4E comparative analysis of energy transition scenarios for the decarbonization of a chocolate factory utilities in Brazil

The government of the state of Espírito Santo, Brazil, has established that minimizing emissions, by considering the natural gas as the best fossil fuel during the energy transition period, and energy efficiency are two of the four strategies for industries to competitively achieve the energy transition and decarbonization. In this framework, a major chocolate factory currently meets its chilled-water demand with electricity from the national grid and its hot-water demand with natural gas boilers. This study evaluates alternative configurations based on the integration of Organic Rankine Cycle (ORC) and/or Vapor Compression Refrigeration (VCR) systems, simultaneously generating electricity, chilled water and/or hot water. Three scenarios are proposed and comparatively evaluated using a 4E (energy, exergy, environmental, and economic) assessment. Thermodynamic and environmental modeling of the current and proposed scenarios was conducted using nominal and operational data, with simulations performed in EES software. Mass, energy, and exergy balances were carried out, along with associated CO₂ emissions. The economic analysis considered both operational costs and capital investments, the latter estimated through parametric equations for equipment sizing and costing. Feasibility indicators were applied, such as payback, net present value (NPV), and internal rate of return (IRR). The results indicate the VCR configuration, without ORC, as the most advantageous performance. This scenario requires an investment of US$ 2,679,612.19, resulting a payback period of 2 years and 3 months, an IRR of 51.40% and achieving the lowest CO₂ emissions (0.467 ton/h) due to the elimination of natural gas boilers, using total electrification of the process. Given the relatively low emission factors of the Brazilian interconnected electric grid and the competitive electricity tariffs, electrification of industrial utilities emerges as the most promising decarbonization pathway. Specifically, in this case, VCR simultaneously produces chilled and hot water with high efficiency and reduced environmental impact. Building on the conclusion that electrification is the most favorable option, new insights for research opportunities arise. Future studies could investigate the use of Photovoltaic Thermal (PVT) hybrid solar collectors for the simultaneous production of electricity and hot water, thereby reducing emissions, as well as the integration of energy storage systems to further enhance emission reductions.

1 Introduction

In pursuit of energy transition and decarbonization, the government of Espírito Santo, Brazil, developed the Espírito Santo’s Decarbonization and GHG Emissions Neutralization Plan (Governo do Estado do Espírito Santo, 2023b), officially joining the United Nations (UN) campaigns “Race to Zero” and “Race to Resilience.” Through this initiative, the state committed to implementing actions aimed at achieving greenhouse gas (GHG) emissions neutrality by 2050 and enhancing climate resilience. The executive summary of the plan (Governo do Estado do Espírito Santo, 2023a) provides a comprehensive overview of the pathways toward emissions neutrality in Espírito Santo, grounded in the guidelines, strategies, indicators, and targets established, as well as in data collected during the diagnostic phase. Furthermore, the plan identifies emission reduction and energy efficiency as two of the four main strategies for industries to remain competitive in advancing energy transition and decarbonization.

The plan delineates four thematic areas for the implementation of actions directed toward the decarbonization of Espírito Santo’s economy: (i) Energy and Industry; (ii) Transport; (iii) Waste; and (iv) Agriculture, Forestry, and Other Land Use (AFOLU). The focus of this study, the chocolate industry, is encompassed within the first domain, Energy and Industry. According to the Plan (Governo do Estado do Espírito Santo, 2023a), in 2021 Espírito Santo’s gross GHG emissions accounted for 1.4% of Brazil’s total emissions. Of this share, 56% originated from the state’s industry and energy sectors, whereas at the national level the same category represented only 23%. This disproportion highlights the strategic relevance of these sectors within the state and underscores the urgency of implementing targeted mitigation measures to align Espírito Santo with Brazil’s broader decarbonization commitments. Among the actions directed toward the energy transition, one specific strategy involves reducing emissions through the adoption of natural gas as an alternative fuel for industrial processes. Most industries in the state still rely on coal as their primary energy source, accounting for approximately 35% of the state’s total emissions. Therefore, this substitution alone could reduce emissions by about 50% in coal-based industries.

In the industrial sector, the pursuit of alternatives for energy transition and decarbonization is essential both to ensure compliance with environmental regulations and to mitigate the environmental impacts associated with industrial activities. This challenge is particularly significant for energy-intensive industries such as chocolate production, where substantial energy is required to support heating and refrigeration processes. Chocolate manufacturing comprises multiple stages that demand precise temperature control, including cocoa grinding, conching, tempering, and molding. Energy performance during these stages not only determines product quality but also exerts a direct influence on operational costs and the overall environmental footprint of the industry. Consequently, enhancing energy efficiency in chocolate production has become a priority.

Emerging technologies such as the Organic Rankine Cycle (ORC) and Vapor Compression Refrigeration (VCR) systems have demonstrated considerable potential to improve energy efficiency and reduce greenhouse gas emissions within this sector. Specifically, the ORC enables the conversion of waste heat into electricity through the use of organic working fluids, making it particularly suitable for processes where waste heat is available at moderate temperatures. Furthermore, the integration of ORC with refrigeration systems (ORC–VCR) provides comprehensive solutions capable of simultaneously meeting the demand for electricity, hot water, and chilled water in chocolate production.

The development of ORC–VCR systems originated in the 1970s and 1980s, a period marked by global energy crises that intensified the search for alternative energy solutions. Early efforts by Prigmore and Barber (1975) pioneered the integration of a solar-powered Rankine cycle with residential air-conditioning systems, employing fluids such as R-113a and R-22 to reduce electricity consumption. Building on this foundation, Biancardi et al. (1982), with support from the U.S. Department of Energy (DOE), advanced the concept by demonstrating a solar-driven Rankine cycle combined with a heat pump operating with R-11 as the working fluid. Despite promising coefficients of performance (COP) for both heating and cooling, the high capital costs of these systems curtailed their widespread adoption. Subsequent contributions, including those of Kaushik et al. (1994), shifted the focus toward optimization, incorporating innovations such as regenerative heat exchangers to enhance thermal efficiency in industrial cooling applications.

Over the past 2 decades, research on ORC–VCR systems has expanded considerably, with applications extending to commercial buildings, marine systems, and industrial plants. Notably, Aphornratana and Sriveerakul (2010) proposed an integrated ORC–VCR configuration employing a free-piston expander–compressor arrangement, achieving significant improvements in energy efficiency. More recent studies, such as Hu et al. (2022), have underscored the pivotal role of working fluid selection, stressing the importance of balancing thermodynamic performance with environmental sustainability in system design. To underscore the relevance and current state of research on ORC–VCR systems, notable studies have examined their operational performance (Li et al., 2013; Sabbaghi et al., 2025), while others have addressed thermoeconomic aspects, including cost allocation (Santos et al., 2022a; 2022b) and system diagnosis (Valero and Torres, 2023).

The ORC–VCR systems have been the subject of increasing investigation, typically categorized into coupled and decoupled configurations. In the coupled configuration, the ORC turbine directly drives the VCR compressor, offering compact system integration and potential efficiency gains (Mounier et al., 2017). By contrast, the decoupled configuration affords greater flexibility in working fluid selection and facilitates trigeneration, enabling the simultaneous production of electricity, heating, and cooling, thereby enhancing system versatility (Mounier et al., 2017). The choice between these configurations remains context-dependent, reflecting the trade-offs between efficiency, adaptability, and environmental impact mitigation. This ORC–VCR combination has also been widely investigated in various applications, as demonstrated in the studies conducted by Carmo et al. (2016); Eppinger et al. (2021); Jawad Al-Tameemi et al. (2019); and Song et al. (2022).

Beyond these configurations, cogeneration systems have also been considered a viable alternative, capable of generating electricity while supplying process utilities such as hot and chilled water. However, economic constraints have limited their deployment. For instance, Lourenço (2010) demonstrated that a gas turbine-based cogeneration system was rendered unfeasible by elevated natural gas costs. Similarly, Pereira (2024) evaluated biogas recovery from wastewater treatment in a chocolate factory, proposing electricity generation (58,400 kWh/year, approximately R$ 20,296 in revenues) and direct boiler combustion (1.02% savings, approximately R$ 32,540/year) as potential strategies, where R$ denotes the Brazilian real (BRL). Although boiler combustion offered superior financial returns, neither option was ultimately implemented.

In summary, ORC–VCR systems represent advanced solutions for enhancing energy efficiency, recovering waste heat, and enabling the combined generation of electricity, heating, and cooling. This literature review and historical contextualization highlight the evolution and application of ORC–VCR cycles over time, emphasizing their contributions to global energy efficiency and the advancement of sustainable industrial solutions.

A diagnostic assessment of the chocolate factory’s current production system, which produces both hot and chilled water, was conducted to identify opportunities for improving efficiency. Based on this analysis, three scenarios integrating Organic Rankine Cycle (ORC) and Vapor Compression Refrigeration (VCR) systems were developed. These configurations enable the simultaneous generation of surplus electricity, chilled water, and/or hot water and were evaluated using a 4E framework (energy, exergy, economic, and environmental) to quantify their technical, economic, and environmental performance.

Thermodynamic modeling was performed to assess system behavior through mass and energy balances, while environmental modeling focused on potential CO₂ emission reductions from substituting conventional energy sources with more efficient technologies. Simulations of both current and proposed scenarios were conducted using nominal and operational data in Engineering Equation Solver (EES) software (F-Chart Software, 2017). In addition, a detailed economic analysis evaluated investment costs and key feasibility indicators, including Payback Period, Net Present Value (NPV), and Internal Rate of Return (IRR).

The study highlights the importance of an integrated approach to energy transition and decarbonization, addressing both operational efficiency and compliance with increasingly stringent environmental regulations. Furthermore, the findings suggest that electrification is the most favorable strategy, providing a basis for exploring the use of Photovoltaic Thermal (PVT) hybrid solar collectors for the simultaneous production of electricity and hot water, as well as the integration of energy storage systems to further enhance emission reduction potential.

2 Plant description, diagnosis and proposed scenarios

This section presents the current system used to produce chilled and hot water to meet the production demands of the chocolate factory. A diagnostic assessment of the existing plant was conducted to identify potential improvements, which served as the basis for proposing three alternative scenarios.

2.1 Current scenario

In the current scenario, referred to here as Scenario A, the chocolate factory’s steam production system is described in terms of annual electricity demand, steam production at the boiler’s maximum operational capacity, and chilled water demand based on the refrigeration system’s characteristics. The factory primarily requires energy in the form of steam and electricity, which is supplied by an external power utility. A portion of the electricity is allocated to the refrigeration system (compression chillers), while the remainder serves general consumption, including machinery, offices, and lighting.

Between 2014 and 2019, energy consumption and occupancy remained stable; however, in 2020, consumption increased by 91%. A continuous rise is anticipated until 2026, highlighting the need to explore alternatives to meet the growing energy demand. The chocolate manufacturing process requires continuous thermal stages of heating and cooling, which are provided by chilled water from compression chillers and hot water from heat exchangers. The maximum daily cooling demand is 3820 refrigeration tons (RT), distributed among nine Chilled Water Plants. The combined system efficiency corresponds to an average coefficient of performance (COP) of 4.26, with a total thermal load of 13,408 kW and an average temperature difference of 6 °C.

The boiler system consists of two steam generators with an efficiency of 88%, capable of producing a maximum of 15 t/h of steam at 9 bar. Currently, there are 24 steam consumption points, mainly supplying heat exchangers. The existing system has several limitations, including energy losses in pipelines, alternating heating and cooling cycles, and long steam lines that cause condensation. Although the plant is complex, it has been simplified to provide a clear representation of energy flows.

The operational steam capacity is approximately 4000 kg/h (1.12 kg/s), with a hot water flow of 713 m³/h (198.05 kg/s). The boiler operates with natural gas having a density of 0.76 kg/m³ and a lower calorific value of 47,345.26 kJ/kg, corresponding to a natural gas mass flow of 0.236 kg/s and a steam mass flow of 4.17 kg/s.

In the current scenario, the systems for producing hot water (using natural gas as the energy source) and chilled water (supplied by grid electricity) operate independently, as illustrated in Figure 1a. Figure 1b depicts the system used specifically for hot water production from natural gas. Table 1 presents the values measured and calculated at the points indicated in Figure 1b. The temperature (T), pressure (p), and flow rate values were obtained from the plant’s instrumentation system, which provides typical operational data monitored by the factory operators through the supervisory control interface. Based on the p and T values, the corresponding enthalpy (h) and entropy (s) values were determined from thermodynamic tables using EES software.

Figure 1

Figure 1. (a) Current scenario and (b) detailed factory boiler and steam circuit.

Table 1

Table 1. Main parameters of the factory boiler and steam circuit.

Still within this scenario, chilled water production is provided by nine chilled water plants equipped with compression chillers with a combined cooling capacity of 13,408 kW (3820 RT), operating at an average COP of 4.26 and a temperature differential of 6 °C, resulting from evaporator temperatures ranging from 13 °C to 7 °C. For hot water production, the system employs 24 heat exchangers, delivering 2495 kW of hot water at 56,3 °C. For the exergy calculation, the reference conditions are ${\mathrm{T}}_0=298.15$ K and ${\mathrm{P}}_0=1$ bar.

Regarding the primary energy sources, the compression chillers consume 3192.38 kW of electricity from the grid, while the boilers utilize 2982.78 kW of natural gas. The steam generation system consists of two natural gas boilers, currently producing 2624.78 kW of steam. In terms of installed capacity, these boilers can collectively supply up to 9842.92 kW of steam.

2.2 Diagnostic

Based on the data and information provided in the plant description (Section 2.1), an energy and exergy analysis is conducted to diagnose potential opportunities for improvement in the current chocolate factory system. Analysis of Figure 1b and the data in Table 1 indicates that, from the total continuous energy input from natural gas (2982.7 kW), around 83.6% is effectively utilized for hot water production. Significant losses occur in the boiler (12%, 357.95 kW), heat exchangers (2.9%, 85.4 kW), and piping (1.5%, 44.4 kW). Energy is thus consumed and dissipated across multiple processes within the facility, with the boiler representing the largest source of losses, followed by the heat exchangers and piping.

Nevertheless, to complement this assessment, an exergy analysis is necessary to determine the maximum potential for natural gas utilization in hot water production. Exergy is defined as the maximum theoretical work that can be obtained from a system–environment interaction when the system reaches equilibrium with its surroundings (Moran et al., 2011), and it is calculated using Equation 1. Figure 2 illustrates the temperature versus heat (T vs. Q) diagram for the chocolate factory’s hot water production system. The boiler exergy production is determined between states 1 and 3 $\left(E_{1:3}\right.$), yielding 863.5 kW. Of this total, the exergy actually utilized to heat the water ($E_{4:5}$) amounts to only 252.7 kW. Equation 2 expresses the difference between the boiler exergy ($E_{1:3}$) and the exergy effectively used for water heating ($E_{4:5}$). This difference represents the irreversibility and, in this case, corresponds to the maximum power that could theoretically be harnessed for hot water production, resulting in an efficiency of only 29%. Consequently, this reveals a potential improvement of up to 610.8 kW of power.

$E_i={\dot{m}}_i\left\{\left(h_i-h_0\right)-T_0\left(s_i-s_0\right)\right\}(1)$

$Irreversibility=W_{\mathit{max}}=E_{1:3}-E_{4:5}(2)$

Figure 2

Figure 2. T vs. Q Diagram of the hot water production system.

These findings suggest that the current system, which relies on a heat exchanger to produce hot water from steam, operates with very low efficiency. A potential solution for enhanced energy recovery is to replace the heat exchanger with a power cycle in the hot water system. For example, alternative configurations, such as integrating an Organic Rankine Cycle (ORC) with a Vapor Compression Refrigeration (VCR) system, could be used. These combined systems can simultaneously generate surplus electricity, chilled water, and/or hot water. These configurations are further detailed in Section 2.3.

2.3 Proposed scenarios

Based on the improvement potential identified in the diagnostic exergy analysis, three scenarios were proposed for further investigation to enhance the efficiency of the chocolate factory’s hot water and chilled water production systems.

2.3.1 Scenario B: ORC-VCR

The first proposed configuration, here referred to as Scenario B- Figure 3, is derived from the diagnostic assessment of the plant’s current system and employs the ORC-VCR system in place of the heat exchanger used in Scenario A. In this scenario, the primary objective of the ORC is to generate power to drive the VCR system, which is responsible for producing hot water and a portion of the chilled water, while the remaining electricity is supplied to the compression chillers with the aim of reducing grid electricity consumption. This alternative is intended to avoid the use of heat exchangers for hot water production.

Figure 3

Figure 3. Scenario B: ORC-VCR system.

2.3.2 Scenario C: VCR

Scenario C, shown in Figure 4, no longer relies on natural gas as a fuel. Instead, electricity from the grid is used to power the compression chillers, which produce chilled water, and also the VCR system, which generates hot water as well as part of the chilled water.

Figure 4

Figure 4. Scenario C: VCR

2.3.3 Scenario D: ORC-VCR (chilled water only)

In Scenario D, shown in Figure 5, the entire power output of the ORC cycle is directed to the operation of the VCR system, thereby providing additional cooling capacity for the plant. In this configuration, the ORC cycle itself is responsible for producing hot water.

Figure 5

Figure 5. Scenario D: ORC-VCR (chilled water only).

To clarify the proposed scenarios (B, C, and D) and distinguish them from the current scenario (A), Figure 6 is used to highlight the main differences among them. By comparing Scenario A (Figure 1a) with Scenario B (Figure 6a), it can be observed that the heat exchanger is replaced by the ORC-VCR system. Furthermore, in Scenario B, the hot water and chilled water production systems are not independent, as part of the power generated by the ORC is used, together with grid electricity, to drive the compression chillers, and the VCR system produces both hot water and part of the chilled water. In this configuration, electricity consumption from the grid decreases, while natural gas consumption increases, following one of the specific strategies for emission reduction through the adoption of natural gas as an alternative fuel for industrial processes in the state of Espírito Santo (Governo do Estado do Espírito Santo, 2023a). The main differences between Scenario B and Scenario A are highlighted in red in Figure 6a.

Figure 6

Figure 6. Main differences between the proposed scenarios (a) Scenario B (b) Scenario C (c) Scenario D.

When comparing Scenario C with Scenario A, it can be observed in Figure 6b, highlighted in red, that that natural gas is no longer used, while electricity consumption from the grid increases to supply both the compression chillers and the VCR system for hot and chilled water production. The exclusion of natural gas is intended to assess its impact on the system’s emissions.

In Scenario D, the heat exchangers from Scenario A (Figure 1a) are also replaced by the ORC-VCR system. However, all the power generated by the ORC is consumed by the VCR system, which produces only chilled water, while the ORC is responsible for the entire production of hot water, as highlighted in red in Figure 6c. In this case, natural gas consumption increases, while electricity consumption from the grid decreases in comparison with Scenario A.

3 Methodology

Based on the nominal and operational data, thermodynamic and environmental modeling of the current and alternative scenarios was performed, yielding mass, energy, and exergy balances, as well as CO₂ emissions, using the EES software (F-Chart Software, 2017). The economic analysis was conducted considering operational costs and employing a parametric equation method to estimate equipment costs, thereby determining the total initial investment and enabling the calculation of feasibility indicators, including payback period, net present value, and internal rate of return. Further details on the entire methodology can be found in Gonçalves (2024) master’s thesis.

3.1 Thermodynamic evaluation

The thermodynamic model was developed using the first law of thermodynamics and implemented in the Engineering Equation Solver (EES), which efficiently handles sets of equations through iterative procedures. The proposed scenarios, derived from the current configuration of the chocolate factory, incorporate the ORC–VCR arrangement with specific variations in their production objectives.

The ORC–VCR system is composed of two distinct subsystems, as illustrated in Figure 7: the ORC cycle (1–6–3–5–1) and the VCR cycle (15–16–17–19-15). The ORC operates as the primary system, in which the heat source transfers energy to the working fluid, causing it to vaporize in the evaporator. The steam then passes through the expander, where it is converted from high-pressure steam to low-pressure steam, producing shaft power that drives the compressor and possibly the generator. After expansion, the low-pressure gas must be condensed, rejecting heat and returning the fluid to the liquid state. Finally, the fluid is pumped back to the evaporator to restart the cycle (Liang et al., 2019). The VCR operates as the secondary system. Its operating principle involves the use of mechanical power to drive the compressor, which pressurizes the working fluid to a high-pressure state. The resulting vapor then passes through the condenser, where it exchanges heat with the surroundings, after which the liquid flows through an expansion valve, where throttling occurs. Finally, the vapor flows through the low-pressure evaporator, removing heat from the environment and thereby producing cooling capacity (Wang et al., 2015).

Figure 7

Figure 7. ORC-VCR system.

The thermal boundary conditions adopted in the model for the simulated scenarios are illustrated in Figure 7. The boiler supplies saturated steam at 9 bar and 175 °C (point 8) to the ORC evaporator and receives condensate at 98 °C (point 7). The operating parameters of the ORC condenser depend on its functional purpose in each scenario. In Scenario B, the condenser operates as a heat-rejection device, with cooling water temperatures ranging from 25 °C to 35 °C (points 9 and 10). Conversely, in Scenario D, the condenser functions as a heat-recovery unit, operating between 53.3 °C and 56.3 °C (points 9 and 10) to supply hot water. The VCR system evaporator operates with chilled-water temperatures between 13 °C and 7 °C (points 21–23) in all scenarios, aiming to produce chilled water for cooling purposes. The VCR condenser (points 22–20) operates with hot water between 53.3 °C and 56.3 °C in Scenarios C and B, whereas in Scenario D it rejects heat to the cooling water circuit, with inlet and outlet temperatures ranging from 25 °C to 35 °C. Regarding chiller performance, the influence of part-load operation is negligible, as multiple chillers are employed and any reduction in chilled-water demand results in the shutdown of some units.

It should be noted that the chilled and hot water demands considered in this study pertain to industrial processes rather than space conditioning or district heating, and are therefore minimally influenced by environmental conditions.

There are two main configurations for the ORC–VCR system: coupled and uncoupled. In the coupled one, the ORC turbine directly drives the VCR compressor, meaning that both cycles are mechanically linked and share the same shaft. In the uncoupled configuration, the ORC and VCR cycles are connected via an electrical transmission, allowing each cycle to use an independent working fluid. In summary, the coupled configuration offers compactness and the potential for higher overall energy efficiency, whereas the uncoupled configuration provides greater fluid flexibility. However, each configuration has its own drawbacks, such as fluid restrictions and increased complexity and cost, respectively. The choice between coupled and uncoupled systems depends on the specific requirements and constraints of the project (Mounier et al., 2017).

Regarding the working fluid of the systems, Macchi and Astolfi (2017) note that its selection influences the thermodynamic cycle, performance, and the cost of components (such as the expander and heat exchangers), as well as the plant layout and safety requirements. Moreover, the choice of working fluid is conditioned by the temperature of the heat source considered in the study.

In the present modeling, the electromechanical efficiency of the electric generator is 0.95 and the isentropic efficiencies of the pump, expander and compressor are 0.9, 0.85 and 0.70, respectively, consistent with the values reported by Wang et al. (2015), Hu et al. (2022) and Asim et al. (2017). Typical heat transfer coefficients for shell-and-tube heat exchangers are assumed to be 1 kW/m²·K for the condenser and 1.1 kW/m²·K for the evaporator.

Based on the optimization results reported by Morawski et al. (2021) and de Araújo et al. (2022), n-pentane was selected as the working fluid for the ORC, covering the same evaporation and condensation temperature range. For the VCR system, R134a was adopted due to its environmental compatibility, as it does not harm the ozone layer, and its physical and thermodynamic properties closely resemble those of CFC-12, making it a suitable alternative (Jawad Al-Tameemi et al., 2019).

Using these parameters, the thermodynamic properties at each point in the cycle are determined. The modeling follows the configuration described by Liang et al. (2019) and Saleh (2016). The following assumptions are adopted.

1. The system operates under steady-state conditions, and all equipment is considered adiabatic.

2. Variations in kinetic and potential energies are neglected, and heat and frictional losses to the environment are considered negligible relative to other energy changes.

3. Pressure drops in heat exchangers and piping are disregarded.

4. The working fluid in the ORC exits the condenser as a saturated liquid and enters the turbine as a saturated vapor.

5. Isentropic efficiencies for the pump and turbine are included in the calculations.

6. The working fluid in the VCR entering the compressor is a saturated vapor and exits the condenser as a saturated liquid.

7. The expansion valve process is assumed adiabatic.

The ORC–VCR system was modeled at the design point to evaluate its technical feasibility, while the remaining components of the existing system were simulated under standard operating conditions.

Component modeling is based on the conservation of mass and energy and efficiencies–Equations 3–20 with detailed information summarized in Table 2. $Q$ represents the heat transfer rate, $h_i$​ the specific enthalpy at each point, ${\dot{m}}_i$​ the mass flow rate at each point, $c_p$​ the specific heat at constant pressure, $\eta$ the efficiency, $\Delta T$ the temperature variation, $w$ the work, and COP the coefficient of performance. Further details on the terms of each equation can be found in Section 6 - Nomenclature.

Table 2

Table 2. Mass and energy balances and efficiencies equations applied to ORC-VCR systems.

The heat transfer areas were determined using the Logarithmic Mean Temperature Difference (LMTD) method, assuming a counterflow configuration. The LMTD is evaluated according to Equation 21.

$\Delta T_{LMTD}=\frac{\Delta T_1-\Delta T_2}{\mathit{ln}\left(\frac{\Delta T_1}{\Delta T_2}\right)}(21)$

where $\Delta T_1$ and $\Delta T_2$​ denote the maximum and minimum temperature differences in the evaporator and condenser heat exchangers, respectively. The corresponding heat transfer area (S) is calculated according to Equation 22, where U is the overall heat transfer coefficient.

$S=\frac{Q}{U·\Delta T_{LMTD}}(22)$

3.2 Economic assessment

The cost analysis of equipment in chemical plants often follows the methodology proposed by Turton et al. (2012), which provides estimates from acquisition through installation. This approach has been applied in recent studies, including Zhar et al. (2021) and Mounier et al. (2017), for the economic assessment of ORC–VCR system configurations, supporting its adoption in the present work. Furthermore, Morawski (2021) validated the parametric cost equations proposed by Turton et al. (2012) using commercial data for ORC investment costs. The base equation for estimating the acquisition cost of equipment $\left(C_P^0\right)$, assuming ambient pressure operation and carbon steel construction, is expressed in Equation 23.

${C_P^0=K}_1+K_2{\mathit{log}}_{10}\left(A\right)+K_3{\left[{\mathit{log}}_{10}\left(A\right)\right]}^2(23)$

Where A denotes the capacity or size parameter of the equipment. Different equipment types, including pumps, turbines, compressors, and heat exchangers, have specific coefficients $\left(K_i\right)$ provided by Turton et al. (2012). To account for variations in materials and operating pressures, appropriate correction factors are calculated by Equation 24.

${{\mathit{log}}_{10}F}_P=C_1+C_2{\mathit{log}}_{10}\left(p\right)+C_3{\left[{\mathit{log}}_{10}\left(p\right)\right]}^2(24)$

Where $p$ represents the operating pressure of the equipment. Typical values of $\left(C_i\right)$​and the corresponding correction coefficients are tabulated for various equipment types and can be found in Turton et al. (2012).

In addition to the capital expenditure for equipment acquisition, further costs must be considered, including installation, auxiliary materials, instrumentation, structural components, piping, and labor. Indirect expenses such as transportation, insurance, and engineering services are likewise incorporated. To account for these, the bare module factor ($F_{BM}$) is applied, which aggregates both direct and indirect investment costs and is multiplied by the equipment cost (Turton et al., 2012).

When the equipment is not constructed from carbon steel, a material factor ($F_M$) must also be applied. This coefficient, obtained from reference tables, varies according to both the equipment type and the construction material. The resulting bare module cost ($C_{BM}$) thus represents the sum of all direct and indirect expenditures (Turton et al., 2012), as expressed in Equations 25, 26.

$C_{BM}=C_p^0.F_{BM}(25)$

$F_{BM}=B_1+B_2+\left(F_M.F_p\right)(26)$

Where the B_i ​coefficients depend on the type of equipment (Turton et al., 2012). For existing thermal plants, additional fees and contingency costs are typically included, corresponding to 3% and 15% of the bare module cost, respectively. The total investment cost is then calculated by Equation 27.

$C_{TM}=1.18{\displaystyle \sum _{i=1}^n}{C}_{BM,i}(27)$

Costs originally estimated for 2001 are updated using the Chemical Engineering Plant Cost Index - CEPCI (Chemical Engineering, 2023) according to Equation 28.

$C_{TM}^{2022}=C_{TM}^{2001}\frac{{CEPCI}_{2022}}{{CEPCI}_{2001}}(28)$

with CEPCI₂₀₀₁ = 397 and CEPCI₂₀₂₂ = 821.3.

In this study, the Net Present Value (NPV), Payback, and Internal Rate of Return (IRR) indices are used to evaluate the economic feasibility of the investments. The analysis considers an interest rate, estimated future cash flows, and the useful life of the investment. Equation 29 defines the Capital Recovery Factor (CRF), which is subsequently used to compute the Net Present Value (NPV) according to Equation 30. The operation and maintenance factor $\left({\mathrm{F}}_{\mathrm{O}\&\mathrm{M}}\right)$ was set at 6%. This parameter is incorporated into the Capital Recovery Factor (CRF), resulting in a value of 0.16, obtained from Equation 29, which was used for the subsequent economic analysis.

$CRF=\frac{j{\left(1+j\right)}^t}{{\left(1+j\right)}^t-1}(29)$

$\text{NPV}=\frac{ACF}{CRF}-I.\left(1+\frac{{\mathrm{F}}_{\mathrm{O}\&\mathrm{M}}}{100}\right)(30)$

Where (ACF) denotes the annual cash flows of the investment, which may represent either costs or revenues and (I) is the project investment value. Herein, j corresponds to the minimum attractive rate of return, set at 15%, and t represents the equipment lifetime, assumed to be 20 years. In addition, an annual dispatch time of 8760 h was considered. These values were selected according to the design engineering criteria already established within the factory under study.

The Internal Rate of Return (IRR), given by Equation 31, corresponds to the discount rate at which the present value of future cash inflows equals the initial investment, i.e., the rate that yields a Net Present Value (NPV) of zero. An investment is considered feasible if the IRR exceeds the Minimum Attractive Rate of Return (MARR), as it then outperforms the benchmark profitability.

$IRR=\left(\frac{ACF}{I.\left(1+\frac{{\mathrm{F}}_{\mathrm{O}\&\mathrm{M}}}{100}\right)}\right).100(31)$

The Total Investment Cost (TIC) represents the comprehensive sum of all expenses associated with a project, encompassing both initial and ongoing expenditures. In other words, it defines the maximum amount that can be allocated while maintaining investment feasibility, as expressed in Equation 32.

$\text{TIC}=NPV+I.\left(1+\frac{{\mathrm{F}}_{\mathrm{O}\&\mathrm{M}}}{100}\right)(32)$

Payback is employed to estimate the period required to recover the capital invested in a project, that is, the time needed to offset the initial investment. There are two main types of payback: simple and discounted. The simple payback does not account for the time value of money, whereas the discounted payback does, applying an interest rate to adjust cash flows over time. However, investment returns are neither fixed nor linear, and the value of money decreases as time progresses. For this reason, simple payback should not be adopted as the basis for decision-making in economic feasibility studies.

The discounted payback period is defined as the time required for the cumulative present value of the project’s cash inflows to equal or exceed the initial investment cost. This metric is closely related to the NPV criterion. While the discounted payback focuses on the time required for the recovery of the investment, the NPV captures the total net economic value created after accounting for both the recovery of the initial cost and the time value of money. A positive NPV implies that the discounted payback period will be achieved within the project horizon, whereas a negative NPV indicates that the discounted payback will not occur.

The investment cost plays a central role in both measures. In the case of the discounted payback, it serves as the reference threshold that must be offset by the present value of cumulative cash inflows. In the case of the NPV, it represents the initial deduction against which the net discounted cash inflows are compared. Therefore, while the discounted payback provides a temporal measure of investment recovery, the NPV evaluates the magnitude of value creation beyond that recovery.

3.3 Electricity and natural gas input costs

The factory relies on natural gas and electricity as its primary inputs. Natural gas is priced at a standard industrial rate of 2.94 R$/m³ according to the Regulatory Agency for Public Services of Espírito Santo (Agência de Regulação de Serviços Públicos do Espírito Santo, 2023), where R$ denotes the Brazilian real (BRL). The analyses were conducted considering an exchange rate of BRL 4.88 per USD.

The annual cost of natural gas ($C_{ng}$) is determined using Equation 33, which accounts for the unit cost of natural gas ($T_{ng}$, in R$/m³), the annual dispatch ($D_A$, fixed at 8760 h/year), and the variation in natural gas flow among scenarios ($V_{ng}$, in m³/h).

$C_{ng}={\mathrm{T}}_{ng}.D_A.V_{ng}(33)$

In the industrial sector, classified under High and Medium Voltage, electricity billing follows a binomial tariff structure, which includes two components: consumption (kWh) and demand (kW). Accordingly, the total annual electricity cost corresponds to the sum of these two components, as defined in Equation 34.

Electricity demand contracted with the utility is seasonal and varies by time of day. The peak period typically occurs from 18:00 to 21:00, while the off-peak period covers 00:00–17:59 and 21:00–23:59. On Saturdays, Sundays, and public holidays only off-peak rates apply. In other words, on weekdays, the peak period corresponds to 3 h, and the off-peak period to 21 h, whereas on weekends and holidays the peak period is null and the off-peak period totals 24 h. Based on these definitions, a monthly average of peak and off-peak hours was used.

According to data from the local electricity utility (EDP, 2023), industrial consumers may choose between two tariff options—blue and green—depending on their operational profile. This study used the blue tariff, which applies two distinct demand charges depending on the period (peak or off-peak) and a single rate for energy consumption regardless of the time of day. In addition to the distinct demand charges applied during peak and off-peak periods, there is a single tariff value for electricity consumption. According to The Brazilian Electricity Regulatory Agency Homologatory Resolution No. 3241 (Aneel and Nacional de Energia Elétrica, 2023), the demand tariff during the peak period is 31.53 R$/kW, while during the off-peak period it is 43.23 R$/kW. The consumption tariff is 0.12177 R$/kWh. The demand represents the power capacity required to meet electricity needs during specific periods and is expressed in kilowatts (kW). In contrast, consumption refers to the actual amount of energy used over time, measured in kilowatt-hours (kWh). A typical electricity bill records the total monthly energy consumption along with the corresponding demand charges.

$C_{Elet}=C_d+C_c(34)$

$C_d$ denotes the annual demand cost (R$), calculated using Equation 35. The off-peak unit rate ($T_a$, R$/kW) and peak unit rate ($T_b$, R$/kW) are applied in conjunction with the electricity produced or consumed in each scenario ($E_{Elet}$, kW). In conventional electricity billing, costs are determined monthly and must be multiplied by 12 to obtain the annual value. $C_c$ represents the annual consumption cost (R$), calculated using Equation 36, where $T_c$ is the unit tariff (R$/kWh). As consumption is expressed in kWh, the formula is multiplied by 720 h per month and by 12 to yield the annual cost. These equations are essential for evaluating electricity costs across different scenarios.

$C_d=\left(T_a+T_b\right).E_{Elet}.12(35)$

$C_c=\left(T_c.E_{Elet}.720\right).12(36)$

3.4 CO₂ emission factors for natural gas and electricity

For natural gas, the emission factor provided by The Intergovernmental Panel on Climate Change - IPCC, 2023 is used to estimate CO₂ emissions for each scenario in the environmental analysis. This value is widely recognized for its credibility and comprehensiveness, as it is based on extensive scientific literature reviews and regularly updated to reflect advances in research, technology, and industrial practices. It is commonly applied to quantify CO₂ emissions from specific activities, such as electricity generation, ensuring that environmental assessments and related decision-making rely on accurate and up-to-date information. The natural gas emission factor is 201.96 kg CO₂/MWh.

For the analysis of CO₂ emissions in the electricity sector, data on the CO₂ emission factor for electricity generation in Brazil, spanning the period from 2011 to 2023 and provided by the National Emissions Registry System–SIRENE (Ministério da Ciência, 2024), were initially employed, as illustrated in Figure 8. According to Espírito Santo’s Decarbonization and GHG Emissions Neutralization Plan (Governo do Estado do Espírito Santo, 2023b), emissions associated with electricity imports are determined by the composition of the national generation matrix and are influenced by the operational requirements of thermoelectric plants to meet domestic demand, which accounts for the observed interannual variability. A CO₂ emission factor of 0.135 tons per MWh was considered in this study, corresponding to the year 2014, the period with the highest recorded value in recent years.

Figure 8

Figure 8. CO₂ emission factor for electricity generation in Brazil (Ministério da Ciência, 2024).

4 Results and discussions

This section presents the results of the thermodynamic, economic, and environmental analyses based on the methodological assumptions. Each scenario is designed to produce hot water for process requirements while concurrently generating chilled water to supplement the existing cooling system.

4.1 Thermodynamic analysis

The thermodynamic evaluation is based on the mass and energy balances for each scenario, including their specific characteristics, as presented in Section 3.1.

4.1.1 Scenario B

In the VCR cycle, the rejected heat is recovered for end-use, with a portion of the ORC power driving the VCR and the surplus for the compression chillers. The ORC operating parameters include a useful heat input of 9842.92 kW and a mass flow rate of 4.17 kg/s, with steam circuit temperatures ranging from 175 °C to 98 °C at the evaporator and from 25 °C to 35 °C at the condenser. In the VCR cycle, the recovered heat satisfies the hot water demand, from 53.3 °C to 56.3 °C at the condenser, and with inlet and outlet temperatures ranging from 13 °C to 7 °C at the evaporator. The results are summarized in Table 3. With this VCR cycle configuration, the factory gains an additional cooling capacity of 1801 kW.

Table 3

Table 3. Main characteristics of Scenario B.

4.1.2 Scenario C

In comparison with Scenario A, the VCR substitutes the steam generated by the boiler, supplying hot water for heating purposes. Furthermore, the VCR provides chilled water, thereby complementing the factory’s existing cooling system. To enable the isolated assessment of the VCR configuration (Scenario C), the VCR of Scenario B serves as the reference case.

4.1.3 Scenario D

In Scenario D, the ORC cycle operates with a useful heat input of 2866 kW, a heat rejection of 2495 kW, and a working fluid mass flow rate of 1.21 kg/s. The ORC evaporator operates with steam circuit inlet and outlet temperatures of 175 °C and 98 °C, respectively, while the condenser operates between 53.3 °C and 56.3 °C. System operation is sustained by regulating the boiler steam supply to satisfy the specific heat rejection requirements. The total power output of the ORC cycle is allocated to drive the VCR, thereby enhancing the plant’s cooling capacity. The results are summarized in Table 4.

Table 4

Table 4. Main characteristics of Scenario D.

The ORC cycle additionally supplies hot water for process requirements. The supplementary cooling capacity delivered by the VCR was quantified at 2043 kW (582 TR).

4.2 Energy consumption

Based on the configuration of each scenario, Table 5 presents electricity consumption, natural gas consumption, and their combined totals for all cases evaluated: the current configuration (A) and the proposed alternatives (B, C, and D). These values are also illustrated in Figure 9.

Table 5

Table 5. Energy consumption for each scenario.

Figure 9

Figure 9. Energy consumption (kW) for each scenario.

Scenario C (VCR only), which relies exclusively on electricity, exhibits the lowest overall consumption at 3457.47 kW, representing a 44% reduction compared to the current configuration (A). This option may be particularly advantageous when accompanied by economic and environmental benefits. In contrast, Scenario B (ORC–VCR) shows the highest total consumption at 13,064.50 kW, primarily due to the extensive use of natural gas. Nevertheless, this configuration may still be economically viable under specific incentive policies, despite entailing a 111% increase relative to Scenario A. Scenario D (ORC–VCR for chilled water only), which combines electricity and natural gas, represents an intermediate and balanced configuration. Overall, these results provide the foundation for scenario comparison and input cost estimation.

The data presented in Table 5 and Figure 9 show the factory’s primary energy demands in each of the scenarios analyzed, required to supply hot water (2495.43 kW) and chilled water (13,408 kW). Table 6 presents the intermediate values obtained from the energy balance for the other system components in each scenario.

Table 6

Table 6. Energy flows (kW) in each scenario.

4.3 Economic assessment

The analysis began with an assessment of the investment costs for each proposed scenario. In Scenario B, the cost of the thermal equipment for the ORC–VCR cycle was estimated using the methodology proposed by Turton et al. (2012), with all values updated to 2022. The resulting total cost was US$ 6,567,685.64. For investment analysis, the costs of the ORC and VCR subsystems were also evaluated separately to provide a clearer understanding of their individual contributions to the overall system cost.

In Scenario C, the total cost of the VCR cycle components was estimated at US$ 1,097,687.17. Contingency and fee adjustments were subsequently applied following the same procedure adopted in Scenario B and updated according to the 2022 CEPCI index. After incorporating these adjustments, the total investment reached US$ 2,679,612.19. This significant increase highlights the influence of indirect costs on the overall investment requirements.

In Scenario D, the total equipment cost of the ORC–VCR system, calculated according to the methodology of Turton et al. (2012) and updated to 2022 values, amounted to US$ 4,333,141.61, of which US$ 2,136,109.86 corresponds exclusively to the ORC subsystem. The cost distribution indicates that, although the combined ORC–VCR configuration requires a higher capital investment than the isolated VCR cycle, it may offer compensating advantages in terms of thermal integration and energy recovery potential, as discussed in the following sections.

Based on the specific configurations of each scenario, an initial comparison of electricity consumption was performed, classifying the outcome either as an expense or as revenue. An expense indicates an increase in electricity consumption, whereas revenue represent a reduction. The comparative analysis of the scenarios aims to determine the optimal configuration of the ORC and/or VCR system for the factory, considering energy efficiency, emissions, and costs. This assessment is essential for identifying the most advantageous alternative from both economic and environmental perspectives.

Table 7 provides a summary of the expenses, revenues, and investment costs associated with each scenario. In the comparison between Scenarios A and C, revenues arise from natural gas savings, whereas in the remaining scenarios, expenses are driven by increased natural gas consumption, with revenues instead resulting from energy generation. The comparison between scenarios in Table 7 is denoted by pairs such as A–C, which, for example, represents the comparison between Scenario A and Scenario C.

Table 7

Table 7. Information on input-related expenditures and revenues for each scenario.

Based on the total costs of each project, several economic evaluation methods are employed, such as the discounted payback period, net present value (NPV), and internal rate of return (IRR).

Initially, the revenue and expense values for both electricity and natural gas are combined to obtain the net revenue or expenditure for each comparative scenario. When applying the NPV method, a result lower than zero indicates that the project is not economically feasible. In other words, it is unnecessary to apply the remaining economic indicators, as they would all yield negative values, confirming the project’s infeasibility. Table 8 presents these results, showing that only Scenario A- C yields a positive NPV. Therefore, it can be concluded that the revenue generated over the project’s lifetime is sufficient to recover the initial investment, confirming the project’s economic feasibility. Consequently, a more detailed analysis is carried out for Scenario C.

Table 8

Table 8. Initial NPV-based analysis of the comparative scenarios.

The results presented in Table 7 and Table 8 indicate that only Comparative A–C yields a positive NPV, confirming its economic viability. The internal rate of return (IRR) for this case is approximately 51.40% per year, exceeding the Minimum Attractive Rate (MAR) of 15% per year and thus reinforcing the feasibility of the investment. Considering the applied discount rate, the discounted payback period is 2.23 years, indicating that the VCR investment is capable of recovering the initial capital outlay within a relatively short timeframe. Therefore, the project is considered economically viable.

In contrast, the other comparisons (A- B, A- D) present negative NPVs, indicating economic infeasibility, largely attributable to the influence of natural gas costs on net revenues. An alternative, therefore, would be to examine whether a reduction in the natural gas rate could yield a positive NPV and, consequently, make the other scenarios feasible. As shown in Table 7, the proposed scenarios (B, C, and D) were initially compared with the current configuration of the factory (Scenario A), resulting in the following comparisons: A–C, A–B, and A–D. As Scenario C was the only one found to be economically feasible, it was subsequently compared with Scenarios B and D (i.e., C–B and C–D). Scenarios B and D include an ORC unit and are therefore classified as cogeneration systems. In Brazil, cogeneration systems can be eligible for a 58% discount on the natural gas price (Chun et al., 2021). Nevertheless, even when this reduced price was applied, the NPVs of Scenarios B and D remained negative. This result indicates that, even with a reduction in natural gas prices, the projects would still not be economically feasible.

4.4 Environmental assessment

The environmental assessment encompassed the analysis of CO₂ emissions associated with electricity consumption and/or natural gas combustion in each scenario. Based on IPCC guidelines (Intergovernmental Panel on Climate Change - IPCC, 2023), a natural gas emission factor of 201.96 kg CO₂/MWh was adopted. The corresponding direct emissions were estimated by multiplying the energy demand in kilowatts (kW) (as presented in Figure 9) by this factor. The results are expressed as CO₂ emissions in tons per hour, represented by the blue bars in Figure 10.

Figure 10

Figure 10. Total hourly CO₂ emissions across various scenarios [ton CO₂/hour].

As shown in Figure 10, Scenario A serves as the reference case, emitting 0.602 tons of CO₂ per hour. Scenario C, which operates exclusively on electricity, produces no CO₂ emissions and therefore represents the most environmentally sustainable alternative. In contrast, Scenario B emits 2.258 tons of CO₂ per hour, indicating a substantial environmental burden, while Scenario D emits 0.656 tons of CO₂ per hour, positioning it as a moderate alternative.

With respect to electricity consumption, the emission factors presented in Figure 8 were applied. For this analysis, a factor of 0.135 tons CO₂/MWh was adopted, corresponding to the year 2014, which represents the highest value recorded in recent years. This choice allowed for a worst-case assessment of maximum emissions. Hourly emissions were calculated by multiplying this factor by the electricity consumed in each scenario, with results illustrated by the green bars in Figure 10. In this case, the emissions are classified as indirect, as electricity in Brazil is supplied through a fully interconnected national grid, with emissions being attributed to consumption processes.

When total emissions are considered, Scenario C presents the lowest rate among the evaluated configurations, confirming that the installation of a VCR system is an effective strategy for reducing overall CO₂ emissions. As depicted in Figure 10, implementation of Scenario C results in a reduction of 0.566 tons CO₂/h compared to Scenario A, corresponding to a 54.83% decrease.

In contrast, Scenario B exhibits the highest total emissions among all alternatives, with a 143% increase relative to the current configuration (A). This outcome demonstrates that Scenario B is not a viable choice from an environmental perspective.

Finally, comparing Scenario D with Scenario A reveals only a minor variation in total emissions, amounting to 0.012 tons CO₂/h. This marginal difference indicates that implementing the ORC–VCR system (with the VCR dedicated solely to chilled water production) would not lead to a significant increase in CO₂ emissions, and thus remains environmentally comparable to the current configuration.

In summary, when analyzing the current operating conditions of the chocolate factory under the three proposed scenarios—considering electricity consumption, natural gas use, economic performance, and environmental impacts—Scenario C (Figure 6b) emerges as the most advantageous solution. This configuration prioritizes system electrification by fully replacing natural gas consumption and employing a VCR cycle to generate both hot water and chilled water. Scenario C achieves the lowest energy demand, representing a 44% reduction compared to Scenario A, and is the only configuration that proves economically viable, with a discounted payback period of 2.23 years. Furthermore, it yields the lowest CO₂ emissions, 54% lower than those of Scenario A, thereby contributing to The Decarbonization Plan of the State of Espírito Santo.

These results reflect the advantages of the Brazilian electricity matrix, which is predominantly hydropower-based, leading to both low emission factors for the interconnected national grid and relatively low electricity prices. Even in the least favorable year (2014), the grid emission factor was 135 kg CO₂/MWh, whereas the emission factor for natural gas is 201.96 kg CO₂/MWh. This discrepancy highlights the environmental and economic benefits of electrification over natural gas use in the Brazilian context. Therefore, even electricity generation from natural gas in a system operating at 100% efficiency would still have a higher emission factor than that of the national grid and would emit more overall. These findings support the selection of Scenario C as the most favorable option, both environmentally and economically, providing a clear basis for the conclusions drawn in this study.

For international comparison, Brazil holds a clear advantage: in the European Union, the electricity grid emission factor was reported at 300 kg CO₂/MWh (Ajanovic and Haas, 2019), while the U.S. average grid factor reached 386 kg CO₂/MWh (U.S. Energy Information Administration, 2021).

5 Conclusion

This study conducted a comprehensive 4E (energy, exergy, economic, and environmental) assessment of alternative configurations for meeting the thermal demands of a large chocolate factory in Brazil. Based on an energy and exergy diagnostic of the current system to identify improvement opportunities, three scenarios integrating ORC and/or VCR technologies were compared with the existing configuration.

Given the low emission factors of Brazil’s interconnected national grid and its competitive electricity prices, the electrification of industrial utilities emerges as a promising decarbonization strategy. In this context, the exclusive adoption of a VCR system (Scenario C) for the simultaneous production of chilled and hot water represents the most advantageous pathway. This scenario eliminates natural gas consumption while requiring 3457.47 kW of electricity, representing a 44% reduction in overall energy demand compared to the baseline, and achieves the lowest CO₂ emissions at 467 kg per hour of CO₂ (a 54% reduction), attributable to the low emission factor of the grid. Economically, Scenario C is the only option with positive feasibility indicators, with an investment cost of US$ 2,679,612.19 and a discounted payback period of 2.23 years.

In contrast, the scenarios involving ORC–VCR integration (B and D) proved to be environmentally or economically unfeasible under the current conditions, mainly due to the high cost and emission intensity of natural gas. Even when accounting for a potential reduction in the natural gas tariff for cogeneration purposes, these configurations remained economically unattractive.

Nevertheless, the use of natural gas remains an important component of the energy transition in Espírito Santo, where most industries still rely on coal, which accounts for about 35% of the state’s total emissions. Replacing coal with natural gas could therefore reduce these emissions by approximately 50% in coal-based industries. However, in the specific case of the chocolate factory analyzed in this study, which requires low-temperature heat production, electrification remains the more advantageous option, given the low emission factor of the national interconnected electricity grid. In fact, the factory under study has already acquired and implemented a VCR system manufactured by Mayekawa, which is currently in operation.

Beyond the scope of this analysis, there are opportunities to further enhance the decarbonization potential of Scenario C, such as the integration of photovoltaic-thermal (PVT) hybrid solar collectors for the simultaneous generation of electricity and hot water, as well as the adoption of energy storage systems to optimize operational flexibility while further reducing grid-related emissions. Future research could also expand the application of the 4E methodology to other energy-intensive industrial sectors in Brazil, thereby contributing to a broader understanding of industrial decarbonization strategies.

Data availability statement

The original contributions presented in the study are included in the article/supplementary material, further inquiries can be directed to the corresponding author.

Author contributions

AG: Data curation, Formal Analysis, Investigation, Methodology, Software, Writing – review and editing. FF: Data curation, Formal Analysis, Methodology, Software, Writing – review and editing. AM: Data curation, Investigation, Writing – review and editing. PF: Data curation, Visualization, Writing – original draft, Writing – review and editing. JS: Conceptualization, Formal Analysis, Supervision, Validation, Writing – review and editing.

Funding

The authors declare that no financial support was received for the research and/or publication of this article.

Acknowledgements

This work did not receive any specific funding. However, the authors would like to acknowledge ANP, FAPES, CAPES, and CNPq for the scholarships and research grants.

Conflict of interest

The authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

Generative AI statement

The authors declare that no Generative AI was used in the creation of this manuscript.

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Glossary

A Size parameter of the equipment

ACF Annual cash flow

AFOLU Agriculture, Forestry, and Other Land Use

B Type of equipment coefficients

BRL Brazilian real

${\mathit{c}}_{\mathit{p}}$ Specific heat [kJ/kg.K]

C Cost [USD]

CEPCI Chemical Engineering Plant Cost Index

COP Coefficient of performance

CRF Capital Recovery Factor

D Dispatch [h/year]

E Exergy [kW]

EES Engineering Equation Solver

F Module factor

GHG Greenhouse Gas

h Specific enthalpy [kJ/kg]

I Investment

IRR Internal Rate of Return

K Specific coefficient

LMTD Logarithmic Mean Temperature Difference

$\dot{\mathit{m}}$ Mass flow rate[kg/s]

MARR Minimum Attractive Rate of Return

NPV Net Present Value

ORC Organic Rankine Cycle

p Pressure [bar]

PVT Photovoltaic Thermal

Q Heat [kW]

RT Refrigeration tons

s Specific entropy [kJ/kg.K]

S Heat transfer area [m²]

T Temperature [°C]

TIC Total investment cost

U Overall heat transfer coefficient [W.m^-2.K]

VCR Vapor Compression Refrigeration

$\mathit{w}$ Power [kW]

$\mathbf{\Delta }$ Variation

$\mathit{\eta }$ Efficiency

0 Environment

A Annual

BM Bare module

comp Compressor

cond Condenser

Elet Electricity

evp Evaporator

EXP Expander

ge Generator

i Indexes

j Rate of return

ng Natural gas

O&M Operation and maintenance

U Useful