the deaerator. Feedwater, cycle. The outlet steam (0.04 bar) goes to the heat condenser. Base heat exchangers cover the basic after removing oxygen and other dissolved gasses, is pumped into the boiler to repeat the cycle. heat demand, resulting from the characteristics of the district heating network, and are supplied with the steam extracted at intermediate pressure (1.9 bar). Part of the heat for the DHS is supplied from the interstage cooling of the CO2 compressors. The same heat extraction from the steam turbine is also used to feed the deaerator after the pressure-reduction valve. The peak heat demand is covered by the gas-fired boilers. The CHP is equipped with the forced draft cooling tower that provides the cooling duty for the condenser, CO2 capture installation, and the interstage cooling of the CO2 compressors. Flue gases from the pulverized biomass boiler are fed into the flue gas conditioning system with selective non-catalytic reduction and an electrostatic precipitator. Due to the low sulphur content in the fuel, the desulphurization system is neglected. Energies 2020, 13, 2841 14 of 34 The outlet steam (0.04 bar) goes to the heat condenser. Base heat exchangers cover the basic heat demand, resulting from the characteristics of the district heating network, and are supplied with the steam extracted at intermediate pressure (1.9 bar). Part of the heat for the DHS is supplied from the interstage cooling of the CO compressors. The same heat extraction from the steam turbine is also used to feed the deaerator after the pressure-reduction valve. The peak heat demand is covered by the gas-fired boilers. The CHP is equipped with the forced draft cooling tower that provides the cooling duty for the condenser, CO capture installation, and the interstage cooling of the CO compressors. 2 2 Flue gases from the pulverized biomass boiler are fed into the flue gas conditioning system with selective non-catalytic reduction and an electrostatic precipitator. Due to the low sulphur content in the fuel, the desulphurization system is neglected. Furthermore, the flue gases are directed to the MEA CO capture installation, where the CO is 2 2 captured from flue gases. A CO capture eciency of 90% and a high purity (99.5%) are assumed. The unit heat consumption is calculated based on the approach presented in [70] and is around 3.36 MJ/kg CO . The saturated steam for the regeneration of the solvent is provided by the extraction of the steam turbine (2.75 bar). Furthermore, the captured CO is directed to the CO compression train, 2 2 which comprises five CO compressors with interstage cooling (to 30 C) and a pump that compresses the CO to 130 bar. The CO is transported via a pipeline for 50 km to the utilization site, where it is 2 2 compressed to the required pressure of the injection well. It was assumed that 5% of the circulating CO is sequestrated, which results in ca. 150 kg/s of CO being constantly injected into the geological 2 2 reservoir. Due to the e ect of CO thermosiphon, there is no need to add the sCO compressor for the 2 2 remaining mass flow. After the turbine, the sCO is cooled down in a gas cooler and is directed to the mixer and then to the injection well. The turbine pressure outlet is determined by the required pressure at the inlet of the injection well plus the pressure loss in the gas cooler [66]. The detailed results regarding the energy performance of the CHP plant, CO capture installation, the geological reservoir, and the sCO cycle can be found in the previous papers of the authors [55,66,71]. 2.3. Thermodynamic Assessment For the purpose of the analysis, the gross and net biomass energy utilization factors (BEUFs) and electrical eciencies (BEEEs) have been defined as follows, respectively: E + Q el DHS = (1) BEUF ch,bio el = (2) BEEE ch,bio where E is the annual electricity production of the system, Q is the annual heat production for the el DHS DHS, and E is the annual chemical energy of the biomass. ch,bio As presented in Equations (1) and (2), the geothermal energy coming from the hot dry rocks is neglected, as the utilization of the geothermal energy is a by-product of the CO storage. On the other hand, the electricity production in the sCO cycle is included in the annual electricity production. The same approach was applied for the calculations of specific energy consumption for CO avoided (SPECCA), where only the biomass chemical energy is considered. 2.4. Economic Assessment Within the economic assessment of the proposed system, both the Levelized Cost of Electricity (LCOE) and that of Heat (LCOH) are calculated. In addition, the Net Present Value (NPV) analysis is performed, including the Break-Even Points (BEP) of negative CO emission credits, electricity, and heat. Both the LCOE and LCOH are aggregated indicators of the costs of the whole process during the system’s assumed lifetime. They comprised total investment costs, operational costs (both fixed Energies 2020, 13, 2841 15 of 34 and variable), and the obtained electricity or heat production. In this study, the LCOE and LCOH are defined as follows: "  (TSC f + OPEX ) B,el a i i LCOE = (3) el ( ) "  TSC f + OPEX B,Q a i LCOH = (4) where TSC is the Total System Cost (EUR), f is the discount factor, and OPEX is the sum of the variable and fixed operational costs. " and " are the total system cost multipliers, which B,el B,Q in accordance with the assumed exergy allocation methodology [72] allow the specific costs to be assigned to electricity and heat production. The calculation of the total system cost multipliers relies on the exergy allocation methodology, which takes into account the exergy of useful products in multi-generation processes. For the analyzed system, they take the values of 0.89 and 0.11 for electricity and heat, respectively, and are calculated as follows: el " =   (5) B,el T T 7008 m,i 0 E + Q el DHS,i i=1 T m,i where T is the logarithmic mean temperature di erence in the DHS, T is the reference temperature, m 0 and " can be calculated as 1 " . B,Q B,el Furthermore, within the economic assessment of the proposed systems, the NPV was proposed to incorporate all the sources of potential income (e.g., the negative CO emission credits). The NPV is calculated based on the following formula: CF NPV = TSC (6) (1 + r) =0 where for  1, the cash flow (CF ) is defined as CF = E  c + Q c + G  c OPEX TAX (7) el el DHS CO2 CO2,NEC i where c , c , and c are the prices of electricity, district heat, and negative CO emission el DHS CO2,NEC 2 credits; r is the discount rate; and TAX is the income tax. The CAC is calculated using the “net present value” method [73], due to the multiple products of the analyzed system (heat and electricity). Necessary assumptions for the validity of the method have been considered, viz. the same net electricity and heat production for the analyzed system with CCS and the reference one. Thus, the CAC is calculated as follows [73]: NPV NPV CCS re f CAC = (8) P G P n CO2,re f n CO2,CCS =0 =0 (1+r) (1+r) where G is the annual CO emissions into the atmosphere. CO2 2 In addition to the CAC, the CO negative emission cost (CNC) is proposed, which is defined as follows: NPV NPV CCS re f CNC = (9) CO2,neg =0 (1+r) where G is the annual negative CO emissions in the analyzed CCS system. CO2,neg 2 Energies 2020, 13, 2841 16 of 34 2.4.1. Methodology for Investment Cost Estimation For each component of the analyzed system, the cost was estimated according to a bottom-up approach where the plants’ (the CHP plant, the CO capture and compression unit, and the sCO 2 2 power plant) costs were broken down. This allowed for an estimation of the Total System Cost (TSC), which is the sum of the total cost of the subsystems. Each subsystem’s total cost was calculated as the Total Equipment Cost (TEC) of the included components and the direct and indirect costs (labor, engineering, integration, etc.). Thus, the TSC of the analyzed system can be defined as follows: 8 9 2 3 > > > > X X 6  7 > > 6 7 < = 6 7 6 7 TSC = > 1 + i + i  1 + i  TEC > + TSC + TSC (10) LC, j E&PC, j 6 P&C, j i, j7 EGS pipeline > > 4 5 > > : ; j i where i is the labor cost indicator, i is the engineering and project cost indicator, and i is the LC E&PC P&C piping and integration cost indicator. The methodology of the TEC calculations for the machinery and equipment, as well as the TSC for the CO transport pipeline and the enhanced geothermal system, is presented in Appendix B. The TEC of the CHP plant components was estimated based on [74]. The TEC estimation of the CO capture and compression unit follows the guidelines presented in [70] and the reference values obtained from [75]. The TEC of the sCO cycle components was estimated based on [76], and the auxiliary equipment’s TEC was estimated based on [77]. For the CO pipeline, the total subsystem cost was taken from [78], and the data regarding Polish geological locations, for the development of the EGS system, were assumed based on [79]. The formulas presented in Appendix B were adopted, by means of the Chemical Engineering Cost Index [80] and the EUR/USD exchange rates, to EUR in 2017 from their origin years and currencies. In Table 4, a list of all the equipment that was part of the Total Equipment Cost assessment is presented, taking into account the proposed methods and division into subsystems (Figure 5). The methods for cost calculations are presented in Appendix B. Table 4. List of equipment considered in the investment cost assessment (MEA: monoethanolamine; sCO : supercritical CO ). 2 2 Subsystem Equipment and Costs biomass receiving and preparation infrastructure biomass grate boiler extraction-condensing steam turbine condenser main heat exchanger (for DHS) regenerative heat exchangers Biomass-fired CHP plant deaerator air fan and flue gas blower with electric motor pumps with electric motor electrical generator force-draft cooling tower steam extraction (for MEA regeneration) direct contact cooler absorber and regenerator (stripper) rich/lean regenerative heat exchanger reboiler CO capture and compression unit MEA reclaimer solvent processing area flue gas blower with electric motor CO drying and compression unit (as whole) 2 Energies 2020, 13, 2841 17 of 34 Table 4. Cont. Subsystem Equipment and Costs 50 km CO pipeline (as whole) CO transport 2 sCO turbine sCO heat exchanger (gas cooler) air fan with electric motor CO -enhanced geothermal system electrical generator wells and casting well drilling and EGS zone stimulation 2.4.2. Financial Assumptions and Scenario Definition Three scenarios were proposed for analysis within the economic assessment: Business as usual, based on the current market in Poland; The investment subsidy scenario, where 50% of the investment cost is subsidized by the state (which is a common practice in relation to biomass CHP plants and geothermal installations [79]); Technological development, where a 30% decrease in the total systems cost occurs (e.g., due to the technological development in the field of CO capture or sCO cycle construction—first of a kind 2 2 vs. nth of a kind). In Table 5, a summary of financial assumptions is presented for all three analyzed scenarios. In addition, a tax rate of 19% is assumed, together with a 5% depreciation charge for equipment and machinery. The year-by-year changes in heat demand or the parameters of CO -EGS were neglected in the study. Table 5. Summary of financial assumptions. Technological Parameter/Scenario Business as Usual Investment Subsidy Scenario Development Location basis Central Poland Cost year basis 2017 Base currency used EUR (Euro) Investment lifetime 30 years Capacity factor 80% (7008 h per year) Discount rate 10% 8% 8% Investment cost according to Equation (3) 30% Subsidies (state grant) 0% 50% 0% Fuel (biomass) cost 6 EUR/GJ OPEX cost: Biomass-fired CHP plant 3.2% of CAPEX CO capture and compression unit 2.5% of CAPEX CO transport pipeline 0.1% of CAPEX EGS wells 0.1% of CAPEX sCO power plant 3.0% of CAPEX Electricity price 100 EUR/MWh 50 EUR/MWh 100 EUR/MWh Heat price 10 EUR/GJ CO credit (negative emission credit) * 20 EUR/t CO 2 2 * CO credit for negative emissions was assumed as the equivalent of the EU-ETS emission allowance. Regarding the assumption in each scenario (Table 4), the discount rate decrease by 2 percentage points in the subsidy and technological development scenario is mainly due to a lower project risk. The electricity price in the subsidy scenario decreases to average market prices in Poland, as state support for the investment cost is assumed. In other scenarios, the RES support scheme deployed in Poland was taken into account, which predicts a maximum price of 440 PLN/MWh (ca. 105 EUR/MWh) Energies 2020, 13, 2841 18 of 34 for the biomass-based and geothermal electricity production. In the current legal system in Poland, a feed-in tari for electricity and subsidy grants for investment costs exclude each other to a large degree due to the legal regulations that state that if an investment grant is higher than the total feed-in tari subsidy (over 15 years) for electricity, then further state support cannot be granted. 3. Results 3.1. Energy Balance In Table 6, a summary of results regarding the annual operation of the analyzed system is presented. Table 6. Summary of the energy and environmental analysis. Parameter Analyzed System * Reference CHP Plant Gross electricity production: in a steam turbine generator 130,157.1 MWh/a 121,372.8 MWh/a in an sCO Brayton turbine generator 23,102.8 MWh/a - Electricity own consumption: in a CHP plant 6157.3 MWh/a 4758.2 MWh/a in a CO capture and compression unit 27,470.3 MWh/a - in an sCO Brayton cycle 3017.7 MWh/a - Net Electricity Production of the System 116,614.6 MWh/a Heat Production to DHS (Total), incl.: 371.3 TJ /a th steam turbine extraction 283.6 TJ /a 371.3 TJ /a th th interstage cooling of CO compressors 87.7 TJ /a - 2 th Heat production for MEA regeneration 697.6 TJ /a - th Energy input, incl.: chemical energy of biomass 2124.6 TJ /a 1674.8 TJ /a LHV LHV heat extracted from geological reservoir 838.7 TJ/a - CO Sequestrated (Removed) 207,276.9 t CO /a 0 t CO /a 2 2 2 Biomass energy utilization factor (Equation (1)): gross (annual average) 43.45% 48.26% net (annual average) 37.24% 47.24% Electrical eciency (Equation (2)): gross (annual average) 25.97% 26.09% net (annual average) 19.76% 25.07% Gross power to heat ratio of the CHP plant 0.48 1.18 * including a biomass-fired CHP plant, CO capture and compression installation, and a CO -enhanced geothermal 2 2 system with an sCO Brayton power cycle. In Table 6, the presented results indicate that the average biomass energy eciency (BEUF) is rather low, which is the result of the significant heat demand in the CO capture installation. For the BEUF net eciency, the decrease in comparison with the reference plant for this study is of 10 percentage points. The electrical eciencies of the analyzed system are also lower than those in the literature (e.g., a 28.2% net annual average in [81] for medium—80 MW feed—wood chip CHP with a power-to-heat ratio of ch 1), but the decrease in the net electricity eciency in comparison with the reference CHP plant without CO capture and utilization in this study is only 5.3 percentage points. It should also be noted that, to keep the same heat and net electrical production, the power-to-heat ratio of the CHP plant changes significantly (from 1.18 in the reference case to 0.48 in the analyzed system), which also strongly a ects the technical design of the steam cycle. If geothermal energy would be included in the eciency calculations, then the net energy utilization factor would be 26.7% and the net electrical eciency would be 14.2%. The negative CO emissions of 97.56 t CO /TJ are similar to those obtained in the 2 2 ch case of CHP plants with a calcium-looping CO capture [23]. In Figure 8, the annual electricity balance of the analyzed system is presented. It should be noted that the sCO cycle net electricity generation compensates around 73% of the electricity consumption 2 Energies 2020, 13, 2841 19 of 34 Energies 2020, 13, x FOR PEER REVIEW 19 of 34 in the CO capture and compression unit. Thus, from the energy point of view, the CO utilization in 2 2 EGS instead of conventional storage in saline formations (which would actually require additional electricity, e.g., for brine management [82]) is more favorable. Energies 2020, 13, x FOR PEER REVIEW 19 of 34 Figure 8. Annual electricity balance of the analyzed system. Figure 8. Annual electricity balance of the analyzed system. Figure 8. Annual electricity balance of the analyzed system. The SPECCA for the analyzed system, compared to that for the reference CHP plant (biomass- The SPECCA for the analyzed system, compared to that for the reference CHP plant (biomass- fired without CCS), is 2.17 MJLHV/kg CO2. When the specific energy consumption for CO2 avoided The SPECCA for the analyzed system, compared to that for the reference CHP plant (biomass-fired fired without CCS), is 2.17 MJLHV/kg CO2. When the specific energy consumption for CO2 avoided includes the geothermal energy, the value increases significantly to 6.22 MJ/kg CO2. The obtained without CCS), is 2.17 MJ /kg CO . When the specific energy consumption for CO avoided includes LHV 2 2 includes the geothermal energy, the value increases significantly to 6.22 MJ/kg CO2. The obtained values of SPECCA, which takes into account only the chemical energy of biomass, can be considered the geothermal energy, the value increases significantly to 6.22 MJ/kg CO . The obtained values of SPECCA, values of SPECCA, which takes into account only the chemical energy of biomass, can be considered as very low, compared to those for other CO2 capture technologies (e.g., for MEA, the base case is as very low, compared to those for other CO2 capture technologies (e.g., for MEA, the base case is which takes into account only the chemical energy of biomass, can be considered as very low, compared to 3.34 MJLHV/kg CO2 in [3]). This is a direct result of the heat integration between the CO2 capture and 3.34 MJLHV/kg CO2 in [3]). This is a direct result of the heat integration between the CO2 capture and those for other CO capture technologies (e.g., for MEA, the base case is 3.34 MJ /kg CO in [3]). This is a 2 LHV 2 compression unit and the DHS, as well as the partial compensation of the electricity consumption for compression unit and the DHS, as well as the partial compensation of the electricity consumption for direct result of the heat integration between the CO capture and compression unit and the DHS, as well CO2 compression in the sCO2 power cycle. The system that excludes the CO2-EGS and assumes CO2 compression in the sCO2 power cycle. The system that excludes the CO2-EGS and assumes as the partial compensation of the electricity consumption for CO compression in the sCO power cycle. conventional CO2 storage, the SPECCA is equal to 3.41 MJLHV/kg CO2, and is comparable with the 2 2 conventional CO2 storage, the SPECCA is equal to 3.41 MJLHV/kg CO2, and is comparable with the values from [83] for analyzed CO2 capture technology. The system that excludes the CO -EGS and assumes conventional CO storage, the SPECCA is equal to 2 2 values from [83] for analyzed CO2 capture technology. In Figure 9, the energy balance of the analyzed system is presented, showing the main heat losses 3.41 MJ /kg CO , and is comparable with the values from [83] for analyzed CO capture technology. LHV 2 2 In Figure (cooling 9, the ener duty), the he gy b at lo alance of the ad (both for th an e DH alyzed S and sy M stem EA r e is pr gener esented, ation proce showing ss heat), the and el main ectricit heat y losses In Figure 9, the energy balance of the analyzed system is presented, showing the main heat losses production and consumption. As shown, the main cooling duty is associated with the sCO2 cycle, (cooling duty), the heat load (both for the DHS and MEA regeneration process heat), and electricity (cooling duty), the heat load (both for the DHS and MEA regeneration process heat), and electricity where the excess heat is rejected to the environment. It should be noted that rejected heat in the sCO2 production and consumption. As shown, the main cooling duty is associated with the sCO2 cycle, cycle has high parameters (around 110 °C), which means that it could be utilized if possible. It can be production and consumption. As shown, the main cooling duty is associated with the sCO cycle, where where the excess heat is rejected to the environment. It should be noted that rejected heat in the sCO2 also noted that a significant amount of heat is used for MEA regeneration in the CO2 capture unit, the excess heat is rejected to the environment. It should be noted that rejected heat in the sCO cycle has cycle has high parameters (around 110 °C), which means that it could be utilized if possible. It can be which leads to almost a triplication of the overall heat production in the system compared with the high parameters (around 110 C), which means that it could be utilized if possible. It can be also noted also noted that a significant amount of heat is used for MEA regeneration in the CO2 capture unit, reference plant. that a significant amount of heat is used for MEA regeneration in the CO capture unit, which leads to which leads to almost a triplication of the overall heat production in the system compared with the almost a triplication of the overall heat production in the system compared with the reference plant. reference plant. Figure 9. Simplified schematic of the analyzed system with the main components of the mass and energy balance. Figure 9. Simplified schematic of the analyzed system with the main components of the mass and Figure 9. Simplified schematic of the analyzed system with the main components of the mass and energy balance. energy balance. Energies 2020, 13, 2841 20 of 34 Energies 2020, 13, x FOR PEER REVIEW 20 of 34 3.2. Economic Evaluation 3.2. Economic Evaluation The TSC of the analyzed system was estimated based on Equation (3) and Appendix B at The TSC of the analyzed system was estimated based on Equation (3) and Appendix B at 153.38 153.38 MEUR . In Figure 10, the share of the TSC for the CHP plant, the CO capture and storage 2017 2 MEUR2017. In Figure 10, the share of the TSC for the CHP plant, the CO2 capture and storage unit, the unit, the CO transport pipeline, the CO -EGS, and the sCO power plant is presented. As can be seen, 2 2 2 CO2 transport pipeline, the CO2-EGS, and the sCO2 power plant is presented. As can be seen, the cost the cost of the CO capture and compression plant is nearly double the investment cost of the plant of the CO2 capture and compression plant is nearly double the investment cost of the plant side. The side. The CO transport and utilization (through CO -EGS and the sCO power plant) comprise 20.5% 2 2 2 CO2 transport and utilization (through CO2-EGS and the sCO2 power plant) comprise 20.5% of the of the TSC, where the development (drilling and fracturing) of the CO -EGS system is dominant. TSC, where the development (drilling and fracturing) of the CO2-EGS system is 2 dominant. Figure 10. The share of system costs for parts of the analyzed system with respect to the total system Figure 10. The share of system costs for parts of the analyzed system with respect to the total system cost. cost. The specific unit investment cost was derived from the total subsystem costs, for which the values The specific unit investment cost was derived from the total subsystem costs, for which the are as follows: values are as follows: The biomass-fired CHP plant: 3073 EUR/kW (gross electric power in full-condensation mode); el • The biomass-fired CHP plant: 3073 EUR/kWel (gross electric power in full-condensation mode); The MEA unit and the CO compression train: 277.5 EUR/tpa; • The MEA unit and the CO2 compression train: 277.5 EUR/tpa; The sCO power plant and CO -EGS: 7090 EUR/kW (gross electric power of the turbine). • The sCO2 power plant and CO2-EGS: 7090 EUR/kWel (gross electric power of the turbine). 2 2 el In the case of the biomass-fired CHP plant, the values are within the range of medium-size CHP In the case of the biomass-fired CHP plant, the values are within the range of medium-size CHP plants fired with wood in the European market, whereas they were 2817 EUR/kWel in the reference plants fired with wood in the European market, whereas they were 2817 EUR/kW in the reference el case. For the enhanced geothermal plants, the TSC is almost 100% higher [84] compared with the case. For the enhanced geothermal plants, the TSC is almost 100% higher [84] compared with the conventional geothermal plants. For the CO2 capture and compression unit, the unit investment costs conventional geothermal plants. For the CO capture and compression unit, the unit investment costs are also higher (by 30%–50%) when compared with some industrial applications [85], mainly due to are also higher (by 30%–50%) when compared with some industrial applications [85], mainly due to the small scale. Nevertheless, the presented results for the cost estimations will be further used in the the small scale. Nevertheless, the presented results for the cost estimations will be further used in the economic assessment of the whole system, including in technological development scenarios. Within economic assessment of the whole system, including in technological development scenarios. Within the analysis, three years of construction time is assumed. the analysis, three years of construction time is assumed. For the analyzed system, in the business as usual scenario, the LCOE is equal to 239.0 EUR/MWh and the LCOH is equal to 9.4 EUR/GJ. When the LCOH is still within an acceptable range, the LCOE For the analyzed system, in the business as usual scenario, the LCOE is equal to 239.0 EUR/MWh is significantly higher than it is in other RES schemes [84]. However, it should be noted here that none and the LCOH is equal to 9.4 EUR/GJ. When the LCOH is still within an acceptable range, the LCOE of the other RES schemes analyzed in [84] have been able to provide negative CO2 emissions, which is significantly higher than it is in other RES schemes [84]. However, it should be noted here that none is one of the main goals of the proposed system. When the reference CHP plant is considered, the of the other RES schemes analyzed in [84] have been able to provide negative CO emissions, which is LCOE is 127.5 EUR/MWh and the LCOH is 5.0 EUR/GJ. In Table 7, the results of the NPV and BEP one of the main goals of the proposed system. When the reference CHP plant is considered, the LCOE is for all three analyzed scenarios are presented. In all cases, the NPV is below 0, but what is worth 127.5 EUR/MWh and the LCOH is 5.0 EUR/GJ. In Table 7, the results of the NPV and BEP for all three mentioning regarding the subsidy scenario (Figure 11a) is that negative cash flow could be analyzed scenarios are presented. In all cases, the NPV is below 0, but what is worth mentioning regarding observed—the same comment can be made for the reference CHP plant (Figure 11b). This means that the subsidy scenario (Figure 11a) is that negative cash flow could be observed—the same comment can the subsidy for investment cost, without support for operational costs (e.g., through a feed-in tariff be made for the reference CHP plant (Figure 11b). This means that the subsidy for investment cost, without support for operational costs (e.g., through a feed-in tari for electricity), does not achieve its purpose. As already mentioned, in the current support system in Poland, a feed-in tari for electricity Energies 2020, 13, 2841 21 of 34 and subsidy grants for investment in RES schemes exclude each other to a large degree. In both cases for the analyzed system, the total state subsidy (resulting from a feed-in tari and investment grants) is around 80 million EUR. As presented in Table 7, in the investment subsidy scenario, the current feed-in tari of ca. 100 EUR/MWh would need to be increased by 30% to meet the BEP, which would only allow one to obtain NPV = 0 (and this is still not attractive for potential investors). Table 7. Summary of the economic assessment. Investment Subsidy Technological Parameter/Scenario Business as Usual Scenario Development Net Present Value (NPV)—Analyzed 127,862,030 EUR 98,362,265 EUR 66,782,545 EUR System, with: Break-Even Point (BEP) for: price of electricity 243.5 EUR/MWh 131.6 EUR/MWh 162.8 EUR/MWh price of heat 55.1 EUR/GJ 35.6 EUR/GJ 29.7 EUR/GJ price of CO credits 100.7 EUR/t CO 65.9 EUR/t CO 55.3 EUR/t CO 2 2 2 2 Energies 2020, 13, x FOR PEER REVIEW 21 of 34 Net Present Value (NPV)—Reference 23,751,231 EUR 45,244,659 EUR 2,136,259 EUR Biomass-Fired CHP Plant, with: for e Brleak-Even ectricityPoint ), do(BEP) es nofor: t achieve its purpose. As already mentioned, in the current support system in price of electricity 126.7 EUR/MWh 86.9 EUR/MWh 98.00 EUR/MWh Poland, a feed-in tariff for electricity and subsidy grants for investment in RES schemes exclude each price of heat 18.4 EUR/GJ 21.6 EUR/GJ 9.37 EUR/GJ other to a large degree. In both cases for the analyzed system, the total state subsidy (resulting from price of fuel 4.2 EUR/GJ 3.4 EUR/GJ 6.1 EUR/GJ a feed-in tariff and investment grants) is around 80 million EUR. As presented in Table 7, in the CO Avoidance Cost (CAC), 63.0 EUR/t CO 27.3 EUR/t CO 35.5 EUR/t CO 2 2 2 investment subsid calculated based ony Equation scenario, the cur (8) rent feed-in tariff of ca. 100 EUR/MWh would need to be increased by 30% to meet the BEP, which would only allow one to obtain NPV = 0 (and this is still CO negative emission cost (CNC), 48.2 EUR/t CO 20.9 EUR/t CO 27.1 EUR/t CO 2 2 2 calculated based on Equation (9) not attractive for potential investors). Figure 11. The Net Present Value (NPV) for different scenarios in (a) the analyzed system and (b) the Figure 11. The Net Present Value (NPV) for different scenarios in (a) the analyzed system and (b) the reference biomass-fired CHP plant, and for the business as usual scenario impact of different (c) negative reference biomass-fired CHP plant, and for the business as usual scenario impact of different (c) CO emission credits in the analyzed system and (d) prices of fuel in the reference biomass-fired CHP plant. negative CO2 emission credits in the analyzed system and (d) prices of fuel in the reference biomass- fired CHP plant. Table 7. Summary of the economic assessment. Investment Technological Parameter/Scenario Business as Usual Subsidy Development Scenario Net Present Value (NPV)—Analyzed System, −127,862,030 EUR −98,362,265 EUR −66,782,545 EUR with: Break-Even Point (BEP) for: price of electricity 243.5 EUR/MWh 131.6 EUR/MWh 162.8 EUR/MWh price of heat 55.1 EUR/GJ 35.6 EUR/GJ 29.7 EUR/GJ price of CO2 credits 100.7 EUR/t CO2 65.9 EUR/t CO2 55.3 EUR/t CO2 Net Present Value (NPV)—Reference −23,751,231 EUR −45,244,659 EUR 2,136,259 EUR Biomass-Fired CHP Plant, with: Break-Even Point (BEP) for: price of electricity 126.7 EUR/MWh 86.9 EUR/MWh 98.00 EUR/MWh price of heat 18.4 EUR/GJ 21.6 EUR/GJ 9.37 EUR/GJ Energies 2020, 13, 2841 22 of 34 In Figure 11c, the impact of the negative CO emission credit on the NPV for the analyzed system in the business as usual scenario is presented. As there is currently a lack of dedicated schemes to support the negative CO emissions, in the analysis, the corresponding EU-ETS CO emission allowance price 2 2 was assumed (20 EUR/t CO ). For the current technological development and economic support mechanism, the price of the negative CO emission credits would need to be five times higher to provide economic justification for investment in the analyzed system. For the reference biomass-fired CHP plant, the impact of the fuel cost on the NPV in the same business as usual scenario has been presented in Figure 11d. As can be observed, the cost of fuel significantly impacts the economic profitability of the reference CHP plant, and prices below 4 EUR/GJ would be needed to provide ch economic justification for such units. In Table 7, beside the NPV for the analyzed system and reference CHP plant, the results for the BEP price of CO credits, CO avoided cost, and CO negative emission cost are presented. Taking 2 2 2 into account their definitions, as expected, the BEP of CO credit is higher than CAC or CNC, as it refers to the overall economic performance of the analyzed system expressed by the NPV. The CAC is higher than CNC, as it refers to the avoided CO emissions, which takes into account the di erence in direct CO emissions resulting from fuel combustion in the analyzed system and reference plant. Finally, the CNC refers only to obtained negative emissions, which correspond directly to the amount of CO capture in the analyzed system, as the reference CHP plant CO emission (coming from biomass 2 2 combustion) is considered to be zero. As the annual net production of electricity and heat in the analyzed system and reference CHP plant are the same (Table 6), the lowest CAC was obtained for the investment subsidy scenario, in which the investment cost decreases by 50% (through subsidies), followed by the technology development scenario, where the investment cost decreases by 30% (Table 5). Thus, the impact of the investment cost on the CAC can be observed. Taking into account the main goal of the proposed system, which is to obtain negative CO emissions, the CNC is a more valuable indicator that quantifies the cost of providing those negative emissions, taking into account the same production levels (in this analysis, electricity and heat) in the energy system. Based on the presented results, it can be stated that the direct cost of negative CO emissions coming from the investment in the proposed CO capture and 2 2 utilization (and storage) is around 50 EUR/t CO , but the economic justification for the development of the analyzed system is two times higher (around 100 EUR/t CO ) in the business as usual scenario. In Figure 12, the discounted cash flow (CF) for the analyzed system is presented. It can be observed that incomes from electricity and heat barely surpass the operational expenditures (fixed and variable ope Energies ration2020 al co , 13 st,s x FO ). TR P huEER s, th RE e N VIEW PV values (e.g., for the business as usual scenario) correspond to 23 of the 34 TSC. Figure 12. Discounted CF in the business as usual scenario in the analyzed system. Figure 12. Discounted CF in the business as usual scenario in the analyzed system. For the performed economic assessment, sensitivity analysis was performed, and the results are presented in Figure 13. As expected, the price of electricity and fuel (biomass) has the highest impact on the NPV. The impact of the price of heat and price of negative CO2 emission credit has a similar effect, although it should be pointed out that the heat price is strictly regulated in Poland, so significant changes in the price of heat should not be expected. Moreover, a dedicated support scheme for heat production operational costs from renewable energy sources is also lacking. Figure 13. Sensitivity analysis in the business as usual scenario in the analyzed system. In Figure 14, the NPV in the function of the cost of fuel and the price of negative CO2 emission credit is presented for the business as usual and the technological development scenarios. It is clear that, with an increase of the price of biomass (fuel), a lower NPV can be obtained. On the other hand, the increase in the CO2 credits helps to increase the profitability of the project. With a decrease in the costs of fuel to 4 EUR/GJ (which is a closer price range in, e.g., the USA) and the technological development of the system components (which is possible, taking into account, e.g. the decrease in the investment cost for other renewable energy source technologies and CO2 capture technology Energies 2020, 13, x FOR PEER REVIEW 23 of 34 Energies 2020, 13, 2841 23 of 34 Figure 12. Discounted CF in the business as usual scenario in the analyzed system. For the performed economic assessment, sensitivity analysis was performed, and the results are For the performed economic assessment, sensitivity analysis was performed, and the results are presented in Figure 13. As expected, the price of electricity and fuel (biomass) has the highest impact presented in Figure 13. As expected, the price of electricity and fuel (biomass) has the highest impact on the NPV. The impact of the price of heat and price of negative CO emission credit has a similar on the NPV. The impact of the price of heat and price of negative CO2 emission credit has a similar e ect, although it should be pointed out that the heat price is strictly regulated in Poland, so significant effect, although it should be pointed out that the heat price is strictly regulated in Poland, so changes in the price of heat should not be expected. Moreover, a dedicated support scheme for heat significant changes in the price of heat should not be expected. Moreover, a dedicated support scheme production operational costs from renewable energy sources is also lacking. for heat production operational costs from renewable energy sources is also lacking. Figure Figure 13. 13. Sensitivity Sensitivity analysis analysis in in the bu the business siness as u as usual sual scenar scenario io in the analy in the analyzed zed systsystem. em. In Figur In Figure e 14, the 14, the NPV i NPV in the n the functi function on of of the the c cost ost of fu of fuel el aand nd the pr the price ice of ne of negati gative CO ve 2CO emission emission credit is presented for the business as usual and the technological development scenarios. It is clear credit is presented for the business as usual and the technological development scenarios. It is clear that, with an increase of the price of biomass (fuel), a lower NPV can be obtained. On the other hand, that, with an increase of the price of biomass (fuel), a lower NPV can be obtained. On the other hand, the increase in the CO2 credits helps to increase the profitability of the project. With a decrease in the the increase in the CO credits helps to increase the profitability of the project. With a decrease in costs of fuel to 4 EUR/GJ (which is a closer price range in, e.g., the USA) and the technological the costs of fuel to 4 EUR/GJ (which is a closer price range in, e.g., the USA) and the technological development of the system components (which is possible, taking into account, e.g. the decrease in Energies development 2020, 13, x FO of the R Psystem EER REVIEW components (which is possible, taking into account, e.g., the decrease 24 of 34 in the investment cost for other renewable energy source technologies and CO2 capture technology the investment cost for other renewable energy source technologies and CO capture technology itself), itself), the BEP of the negative CO2 emission credit is around 35 EUR/t CO2, which is a very promising the BEP of the negative CO emission credit is around 35 EUR/t CO , which is a very promising option 2 2 option for heat and electricity supply together with carbon dioxide removal from the atmosphere. for heat and electricity supply together with carbon dioxide removal from the atmosphere. Figure 14. NPV in the function of negative CO emission credits and the cost of fuel in (a) the business Figure 14. NPV in the function of negative CO2 emission credits and the cost of fuel in (a) the business as usual scenario and (b) the technological development scenario. as usual scenario and (b) the technological development scenario. Within the analyzed system, the TSC includes the costs associated with CO2 utilization—the CO2 transport pipeline, CO2-EGS system development (drilling and fracturing), and the sCO2 power plant. This approach might not correspond to current trends in CCUS technologies, while dedicated operators are proposed for CO2 transport and CO2 utilization or storage. In Figure 15, the impact including the proposed CCUS chain associated with CO2 transport and utilization on the NPV is presented. The black lines correspond to the currently analyzed option for two CO2 transport distances (50 and 100 km). The coloured lines indicate the impact on the NPV when the costs of CO2 transport and storage (T&S) are given. As can be seen, the proposed option (for a 50 km CO2 transport pipeline) is competitive when the CO2 transport and storage costs are above 10 EUR/t CO2 (which is the case for Poland [82]). This proves that the proposed design of CO2 transport and utilization (including storage) is an economically favorable option, and that the electricity production from renewable energy sources (geothermal energy) can be increased. Figure 15. ΔNPV resulting from different options for capture CO2 utilization and storage. Energies 2020, 13, x FOR PEER REVIEW 24 of 34 itself), the BEP of the negative CO2 emission credit is around 35 EUR/t CO2, which is a very promising option for heat and electricity supply together with carbon dioxide removal from the atmosphere. Energies 2020, 13, 2841 24 of 34 Figure 14. NPV in the function of negative CO2 emission credits and the cost of fuel in (a) the business as usual scenario and (b) the technological development scenario. Within the analyzed system, the TSC includes the costs associated with CO utilization—the CO transport pipeline, CO -EGS system development (drilling and fracturing), and the sCO power 2 2 2 Within the analyzed system, the TSC includes the costs associated with CO2 utilization—the CO2 plant. This approach might not correspond to current trends in CCUS technologies, while dedicated transport pipeline, CO2-EGS system development (drilling and fracturing), and the sCO2 power plant. operators are proposed for CO transport and CO utilization or storage. This approach might not correspond 2 to current 2 trends in CCUS technologies, while dedicated In Figure 15, the impact including the proposed CCUS chain associated with CO transport and operators are proposed for CO2 transport and CO2 utilization or storage. In Figure 15, the impact including the proposed CCUS chain associated with CO2 transport and utilization on the NPV is presented. The black lines correspond to the currently analyzed option for utilization on the NPV is presented. The black lines correspond to the currently analyzed option for two CO transport distances (50 and 100 km). The coloured lines indicate the impact on the NPV two CO2 transport distances (50 and 100 km). The coloured lines indicate the impact on the NPV when the costs of CO transport and storage (T&S) are given. As can be seen, the proposed option when the costs of CO2 transport and storage (T&S) are given. As can be seen, the proposed option (for a 50 km CO transport pipeline) is competitive when the CO transport and storage costs are 2 2 (for a 50 km CO2 transport pipeline) is competitive when the CO2 transport and storage costs are above 10 EUR/t CO (which is the case for Poland [82]). This proves that the proposed design of above 10 EUR/t CO2 (which is the case for Poland [82]). This proves that the proposed design of CO2 CO transport and utilization (including storage) is an economically favorable option, and that the transport and utilization (including storage) is an economically favorable option, and that the electricity production from renewable energy sources (geothermal energy) can be increased. electricity production from renewable energy sources (geothermal energy) can be increased. Figure 15. ΔNPV resulting from different options for capture CO2 utilization and storage. Figure 15. DNPV resulting from di erent options for capture CO utilization and storage. 3.3. Technology Readiness Level of the Analyzed Concept The concept of the Technology Readiness Level (TRL) is used to estimate the maturity level of a technology, which is necessary to achieve a low-carbon economy but not yet available at a commercial scale. One of them is CCS, including BECCS. However, there are factors that can put important limitations on its global spread. These include a lower eciency compared to other combustion methods and a weak infrastructure for CO transport and storage. On the combustion side, a lower energy density and less ash deposition can be problematic [86]. However, the key prerequisites for large-scale BECCS are the availability of biomass feedstock and land for production. The challenges for the former include competition between di erent sectors of the economy for feedstock and competition with other ecosystem services, for example food production. The seasonal availability of certain crops can also be a limitation. A related issue is land availability for biomass feedstock production. BECCS is one of the CCS technologies that have reached (or are close to reaching) the commercial phase of development. What is underlined by researchers is that BECCS’ spread relies on a mature CCS industry. In 2019, five BECCS plants were operating worldwide. By 2100, this could provide more than 5% of total global primary energy [87]. However, if other negative emission technologies are to be quickly developed, this could potentially lead to a slower and lower uptake of BECCS. This can only be realized if they are to be cost-competitive in comparison to BECCS [87]. Energies 2020, 13, 2841 25 of 34 There were four EGS sites in the US in 2017, operating at around a 2 MW capacity. Some of them el are planned to reach 5 MW by 2020. However, the small project size can be misleading, as the target el is the development of (low- and medium-temperature) geothermal systems in the range of hundreds of kWe to an MWe for electricity in remote towns as well as the utilization of coproduced thermal power generation that results from the by-products of existing oil and gas wells. Only afterwards is the development of larger systems planned [42]. There have been attempts to develop an EGS in Asia as well. Japan developed two, but they are now closed. South Korea, China, and Taiwan are currently experimenting with the technology [42,88]. It has also been recently argued that, despite promising initial ideas on applying unconventional oil and gas technologies, there are shortcomings that make EGSs uneconomical [89]. Research has indicated that an adequate mass flow rate, of 80 kg/s at 200 C, is required for the proper functioning of an EGS plant. However, the systems currently in operation do not even reach 25 kg/s [90]. Moreover, the costs of deep wells remain highly uncertain [90]. The key challenge that remains addressed is how to establish and maintain a suitable reservoir. Furthermore, its change over time is insuciently understood. Finally, knowledge on the long-term interaction between working fluids and rock structure is incomplete [91]. To sum up, EGSs are heavily subsidized and are more expensive than other energy sources, which makes them not economically feasible. Therefore, governments should focus on reducing costs to 2030 to a competitive level [88]. This is assuming remarks that refer to a water-based EGS, while the TRL level of a CO -based EGS is around 3–4. There are five research institutes in the US and one each in Japan and South Korea that have indicated experimentation with sCO since 2009 [48,92]. According to the energetic rule of thumb that thermal eciency rises with the size of the system, sCO eciency is expected to rise. However, all test facilities operate at small scales; therefore, the development of a large-scale (>10 MW) prototype sCO system is necessary [92], and some of the most recent research points out that scaling up remains an issue [47,48]. Better designs of heat exchangers, bearings, and seals are necessary [47]. Two experiments of the application of the sCO power cycle in geothermal energy have shown that (1) the relationship between the mass flow rate of sCO and the power capacity is nonlinear and that (2) the cycle eciency was around 18% [47]. Thus, the overall TRL is also rather low, around 4–5. Thus, taking into account all of the aforementioned considerations, the overall TRL of the proposed concept can be assessed as TRL4 (technological development), mainly due to the early stage of the CO -enhanced geothermal system development. 4. Discussion Based on the presented results, it can be concluded that, in the current energy market in Poland, the proposed option is not economically feasible. The break-even price of the negative CO emission credit (the CO emission allowance price) should be approximately 100 EUR/t CO , which, even with the latest 2 2 rapid increase in EU ETS prices, could be expected by 2050. Within the analyzed scenarios, the government investment subsidies could improve the economic profitability of the system, but this is still not enough to provide economic justification at present without further support for the operational costs (e.g., through a feed-in tari for electricity or additional negative CO emission credits). Thus, further technological advances should be pursued to lower the investment costs of system components, mainly of the CHP plant, post-combustion CO capture, and CO -EGS system development (the cost of wells 2 2 drilling). In the first case, the potential is already visible when comparing the investment costs around the world—e.g., in China and India, the unit investment costs for biomass-fired CHP plants are almost two times lower than in Europe [84]. Additionally, a decrease in the CO capture installation investment cost should also be expected due to the development and maturity, as well as the redesign, of the units for smaller capacities. In addition, there is still small room for improved energy performance, as a decrease in the energy consumption in CO capture units can be observed. Where operational costs are concerned, fuel cost is of great significance; the assumed paper price of 6 EUR/GJ for waste wood biomass in Poland seems higher than in other parts of the world—e.g., in the USA, the prices are up to 2.5 USD/GJ [93]—but if the transport to Europe and other costs are Energies 2020, 13, 2841 26 of 34 included, in the end, the prices of biomass are even higher (up to 10 USD/GJ). The prices of wood biomass are expected to grow over the next several years in Poland, so only a locally specific source of cheap biomass could positively influence the economic profitability of the system. From an economic point of view, CO utilization instead of conventional storage in saline formations proved to be more economically justified, as the sequestration during the operation of the CO -EGS system could generate additional income per unit of CO stored. The low electrical eciency 2 2 of the CO -EGS power plant can be significantly improved when additional ORC is added or there is a local demand for heat at the site. Those options should be analyzed in further studies to estimate the potential economic benefits resulting from the change in system design. In [94], the cost of BECCS was estimated between 15 and 400 USD/ton of CO removed. It was also stated that BECCS was the best solution for providing negative CO emissions in most climate change scenarios. It should be noted that BECCS also has several drawbacks—mainly increased water and land use [94]. Where the maturity of the analyzed technological design is concerned, the conventional BECCS components are usually mature technologies. In the analyzed system, the CO -EGS system was included, which would decrease the TRL of the technology. However, as stated in the introduction, Poland still has much to do in the field of regulations and laws for CCS deployment, and probably even more where CCUS is concerned. Nevertheless, despite rather negative results coming from the study, research should be continued in terms of whole system energy and economic optimization, as well as more detailed investment cost estimations. Taking into account the importance of negative CO emissions for meeting climate goals [10], there might not be a better alternative than the wide deployment of BECCS technologies. 5. Conclusions The obtained results indicate that, in the current energy market in Poland, the proposed system is not economically feasible. The main obstacles, from an economic point of view, are associated with the high investment cost of the CO capture and compression unit, as well as a lack of dedicated comprehensive governmental incentives to pursue negative CO emissions in the energy sector. The latter is associated with the general lack of interest on behalf of the Polish government in CO capture and storage technologies, despite their general increased technological maturity over the last few years. Author Contributions: Conceptualization, P.G.; methodology, P.G. and M.M.; software, P.G. and M.M.; validation, P.G., A.S. and M.M.; formal analysis, P.G. and M.M.; investigation, P.G., M.M. and M.H.; resources, P.G., A.S. and L.P.; data curation, P.G., M.M. and A.S.; writing—original draft preparation, P.G., A.S., M.M., L.P. and M.H.; writing—review & editing, P.G., A.S., M.M. and M.H.; visualization, P.G. and A.S.; supervision, P.G.; project administration, P.G.; funding acquisition, P.G. All authors have read and agreed to the published version of the manuscript. Funding: This research was funded by the National Science Centre, Poland, grant number 2017/24/C/ST8/00204. Conflicts of Interest: The authors declare that there is no conflict of interest. Appendix A Governing equations for steady-state, single-channel flow and heat exchange in the reservoir–wellbore coupled model are presented in Appendix A. From the law of energy conservation and assuming a Darcy flow of constant cross-sectional area in the reservoir, the following set of equations is used to estimate the necessary injection pressure to be maintained at the wellhead: P = P + DP + DP gDz (A1) inj res f, well res Dz V Dzm DP = f  = 8f (A2) f, well D 2 D Energies 2020, 13, 2841 27 of 34 6.9 f = 1.8 log + (A3) Re 3.7D VD 4 m Re = = (A4) m DL DP = (A5) res KA For the production well, the following relationship is valid: P = P DP gDz (A6) prod res f, well where P and P are the pressures at the wellheads of the injection and production wells, respectively; inj prod DP represents the frictional pressure loses in the wellbore; DP represents the reservoir pressure f, well res losses due to laminar (Darcy) flow; V is the fluid velocity; m is the mass flow rate;  is the fluid density;  is the fluid dynamic viscosity; Re is the Reynolds number; g is the standard gravity; D is the pipe inner diameter;  is the pipe roughness; K is the average permeability of the reservoir zone; DL and Dz are the incremental reservoir and well intervals (lengths), respectively; and A is the cross-sectional swept area of the fluid flow in the reservoir. The temperature of the working fluid (e.g., water and CO ) at the bottom of the injection well and at the production wellhead can be estimated using the approximate solution of the line-source heat equation. The solution of Equation (A7) allows for the determination of the unit heat transfer rate between the borehole and flowing well. " ! # 4 t q = 4 (T T ) ln (A7) a w 1 r c r r where q is the unit heat transfer rate;  is the apparent thermal conductivity of the wellbore, casings, and surrounding rock formation; c is the specific heat of rock formation;  is the density of the rock formation; T is the temperature of the fluid in the analyzed interval; T is the natural temperature of w 1 the rock formation in the analyzed interval, undisturbed by the drilling of the fluid flow; t is the time; r is the well diameter; and is the Euler constant (  0.577216). Equation (A7) is valid only when r c w r u =  1 (A8) 4 t The determination of the unit heat transfer rate requires the use of an apparent thermal conductivity coecient, which takes into account the thermal conductivity of the casings, grouts, and rock formation, at a distance from the well axis to the distance at which the impact of the well operation on the natural temperature of the rock formation is negligible. The apparent thermal conductivity coecient for cylindrical layers can be determined using Equation (A9): i=1 = (A9) s D i mz i=1 i mi where s is the thickness of the ith layer,  is the thermal conductivity of the ith layer, D is the i i mz equivalent logarithmic mean of the extreme diameters, and D is the logarithmic mean of the outer mi and inner diameters of the ith cylindrical layer (m). D = 4 t (A10) mz where is the thermal di usivity of rock formation, and t is the time of the simulation period (1 year). Energies 2020, 13, 2841 28 of 34 The formula for the logarithmic mean of the pipe diameters is D D out inn D = (A11) out ln inn where D and D are the pipe’s outer and inner diameters, respectively. out inn The temperature at the outlet of each borehole’s interval can be calculated using the following equation: q z I,i T = T (A12) out, i inn, i V c where T and T are the temperatures at the outlet and inlet of the ith section, respectively; l is out, i inn, i i the length of the ith section; V is the volumetric flow rate; c is the specific heat; and % is the density of the injected/pumped fluid (kg/m ). Appendix B All total equipment cost (TEC) values are given in EUR (2017). The TECs were given as “power functions” for the following components: The biomass receiving and preparation infrastructure: 0.4096 TEC = 332, 786 G (A13) RPI bio where G (ton/day) is the biomass mass flow (as received); bio The biomass grate boiler: . . 0.1195 TEC = m  274 352 m  C  C (A14) GB st p,GB t,GB st where C and C stand for the pressure and superheated steam multipliers: p,GB t,GB > C = 1 p  2.0 MPa > p ,GB st > C = 0.0278  p + 0.5348  p + 0.0044 for 2.0 MPa < P < 6.0 MPa (A15) p,GB st st > st C = 2.21 P  6.0 Mpa p,GB st 6 2 C = 0.910  DT + 0.0043 DT + 1.0051 (A16) T,GB st st where and m (kg/s) is the boiler steam mass flow, p (MPa) is the boiler steam pressure, and DT (K) st st st is the di erence between the steam temperature from the boiler and saturation temperature; The extraction-condensing steam turbine: 0.287 TEC = 4008.22 P  P (A17) EC,ST ST,con ST,con where P (kW ) is the electrical power of the turbine in full-condensation mode; ST,con el The water/steam heat exchangers: . . 0.18 TEC = 313 Q  Q (A18) WS,HX HX HX where Q (kW ) is the heat transfer in the heat exchanger; HX th The air fans: Energies 2020, 13, 2841 29 of 34 0.67 AF TEC = 103, 193 (A19) AF where P (kW ) is the electrical power of the air fan motor; AF el The electrical generator: 0.95 TEC = 85.4 P (A20) GEN GEN where P (kW ) is the electrical power of the generator; GEN el The cooling tower: TEC = 32.2 Q (A21) CT CT where Q (kW ) is the cooling tower heat duty; th CT The supercritical CO turbine: 0.8 TEC = 168, 840 P  C  C (A22) CO2,ST p,CO2 t,CO2 ST where P (MW ) is the e ective power of the turbine, and C and C stand for the pressure el p,CO2 t,CO2 ST and temperature multipliers for the sCO machinery: C = 1 if p < 10 MPa max p,CO2 (A23) C = 0.8 + 0.02 p if p  10 MPa p,CO2 max max C = 1 if t < 400 t,CO2 max (A24) C = 5.32 0.0238 t + 0.00003 t if t  400 t,CO2 max max max where and p (bar) is the maximal pressure, and t ( C) is the maximal temperature at which the max max machinery is operated; The supercritical CO chiller: TEC = 168 UA  C  C (A25) CO2,HX p,CO2 t,CO2 HX where UA (kW/K) is the overall heat transfer coecient U multiplied by the heat transfer area A of HX the heat exchanger. For the CO capture and compression equipment, the total equipment cost was estimated as 0.6 TEC = TEC  (A26) re f re f where X is the scaling parameter. For the components of the CO capture and compression equipment, the scaling parameters are presented in Table A1. Energies 2020, 13, 2841 30 of 34 Table A1. Scaling parameters for the CO capture and compression equipment. Equipment Scaling Parameter, X Direct contact cooler V T f g f g Flue gas blower f g,re f f g,re f Absorber Rich/lean cross heat exchanger solv Regenerator V solv,re f f g G st . . Reboiler V G f g,re f st,re f st Steam extractor . st,re f DMEA MEA reclaimer DMEA,re f solv Solvent processing area solv,re f CO2 CO drying and compression unit CO2,re f where V is the flue gas volumetric flow; T is the flue gas temperature at the inlet to given f g f g . . . machinery; V is the solvent volumetric flow; G is the steam mass flow; G is the make-up solv st DMEA solvent mass flow; and G is the compressed CO mass flow. CO2 2 For the CO transport pipeline, the following formula was used to estimate the total system cost: 0.35 0.13 TSC = 9745.6 G  L  L (A27) pipeline CO2 pipeline pipeline where G (ton/day) is the CO mass flow rate, and L (km) is the pipeline length. CO2 2 pipeline For the enhanced geothermal system development, including drilling and fracturing, the following formula was used to estimate the total system cost: TSC = (n D  1400) + 2, 123, 800 (A28) EGS well where n is the number of wells, and D (m) is the depth of the well. Factor 1400 corresponds to the well unit drilling cost for wells above 5000 m. References 1. Polish Ministry of Economy. Polish Energy Policy until 2030; Polish Ministry of Economy: Warsaw, Poland, 2009. 2. Polish Ministry of Development. Responsible Development Strategy; Polish Ministry of Development: Warsaw, Poland, 2017. 3. Global CCS Institute. The Global Status of CCS: 2019. Australia, 2019. 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Published: Jun 3, 2020

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