Assessment of the potential for small-scale CHP production using Organic Rankine Cycle (ORC) systems in different geographical contexts: GHG emissions impact and economic feasibility

According to the European Commission’s 2050 Climate Strategy, renewable electricity is the most important driver for decarbonising the energy system. The intermittent nature of wind and solar creates a demand for dispatchable electricity production that can contribute to a stable and steady supply all year. This supply can be provided, for example, by biomass boilers with combined heat and power production. This paper analyses the potential for small-scale electricity production in Organic Rankine Cycle systems (ORC) in different geographical contexts. The focus is on installing ORC systems with existing biomass-fired boilers in district heating (DH) systems or industry, and with industrial excess heat streams. Economic and climate effects are studied in three countries with different climates and energy-market conditions, namely Sweden, the United Kingdom and Brazil. The results show that there is the potential to install ORC systems around the world that are both economically viable and reduce global greenhouse gas emissions. Equipment size has a large effect on the profitability of the investments. Moreover, the benefits of tax exemptions and certificates for renewable electricity production significantly impact profitability, particularly for smaller equipment sizes. ©


Introduction
According to the European Commission's 2050 Climate Strategy (European Commission, 2018), ''the most important single driver for a decarbonised energy system is the growing role of electricity both in final energy demand and in the supply of alternative fuels, which will be mostly met by renewables, and in particular by wind and solar electricity''.Globally, the demand for electricity has increased faster than that for other energy sources (IEA, 2020a).Additionally, the means of supplying electricity are under transformation as renewable sources such as wind and solar photovoltaic (PV) play an ever-increasing role (IEA, 2020a).However, to avoid adverse effects, such as less secure energy systems due to the intermittent nature of wind and solar energy, this transition requires new approaches to the design and operation of power systems (IEA, 2020a;Johnson et al., 2020).
Replacing stable electricity production from nuclear and fossilfuel power plants with intermittent output from wind and solar PV, which have lower predictability and controllability, creates a demand for dispatchable electricity production that can guarantee a steady supply all year (Jurasz et al., 2020).This supply can be provided, for example, by small-scale heat-driven electricity production, where the heat can be supplied by a biomass boiler (Mascuch et al., 2020) or industrial excess heat (Bühler et al., 2018;Lemmens and Lecompte, 2017).One such electricity generation technology is the Organic Rankine cycle (ORC).In the aforementioned case, the ORC acts as a combined heat and power (CHP) plant, producing both electricity and heat.Unlike the traditional steam cycle, ORCs use an organic working fluid with a lower evaporation temperature than water, making it suitable for low-temperature applications.For example, large amounts of excess heat from industrial processes are not currently recovered (Manz et al., 2021).Introducing electricity production from this heat will increase resource efficiency and provide a secure electricity supply.In the case of a biomass boiler, resource efficiency can be increased by combining heat and power production instead of only producing heat.This stable, distributed electricity production can contribute to the baseload in the electricity system and improve the network's security.Distributed power production can also release existing transmission capacity since the electricity is produced closer to its users (Gomes and Saraiva, 2019).
Different technologies have been proposed for the recovery of industrial excess heat (Broberg Viklund and Johansson, 2014;Hammond and Norman, 2014;van de Bor et al., 2015), and the potential for excess heat recovery has been investigated for different countries and regions (Brueckner et al., 2014;Hammond and Norman, 2014;Miró et al., 2015;Papapetrou et al., 2018).There are extensive studies of the technical performance of ORC technology; see e.g.Landelle et al. (2017), Ziviani et al. (2016) and Macchi et al. (2017).Various studies identified the technical potential of small scale ORC systems for CHP power generation (Dong et al., 2009;Ferla and Caputo, 2022), and compared such systems with other technologies (Mascuch et al., 2020;Tagliaferri et al., 2018).Moreover, previous studies have evaluated the techno-economic potential of electricity production using the ORC in several sectors.For example, the steel industry, cement industry and glass manufacturing in Germany (Pili et al., 2020), the oil-refining industry (Gangar et al., 2020), clinker manufacturing and the steel industry in Europe (Pili et al., 2017), the aluminium industry (Pan et al., 2020), the agrarian industry in Indonesia (Nur et al., 2019) and Nigeria (Ofodu et al., 2019), biomass-based DH plants (Goldschmidt, 2009), and the pulp and paper industry in Sweden (Öhman, 2012).A few recent studies investigated the techno-economic performance of biomass-based cogeneration units using ORCs.Hennessy et al. (2018) found that ORC systems in DH plants are not economically feasible under current Swedish market conditions, Braimakis et al. (2021) found low economic performance under favourable operational and market conditions in Greece, Finland and Germany, Pina et al. (2021) found that a hybrid solar-biomass ORC is not currently profitable in Spain, but could be profitable in the medium term if investment cost reductions are achieved, and Diemuodeke et al. (2021) concluded that a rice husk fuelled plant in Nigeria would results in economic savings.
While the technical, economic, and environmental performances of small-scale ORC systems have been studied for various cases, few studies attempt to put these systems into the broader context of the different local energy markets.These markets have particular geographies, climates, demographics and policy conditions, and the resources available are vastly different.Therefore, this study focuses on analysing the economic and climate performance of small-scale CHP electricity generation using ORC systems in applications that identify and incorporate local conditions.Three countries with different energy markets, climates, and industrial sectors were considered for this purpose, namely Sweden, the United Kingdom, and Brazil.This comparison then highlights how marginal electricity production and related CO 2 emissions, feedstock prices, potential economic incentives, etc. might influence the adoption of small-scale ORC systems in different local contexts.An analysis considering both GHG emissions and economic aspects is important because achieving the ambitious GHG emissions targets aiming at limiting the effects of global warming requires technologies that combine resource efficiency and economic feasibility.Only technologies that fulfil these requirements will receive relevant investments.

Organic Rankine Cycle (ORC) systems
The ORC is in principle equivalent to a conventional Rankine Cycle but uses an organic working fluid instead of water.The ORC is well suited for generating electricity from low to hightemperature heat sources (80-350 • C), depending on the thermal properties of the organic fluid used (Quoilin et al., 2013).However, the ORC is typically used in applications where the heat source is below 240 • C (Dai et al., 2009).The working principle of an ORC system is shown in Fig. 1.
The design of an ORC system and its incorporation into the overall installation is an engineering challenge in which thermodynamic performance must be considered, along with possibilities and constraints related to technical, economic, and environmental aspects.All these aspects interact and should therefore be accounted for collectively during system design.The starting point is the choice and design of the turbine (expander) solution and the working fluid to be used.A deeper discussion of ORC technology and its advantages and limitations can be found e.g. in Macchi et al. (2017).
Many working fluids can be used in an ORC system, for example common refrigerants used in heat pumps and refrigeration systems or hydrocarbons.The choice depends primarily on the temperatures between which the ORC will be required to work (Garg et al., 2016).The thermodynamic characteristics of the fluid and the temperature levels between which the cycle works set the performance and efficiency limits.In general, organic working fluids have a relatively large molecular complexity, a large molecular mass, and low critical pressure.This leads to reduced technical demands and decreased costs due to lower system pressure, fewer turbine stages or lower peripheral speed when compared to traditional Rankine systems running on steam.Altogether, these aspects are vital in adopting such systems to low-temperature applications, for downsizing ORC systems to small-scale applications and keeping down investment and installation costs per kilowatt-hour of electricity produced.Other working fluid aspects to consider are price, risks (toxicity, flammability etc.), potential climate impact (global warming potential (GWP)) and ozone depletion potential (ODP), see e.g.Luo et al. (2015).The development of modern refrigerants has greatly decreased GWP and ODP, and it is now possible to choose working fluids with excellent performance and low climate and environmental impact.

Countries and system configurations studied
To account for the different geographical contexts and settings of small-scale electricity production, three countries with different climates, energy markets and regulations in the electricity sector were selected.For example, Sweden and the UK have low annual average temperatures, and thus the demand for comfort heating exists, while in Brazil there is almost no demand for comfort heating.At the same time, while the need for heating exists in Sweden and the UK, the way in which this demand is met is different.In Sweden, district heating (DH) systems are most prevalent (Swedish Energy Agency, 2020a), while in the UK individual heating units are more common, and only about 2% of the heat demand is met by heating networks (ADE, 2018).The ORC systems analysed are installations in (1) a Swedish district heating system using biomass boilers (SE1), (2) a manufacturing industry in the UK (UK1), and (3) a Brazilian agroindustry (BR1).Additionally, the option of industrial excess heat (IEH) recovery for electricity generation in the same markets was included in the analysis (identified as SE2, UK2 and BR2).This option of IEH recovery considers the same temperature levels as the three cases mentioned before (SE1, UK1 and BR1) but with a lower condenser temperature, as detailed in Section 4.3.The ORC systems considered range between 50 and 2000 kW installed electrical power (kW el ).Apart from being a growing application of ORC systems, the case for IEH recovery provides an important basis for direct comparison between the results for the three countries analysed, as only the specific market conditions will affect these results when compared to each other.A general description of the local conditions relevant to the analysis is presented in this section for each of the countries studied.

Sweden
In Sweden, all major cities and towns have district heating systems (Werner, 2017), but only about 20% of these employ combined heat and power production (Byman and Koebe, 2016).Large systems often have combined heat and power production, while the small systems mainly employ heat-only boilers.In these small systems, which often have a capacity of 2-10 MW th and are fuelled with wood chips, there is potential to install an ORC system running as a CHP unit.
For case SE1, it was assumed that the ORC is installed in a small district heating system and that the heat output from the system is the same as before the ORC installation.Therefore, more biomass is purchased for the boiler to produce the extra heat needed for electricity production.ORC systems for this application are designed to use heat from the boiler and reject heat to the district heating return flow.The temperature difference between the boiler and the district heating return is typically low, often between 60-120 • C, and the electrical efficiency is therefore low (2%-10%).However, the marginal electricity efficiency is close to 100% since nearly all the extra heat supplied to the ORC system is converted to electricity or used to heat the district heating return.
The assumption is that up to 1000 kW el installed capacity, the electricity produced is used in-house by the heating plant to cover its electricity requirements, which results in avoided costs for purchased electricity, grid costs and some tax exemptions.For plants larger than 1000 kW el , it is assumed that the first 20% of the production above 1000 kW el is sold to the grid.
In Sweden, the renewable electricity certificate system pays a premium for electricity produced with renewable resources (Swedish Energy Agency, 2020b).Eligible production is awarded electricity certificates for 15 years.Renewable electricity production up to 100 kW el is exempt from electricity tax (Swedish Finance Department, 2020).Regardless of the installed capacity, a tax reduction to 0.5 EUR/MWh is applied for the share of electricity used in-house.

The United Kingdom
In the UK, the ORC is assumed to be installed at an industrial company with a demand for process heat.This could be e.g. an industry for the food and drink sector, which responds for around 25% of the industrial energy use in the UK, out of which 65% is demand for low-temperature processes (Law et al., 2013).The electricity produced is used in-house by the company, with the implication that the company avoids the costs of purchasing an equivalent amount from the grid.In case UK1, the company owns a biomass boiler on which the ORC is installed.To meet the company's heat demand, the heat output from the boiler and the ORC system must be the same as the heat produced by the boiler before the ORC installation.Hence, there will be an increased purchase of biomass.
The most relevant policy related to renewable electricity production is the Smart Export Guarantee (SEG), which obliges electricity suppliers to buy electricity surplus from renewable sources and applies to micro-CHP electricity generation up to 50 kW el or electricity only generation up to 5 MW (Ofgem, 2020).

Brazil
The agroindustry is one of the most important industries in Brazil and includes the production of livestock, coffee, soybeans, sugarcane and citrus (Alves, 2020).The agroindustry generates large amounts of biomass waste, which is largely used as fuel in the production of process heat.However, biomass waste is often greater than the demand for process heat.In such cases, the waste is sometimes burnt without energy recovery or spread out in fields (Forster-Carneiro et al., 2013), especially in smaller plants.The National Energy Plan 2030 (MME, 2007) has provisions for greater adoption of biomass cogeneration in CHP plants, especially using sugar cane bagasse.
For the BR1 case, it is assumed that the ORC is installed at an agroindustry site, and although there is a biomass excess, a fuel cost is considered to maintain this case consistent with the cases for the other countries.The electricity is assumed to be used inhouse by the industry, and hence the company avoids the cost of purchasing electricity from the grid.
The electricity market in Brazil is partially regulated, depending on the power demand of the consumer.Consumers with a power demand below 500 kW are captive consumers and can only contract with the power distribution company in their region.The regulated market accounts for 70% of the total power demand, and has prices approved by the national electricity market regulatory agency (ANEEL, 2020).From January 2021 onwards, the deregulated market is accessible to users with a contracted demand above 1500 kW, who are free to trade electricity in the deregulated market (CCEE, 2021).Consumers with a total demand between 500 kW and 1500 kW can trade in the deregulated market only for electricity from certain renewable sources, which include solar, wind, biomass, and small-scale hydropower.These renewable sources benefit from exemptions in transmission and distribution network fees.Additionally, there is a simplified scheme for distributed generation from renewable sources up to 5 MW (ANEEL, 2012).Fig. 2. System boundaries and system expansion, where the ORC equipment uses heat from a biomass boiler to produce electricity and supply district heating.In the cases with excess heat recovery, the heat supplied to the ORC is industrial excess heat rather than heat from a biomass boiler.

System boundaries
To understand the potential economic and environmental benefits of installing the ORC systems considered, it is important to understand both the surrounding energy system and the regional characteristics (see Fig. 2).This study uses a consequential analysis with system expansion, which considers additional aspects related to the energy market (Pettersson et al., 2020).Since this study evaluates long-term changes in electricity production, the build-margin approach for assessing the effects of electricity production in the ORC was used.In the analysis of the cases for Sweden and the UK, the system is assumed to be part of the European market for electricity and biomass.Factors that influence this analysis are presented in Section 4.2.

Scenarios
While the future cannot be predicted with certainty, different scenarios that describe the future energy system can be used.In this study, the ENPAC (Energy Price and Carbon Balances Scenarios) tool (Axelsson and Harvey, 2010) was used to generate scenarios with build-margin technologies for electricity and heat generation across different timeframes, as well as related future energy prices and CO 2 emissions.The tool provides consistent energy market scenarios that show the current and future energy prices paid by end-users, and the CO 2 emission factors related to the use of different fuels, electricity and heat, from a lifecycle perspective (Axelsson and Harvey, 2010).The scenarios in ENPAC were constructed with an input of world commodity energy prices and CO 2 emissions charges based on the scenarios published by the International Energy Agency in the report World Energy Outlook (WEO) 2020(IEA, 2020b)).
The input scenarios from WEO2020 are Stated Policies (SP), Delayed Recovery (DR) and Sustainable Development (SD) (IEA, 2020b).The SP scenario incorporates today's policy intentions and targets, and an assumption that the Covid-19 situation is gradually brought under control and the global economy returned to pre-crisis levels in 2021.The DR scenario makes the same assumptions as the SP scenario but incorporates a prolonged pandemic situation, with the global economy returning to precrisis levels in 2023.Finally, the SD scenario maps out a way to fully meet sustainable energy goals, including the Paris Agreement, energy access, and air quality goals.This requires rapid and widespread changes across all parts of the energy systems.
When biomass is not considered a limited resource, the burning of biomass is seen as CO 2 neutral and only includes emissions from harvesting, transport, etc.On the other hand, when biomass is considered a limited resource, competition for the resource is included in the analysis.The consequence is that if the demand for biomass increases in the system, the marginal (i.e., pricesetting) user of biomass has a deficit in supply and must therefore use another energy carrier instead.For the Swedish and UK cases, the price-setting user is assumed to be either a coal-fired power plant with the capability of co-firing some wood fuel with the fossil coal (thus fossil coal consumption is affected) or a producer of biofuel for transportation (thus gasoline or diesel consumption is affected) (Axelsson and Harvey, 2010).For the Brazilian case, the price-setting user of biomass is assumed to be pig iron production, with charcoal as the reducing agent (Leme et al., 2018;Paiva, 2001) instead of coal (fossil coal consumption is affected).
The inputs for the scenarios and resulting prices and emission factors are available in Table 1.
Possible build-margin technologies for electricity production embedded in the ENPAC tool are coal-fired power plants and natural gas combined cycle (NGCC) plants, with and without carbon capture and storage (CCS), nuclear power and wind power.Wind power is not allowed as a build margin in Sweden or the UK in the SD scenario 2040 because it is assumed that by 2040 there will be no more growth potential in the continent.Policies to support CO 2 -neutral technologies in the SD and SP scenarios motivate why nuclear power is allowed for marginal electricity production in the European context.However, in Brazil, nuclear power is not assumed to be an alternative, as there are no plans to increase nuclear capacity in Brazil according to the National Energy Plan 2030 (MME, 2007).Moreover, coal-fired power plants are not considered a marginal technology in Brazil, as the energy plan only considers a small addition of such plants in the future, with natural gas thermal plants taking a more significant role (MME, 2007).

Technical and economic calculations
The efficiency of the ORC system was calculated for an evaporator hot side supply temperature of 120 • C, a typical supply temperature in low-temperature hot water boilers, and a condensation temperature of 60 • C. The condenser temperature was This fluid is a common choice because it performs well at the temperatures of interest (Yang et al., 2018).The calculated net electrical efficiency for the ORC system running in conjunction with the biomass boiler and rejecting heat at 60 • C is 6.2%.
The system powered by IEH with a condenser cold-side supply temperature of 25 • C has a calculated net electrical efficiency of 9.1%.A marginal electricity efficiency of 95% was considered.
Important aspects affecting profitability are the electricity network costs, taxes and fees for electricity.Table 2 shows the costs associated with transmission and distribution networks and the taxes and levies for electricity in the countries studied.
For consistency with the energy market scenarios in ENPAC, economic calculations were performed for the lifecycle costs (LCC) of the ORC system.These involve investment, operation, and maintenance costs.To account for the economic lifetime of equipment and capital costs, the capital recovery factor (CRF,  2013), Johansson and Söderström (2014) and Bühler et al. (2018).
Eq. ( 1)) was used to annualise the investment costs (I) over the economic lifetime (N L ) using the interest rate (i).Specific investment costs were adapted from Bühler et al. (2018), Johansson andSöderström (2014) and Quoilin et al. (2013), using an exponential function to fit the data for the range of equipment sizes considered, which resulted in the costs shown in Fig. 3.These specific investment costs were then used in the economic calculations for equipment sizes between 50 kW el and 2000 kW el .The ORC machine operation time was set at 7838 hours per year (approximately 90% availability).
The net present value (NPV, Eq. ( 2)) of the investment over the economic lifetime (N E ) was then calculated by considering the annual cash flows (CF n ) for a discount rate (d), with the electricity, heat and fuel costs and the certificates for renewable electricity calculated according to the scenario results from ENPAC.In line with similar studies, an operation and maintenance cost of 2% of the investment costs was used, excluding fuel costs (Bühler et al., 2018;Johansson and Söderström, 2014).The economic lifetime considered was 20 years, with a discount rate of 5% for all cases, in line with the recommendations of the European Commission for the analysis of energy investment projects (European Commission, 2014).The loan period considered was five years, with a 5% interest rate for Sweden and the UK and 10% for Brazil (BCB, 2020). (2)

Economic feasibility
The results are presented both with and without certificates for renewable electricity, electricity taxes, and network costs to show the impact of different economic policy instruments and conditions.
The economic analysis shows that the installation of smallscale electricity production with a lifetime of 20 years and the previously stated electrical efficiencies could be profitable in all countries studied, depending on the size of the equipment (see Fig. 4).As shown in Fig. 4, the size of the ORC equipment has a significant impact on profitability, showing that economies of scale are an essential aspect to consider.With the assumptions made in the scenarios in ENPAC, considering the specific investment costs adopted and excluding certificates, taxes and grid costs for electricity, the smallest ORC machine (50 kW el ) shows no profitability when working as a CHP plant, but are profitable in all scenarios for the IEH recovery cases.Excluding the SD scenario and BR cases, ORC machines of 100 kW el are profitable.However, the ORC machines with larger power output, i.e., 500 kW el and higher, could be interesting investments in combination with small district heating systems in Sweden and the manufacturing industry in the UK in the SP and DR scenarios even without considering the benefits of certificates for renewable electricity and avoided costs for taxes and grid costs.The case for the agroindustry in Brazil (BR1) shows poorer profitability if biomass has an associated cost and is not a profitable investment for all equipment sizes in the SD scenario.
The increased fuel input in the SE1, UK1 and BR1 cases incurs extra costs.This explains why installing an ORC for IEH recovery is more profitable than in a biomass boiler.An additional reason the BR1 case shows the lowest profitability is that biomass prices are much higher in the energy-market scenarios, which means the higher cost to produce electricity does not entirely offset the electricity purchase prices.In general, the most profitable alternative would be the installation of an ORC using excess heat in Sweden.
Fig. 5 shows the results when country-specific economic policies (i.e., taxes and certificates for renewable electricity) and electricity network costs are included in the analysis.For an installed electricity capacity below 100 kW el , the electricity tax and the network costs become avoided costs for the Swedish case.Capacities above 100 kW el pay electricity tax, but with a tax reduction to 0.5 EUR/MWh.For capacities above 1000 kW el , it was assumed that 20% of the extra electricity generation is sold.This share of the electricity pays network costs in addition to electricity tax.In the UK and Brazilian cases, all the electricity is used in-house, and the companies therefore pay no electricity taxes or network costs.Sweden and the UK have certificates for renewable electricity production, which contributes to increased profitability.When comparing Fig. 4 with Fig. 5, the profitability is greatly influenced by including the avoided costs for electricity taxes and network costs and income from certificates in the analysis.For ORC units up to 100 kW el , the tax exemption and avoided grid costs compensate for the higher specific investment costs in all scenarios and all cases.For units larger than 100 kW el ,  the profitability is also increased, improving the economic performance of ORC units in all scenarios.The high avoided costs in the Brazilian and UK cases, due to higher taxes and network costs, greatly increase profitability, even compensating for the lack of certificates for renewable electricity in the Brazilian cases.
To visualise the effects of taxes, certificates, and network costs in more detail, Figs. 6 and 7 show the Swedish cases (SE1 and SE2, respectively) with and without taxes, certificates, and network costs in the same diagram.Considering the avoided costs, even the smaller ORC units are profitable.In Fig. 7, it also becomes apparent that the results are less sensitive to the different ENPAC scenarios because no fuel costs exist for these cases.

Global CO 2 emissions
The evaluation of how small-scale electricity generation using ORC systems would affect global emissions of GHG shows that the emissions would decrease in all countries and all scenarios studied (see Fig. 8), except for the SE1 and UK1 cases in the SD scenario.
The results for emission reductions are the same for the SP and DR scenarios, where the Swedish and UK cases have equal values.In these scenarios, the Brazilian case would yield lower reductions.The reason for this is that in the Swedish and UK cases the electricity that is produced would replace electricity production in coal-fired power plants up to the year 2025, while for the same period in Brazil the electricity production replaces power generation by NGCC, which is less carbon-intensive.The effects on emissions due to ORC installation are less pronounced in the SD scenario.This is explained by the fact that the electricity produced by the ORC in Sweden, the UK and Brazil replaces carbon-neutral electricity from wind or nuclear from 2030 onwards.In the SD scenario, biomass is considered a limited resource from 2030 onwards.This implies that there is a CO 2 emissions penalty associated with the increased demand and use of woody biomass.This penalty equates to the emissions that the marginal biomass user emits as a result of using fossil fuels instead of biomass.In the Swedish and UK cases, the marginal biomass user is a coal-fired power plant substituting part of its fossil coal with woody biomass.In the Brazilian case, the marginal user is a pig iron plant using charcoal instead of fossil coke in the blast furnace.Since no extra biomass is used in the excess heat utilisation cases, there is no CO 2 emissions penalty, which explains why these cases achieve more significant GHG emissions reductions in the SD scenarios.Outlook 2020(IEA, 2020b).The emissions reductions are shown as tonne of CO 2 -eq per kW of electrical power installed.

Discussion
The cases chosen in this study aimed to reflect real conditions in different energy-market contexts and the associated potentials for ORC systems.Consequently, the ORC was assumed to be installed in three different systems: (1) a small district heating system in Sweden, (2) the manufacturing industry in the UK, and (3) the agroindustry in Brazil.Additionally, the use of industrial excess heat in the same energy markets was considered.Hence, the paper does not compare equal installations in the countries studied, since the local conditions are different, but provides one set of cases that show a similar application (IEH recovery).Consequently, these results apply to different circumstances and give knowledge on the context-dependent potential for increasing electricity production using ORC technology.Additionally, a sensitivity analysis was conducted by using three future energy market scenarios, and the results show that ORC installations could be profitable in all the scenarios studied.This implies that ORC systems are potentially a robust investment in all the countries and settings studied, which is a good indication that the technology is sufficiently mature and flexible to different operational conditions.Performing an economic analysis which takes into account the equipment lifetime and different future scenarios is important to understand any lock-in effect of the investment in an ORC system.
It is especially advantageous to install an ORC system if there is an excess heat source available and in contexts in which biomass is not a limited resource, such as in two of the energy market scenarios presented (SP and DR).The results also show that it would be beneficial for industry to produce electricity from the excess heat in its industrial processes.This is in line with previous studies (Fierro et al., 2020;Gangar et al., 2020;Pan et al., 2020;Pili et al., 2020), which have shown that electricity production from industrial excess heat using ORC could be economically feasible.However, other studies have shown that such installations would not be profitable, mainly due to the low efficiency value (Cavazzini and Dal Toso, 2015) and the costs of cooling water and a refrigeration system (Gutiérrez-Arriaga et al., 2015).The results show that a configuration where the heat from the ORC condenser is used elsewhere (e.g., to heat the return flow in a district heating system) positively affects the economics.Previous research (Ofodu et al., 2019;Tańczuk and Ulbrich, 2013) also confirms that electricity production using ORC at a biomass-fired cogeneration plant for heat, cooling, and electricity could be profitable.However, the economics depend to a large degree on the price of electricity (Fierro et al., 2021;Tańczuk and Ulbrich, 2013).In the results shown here, biomass prices affect the profitability more than the different electricity prices for the three energy-market scenarios, and the avoided costs when self-producing electricity have the most significant impact on profitability.These results also consider a heat demand for 7838 hours per year is present.Lowering the share of time with a heat demand would negatively affect the profitability of the ORC systems.Individual plants could size the ORC systems to maximise operational hours and supply heat demands with lower timeshares with the current biomass boilers available in the cases studied.
Small-scale electricity production from biomass or industrial excess heat using an ORC would reduce global emissions of GHG in all the cases studied, except if biomass is considered a limited resource.The size of these reductions depends to a substantial extent on the electricity production that would be replaced and whether wood fuel is a limited resource.These results are in line with previous studies, which have identified the same factors as key elements in how IEH deliveries to DH systems would affect global GHG emissions (Pettersson et al., 2020) and how a fuel switch in the iron and steel industry would impact global CO 2 emissions (Johansson, 2016).
Even though the manufacturing industry considered in this study is in the UK, the ORC installations evaluated apply to any industry in other countries with a demand for process heat or with excess heat available.Moreover, the UK district heating system is developing (Euroheat & Power, 2019), and there is potential for ORC installations in the UK heat network market in the future.
The purpose of this study was not to just compare similar installations but to demonstrate a range of possible applications for small-scale electricity production in different contexts, focusing on the opportunities presented by the regional energy markets and policy instruments.
The results reveal the clear economic advantage of investing in larger ORC systems.However, the smaller sizes are nevertheless still profitable if the avoided costs (taxes, grid costs and certificates for renewable electricity) are considered.Hence, the results highlight the importance of long-term policy measures such as tax exemptions, subsidies, and certificates to make investments in smaller ORC systems profitable.Previous research has also highlighted this (Pili et al., 2020).
As only ORC systems are considered in this study, no comparison is made between the profitability and GHG emissions reductions of ORC systems and alternative small-scale renewable energy generation, e.g., solar power.Other renewable energy generation can potentially be more advantageous as a capital investment or to reduce GHG emissions.Still, ORC systems in the applications considered in this study have advantages such as controllability and increased resource efficiency.These advantages are likely to gain importance as the share of intermittent renewable electricity increases in the energy systems worldwide, with increased price volatility and high variation in supply.

Conclusions
In this paper, the economic performance and GHG emissions consequences of installing small-scale ORC systems in different energy-market contexts were investigated.There is potential to install ORC systems that are both economically viable and that reduce global GHG emissions in varying energy-market conditions.The size of the ORC system installed has a significant effect on profitability, showing that economies of scale are still a key factor, at least with the capital requirements considered in this study.In an analysis that considers country-specific taxes, regulations, renewable electricity incentives and grid costs, the economic performance of ORC units is positively affected and proved viable in all scenarios considered.The benefits of tax exemptions, certificates and avoided electricity costs have the highest impact on ORC units up to 100 kW el , and more than compensate for the higher specific investment costs.This indicates that policy instruments that favour small-scale renewable electricity production still play an important role as an incentive for their adoption.
Since the economics and effects on global GHG emissions of ORC systems have been analysed in different geographical settings and considering different future energy market scenarios, it can be concluded that small-scale electricity production with an ORC system could be an interesting investment in general, given the conditions set in this study.The variety of conditions considered offers a positive outlook for the increased adoption of ORC technology, as most of the use cases analysed have both economic and GHG reductions potentials.
Long-term policy measures can be necessary to stimulate investment in ORC systems, especially for smaller installed capacities.By investigating the conditions under which small-scale ORC systems are economically and environmentally viable, this study may help inform policymakers, manufacturers, and companies in understanding the potentials of the technology and increase the adoption of such systems.Future works could consider ORC systems operating at other temperature levels, and thus with different efficiencies, and analyse in more detail the effect of operating times on economic and environmental performance.

Fig. 1 .
Fig.1.Schematic diagram of an ORC system with the internal energy flows emphasised.The system is connected to a heat source (e.g., a boiler) on the hot side, and a heat discharge (e.g., the return flow of a district heating network) on the cold side.

Fig. 4 .
Fig. 4. Economic analysis of the installation of ORCs of different sizes (electrical power output) in three countries, including CO 2 emission charge, but excluding certificates for renewable electricity, electricity taxes and network costs.The economic feasibility is shown as NPV per kW of electrical power installed.The economic results are shown for three scenarios taken from (IEA, 2020b): Sustainable development (SD), Stated policies (SP) and Delayed recovery (DR).

Fig. 5 .
Fig. 5. Economic analysis of the installation of ORCs of different sizes (electrical power output) in three countries, including CO 2 emission charge, certificates for renewable electricity, electricity taxes and network costs.The economic feasibility is shown as NPV per kW of electrical power installed.The economic results are shown for three scenarios taken from IEA (2020b): Sustainable development (SD), Stated policies (SP) and Delayed recovery (DR).

Fig. 6 .
Fig. 6.Economic analysis of the installation of ORCs of different sizes (electrical power output) for the SE1 case.The economic feasibility is shown as NPV per kW of electric power installed for the scenarios with and without certificates for renewable electricity, taxes, and network fees in Sweden.

Fig. 7 .
Fig. 7. Economic analysis of the installation of ORCs of different sizes (electrical power output) for the SE2 case.The economic feasibility is shown as NPV per kW of electric power installed for the scenarios with and without certificates for renewable e electricity, taxes, and network fees in Sweden.

Fig. 8 .
Fig. 8. Lifecycle emissions reductions of ORCs in Sweden, the UK and Brazil, assuming three future energy market scenarios.The scenarios are based on the Sustainable development (SD) scenario, the Stated policy (SP) scenario, and the Delayed recovery (DR) scenario in World Energy Outlook 2020 (IEA, 2020b).The emissions reductions are shown as tonne of CO 2 -eq per kW of electrical power installed.

Table 1
Scenario inputs(IEA, 2020b)and resulting energy prices and emission factors for the countries studied.Pellets = co-firing in coal power plants.Charcoal = pig iron production.

Table 2
Electrical network costs and taxes and fees used for the economic calculations.Exchange rates used are 1 GBP = 1.127EUR, 1 SEK = 0.104 EUR, 1 BRL = 0.235 EUR.The prices shown are for customers using 2000-19 999 MWh annually for the UK and Sweden and average industrial customers in the regulated market for Brazil.