Evaluating Coal, RDF, and Ammonia Blends in Power Plants: Techno-Economic Insights and Coal Phase-Out Implications

Abstract

This comprehensive techno-economic analysis focuses on a proposed power plant that uses cleaner alternatives to traditional combustion methods. The study meticulously examines ternary blends of ammonia, refuse-derived fuels (RDFs), and coal. Utilizing an Aspen Plus simulation equilibrium model, a thorough review of the relevant literature, and evaluation reports on biomass-to-energy power plants and ammonia combustion, the analysis spans 20 years. It considers vital financial metrics such as the net present value (NPV), internal rate of return (IRR), and payback period (PBP). The findings indicate that the combustion of pure coal is the most energy-efficient but has the highest global warming potential (GWP). In contrast, ammonia and RDF blends significantly reduce GWP, with ammonia showing a 3215% lower GWP than coal. Economically, pure coal remains the most attractive option. However, blends of 80% coal, 10% ammonia, and 10% RDF also show promise with a PBP of 11.20 years at a 15% discount rate. These results highlight the potential of ammonia and RDF blends to balance environmental and economic considerations in power generation.

1. Introduction

Humanity has been harnessing the power of coal since the dawn of civilization [1]. However, it was not until the Industrial Revolution that coal indeed took center stage. In 1765, the brilliant James Watt made a groundbreaking improvement to the Newcomen engine by adding a separate condenser, preventing the cylinder from overheating and cooling with each cycle [2]. This revolutionary advancement transformed the way industries operated, as steam-powered ships and railroads, driven by coal-fired boilers, became the dominant modes of transportation. As the 19th century progressed, scientists uncovered even more applications for coal. During the American Civil War, coal proved invaluable in powering the weapons factories that supplied the warring factions [3]. By 1875, coke (not the fizzy drink) had usurped charcoal as the primary fuel for the steel industry’s blast furnaces [4]. However, using coal to generate electricity is a relatively recent development. In the 1880s, coal first began powering homes and factories. [5]. Nevertheless, it was not until 1961 that coal surpassed oil as the most common energy source in the United States, solidifying its position as a crucial component of the nation’s energy landscape.

The global energy landscape remains dominated by fossil fuels, with coal still leading the way in electricity generation. According to the latest data, coal accounts for 35.5% of the world’s electricity production, followed by natural gas at 22.5% and oil at 2.7%. Nuclear power contributes 9.1%, while renewable energy sources comprise 30.2% of the electricity mix (see

Table 1. Electricity production by source, 2023 [6].

Source	Electricity Production (TWh)	Share
Coal	10,467.93	35.5%
Gas	6622.93	22.5%
Oil	788.55	2.7%
Nuclear	2685.74	9.1%
Hydropower	4211.01	14.3%
Wind	2304.44	7.8%
Solar	1629.9	5.5%
Bioenergy	678.74	2.3%
Other renewables	89.81	0.3%
TOTAL	29,479.05	100%

) [6].

However, coal’s impact goes beyond electricity generation. It is also widely used for heating and cooling, contributing around 14.98 billion tons of CO₂ annually [7]. Coal usage accounts for 40.32% of global CO₂ emissions, underscoring its outsized role in driving climate change [8].

Despite the growth of renewable energy, the continued reliance on coal highlights the formidable challenge of transitioning to a more sustainable energy future. As the world grapples with the urgent need to reduce greenhouse gas emissions, addressing coal’s dominance in the global energy system will be crucial in the fight against climate change.

Addressing the challenge of reducing coal-based emissions is a complex issue. Nevertheless, a promising solution may involve replacing part of the coal used in energy production with RDF and ammonia during combustion. Incorporating RDF into the fuel mix decreases CO₂ emissions due to its lower atomic carbon content than coal [9]. Conversely, burning ammonia is remarkably clean, as it generates no CO₂ emissions, making this fuel combination an appealing option for reducing the carbon footprint associated with coal usage. However, it is crucial to note that burning ammonia produces nitrogen oxides (NO_x = NO + NO₂) and nitrous oxide (N₂O). NO_x is 33 times more environmentally damaging than CO₂ [10], and N₂O is 273 times more potent than CO₂ [11]. During this techno-economic analysis, the emissions of blends with and without ammonia are assessed, emphasizing that the emission of ammonia is still cleaner than coal.

1.1. RDF Consideration

RDF is a carbon-neutral energy source made from municipal solid waste (MSW), presenting a valuable opportunity to lessen our dependence on coal [12]. Since the carbon emitted during RDF’s combustion is balanced by the carbon absorbed by organic waste during its growth, it is a sustainable alternative. Co-firing RDF with coal can substantially reduce CO₂ emissions from power plants [13,14]. Furthermore, RDF helps convert a challenging waste stream into a helpful resource, keeping it out of landfills and addressing environmental problems associated with MSW management, such as leachate contamination and methane release [9]. Therefore, the RDF cuts emissions and fosters responsible waste management practices. Implementing RDF as an energy vector holds significant promise, but successful integration requires a careful consideration of several crucial aspects.

The availability of RDF as a viable energy source significantly depends on the efficiency of a region’s waste collection and sorting systems [9]. Countries with advanced and well-established waste management infrastructure, such as those commonly found across Europe (especially in nations like Germany, Sweden, and Denmark), typically show much higher RDF availability than regions with less developed systems. This gap results from the capacity of these advanced infrastructures to effectively separate and process waste streams, maximizing the recovery of materials suitable for RDF production [9].

The RDF production process is a multi-stage operation that converts MSW into usable fuel [15]. This process typically involves several key steps: initial waste sorting to remove non-combustible materials like metals, glass, and inert debris; subsequent shredding to reduce the size of the combustible waste; a drying stage to decrease moisture content, thus enhancing combustion efficiency and heating value; and finally, compacting the processed material into pellets or briquettes for easier handling, storage, and transportation. Specific technologies used at each stage vary, ranging from manual sorting to automated optical sorting systems and simple air drying to more energy-intensive thermal drying methods.

Despite these costs, on average, RDF costs 0.07133 €/kg [16,17], and it is increasingly competitive with traditional fossil fuels, especially when considering the broader environmental benefits and potential revenue streams generated from reduced landfill use. The savings associated with lower landfill disposal fees and the revenue potential from selling RDF as a fuel source can significantly counterbalance production costs. Furthermore, the environmental advantages—such as reducing greenhouse gas emissions from landfills and displacing the need for fossil fuel combustion—often create a strong economic case for RDF adoption, particularly when viewed under the lens of carbon taxes or other environmental incentives.

Regulations governing RDF production and use differ significantly across various regions and jurisdictions. Europe, for instance, has implemented relatively stringent standards to ensure RDF’s quality and environmental performance [18].

1.2. Ammonia Consideration

Another noteworthy alternative fuel is ammonia, predominantly produced via sustainable processes, often called “green ammonia” [19]. Ammonia, acting as a hydrogen carrier, has significant potential for decarbonizing the energy sector [20]. A key benefit of ammonia combustion is that it generates no CO₂ emissions. By incorporating ammonia into the fuel mix for coal-fired power plants, we can significantly reduce the carbon footprint, paving the way for a cleaner energy future. The carbon intensity of ammonia production can decline substantially if renewable energy sources are used in the Haber–Bosch process. Implementing ammonia as an energy vector holds significant promise, but successful integration requires the careful consideration of several crucial aspects.

Global ammonia availability is robust, with production hubs in North America, Europe, and Asia ensuring a steady supply for industrial and agricultural applications [21]. Therefore, its use as an energy vector has significant potential.

The Haber–Bosch process, which combines atmospheric nitrogen with hydrogen derived from natural gas, remains the primary method of ammonia production [22]. However, ammonia availability can fluctuate due to changes in natural gas prices, maintenance shutdowns, and expansions at production plants. Investment in new capacity, driven by rising agricultural demand and potential future needs in the energy sector, will also influence long-term availability.

Production methods, market conditions, and geopolitical factors all affect ammonia costs. The traditional natural gas method is cost-effective but subject to price volatility [23]. Green ammonia, produced using renewable energy to generate hydrogen, is more sustainable but currently more expensive due to higher infrastructure costs. As renewable technology and electrolyzer costs decrease, the price gap between conventional and green ammonia is expected to narrow. As of early 2025, ammonia prices in North America were approximately $588 per metric ton, subject to change based on the earlier factors [24].

Ammonia use is regulated to ensure safety, environmental protection, and compliance with industry standards. Given its toxicity and handling requirements, this regulation is particularly critical when considering ammonia as a fuel. The International Maritime Organization (IMO) has developed interim guidelines for utilizing ammonia as a marine fuel, addressing fuel containment, fire safety, and toxicity mitigation to protect personnel and the environment [25].

1.3. Paper Outlook

Recent studies have concentrated on the technical feasibility of co-combustion with RDF [26,27] and ammonia [28,29], both separately and alongside coal. These investigations examine optimal mixing ratios, combustion efficiency, and their effects on boiler performance [30]. For example, researchers are analyzing how co-firing RDF and ammonia with coal impacts flame stability [31], heat transfer rates [32], byproduct formation to enhance the combustion process for maximum energy efficiency and minimal emissions [33], technical aspects of ammonia combustion [34], its reactivity [35], toxicity [36], and the emissions of NO_x [37] and N₂O [38]. Nonetheless, the economic feasibility of this integrated approach poses a significant barrier to widespread implementation. While technically viable, the large-scale adoption of RDF/coal/ammonia co-combustion depends on its cost-effectiveness compared to conventional coal combustion. A thorough techno-economic analysis is vital to assess the practicality of using coal, ammonia, and RDF as a combined fuel source, weighing various factors such as the costs of RDF and ammonia, necessary equipment for existing power infrastructure, and potential revenue streams.

By strategically blending sustainably sourced RDF with carefully regulated amounts of ammonia in the fuel mix for power generation and heating, we can realize considerable and quantifiable reductions in carbon emissions. This strategy presents a promising route toward a cleaner energy future, especially alongside the urgent need for effective urban waste management solutions. Utilizing urban waste streams as a primary RDF source can establish a circular economy model, converting a challenging disposal issue into a valuable energy resource.

This paper is structured as follows: Section 2 describes the materials and methods used in the study, including the Aspen Plus simulation and economic analysis. Section 3 presents the results and discusses the influence of various factors on emissions and energy balance. Section 4 concludes with the key findings and implications for future research and policy. Having established the context and significance of this study, we now turn to the detailed description of the materials and methods used in our analysis.

2. Materials and Methods

This article analyzed two critical parameters essential in evaluating the viability of using different fuel mixtures for power generation. The first parameter focuses on the emissions produced by coal combustion alone and those generated using various blends of coal, ammonia, and RDF. These emissions are calculated using a comprehensive simulation model developed in Aspen Plus, a widely used process simulation software. The simulation will employ a thermodynamic chemical equilibrium approach.

The second parameter to be evaluated is the economic viability of the proposed fuel blends. Several key considerations will be made in this analysis. Firstly, a coal-fired power plant’s capital expenditure (CAPEX) will be compared to that of a power plant utilizing blends of coal, ammonia, and RDF. It is hypothesized that the CAPEX for both types of power plants will be similar, as the core infrastructure and technology required may not differ significantly.

Furthermore, the operational expenditure (OPEX) for power production is also evaluated. It is assumed that the OPEX for a coal-fired power plant will be comparable to that of a power plant using the proposed fuel mixture. This assumption is based on the premise that the same personnel and services would be required to operate and maintain both types of power plants. However, the key differences between the two processes lie in the cost of the raw materials (coal, ammonia, and RDF) and the potential incentives or benefits that may be received for using MSW.

By considering these two critical parameters—emissions and economic viability—this article aims to provide a comprehensive assessment of the feasibility and potential advantages or disadvantages of using a mixture of coal, ammonia, and RDF as an alternative fuel source for power generation compared to the traditional coal-fired power plant.

2.1. Aspen Plus Simulation

2.1.1. Aspen Plus Properties

The first crucial step in initiating a simulation is meticulously defining the system’s properties, which form the foundation for all subsequent calculations and predictions. This involves specifying the participating components, including all chemical species in the thermodynamic calculations, from simple molecules like water and methane to non-conventional components.

The Aspen Simulation Properties environment provides robust tools for defining and managing these system properties. The following sections will explore leveraging these tools to accurately represent the components and their characteristics, ensuring a reliable simulation outcome. Properly implementing this initial property definition is essential for achieving accurate and reliable results from the Aspen Simulation.

2.1.2. Components

The simulation environment encompasses a range of feedstocks, classified as conventional or non-conventional, to accurately model the intricate chemical processes involved. The simulation employs NH₃ and air as primary feedstocks for the conventional components. These components are treated using standard thermodynamic properties. They are fully integrated into the phase and chemical equilibrium calculations governing the simulation.

Conversely, the non-conventional components are represented by coal, RDF, and ashes. These materials are defined with specific enthalpy and density models that capture their distinct thermal behavior. However, due to their complex and often poorly characterized composition, they are not directly involved in the detailed phase and chemical equilibrium calculations. Instead, their contributions are accounted for through a series of characterization steps. This step includes the proximate analysis, which determines the moisture content, volatile matter, fixed carbon, and ash content; ultimate analysis, which quantifies the elemental composition of carbon, hydrogen, oxygen, and nitrogen; and sulfur feedstock analysis, which measures the sulfur content. This detailed characterization is essential because the simulation requires that all non-conventional components be eventually decomposed into their constituent primary elements: C, H, O, N, and S. This decomposition enables the simulation to indirectly account for the contributions of these elements to the overall chemical reactions and product formation.

The simulation produces various gases, including CO, CO₂, NH₃, NO, NO₂, SO₃, SO_2, and N₂O as conventional coal power facilities.

The three feedstocks used in the simulation—coal, NH_3, and RDF—each have unique properties that make them valuable for different purposes. Coal is an exceptional fuel due to its high carbon content. RDF is a fuel made from the non-recyclable portion of MSW. This heterogeneous mixture includes materials like plastics, paper, cardboard, and other combustible substances, with the plastic providing a higher volatile matter content. Ammonia, the third component, is a nitrogen and hydrogen chemical compound. Their characteristics are described in

Table 2. Aspen Plus components.

Description	RDF Pellets	Coal [39]	Ammonia
Proximate Analysis
Moisture (wt-%, dry basis)	4.30	2.20	0.00
Volatile Matter (wt-%, dry basis)	78.58	37.20	0.00
Fixed Carbon (wt-%, dry basis)	7.42	51.30	0.00
Ash (wt-%, dry basis)	14.00	13.80	0.00
Ultimate Analysis
Ash (wt-%, dry basis)	14.00	13.80	0.00
C (wt-%, dry basis)	54.00	83.80	0.00
H (wt-%, dry basis)	7.40	4.80	19.65
N (wt-%, dry basis)	0.50	2.00	80.35
O (wt-%, dry basis)	24.10	8.40	0.00
S (wt-%, dry basis)	0.00	1.00	00.00
LHV (MJ/kg)
	24.8 [40]	22.73–33.4 [41]	18.8 [42]

.

2.1.3. Thermodynamic Method

The Peng–Robinson equation of state was the thermodynamic method used to simulate the combustion of coal, RDF, and ammonia blends. This particular equation was chosen for its ability to accurately predict the phase behavior and thermodynamic properties of the complex mixtures involved in the combustion process while also maintaining computational efficiency. Specifically, the Peng–Robinson equation is known for its robustness in handling non-ideal gases and liquids, which are commonly encountered at the high temperatures and pressures typical of combustion environments [43].

2.1.4. Equilibrium Model

Simulating combustion processes involving complex fuel blends of coal, refuse-derived fuel (RDF), and ammonia leverages an equilibrium method based on the direct minimization of Gibbs free energy. This approach includes a phase-splitting algorithm to accurately determine the equilibrium composition, including species distribution across different phases (e.g., solid, liquid, gas) [44].

Minimizing Gibbs free energy is well-suited for combustion modeling. It effectively predicts the spontaneity of a reaction and the final equilibrium ratios of reactants and products under given conditions [44].

While kinetic models offer more detailed insights into reaction pathways, the equilibrium method provides computationally efficient results with acceptable accuracy, especially for systems close to equilibrium, as is often the case in combustion chambers [45].

To ensure complete combustion, simulation employs an air excess. This guarantees sufficient oxygen to oxidize all carbon atoms in the fuel mixture into carbon dioxide, the thermodynamically favored product. Insufficient oxygen would lead to the formation of undesirable byproducts like carbon monoxide and soot, reducing energy efficiency and increasing emissions. The air excess ratio, a crucial parameter in combustion engineering, is carefully chosen to balance complete combustion by minimizing the heat loss associated with heating the excess air [44].

The thermodynamic foundation for this approach lies in the relationship between Gibbs free energy (G) and the equilibrium constant (K). The following equations elucidate this fundamental connection, demonstrating how changes in Gibbs free energy dictate the position of equilibrium and the relative concentrations of reactants and products at equilibrium:

$$\Delta G=\Delta G^0+\mathrm{RTlnQ}$$

(1)

$$Q=K={\displaystyle \frac{{\left[C\right]}^c{\left[D\right]}^d}{{\left[A\right]}^a{\left[B\right]}^b}}$$

(2)

where $\Delta G$ is the difference between the free energy of products and reactants at any moment, $\Delta G^0$ is the difference between the free energy of products and reactants at standard conditions, $R$ is the gas constant, $\mathrm{T}$ is temperature, and $\mathrm{Q}$ is the reaction quotient. In the equilibrium, $\Delta G=0$. Thus, equation 1 can be rearranged as follows:

$$\Delta G^0=-\mathrm{RTlnK}$$

(3)

These equations highlight the importance of understanding Gibbs free energy in predicting and controlling combustion outcomes. The negative relationship between ΔG and lnK implies that a decrease in Gibbs free energy (ΔG) corresponds to a larger equilibrium constant (K), favoring the formation of products and driving the reaction forward. Conversely, a positive ΔG indicates that the reactants are favored at equilibrium.

2.1.5. Simulation Process

The simulation process described in Figure 1 is a multifaceted procedure that involves transforming non-conventional solid components, such as coal and RDF, into their elemental composition. This step is crucial in facilitating the subsequent reactions that will take place within the system. In contrast to the non-conventional solid components, ammonia, a conventional component, does not require this initial decomposition step. The three elements are then sent through a mixer and thoroughly combined to create the combustion reaction. The combustion reactant and an excess air stream are fed into the system. This excess air stream is essential in providing oxygen for the combustion process to occur efficiently.

The building blocks used for each part of the process are described in detail in

Table 3. Simulation equipment.

Equipment	Type	Description
DECOMP 1	RYILD	It discomposes coal into its primary elements
DECOMP 2	RYILD	It discomposes RDF into its primary elements
Mixer	MIXER	It mixes the primary elements from coal and RDF with ammonia
Combust	RGIBBS	It is a Gibbs reactor

. It is essential to note that the combustion reactant is specifically modeled using an RGIBBS reactor. This type of reactor provides a thermodynamic equilibrium-based model. The RGIBBS reactor enables the model to determine the combustion products’ equilibrium composition, considering factors such as temperature, pressure, and the relative concentrations of the reactants. Using the RGIBBS reactor ensures that the model adheres to the fundamental principles of chemical equilibrium, such as the law of mass action and the Gibbs–Duhem equation.

Finally,

Table 4. Simulation runs.

Run	Feedstock (kg/h)
	Coal	NH3	RDF
100/0/0	250	0	0
0/0/100	0	0	250
0/100/0	0	250	0
50/50/0	125	125	0
0/50/50	0	125	125
50/0/50	125	0	125
80/10/10	200	25	25
60/20/20	150	50	50
40/30/30	100	75	75
20/40/40	50	100	100

describes the blends utilized in this simulation. The runs consider a temperature operation of 1000 °C, 250 kg of a blend, and 2625 kg/h of air. The specific conditions were selected based on typical operational parameters for coal-fired power plants and the properties of the fuel blends being studied. These conditions aim to simulate real-world combustion processes as closely as possible. The temperature of 1000 °C and the air-to-fuel ratio were chosen to ensure complete combustion and to reflect the conditions under which coal, ammonia, and RDF are commonly combusted in industrial settings [46,47].

The simulation using Aspen software will provide a comprehensive understanding of gas composition. This information will be crucial for evaluating the feasibility of incorporating ammonia into the gas mixture to reduce CO₂ emissions.

The energy balance is also calculated using the Aspen simulation, which will be a critical factor in the techno-economic evaluation of the process.

2.2. Economic Feasibility

The economic feasibility of utilizing a combination of coal, RDF, and ammonia as energy sources will be evaluated using three key financial metrics: net present value (NPV), internal rate of return (IRR), and payback period (PBP). These parameters comprehensively assess this energy mix’s potential profitability and viability.

2.2.1. Net Present Value

The NPV is a powerful tool for assessing a project’s profitability. It involves comparing the present value of the anticipated cash inflows with the present value of the expected cash outflows associated with the project. This allows for a comprehensive evaluation of the project’s financial viability. The calculation of the NPV is straightforward. It involves discounting the future cash flows, both inflows and outflows, back to their present-day equivalents. This considers the time value of money, ensuring that the analysis accurately reflects the actual worth of the project. The following equation depicts the NPV [48].

$$NPV=-C_t+{{\displaystyle \sum }}_1^n\left[{\displaystyle \frac{\left(C_f-C_0\right)}{{\left(1+r\right)}^n}}\right]$$

(4)

where $C_t$ (€) is the total project cost. $C_f$ (€) is the cash inflows generated by the project, $C_0$ (€) is the cash outflows in the project lifetime, r is the discount rate (%), and n is the project lifetime (years).

By comparing the present values of the cash flows, the decision-maker can determine whether the project is a worthwhile investment, with a positive NPV indicating a profitable venture and a negative NPV suggesting the project may not be financially viable. This comprehensive assessment of the project’s financial performance helps decision-makers make informed choices, prioritizing projects that have the potential to deliver the most value to the organization. The NPV is a valuable tool in financial analysis, providing a clear and objective means of evaluating a project’s merits and making sound investment decisions.

2.2.2. Internal Rate of Return

The IRR (%) is the discount rate that makes a project’s NPV equal to zero. This means that the IRR is the rate at which the present value of the project’s future cash inflows equals the initial investment [49].

Equation (5) [49] calculates the IRR, a powerful tool for evaluating a project’s profitability. By solving this equation, we can determine the discount rate that satisfies the condition of a zero NPV, indicating the maximum rate of return the project can generate.

$$0=-C_t+{{\displaystyle \sum }}_1^n\left[{\displaystyle \frac{\left(C_f-C_0\right)}{{\left(1+r\right)}^n}}\right]$$

(5)

where $C_t$ (EUR) is the total project cost. $C_f$ (EUR) is the cash inflows generated by the project, $C_0$ (EUR) is the cash outflows in the project lifetime, r is the discount rate (%), and n is the project lifetime (years).

Understanding and accurately calculating the IRR is crucial in making informed investment decisions. It provides a clear and objective measure of a project’s long-term viability. It helps decision-makers weigh the risks and rewards of a particular investment opportunity.

2.2.3. Pay Back Period

The PBP evaluates the time it takes for an investment to recoup its initial cost through the cash flows it generates. It provides a straightforward way to assess an investment’s liquidity and risk by determining how quickly the initial outlay can be recovered.

$$PBP={\displaystyle \frac{Cost of Investment }{Annual revenue}}$$

(6)

2.3. Production & Economic Parameters

2.3.1. Production

To conduct the economic analysis, consider a scenario with 1000 kWh production per day and a continuous 24 h daily operation for 310 days a year. This annual production volume of 7440 MW was selected as a representative case to evaluate the project’s financial viability and profitability.

The 24 h daily operation assumption reflects the continuous nature of the energy generation process, which is crucial for a reliable and consistent power supply. Operating the facility for 310 days per year instead of 365 days accounts for potential downtime required for maintenance, repairs, or unforeseen circumstances.

2.3.2. Economic Parameters

The discount rate is a crucial factor in the valuation of investments, as it reflects the time value of money and the perceived risk of the investment. Investors typically seek to maximize their returns while minimizing their risk exposure. For this analysis, a 15% discount rate is considered competitive with other investment opportunities in the market, such as government bonds, corporate bonds, or even alternative asset classes like real estate or private equity. If the discount rate were lower than the rates offered by these other instruments, it would be less appealing to investors, as they could find better risk-adjusted returns elsewhere. However, this paper analyses the influence of the discount rate. This project has been evaluated for over 20 years.

2.3.3. Expenses

For this comprehensive economic analysis, four key parameters are considered significant expenses: (1) CAPEX (capital expenditure), (2) OPEX (operational expenditure), (3) the cost of raw materials, and (4) the cost of CO₂ emissions.

CAPEX

Firstly, CAPEX refers to the significant investment costs required to construct and install a coal-fired power plant. These construction prices can vary considerably depending on the specific country or region, the current market prices of construction materials, and the prevailing inflation rates, among other factors. While construction costs can differ substantially across locations, the analysis relies on established ratios and industry benchmarks previously documented in the relevant literature.

The International Energy Agency (IEA) provides a range of cost estimates for building a modern coal-fired power plant, emphasizing the variability based on several key factors. Their data indicate that construction costs typically range from EUR 1.8 million to EUR 4.5 million per MW installed capacity [50,51]. This broad range reflects the diverse technological approaches, geographical locations, and regulatory environments associated with such projects. More advanced coal-fired power plants, which incorporate technologies like carbon capture and storage (CCS) to reduce environmental impact, generally fall toward the higher end of this cost spectrum.

However, the IEA notes that construction costs can drop significantly below the EUR 1.8 million per MW threshold under certain conditions, even falling below EUR 1 million per MW. These lower costs are often seen in particular investment projects, especially in countries with lower labor costs and less stringent environmental regulations (For example, in China, 0.8 Million CNY/MW) [51]. Reduced labor expenses directly influence the overall project budget. At the same time, weaker environmental requirements lessen the need for expensive pollution control equipment and complicated permitting processes. This underscores the trade-off between initial investment and long-term ecological effects.

Thus, this study acknowledges the inherent variability and the potential for inflated and deflated figures. The average cost of constructing a plant, presumably energy-based (given the reference to MW and kW), is EUR 2.7 million per megawatt. This figure can also be expressed as EUR 2750 per kW to provide additional granularity and facilitate comparison with other units of measure. This means that, on average, generating 1 kilowatt of energy requires an investment of EUR 2750. This cost likely includes a variety of expenses, including equipment purchase, construction, installation, grid connection, and possibly even design and permitting fees.

On the other hand, the cost associated with ammonia transportation and handling is not relevant because the pipeline transportation cost is 0.0344 EUR/kg for ammonia [52]. For storage, it is estimated to be EUR 0.10–0.20/kW [53]. Therefore, it can be assumed that the selected cost of the CAPEX includes the cost associated with ammonia.

OPEX

Secondly, OPEX represents the ongoing operational expenses of running a coal-fired power plant daily. Like CAPEX, this parameter is also influenced by many factors, such as geographical location, material costs, and inflationary pressures. The OPEX costs cover a range of expenditures, including fuel, labor, maintenance, and other operational overheads.

According to research conducted by Mitavachan Hiremath et al. [54,55], the annual OPEX costs associated with coal power generation exhibit significant variability. Their analysis reveals that OPEX can fluctuate annually between € 42 and € 50 per kilowatt (€/kW). This variation, observed over an extensive period of 25 years, highlights the long-term uncertainty inherent in predicting these costs.

Given this range of potential values, the present paper necessitates the selection of a representative OPEX figure for modeling purposes. An intermediate value within the reported range was chosen for a balanced and conservative estimate. The authors used a €48/kW value as a representative annual OPEX cost. This figure falls squarely within the observed fluctuation and provides a reasonable approximation for the long-term average. This choice allows for a practical and justifiable basis for further analysis and calculations within the study.

Raw Materials

Thirdly, the analysis accounts for the cost of raw materials, particularly commodities like ammonia and coal, which are essential inputs for the coal-fired plant. These commodity prices are subject to significant volatility due to fluctuations in global supply and demand and other macroeconomic forces that can drive prices up or down over time. However, the price of electricity is often tied to the price of coal, especially in areas that rely heavily on coal-burning power plants. Coal is a significant fuel for many power plants, so its cost directly affects how much it costs to run them. When coal prices go up, electricity prices usually follow. When coal prices go down, electricity prices decrease because fuel is a big part of producing electricity [55].

Electricity prices are often set based on the marginal cost of production, which includes fuel costs. In markets where coal-fired power plants are the marginal producers, changes in coal prices can directly affect electricity prices. This mechanism helps pass on the cost changes to consumers, mitigating the impact of coal price fluctuations on power producers [56].

Many coal-fired power plants have long-term contracts to sell their electricity, which are called Power Purchase Agreements (PPAs). These contracts often include clauses that adjust electricity prices when fuel costs change. These agreements help power companies keep their income steady by allowing them to pass higher fuel costs on to electricity buyers [57].

Power companies also commonly use financial tools to protect themselves from sudden changes in fuel prices. Using economic tools like hedges, coal power plants can protect themselves from changing coal prices and stabilize electricity costs. This means the plant’s profits will not significantly affect the coal market’s ups and downs [58].

However, the price of ammonia and RDF presents a unique challenge. Because the cost of ammonia and RDF fluctuates significantly, using them alongside coal and waste to create energy can become unreliable. Currently, producing electricity with ammonia is not affordable. If ammonia prices rise further, it will become an even less practical fuel source. On the other hand, if ammonia becomes cheaper than today, it could become a more appealing energy option, especially if the government offers incentives or the cost of CO₂ emissions continues to climb.

CO₂ Emission Cost

Finally, the fourth parameter considers the cost of CO₂ emissions associated with the price of EU carbon permits (EUAs). This factor has shown an upward trend in recent years due to growing global concerns about the environmental impact of greenhouse gas emissions and the potential implementation of carbon pricing mechanisms or emission trading schemes. It reached a maximum price in February 2023 (105.73 €/ton of CO₂); the lowest point was in September 2007 (0.35 €/ton of CO₂). In March 2025, the price decreased to 71 €/ton of CO₂. However, the overall trend is upward [59].

Incomes

The primary income streams considered in this analysis are the cost of electricity generation and the financial incentives associated with using MSW as a fuel source in the form of RDF. These revenue sources are crucial in determining the project’s overall economic viability.

Table 5. Production and economic parameters.

Parameter	Unit	Average	Source
1. Production *
Production	kWh	1077
Operational hours	h/day	24
Operational day	days/year	310
Total coal required	kg/h	250
Total air required	kg/h	2625
2. Economic parameters
Discount rate	%	15
Evaluation period	year	20
3. Expenses
CAPEX	€/kWh	2750	[50]
Total CAPEX	EUR	2,750,000
Coal cost	EUR/ton	150.25	[56]
Blue ammonia cost	EUR/ton	564	[60]
RDF cost	EUR/ton	71.33	[16,17]
Carbon emissions cost	EUR/ton	86	[61]
OPEX	EUR/kW-annually	48	[54]
Total OPEX	EUR	48,000
4. Incomes
Tipping fees for MSW	EUR/ton of waste landfilled	25	[62,63]
Energy cost	EUR/MWh	208.9	[64]

* Based on a Coal-fired plant to produce 1077 kWh or 250 kg/h of coal.

comprehensively summarizes the production, economics, expenses, and income parameters considered for this analysis. These parameters are the foundation for evaluating the different scenarios, each corresponding to the specific simulation runs conducted using the Aspen Plus software.

3. Result Analysis

3.1. Gas Composition

Various climate measurements must be defined to estimate a substance’s impact on the global greenhouse effect (GHE). One of the most commonly used measurements is global warming potential (GWP) [65]. The global warming potential measures how much energy the emissions of one ton of gas will absorb over a given period compared to one ton of CO₂. GWP is expressed as a factor, with CO₂ having a GWP of 1. For example, if a gas has a GWP of 10, it means that one ton has the same effect on the climate as the emission of 10 tons of CO₂ over the same period [66]. The GWP of NO₂ is 273, an NO_x’s GWP is 33 [10].

The following table (

Table 6. Gas composition.

Run	Feedstock (kg/h)			Gas Composition (Kg/h)									GWP
	Coal	NH3	RDF	H2O	CO2	N2	O2	SO3	SO2	NO	NO2	N2O	GWP	%
100/0/0	250	0	0	97.2548	661.4698	2078.0198	4.1332	0.0286	4.2811	0.0828	0.00012	7.0478 × 10−6	0.6642	0
0/0/100	0	0	250	168.9695	473.3864	2074.7336	123.9540	0.0000	0.0000	0.4531	0.00350	3.7885 × 10−5	0.4885	36%
0/100/0	0	250	0	396.6827	0.0000	2279.0795	198.6310	0.0000	0.0000	0.6012	0.00556	4.9837 × 10−5	0.0200	3215%
50/50/0	125	125	0	246.9688	330.7355	2178.5133	101.3298	0.0669	2.0985	0.4198	0.00287	3.5235 × 10−5	0.3447	93%
0/50/50	0	125	125	282.8261	236.6932	2176.9055	161.2912	0.0000	0.0000	0.5295	0.00453	4.4069 × 10−5	0.2543	161%
50/0/50	125	0	125	133.1122	567.4286	2076.3498	64.0044	0.0550	2.1080	0.3257	0.00182	2.7475 × 10−5	0.5782	15%
80/10/10	200	25	25	134.3692	576.5152	2097.7634	35.5176	0.0658	3.3905	0.2439	0.00102	2.0660 × 10−5	0.5846	14%
60/20/20	150	50	50	171.4834	491.5598	2117.5391	66.9462	0.0668	2.5290	0.3364	0.00191	2.8368 × 10−5	0.5027	32%
40/30/30	100	75	75	208.5976	406.6043	2137.3237	98.3880	0.0533	1.6790	0.4097	0.00279	3.4397 × 10−5	0.4202	58%
20/40/40	50	100	100	245.7118	321.6488	2157.1131	129.8372	0.0302	0.8366	0.4729	0.00366	3.9525 × 10−5	0.3374	97%

) analyzes the emissions of different fuel blends and their respective GWPs. The data demonstrates that pure coal combustion has the highest GWP among all the tested blends.

As can be seen from the data, the GWP of the combustion gases produced from the mixture containing 100% coal at a feed rate of 250 kg/h is 0.6642, which represents the highest GWP value among the scenarios analyzed. This indicates that the combustion of this coal-dominant mixture has a significant environmental impact in terms of greenhouse gas emissions and contribution to global climate change. In contrast, the GWP of the combustion gases from the mixture containing 100% ammonia at a feed rate of 250 kg/h is significantly lower, at 0.0200. This value is 3215% lower than the GWP of coal-based combustion, highlighting the vastly reduced environmental impact of using ammonia as a fuel compared to coal. The results indicate that while pure coal combustion is the most energy-efficient, it has the highest GWP. This suggests that transitioning to cleaner fuel blends, such as those incorporating ammonia and RDF, could significantly reduce the environmental impact of power generation. These findings are consistent with those of Kobayashi et al. [67]. This study found that co-firing ammonia with coal can reduce CO₂ emissions by up to 50% compared to pure coal combustion, as seen in blends with ammonia. Ito et al. [68] reported that co-firing ammonia with coal can directly reduce CO₂ emissions. For example, applying 20% ammonia co-firing to a USC boiler reduced CO₂ emissions from 795 g-CO₂/kWh to 636 g-CO₂/kWh.

Additionally, implementing carbon capture and storage (CCS) technologies can improve the environmental performance of coal and blended fuel combustion. CCS involves capturing CO₂ emissions produced during power generation and storing them underground to prevent their release into the atmosphere. This technology can significantly reduce the overall GWP of coal combustion by capturing up to 90% of CO₂ emissions [69]. When combined with ammonia and RDF blends, CCS can enhance the reduction of greenhouse gas emissions, making power generation even more sustainable. Integrating CCS with existing power plants can also provide flexibility and stability to power networks, supporting the transition to low-carbon energy systems.

It is important to note that the combustion of pure ammonia generates significantly higher amounts of N₂O and NO_x. Their GWP is 273 times and 33 times greater than CO₂, respectively. However, the overall quantities of these pollutants produced are tiny. As a result, the GWP values for the blends containing ammonia are considerably lower than the mixtures with a higher coal content. This underscores the importance of considering the relative proportions and potencies of various greenhouse gases when evaluating the environmental impact of different fuel sources.

The findings suggest that the incorporation of ammonia and RDF, even in small amounts, can help mitigate the overall environmental impact of fuel combustion despite the potent warming effects of N₂O and NO_x. This information could be valuable for policymakers, industry stakeholders, and researchers in exploring more sustainable energy solutions that balance economic needs with environmental protection.

The study conducted by Ebrahim Nadimi et al. [70] has provided valuable insights into the potential of using ammonia as a fuel additive to reduce CO₂ emissions from the combustion of fossil fuels. Their findings suggest that introducing ammonia during the combustion process can significantly lower the overall CO₂ emissions, which is crucial in addressing the pressing issue of climate change. However, the researchers also acknowledge a notable drawback of this approach—the formation of N₂O.

As highlighted above, introducing ammonia into the combustion process produces N₂O as a byproduct. However, the amount of N₂O produced during ammonia combustion is typically small, often negligible compared to the overall emissions. This finding is consistent with the research conducted by Jeffrey V. et al. [71], which explored the emissions profile of ammonia-based combustion systems.

Ekenechukwu C. [72] mentions that the low levels of N₂O emissions are primarily because N₂O is reduced through two critical reactions. The first is the reaction with the hydrogen (H) atom, which has a markedly high-temperature sensitivity:

$${\mathrm{N}}_2\mathrm{O}+\mathrm{H}\leftrightarrow {\mathrm{N}}_2+\mathrm{O}\mathrm{H}$$

(7)

This means that this reaction occurs rapidly in regions of the flame where the temperature is very high, such as the inner core of the flame. The high temperature gives the reaction the necessary activation energy to proceed quickly, efficiently converting the N₂O into molecular N₂ and the hydroxyl OH radical.

However, the rate of this reaction drops off significantly at relatively lower flame temperatures, which can occur in the outer regions of the flame. This is where the second reaction becomes more critical—the thermal dissociation reaction:

$${\mathrm{N}}_2\mathrm{O}+\left(\mathrm{M}\right)\leftrightarrow {\mathrm{N}}_2+\mathrm{O}+\left(\mathrm{M}\right)$$

(8)

Here, the N₂O molecule is split apart by collisions with other molecules, designated by (M), to form N₂ and an oxygen (O) atom. While this thermal dissociation reaction may proceed slower than the high-temperature H-atom reaction, it can continue even at lower flame temperatures.

Further data analysis may reveal additional insights, such as the optimal blend ratios, the potential trade-offs between different pollutants, and the feasibility of implementing ammonia-based fuels on a larger scale. Ongoing research and innovation in this field can contribute to developing cleaner and more efficient energy systems that minimize the carbon footprint and support global efforts to address climate change.

3.1.1. Influence of Temperature for NO_x and N₂O Formation

Various factors contribute to the formation of NO_x during combustion processes. However, the most critical factor governing NO_x formation is the temperature within the combustion zone [73,74,75]. As the temperature increases, the rate of NO_x formation rises exponentially due to the high activation energy required for the chemical reactions that produce NO_x.

As shown in Figure 2, NO_x and N₂O are strongly related to temperature. The relationship between temperature and the formation of NO_x and N₂O is a well-established phenomenon. As the temperature increases, the kinetic energy of the molecules involved in the combustion reactions also increases. This higher energy breaks the solid triple bond in the nitrogen molecule, allowing the nitrogen and oxygen atoms to recombine and form the various nitrogen oxides.

The trend observed in the figure shows that the formation of these compounds increases gradually as the temperature rises. However, it becomes much more pronounced after the 600 °C mark. Higher thermal energy overcomes the activation energy barriers, leading to a rapid acceleration in the reaction rates and, consequently, the production of pNO_x and N₂O.

3.1.2. Influence of Air Flow on NO_x and CO₂

Figure 3 illustrates the complex relationship between airflow rates and emissions during the combustion of a 50/50 coal-ammonia blend, explicitly focusing on the influence of temperature. The data presented compares emissions profiles at two distinct temperatures: 1000 °C and 800 °C. Despite the temperature difference, a similar trend emerges across both scenarios, indicating a consistent pattern in how airflow impacts the generation of various gaseous products.

The data reveals a significant reduction in the formation of NO_x and N₂O when the combustion occurs at a lower temperature of 800 °C. This suggests that lower temperatures favor pathways that are less conducive to forming these specific nitrogen-containing pollutants. This is likely due to the reduced availability of activation energy required for the chemical reactions that lead to NO_x and N₂O formation at the lower temperature.

Furthermore, the analysis highlights the behavior of CO₂ emissions as airflow increases, mainly after complete combustion is achieved. The observation indicates that CO₂ decreases with increasing airflow due to a dilution effect. As more air is introduced into the system, the concentration of CO₂ in the exhaust gas is reduced as it is mixed with a larger volume of air. This dilution effect is a straightforward consequence of increasing the total volume of exhaust gas without a corresponding increase in the absolute amount of CO₂ produced.

However, a contrasting trend is observed for NO_x and N₂O emissions. The data demonstrates that the amounts of NO_x and N₂O increase rapidly as airflow increases. This phenomenon is attributed to the heightened availability of nitrogen at higher airflow rates. The presence of more air inherently introduces more nitrogen into the combustion chamber. This excess nitrogen then participates in chemical reactions, forming higher concentrations of NO_x and N₂O. Increasing the airflow while diluting CO₂ simultaneously provides more nitrogen for forming undesirable nitrogen-based emissions, thus increasing their levels. Therefore, optimizing airflow becomes a delicate balancing act, aiming to burn all fuel while mitigating the formation of NO_x and N₂O.

3.1.3. Influence of Ammonia for NO_x and CO₂ Formation

NO_x formation during ammonia combustion is a complex and poorly understood phenomenon. The mechanisms underlying NO_x formation during combustion remain a topic of ongoing research and debate [76]. However, it is well known that the combustion of ammonia produces higher amounts of NO_x and N₂O than conventional fossil fuels. [77,78].

Figure 4 depicts the correlation between NO_x and CO₂ emissions for various experimental runs. The data indicates that mixtures with a higher NH₃ content generate significantly less CO₂. The run where the mixture was composed entirely of ammonia (100% NH₃) resulted in zero CO₂ emissions. Conversely, the mixtures with a more significant proportion of coal exhibited higher CO₂ production.

On the flip side, the data also reveals a direct correlation between the addition of NH₃ and the increase in NO_x emissions. Mixtures with a higher proportion of ammonia consistently generate more significant quantities of nitrogen oxides. This is because the nitrogen atoms in the ammonia molecules are readily available to participate in forming various NO_x species during the high-temperature combustion reactions.

The observed trends significantly affect the development of more efficient and environmentally friendly combustion systems. By carefully controlling the ammonia-to-carbon ratio in the fuel mixture, a balance may be struck between minimizing CO₂ emissions and managing the production of NO_x.

3.1.4. Influence of Ammonia on N₂O

Figure 5 shows the ratio of N₂O formation in the different simulation runs conducted. As can be seen from the data presented in the figure, the amount of N₂O formed by the combustion of 250 kg of various fuel blends is relatively minuscule. However, despite the overall low levels of N₂O formation, a clear trend can be observed in the results. The data indicates that as the amount of NH₃ present in the fuel blend increases, there is a corresponding increase in the production of N₂O. This suggests that including higher proportions of ammonia in the fuel blends leads to a rise in N₂O emissions during combustion.

3.2. Energy Balance

Table 7. Energy Balance.

Run	Feedstock (kg/h)			Energy Balance		Extra Mass to Match Coal Energy
	Coal	NH3	RDF	kWh	kWh/kg	kg/h	%
100/0/0	250	0	0	1077.42	4.31	-	0
0/0/100	0	0	250	826.56	3.31	75.90	30.36%
0/100/0	0	250	0	294.89	1.18	663.48	265.39%
50/50/0	125	125	0	686.11	2.74	142.61	57.05%
0/50/50	0	125	125	560.72	2.24	230.41	92.16%
50/0/50	125	0	125	951.96	3.81	32.97	13.19%
80/10/10	200	25	25	974.04	3.90	26.55	10.62%
60/20/20	150	50	50	870.70	3.48	59.38	23.75%
40/30/30	100	75	75	767.37	3.07	101.04	40.41%
20/40/40	50	100	100	664.05	2.66	155.66	62.26%

shows the kWh produced by each of the simulated runs. The blends with higher coal content create a more significant number of kWh. This is because coal is a highly energy-dense fuel, containing a considerable amount of stored chemical energy that can be released during combustion. Suppose it is compared to a blend of 100% coal with 100% RDF and 100% ammonia. In that case, the differences in energy output become more apparent.

The combustion of ammonia will require 265.39% additional mass to produce the same amount of energy as coal combustion. This is due to ammonia’s lower energy density compared to coal. Ammonia is a promising alternative fuel with a significantly lower calorific value than coal. This means a much larger ammonia is required to generate the same energy as coal. The additional mass needed for the combustion of ammonia to match the energy output of coal is a significant drawback, as it can lead to more extensive and expensive fuel storage, equipment, and handling requirements.

Meanwhile, the combustion of pure RDF would need 30.36% additional mass to equal the energy produced by the combustion of pure coal. RDF, a fuel derived from the non-recyclable components of MSW, has a higher energy content than ammonia but is still lower than coal. The 30.36% increase in mass required for RDF combustion to match coal’s energy output reflects the difference in the energy density of these two fuel sources.

The variations in energy output between these fuel sources highlight the importance of considering different fuels’ specific properties and characteristics when designing and operating power generation systems. Understanding various fuel mixtures’ energy density and combustion efficiency is crucial for optimizing power plant performance and efficiency.

3.3. Economic Analysis

Table 8. Economic Analysis.

Run	Blend (wt.%)			CO2 Cost	Blend Cost	Energy Income	Discount Rate 15%			Discount Rate 10%			Discount Rate 5%			Discount Rate 3%
Run	Coal	NH3	RDF	(EUR/year)	(EUR/year)	(EUR/year)	NPV	IRR	PBP	NPV	IRR	PBP	NPV	IRR	PBP	NPV	IRR	PBP
100/0/0	100	0	0	EUR423,234	EUR279,465	EUR1,674,546	EUR2,394,839	26%	7.30	EUR6,041,616	30%	4.88	EUR12,968,764	34%	3.61	EUR17,443,643	36%	3.26
0/0/100	0	0	100	EUR302,891	EUR132,674	EUR1,284,660	EUR1,210,242	21%	10.43	EUR4,292,673	25%	6.14	EUR10,157,453	29%	4.29	EUR13,952,257	31%	3.81
0/100/0	0	100	0	EUR0	EUR1,049,040	EUR458,320	EUR(9,151,421)	-	-	EUR(10,221,273)	-	-	EUR(11,851,950)	-	-	EUR(12,732,617)	-	-
50/50/0	50	50	0	EUR211,617	EUR664,253	EUR1,066,361	EUR(3,378,832)	−3%	-	EUR(2,090,593)	2%	-	EUR557,235	6%	17.92	EUR2,354,087	8%	13.91
0/50/50	0	50	50	EUR151,445	EUR590,857	EUR871,487	EUR(3,970,612)	−11%	-	EUR(2,964,331)	−3%	-	EUR(847,296)	2%	-	EUR609,761	5%	18.03
50/0/50	50	0	50	EUR363,063	EUR206,069	EUR1,479,551	EUR1,802,147.38	23%	8.58	EUR5,166,588	27%	5.44	EUR11,562,258	32%	3.92	EUR15,696,914	33%	3.51
80/10/10	80	10	10	EUR368,877	EUR341,743	EUR1,513,866	EUR1,121,233.31	20%	11.20	EUR4,239,697	24%	6.54	EUR10,204,436	28%	4.52	EUR14,075,508	30%	4.01
60/20/20	60	20	20	EUR314,519	EUR404,022	EUR1,353,253	EUR(151,864)	14%	-	EUR2,438,497	18%	9.55	EUR7,441,207	22%	5.98	EUR10,708,711	24%	5.15
40/30/30	40	30	30	EUR260,161	EUR466,300	EUR1,192,657	EUR(1,424,833)	8%	-	EUR637,479	12%	15.93	EUR4,678,258	16%	8.54	EUR7,342,255	18%	7.07
20/40/40	20	40	40	EUR205,803	EUR528,579	EUR1,032,070	EUR(2,697,740)	1%	-	EUR(1,163,451)	6%	-	EUR1,915,442	10%	13.57	EUR3,975,961	12%	10.69

presents the NPV, IRR, and PBP for various fuel mixture scenarios at four different discount rates. As can be seen from the results, only four scenarios are deemed economically viable at a discount rate of 15%.

The most economically viable scenario is the combustion of pure coal, which has an NPV of EUR 2,394,839, an IRR of 26%, and a PBP of 7.30 years. This scenario is the most attractive, despite having the highest costs for CO₂ emissions, at EUR 423,234. The reason for this is that the price of the raw material, coal, is much lower than that of ammonia and slightly higher than that of RDF. Furthermore, pure coal combustion produces more energy than RDF and ammonia, generating more income.

The second viable scenario uses 100% RDF. This is followed by a ternary mixture of 80% coal, 10% ammonia, and 10% RDF, and finally, a binary mixture of 50% coal and 50% RDF. These scenarios demonstrate the trade-offs between fuel costs, emissions, and economic viability.

Two additional scenarios become economically viable when the discount rate is reduced to 10%. The first is a mixture of 60% coal, 20% ammonia, and 10% RDF. The second is a binary blend of 50% coal and 50% RDF. The combustion of pure coal reduces the PBP to 4.88 years.

Similarly, two new scenarios are viable when the discount rate is 5%. Finally, when considering a discount rate of 3%, the only scenario that is not economically feasible is the combustion of pure ammonia.

Introducing these new viable scenarios at a lower discount rate highlights the sensitivity of the economic analysis to the chosen discount rate. It also suggests that as policymakers and decision-makers seek to promote more sustainable fuel blends, adjusting the discount rate may be an essential lever to incentivize the adoption of cleaner but potentially more expensive fuel sources.

The PBP of coal at 100% (4.88 years) is very close to the PBP reported by Keval Nikam et al. [79] in their study on the economic and exergoeconomic investigation of a 660 MW coal-fired power plant. The study by Nikam et al. found a PBP of 4.5 years for a plant with a 30-year lifespan and an interest rate of 9%. The proximity of the PBP values between the pure coal combustion scenario and the specific power plant analyzed by Nikam et al. suggests that the operating parameters and financial assumptions used in the two cases are similar. This alignment of the PBP metrics indicates that the pure coal combustion approach can achieve a relatively short payback period, making it potentially attractive from an investment perspective.

Yuli Fitrianingrum et al. [80] developed a techno-economic analysis to explore the viability of co-firing RDF in a coal-fired power plant. The study indicates a PBP of 6.33 years, assuming a discount rate of 8%. Interestingly, these results are remarkably similar to the findings of the current investigation, which examined the use of pure RDF at a slightly higher discount rate of 10%. In this case, the PBP was calculated to be 6.14 years, somewhat shorter than the co-firing scenario. The close alignment of the payback periods between the two studies suggests that RDF can be a financially attractive option for power plant operators.

Du Wen et al. [81] examined the potential of using ammonia as an energy carrier within a multi-generation system. Their analysis resulted in a PBP of 22 years. An investment with a PBP of 22 years is generally considered unattractive for many investors, as it takes a long time to recoup the initial capital outlay. Investors typically prefer investments with shorter payback periods, as they offer a faster return on their capital. Consequently, the long payback period obtained by Du Wen et al. would likely deter investors from committing funds to such a project. The current study found that energy generation from ammonia alone resulted in a financial loss, as no payback period was achieved under any of the scenarios investigated at different discount rates. This poor economic performance is primarily attributed to the high production costs associated with “Blue” ammonia, which refers to ammonia produced through low-carbon or carbon-neutral processes.

Therefore, the only viable way to utilize ammonia for energy generation is by combining it with other energy sources, such as RDF or coal. This approach would help offset the high costs of “Blue” ammonia and make the overall energy generation system more economically feasible. The viability of using 100% ammonia as an energy source could be improved if either energy prices rise significantly or if there is government intervention in the form of subsidies or other support mechanisms. Such interventions could help bridge the gap between the production costs of ammonia-based energy and traditional fossil fuel-based processes, making the former a more attractive and competitive option for investors and energy providers.

Improving Viability

Two primary strategies enhance the appeal and viability of zero-emission fuels such as ammonia.

EU Carbon Permit Prices: The expense associated with EU carbon permits is pivotal. The EU Emissions Trading System (ETS) renders carbon-intensive fuels like coal more costly. As permit prices rise, it becomes increasingly expensive for power plants and industries to use polluting fuels, making cleaner alternatives more attractive [82].

Government Programs and Incentives: Several government initiatives can advance zero-emission fuels. These initiatives encompass research grants, subsidies, tax incentives, loans, infrastructure investments, public–private partnerships, supportive regulations, and training programs. For example, the U.S. government has launched the National Blueprint for Transportation Decarbonization, aiming to eradicate all greenhouse gas emissions from the transportation sector by 2050 [83]. The EU’s Innovation and Modernization Fund provides financial support for developing and implementing low-carbon technologies [84]. In summary, economic pressure from rising EU carbon permit prices and robust government programs and incentives can significantly enhance the feasibility and adoption of zero-emission fuels like ammonia, paving the way toward a sustainable, low-carbon future.

3.4. Retrofitting Plants Implications

Implementing ammonia and RDF in coal-fired power plants requires several modifications to existing processes to ensure efficient and environmentally responsible operation (See Figure 6). While co-firing coal with biomass is an established practice, integrating ammonia and RDF presents unique challenges and opportunities for optimization [85].

A sophisticated control system is recommended to manage the introduction of RDF and ensure stable combustion effectively. Specifically, a pneumatic logic valve (PLV) system should be installed to regulate airflow. This PLV would connect to multiple control valves (CVs) strategically positioned throughout the system. The PLV’s operation would be guided by a Feedback Input Transducer (FIT) that is continuously monitoring airflow. By utilizing the FIT for real-time airflow data, the PLV can dynamically adjust the CVs, maintaining optimal combustion conditions and preventing issues like incomplete combustion or excessive emissions [86].

Furthermore, precise control over the fuel mixture is crucial. To achieve this, the system should incorporate two-blade control valves directly linked to the speed driver (SD) of the screw conveyor motor, which is responsible for transporting both RDF and coal. This direct connection allows for immediate and accurate adjustments to the flow rates of each fuel component. By monitoring the motor’s SD, the CVs can regulate the proportion of RDF and coal entering the combustion chamber, ensuring a consistent and controlled fuel supply. This is essential for maintaining stable combustion temperatures and minimizing variations in energy output. The combined, precisely controlled fuel flow and airflow will connect to the burner, forming the combustion input [87].

The injection of ammonia for NO_x reduction also requires careful consideration. Several approaches can be employed, each with its advantages and drawbacks. One method involves impregnating the RDF and coal mixture with ammonia within the screw conveyor or in the mixing hopper. This pre-treatment allows for a more homogeneous distribution of ammonia throughout the fuel stream. Another approach involves installing a series of nozzles with spray systems strategically located along the burner body. These nozzles would inject ammonia directly into the combustion zone, allowing for more targeted and responsive NO_x control.

Crucially, research indicates that the location of ammonia injection significantly impacts NO_x formation due to the varying temperature profiles along the burner. Regions experiencing the highest temperatures tend to promote NO_x formation. Therefore, the careful mapping of the temperature gradients within the burner is essential for determining the optimal injection points. The overall efficiency of NO_x reduction can be significantly enhanced by strategically positioning the ammonia injection system in cooler regions or areas where it can effectively react with NO_x precursors. This detailed understanding of temperature profiles and their influence on chemical reactions is vital for minimizing environmental impact and optimizing the performance of coal-fired power plants that utilize ammonia and RDF.

The scientific world is deeply engaged in solving the complex influence of NH₃ on the performance and emissions of burners and internal combustion engines. This research spans many investigations, from understanding how ammonia combustion characteristics differ from traditional fuels to pinpointing the precise chemical kinetics of its oxidation [88]. Furthermore, a significant portion of this research is dedicated to evaluating and developing effective strategies to mitigate the formation of NO_x. These NO_x emissions are an essential concern, contributing to smog, acid rain, and respiratory problems. Scientists are exploring various techniques, including optimizing combustion parameters like temperature and air-to-fuel ratio, employing advanced burner designs that promote lean combustion, and investigating post-combustion technologies like selective catalytic reduction (SCR) to minimize NO_x release into the atmosphere. Ultimately, the goal is to harness the potential of ammonia as a cleaner-burning fuel while reducing its environmental impact [89].

3.5. Operational and Safety Challenges of Using Ammonia as Fuel

Incorporating ammonia into coal power generation presents storage, safety, and transportation challenges. Therefore, developing ammonia infrastructure requires careful planning and implementation to minimize risks and ensure efficient operation.

Ammonia storage, for instance, necessitates specialized tanks and containment systems designed to prevent leaks and spills, often demanding specific pressure and temperature controls based on the scale and type of storage. Fortunately, this is regulated by the ASME Boiler and Pressure Vessel Code (BPVC) [90], ASTM (American Society for Testing and Materials) [91] and DOT (Department of Transportation) [92].

Safety protocols are critical since ammonia is toxic and corrosive. This parameter is also regulated by some institutions, namely OSHA (Occupational Safety and Health Administration) [93] and NIOSH (National Institute for Occupational Safety and Health) [94], which comprehensively include training programs for personnel, emergency response procedures, and the proper use of personal protective equipment. It is worth noting that ammonia is rated as a one on a scale from zero to four, indicating that ammonia requires preheating before ignition. The safety protocols are reported by NFPA (National Fire Protection Association) [95].

Regarding the large-scale transportation of ammonia—whether by pipeline, truck, or rail—they are also regulated by EPA (Environmental Protection Agency) [96], which addresses potential environmental impacts.

These significant considerations do not require completely reinventing the wheel. The Haber–Bosch process for ammonia production has existed for over a century, and ammonia’s industrial applications are extensive. This means there is a wealth of existing knowledge and best practices available from various industries, including fertilizer production and chemical manufacturing, which can be utilized to tackle the challenges of using ammonia in coal power plants. Extensive research and operational experience have already been established regarding ammonia handling, storage, transportation, and safety, allowing for adapting and optimizing proven technologies and procedures rather than starting from scratch. Rather than pioneering entirely new solutions, the emphasis can be placed on customizing existing methods to fit the requirements and constraints of integrating ammonia into the coal power generation process. This established knowledge base offers a solid foundation for developing a safe, efficient, and environmentally responsible ammonia co-firing system.

4. Conclusions

This comprehensive techno-economic analysis evaluated the feasibility and implications of using ternary coal, RDF, and ammonia blends in power generation. This study employed an Aspen Plus simulation model and considered various financial metrics, including the NPV, IRR, and PBP.

While pure coal combustion is energy-efficient, it has the highest global warming potential (GWP). Ammonia and RDF blends significantly reduce GWP, exhibiting a 3215% lower GWP than coal. Incorporating ammonia and RDF, even in small amounts, can mitigate the overall environmental impact of fuel combustion.

Pure coal remains the most economically attractive option, boasting the highest NPV and a PBP of 7.30 years at a 15% discount rate. Blends consisting of 80% coal, 10% ammonia, and 10% RDF also show promise with a PBP of 11.20 years at a 15% discount rate. Blends with 10% and 20% ammonia are economically viable and do not require significant modifications to coal power facilities. The economic feasibility of using ammonia alone is impractical due to high production costs but blending it with coal and RDF can enhance viability.

Ammonia and RDF have lower energy outputs than coal, necessitating additional mass to match coal’s energy production. Retrofitting existing coal-fired power plants to accommodate ammonia and RDF requires careful planning, including advanced control systems and precise fuel mixture management.

Ammonia storage, safety, and transportation present challenges but can be managed with existing industrial knowledge and best practices. Regulatory compliance and safety protocols are critical for ensuring ammonia’s safe handling and use in power generation.

Governments should consider implementing policies and incentives to promote the use of ammonia and RDF in power generation. This could include subsidies, tax incentives, and support for research and development. Continued research is necessary to optimize the combustion process, reduce NO_x and N₂O emissions, and enhance the economic viability of ammonia and RDF blends. Investment in ammonia storage, transportation, and handling infrastructure is vital to support the transition to cleaner fuel blends.

While pure coal combustion remains economically attractive, the environmental benefits of ammonia and RDF blends present a compelling case for their integration into power generation. Balancing economic and environmental considerations will be crucial in moving toward a more sustainable energy future. This study’s findings emphasize the importance of considering ecological and financial factors when evaluating the suitability of different fuel sources for energy production. Analyzing various fuel blends provides valuable insights for decision-makers and policymakers in the energy sector, enabling them to make informed choices that balance environmental concerns with economic considerations.