The Return of Coal-Fired Combined Heat and Power Plants: Feasibility and Environmental Assessment in the Case of Conversion to Another Fuel or Modernizing an Exhaust System

Abstract

Large city-scale coal-fired combined heat and power (CHP) plants are one of the main contributors to greenhouse gas emissions. The motivation is to find a way to decrease the contributions in the most feasible way possible. The importance of this study is that it presents a methodology for comparing scenarios from both environmental and economic points of view. The scenarios aim to enhance the environmental performance of combustion flue gas-treatment units. The scenarios include installing an advanced electrostatic precipitator (ESP), a hybrid system comprising ESP and a bag filter, a combined cyclone and baghouse filter, a hybrid baghouse filter with novel electrostatic tissue, a wet flue gas desulfurization (WFGD) scrubber, a WFGD with (NH₄)₂SO₄ technology, and fuel conversion (incl. biomass). Each of the scenarios is evaluated according to (a) primary energy consumption, (b) capital (CapEx) and operational (OpEx) costs, and (c) the obtained environmental effect (decreasing emissions of particulate matter (PM), CO₂, SO₂, and NO_x). Adopting biomass waste decreases CO₂ emissions by 50%. PM from the coal-fired boiler with particle filtration is lower compared to biomass but is two times higher than that from natural gas. Using advanced filters for a CHP plant decreases total emissions and PM by 2100–2800%. The largest effect on air quality is achieved by filtration and WFGD, with emissions decreasing by 43%. Primary energy consumption is maximal in fuel conversion and ESP scenarios. The conversion to limestone-based WFGD or the installation of a hybrid filter separately are the most viable options, totaling EUR 14.2 billion of CapEx. However, combining several technologies is essential to increase the quality of flue gas treatment.

1. Introduction

Forthcoming European codes limit particulate emission to between 30 mg/m³ and 20 mg/m³ for existing boilers and 5 and 50 MW for new boilers [1]. To meet this requirement, both the modernization of CHP plants and a new methodology to assess CHP plant performance in novel conditions are required. Caligiuri et al. [2] compared CO₂ emission levels for the three different power levels. When power levels decrease, a strong increase in emissions is detected, especially at low loads. As the load and the absolute fuel mass flow increase, relative CO₂ increments fall. Similarly, another factor in changing emissions is the global excess air. The air-to-fuel ratio significantly affects the emissions of CO₂ and NO_x. It was concluded that combustion at a low excess air rate produced fewer emissions, but this trend is more apparent in the case of NO_x emissions.

Aunon-Hidalgo et al. [3] presented the results of a CO₂ emissions’ evaluation. They include both the CO₂ generated during the experiment on a system and also the empirically calculated emissions for a system. The first difference was the use of not only cogeneration but also solar energy. Another difference was the consideration of the residential heat demand only, taking into account neither the heat losses nor the electricity exported to the power network.

Paakkonen et al. [4] presented another study on fuel transition. They demonstrated that bio-fueled combined heat and power (CHP) plants play a beneficial role in balancing power outages and align well with the concept of sustainable energy. However, a notable drawback is the cost of energy, which remains relatively high, hovering around its current value of EUR 25/MWh. This is mainly due to the need for subsidies to offset the generation of excess heat. The study primarily emphasized feasibility indicators, and the researchers concluded that providing sufficient compensation for the electricity price could significantly improve the overall performance of the plant. Coady et al. [5] strongly supported the adoption of biomass-fired DH plants in the remote northern and rural towns of Canada, especially those currently dependent on aging diesel generators. Another suggestion was to consider connecting them to remote electrical transmission lines. The results showed that biomass-fed CHP plants are a feasible alternative for any town or village when electrical transmission grid costs are considered. In both remote and rural settlements, the process of biomass gasification is advantageous when compared to biomass organic ranking CHP plants from the feasibility point of view.

To evaluate the impact of the suggested ideas, Galvagno et al.’s [6] case study examined a CHP plant in Italy, which generates energy for a factory producing citrus juices and oils. Unlike the present paper, the indicators in this study were the share of non-renewable heat production, specific primary energy consumption, and specific CO₂ emissions. These two latter values were defined as a correlation of the unit mass of the factory’s products and were used to assess the influence of citrus juice production on the consumption of primary energy and, consequently, on GHG emissions.

The CO₂ emissions from plants converted to biofuel plants are generally lower than those in the base integrated case. The problem stems from the higher operation of biofuel plants and increased power import; the total CO₂ and the marginal emissions from power consumption are higher in the case of biomass. In [7], they were 930 kton and 318 kton, respectively. The higher import costs and the primary energy consumption led to a 30% increase in O&M costs and reduced the system efficiency to 72%, in this case, from 79% in the base integrated scenario.

Salman et al. [8] presented the resulting waste flow in the combustor combined with recorded plant data. The waste flow from modeling follows the profiles of operational data, although the forecast of waste flow given by simulation is much lower at higher heat demand. One of the scenarios considered in that research implies using refuse-derived fuel as the primary energy source.

Like the present paper, Santoli et al. [9] reported on pollutant emissions. However, the case study was quite different—they assumed that the internal combustion engines were the base energy generators and paid more attention to the chemical species concentrations normalized at 5% O₂ in the exhaust gas (as required by the existing legislation). The third difference was in the methodology applied, e.g., CO₂ values were calculated by the Ostwald formulae of the combustion process.

Furubayashi et al. [10] studied a thermal power plant that generated electricity in full condensing mode, while heat demand was covered by the heat-only boilers in the ‘Heat Only’ and ‘Heat DHS’ cases. To detect the CHP capacity and consumption of wood chips, they introduced only a ‘CHP Base’ case, where heat demand equaled the base load. To sum up, the amount of wood chips used in each case was constant and set to enough to match the heat consumption in the ‘Heat Only’ scenario. Therefore, compared to Furubayashi et al. [10], the variations in fuel use and the associated amount of emissions are the novelties in our paper.

Both the transition to gas fuel and scenario analyses were detailed by Ward et al. [11]. However, they considered only the clean syngas produced by the gasifier. At the same time, their scenarios assumed the internal combustion engine (ICE) consuming a mix of ultra-low-sulfur diesel (deemed to be provided supplied at USD 0.62/L) and pyrolysis liquids generated by a gasifier. A gasifier equipped with a human–machine interface was operated at full load of the two Jenbacher engines. Upward adjustment factors (UAF) were used for emission tests. The gasifier produced sufficient pyrolysis liquids to represent 9.0% of the installed 9.6 MWe ICE capacity when it runs at full load. Another case is when the fuel required by an ICE is ultra-low-sulfur diesel only.

The secondary utilization of recirculated flue gas has an advantageous impact on NO_x emissions, as shown in the case of a large boiler [12]. The minimum NO_x emissions with the secondary utilization of recirculated flue gas were 95 mg/m3 and the NOx emission distinct curve values were reduced by 10% compared to the reference case. They concluded the reduction from complete to partial load considerably impacts NO_x emissions.

In Chakrovorty et al.’s [13] research, the rice parboiling system without an ash removal unit was titled an ‘Existing rice parboiling system’ or ‘Existing system’. On the other hand, rice parboiling systems with ash removal units were referred to as ‘Modified rice parboiling system’ or ‘Modified system’. The case study system consisted of a furnace, boiler, flue gas duct, and chimney. In contrast, the modified rice parboiling system now included an additional unit, an ash removal unit (ARU), installed between a boiler and a chimney.

The paper by Ala’a Khalil Al-Bawwat et al. [14] focused on Jordan’s energy independence, its reliance on imported oil and gas, and the potential use of biomass. The aim was to address Jordan’s energy challenges and assess biomass resources for electrical generation and biogas production through thermal treatment and direct combustion. Unlike the present research, which concentrates on large-scale coal-fired plants, Ala’a Khalil Al-Bawwat et al.’s work delved into the specific energy situation of Jordan, emphasizing the potential of biomass resources for a more diversified energy mix. Ref. [15] discussed Jordan’s energy dependency, emphasizing bioenergy, mainly biomass, as a competitive and environmentally friendly alternative. It highlighted that biomass is expected to supply half of Jordan’s primary energy demand by 2050 and explored nanotechnology applications in bioenergy production. Compared to the present paper, this work provides a broader perspective on bioenergy, including nanotechnology applications, and specifically focuses on Jordan’s energy landscape.

Mohamed R. Gomaa et al. [16] investigated the gasification of biomass materials using a solar reactor, aiming to produce syngas. The study focused on meeting global energy demands, especially in rural areas, and utilizing solar energy for gasification. The findings indicated that solar gasification of olive pomace and lignite can reduce tar formation and increase the gasification temperature. Unlike this paper, which concentrates on the combustion flue gas treatment in coal-fired plants, Mohamed R. Gomaa et al. explored the potential of solar-based gasification, offering a different approach to utilizing biomass for energy production. Ref. [17] proposed a method combining a solar energy heat source with a co-gasification process dependent on biomass and coal for syngas production. The objective was to transition from fossil fuels to renewable energy sources and extend reliable power sources to remote areas. Their findings suggested that solar-based co-gasification produces clean syngas, with oxygen crucial during periods of low or no solar energy. Unlike the present paper, that work combined solar energy with co-gasification, presenting a unique approach to harnessing renewable energy sources for syngas production, particularly in remote areas.

To the best of the authors’ knowledge, there is also no full methodology for a thorough feasibility and environmental assessment in case of conversion or modernization being available. The research question investigates the impact of modernizing a CHP plant to comply with forthcoming codes that prescribe particulate emission limits. This study differs from existing ones as it assesses the performance of the CHP plant under novel conditions and explores methodologies to meet stringent emission standards. Additionally, this research investigates the influence of various factors, such as power levels, air-to-fuel ratio, and fuel transition, on CO₂ and NO_x emissions in the context of coal-fueled CHP plants.

Regarding different engineering and research aspects, the motivations and importance are as follows:

• Emission Compliance: This study is motivated by the need to adhere to upcoming European codes that set specific particulate emission limits for different categories of boilers. Compliance is crucial for environmental sustainability and regulatory adherence.
• Performance Assessment: Modernizing the CHP plant requires comprehensively evaluating its performance in novel conditions. This research addresses the need for methodologies to ensure optimal operation and compliance with emission standards.
• Impact of Power Levels: The investigation into CO₂ emissions at different power levels highlights the importance of understanding how variations in load affect emission levels. This knowledge is vital for designing efficient and environmentally friendly energy systems.
• Air-to-Fuel Ratio: This study emphasizes the significant influence of the air-to-fuel ratio on both CO₂ and NO_x emissions. The findings contribute to understanding combustion dynamics and guide decisions toward reducing environmental impact.
• Fuel Transition: The conversion of coal-fueled CHP plants and their role in balancing power outages aligns with the global shift towards sustainable energy. The present study considers the economic aspects of fuel utilization, indicating the potential for feasibility improvements.
• Case Study Analysis: Including a case study and comparisons with other research highlights the versatility of the findings. It demonstrates the need to consider various indicators, including non-renewable heat production and specific CO₂ emissions, to comprehensively assess the environmental impact of energy generation.
• Synthesis of Findings: The diverse range of studies referenced provide a holistic understanding of factors influencing emissions in CHP plants. Synthesizing these findings contributes to a comprehensive knowledge base for researchers, policymakers, and practitioners involved in sustainable energy solutions.

Summarizing all the abovementioned efforts, this paper globally:

• integrates findings from various studies to propose a comprehensive approach to CHP plant modernization, considering power levels, air-to-fuel ratio, and fuel transition;
• mentions the policy implications of adhering to emission standards and the potential role of government incentives in promoting the transition to sustainable energy sources;
• explores the economic feasibility of coal-fired CHP plants, taking into account the impact on operational and maintenance costs and the potential for subsidies to offset excess heat generation;
• highlights any technological innovations or improvements suggested by other studies that could enhance CHP plants’ efficiency and environmental performance;
• considers the global applicability of the findings, especially in the context of diverse energy demands and regulatory environments.

In summary, the novelty is in highlighting the challenges and opportunities associated with modernizing CHP plants to meet stringent emission standards, offering a foundation for further research and practical applications in sustainable energy. The overall research project aims to comprehensively investigate and evaluate various filtration and operational scenarios implemented in coal-fired boilers to enhance efficiency, mitigate the environmental impact, and overcome inherent limitations. Through a systematic analysis of seven distinct filter types and associated modifications, coupled with fuel conversion technologies, this paper specifically aims to:

• assess the effectiveness of ESP, hybrid systems, cyclone-baghouse combinations, and modified ESP configurations in capturing particulate matter, addressing the specific challenges associated with each scenario;
• evaluate the performance of innovative technologies, such as electrostatic tissue in hybrid baghouse filtration systems, to enhance the removal of submicron and nanoparticle pollutants, contributing to improved overall air quality;
• investigate the impact of incorporating raw water scrubbing and limestone-based WFGD scrubbers on ash removal and sulfur compound capture, respectively, to achieve more effective and comprehensive pollution control;
• examine the advantages and challenges associated with fuel conversion technologies, specifically the transition to natural gas and the utilization of heavy oil as a backup fuel source, aiming to understand the implications for emissions, efficiency, and operational flexibility;
• provide insights into integrating these scenarios and their potential synergies, considering the holistic impact on the coal-fired boiler system’s overall performance and environmental sustainability.

By addressing these objectives, this paper is expected to contribute valuable knowledge to the field of coal-fired boiler technology, offering practical insights for researchers, engineers, and policymakers seeking sustainable solutions to enhance energy production while minimizing environmental impact and operational challenges.

2. Materials and Methods

Design primary energy consumption [kg/h] is:

$${\mathrm{B}}_{\mathrm{d}}=\frac{{\mathrm{Q}}_{\mathrm{d}}}{\mathrm{LHV}·\eta }\times {10}^6,$$

(1)

where Q is the design heat capacity of a boiler unit [MW];

• LHV is the lower heating value [MJ/kg];
• η is boiler efficiency.

Total fuel consumption [g/s] or [tones per annum] is then:

$$\mathrm{B}={\mathrm{K}\mathrm{B}}_{\mathrm{d}},$$

(2)

where K is the demand factor [-]:

$$\mathrm{K}={\tau }_{\mathrm{O}\mathrm{T}}/8766,$$

(3)

where τ_OT is the average duration of an SH season [h per annum].

Total fuel consumption for natural gas is [g/s] or [tons per annum]:

$$\mathrm{B}=\mathrm{V}\mathsf{\rho };$$

(4)

$$\mathrm{LHV}={\mathrm{LHV}}_V/\rho ,$$

(5)

where V is the consumption of natural gas [m³/year];

• ρ is the density of natural gas [kg/m³], typically ρ = 0.76–0.85;
• LHV_v is the lower heating value (volumetric) [kJ/m³].
• Ash typically includes SiO₂ (30–60%), Al₂O₃ (15–28%), Fe₂O₃ (2–10%), CaO, MgO, K₂O, Na₂O, TiO₂, MnO₂, P₂O₅, and C_mH_n.

To assess its amount, Formula (6) is suggested:

$${\mathrm{M}}_{\Pi }={\mathrm{B}\mathrm{A}}^{\mathrm{P}}\frac{{\alpha }_{\mathrm{y}\mathrm{H}}}{100-\mathrm{CCRs}}(1-{\eta }_3),$$

(6)

where η₃ is the filter efficiency;

• α_yH is the fly ash [%];
• CCRs are the total content of combustible material in fly ash [%].

CCRs are simpler to assess with Equation (7):

$$\mathrm{CCRs}=\frac{{\mathrm{q}}_4^{\mathrm{y}\mathrm{H}}}{{\mathrm{q}}_4^{\mathrm{y}\mathrm{H}}+\frac{32680}{{\mathrm{Q}}_{\mathrm{H}}^{\mathrm{P}}}{\mathrm{A}}^{\mathrm{P}}{a}_{\mathrm{y}\mathrm{H}}}100,$$

(7)

where ${\mathrm{q}}_4^{\mathrm{y}\mathrm{H}}$ are heat losses due to fly ash [%]; and A^p is the ash content.

For heavy oil, V₂O₅ emissions are also assessed [tons/year]:

$${\mathrm{M}}_{{\mathrm{V}}_2{\mathrm{O}}_5}=10^{-6}{\mathrm{G}}_{{\mathrm{V}}_2{\mathrm{O}}_5} \mathrm{B}$$

(8)

where ${\mathrm{G}}_{{\mathrm{V}}_2{\mathrm{O}}_5}$ is the specific mass content of V₂O₅ [g/t].

If no data on ${\mathrm{G}}_{{\mathrm{V}}_2{\mathrm{O}}_5}$ are available, it can be characterized by an empirical formula (based on data obtained from experiments in JSC, the “All-Russia Thermal Engineering Institute” (JSC “VTI”)):

$${\mathrm{G}}_{{\mathrm{V}}_2{\mathrm{O}}_5}=95.4{\mathrm{S}}^{\mathrm{P}}-31.6,$$

(9)

where S^P is the sulfur concentration per volume of heavy oil at dry, normal conditions (273 K and 101 kPa) [-].

The mass flow rate of SO₂ produced by a boiler per annum [tons/year]:

$${\mathrm{M}}_{{\mathrm{SO}}_2}=0.02 \mathrm{B} {\mathrm{S}}^{\mathrm{P}}(1-{\eta }_{{\mathrm{SO}}_2}^{\prime }\left)\right(1-{\eta }_{{\mathrm{SO}}_2}^{″})$$

(10)

where ${\eta }_{{\mathrm{SO}}_2}^{\prime }$ is the efficiency of sulfur converted by fly ash per dry, normal cubic meter of flue gas, normalized at a 13 vol% O₂ concentration (

Table 1. Average ${\eta }_{{\mathrm{SO}}_2}^{\prime }$ for various types of fuel.

Fuel	${\mathbf{\eta }}_{{\mathbf{SO}}_2}^{\prime }$
Peat	0.15
Oil shale	0.5–0.8
Anthracite	0.02
Lignite, often referred to as brown coal	0.5
Bituminous (black) coal	0.1–0.2
Heavy oil	0.02
Natural gas	0

) [-].

3. Case Study

The scenario analyses to prove whether fuel transition or gas treatment is better, or the proper options for a larger plant, are performed for CHP plants supplying the DH system of Omsk (Russia), where the ecological situation is relatively poor (Figure 1).

As the emphasis of this research is on GHG emissions, a large DH plant ought to be studied thoroughly, and may provide detailed data on the role of the flue gas treatment in balancing the pollutant emissions (scenarios 1–7). The environmental simulation was also performed using a CHP plant in Omsk (Russia) as a case study. A CHP plant is assumed to run either in combined mode, heat mode (following heat demand), or power mode (following power demand).

CHPP#5 (1763 MWth/735 MWel), put into operation in 1986, was used as a reference case and in future scenarios to check how new filtering equipment will affect the plant’s emissions.

The scenarios of a transition to natural gas and heavy oil applied to these CHP plants were also used to validate the model. There are also plans to increase plant capacity in the long term (2030–2035) up to 2.06 GWth/785 MWel. To compare, Galvagno et al. [6] reported a CHP plant in Italy producing electricity and heat for a citrus juice factory. Despite this, the CHP plant has a continuous need for power from the electricity network during the year. Revenues of heat production and electricity generation to return costs of the suggested technologies are limited because of the scheduled service work at the CHP plant in June and July. It provides operating hours of only ~8450 h per annum. As a result, the suggested system’s heat and net electricity generation have decreased to 2.26 TWh per annum and 2.55 GWh per annum, respectively, compared to the current values of 2.38 TWh/year and 2.79 GWh/year.

In total, seven different filter types are assessed:

• An ESP (scenario #1). ESPs are commonly used for particulate matter removal in flue gas. They can be effective in capturing fine particles through the application of an electric field;
• A hybrid system for particles installed at a coal-fired boiler comprising an ESP and a conventional bag filter operating alone (scenario #2). Combining an ESP and a traditional bag filter provides a dual-stage filtration system, enhancing the overall particulate removal efficiency. This hybrid approach can address a broader range of particle sizes;
• Combined cyclone + baghouse filter (scenario #3, Figure 2). Cyclones are efficient in removing larger particles, while baghouse filters are effective for finer particles. Combining them provides comprehensive particle removal;
• An ordinary ESP, adding a metal sheet to be used as a new roof, increasing volume, and dividing the whole unit into two chambers: an existing chamber and a new one (scenario #4). Modifying the ESP to create separate chambers with a metal sheet can improve efficiency by controlling airflow and particle distribution;
• A novel type of electrostatic tissue may be used in a hybrid baghouse filtration system for the deposition of submicron- and nanoparticles on particles of medium size (5–20 μm, scenario #5). The novel electrostatic tissue in a hybrid baghouse can enhance particle capture, especially for submicron- and nanoparticles, providing improved filtration efficiency;
• Sometimes, raw water is used as a scrubbing liquid to make the ash removal unit more effective (scenario #6). Using plain water as a scrubbing liquid can enhance ash removal efficiency. Water can capture and remove particles more effectively than dry methods;
• As in 6 above, but augmented with a limestone-based wet flue gas desulfurization (WFGD) scrubber (scenario #7). Adding a WFGD scrubber can further improve air quality by removing sulfur compounds. Combining this with raw water scrubbing enhances the overall pollution control.

The fuel conversion technology utilized in this research includes conversion to natural gas. The backup fuel is either the same—hard coal, which is referred to as scenario #8, or heavy oil (scenario #9). Natural gas combustion generally produces fewer pollutants than coal, producing cleaner emissions. This conversion can help meet environmental standards and reduce operational challenges associated with coal combustion. Having a backup fuel source provides operational flexibility. Heavy oil combustion may have different emission characteristics than coal, potentially offering advantages in specific scenarios.

In summary, the effectiveness of these scenarios lies in their ability to address specific limitations and operational challenges associated with coal-fired boilers. Combining different filtration methods, modifications, and fuel conversions contributes to an integrated approach for improving overall efficiency and reducing environmental impact. However, the specific effectiveness of each scenario would depend on factors such as the scale of the system, local regulations, and the characteristics of the fuel used, as discussed in this paper.

4. Results and Discussion

This section considers what may affect the CHP technology’s total profitability, as shown in Figure 3, once the O&M costs and investments are combined.

The capital costs for bag filters and ESPs are almost similar, while O&M costs for an ESP are 11 times lower (approximately 990%), going from EUR 2.15 M/year to EUR 197 k/year. The reason is the lifespan of bags: 1.5–2 years for a traditional one and 1 year for an advanced one (scenario 5). O&M costs for ESPs and combined options range between EUR 197 k/year and EUR 1.31 M/year due to the scheduled work of the boilers and turbines in June and July. According to the suggested system’s actual gross and net electricity production, capital costs vary between EUR 302 and 552 k. Compared with the revenues associated with the annual heat production and electricity generation of 2.26 TWh/year and 2.55 GWh/year, respectively, as shown in Section 3, that makes it quite affordable equipment.

The performance characterization results when switching to natural gas- or heavy oil-fired plants are shown in

Table 2. Overview of costs for natural gas and heavy oil as backup fuel. The primary fuel is natural gas.

Backup Fuel/CAPEX [bn EUR]	Coal			Heavy Oil
	CHPP#3	CHPP#4	CHPP#5	CHPP#3	CHPP#4	CHPP#5
Conversion of boiler units	0.95	2.4	3.4	0.95	2.4	3.4
Connecting to the supply of natural gas	Completed	n/a	0	Completed	n/a	0
Constructing flue gas treatment	1.0	1.0	2.0	1.0	1.0	2.0
Reconstructing an ash dump	n/a	n/a	n/a	0.8	0.8	1.6
Modernizing the supply of heavy oil	n/a	n/a	n/a	0.15	0.3	0.4
Total	1.95	3.4	5.4	2.9	4.5	7.4

and

Table 3. Overview of toxicological responses. Results for gases and particulate matter are given for no exposure after the empirical transition to combustion of natural gas and coal/heavy fuel oil (backup fuel, scenarios #8 and #9).

Indicator/CHP	Before			After
	CHPP#3	CHPP#4	CHPP#5	CHPP#3	CHPP#4	CHPP#5
Total emissions [t]	1746	34,603	53,901	1746	1202	2510
Particulate matter [t]	n/a	15,714	9384	n/a	n/a	n/a
SO2 [t]	20	13,065	30,355	20	14	3091
CO2 [t]	0	299	438	0	0	0
NOx [t]	1704	5522	13,723	1704	1173	2450
Other gases [t]	22	2	1	22	15	32
Total [t]	90,250			5458

.

Both alternatives are assigned an equivalent primary energy consumption value to meet the existing heat production requirements from the steam boiler, along with extraction from a high-pressure steam turbine supplying the low-pressure steam header and subsequently distributing through a district heating network to city consumers. These options’ capital expenditure (CapEx) are assessed at EUR 5.4 and 7.4 billion, respectively.

In terms of their configurations, all five proposed scenarios for installing filtration equipment (see Figure 4) exhibit lower investments than scenarios involving a switch to either gas or heavy oil. Notably, even though these filtration scenarios include additional equipment, their overall costs are still more economical. It is essential to highlight that the excluded expenses—comprising the operation of the gasifier/gas boiler—encompass operating materials, consumables (such as ammonia, limestone, hypochlorite for gas treatment, and catalysts for SO₂ and CO₂ conversion), and waste disposal (including exhausted catalysts, wastewater, ash, and other solid waste), which will be elaborated upon later.

Furthermore, it is essential to note that the costs associated with transitioning to natural gas and modernizing heavy oil facilities both escalate with increasing plant capacity, whereas other expenses remain fixed. To compare, in Daraei et al. [7], approximately 183 kton (~205,000 m³) of bio-oil was produced in the system, from the sale of which a revenue of only EUR 166 million was achieved. By assuming the generation costs of the pyrolysis and the onsite hydrogen supply from the sales revenues, a profit of about EUR 20 Mis performed in their combined system.

The environmental advantages of the ‘transition to gas’ scenario in this study hinge on both particulate matter and gaseous emissions, which have a pronounced impact on local air quality. This improvement is particularly noteworthy as emissions of key pollutants like SO₂ and NO_x decrease significantly. Utilizing Equations (1)–(5), the annual emissions of CO₂ associated with the production of heat and power are calculated to be 299 and 438 tons per year, respectively. However, these emissions are reduced to 0 tons per year under the new scenario. Similarly, the NO_x emissions, according to Table 3, are quantified at 1173 and 2450 tons per year, and they are markedly diminished with the implementation of the new scenario. The total flue gas volume emitted in meeting power and heat demand is 90,250/5458 tons per annum (before/after, respectively). The respective shares of NO₂ in this emission are detailed as 1704/1704 for CHP plant #3, 5522/1173 for CHP plant #4, and 13,723/2450 for CHP plant #5. To compare with Galvagno et al. [6], the yearly emissions of CO₂ related to the production of citrus juice and oils were 10,698 t/year. In contrast, after the new options were implemented, they were reduced to 5666 t/year, accounting for 0.31 and 0.17 tons of CO₂ per product. These results corroborate that adopting biomass waste as a fuel for a combined gasification–CHP system may decrease the carbon dioxide emissions of the production of citrus juice and oils by about 50%, compared to the average citrus processing plant in Europe.

The total emissions of particulate matter from the coal-fired boiler with particle filtration were lower or on a similar level to the particulate matter emissions, which were registered from wood-fired grate boilers, but 1.5–2 times higher than from natural gas-fired boilers. These insights reveal that using natural gas as the fuel for a CHP plant may decrease total emissions and particulate matter production by about 2100–2800%, compared to the reference CHP plant in Omsk. To compare with Sippula et al. [1], emissions from the biomass boiler without particle filtration were lower or on a similar level to the total particulate matter emissions, which were registered from wood-fired grate boilers but two–three times higher than from heavy fuel oil-fired boilers.

The total emissions for each scenario before and after implementation are reported in Figure 4.

The expenses for filtration and the side production of sulfur fertilizer or gypsum (4.99–14.1 bn EUR) are nearly the same as the cost of changing the primary fuel (EUR 5.4 or 7.4 bn). O&M costs are EUR 65, 280, 1500, and 2750 M for scenarios 2, 3, 6, and 7, respectively. Compared to [11], these costs are higher, but Ward et al. considered no expenses for, e.g., sulfur, ammonia, or limestone facilities. In addition, there was no accounting for GHG taxes or fines, as none were reported in Ward et al.’s [11] paper. Of the scenarios in the study of Coady et al. [5], the biomass-based CHP options have the second lowest and second highest O&M costs at USD 370 and 406/MWh, respectively.

The anticipated shifts in air quality stemming from the adoption of multiple filtration cases and wet flue gas desulfurization scrubbers, resulted in an anticipated reduction in total emissions by 22.5 and 39 tons, respectively. Correspondingly, scenarios #6 and #7 ensure a 43% reduction in total emissions when 100% of boilers are equipped. Simultaneously, scenarios #2 and #3, through a significant decrease in the concentration of particulate matter in the exhaust gases, contribute to a 25% reduction in total emissions. This reduction extends to NO_x emissions and a decrease in flue gas sensible heat loss compared to the reference plant settings and conditions.

It is crucial to note that there is no option for a fossil fuel-free energy supply capable of reducing emissions to zero, a concept that was explored by Daraei et al. [7]. The CapEx and, thus, the prices for heat supplied from the CHP plant in ‘fuel conversion’ cases include heavy oil facilities. Additionally, with estimated long-term data [18], the hourly heat supply decreases. Hence, the total primary energy consumption from the DH plant has its maximum in ‘fuel conversion’ and ‘electrostatic precipitator’ cases when compared to other scenarios. That results in an increased primary energy supplied to the DH plant. Thus, the stack emission analysis shows that the CO₂ emissions from the CHP plant may even increase. Another downside is that there are no reducing payments of ecological charges and penalties from natural gas and heavy oil in the system in fuel transition cases.

The overall effect is mostly about decreasing fossil-based emissions from the CHP plants. A total of 84.7 k tons were reduced compared to 22.5 and 39 k tons for the best obtained ‘filtration’ and ‘wet flue gas desulfurization scrubber’ cases, respectively (

Table 4. Overview of indicators describing scenarios #3, #2, #6, and #7 (specific CapEx ascending).

Scenario	Decrease in Emissions	CAPEX	O&M Costs	Specific CAPEX *
Unit	kton	bn EUR	bn EUR/yr.	MEUR/t
#3	22.5	5.0	0.28	0.217
#2	22.5	5.8	0.07	0.252
#6	39	13.8	1.5	0.764
#7	39	14.1	2.75	0.783
Total effect **	61.5	19.9	3.03	-

* Per 1 ton of emission gases; ** when combining all the scenarios according to the assessment of technical capability.

).

To sum up, the specific expenses for the studied scenario #3 are the lowest compared with the standalone scenarios in the reference system. The composition of emissions expected for scenario #3 is reported in

Table 5. Comparison of CHPP#5 emissions for current and advanced filtration solutions (scenario #3).

	Before	After
Total emissions [t]	53,901	18,598
Particulate matter [t]	9384	1314
SO2 [t]	30,355	3091
CO2 [t]	438	438
NOx [t]	13,723	13,723
Other gases [t]	1	32

.

The observation here is that the minimum capital costs of EUR 5.0 billion are associated with the baghouse filter’s design operating conditions. In comparison, the maximum capital costs of EUR 20 billion are universally related to the wet scrubbers. The optimal choice for the local district energy company involves converting the filtration system to a wet scrubber at CHP plant #5 and installing hybrid filters at CHP plants #4 and #5, incurring a total capital cost of EUR 14.2 billion.

Another consideration is that concentrations of particulate matter in the exhaust gas were consistently higher after a hybrid filter (scenario #2) than after a baghouse filter (scenarios #3 and #5). Furthermore, specific capital costs for a proper particle filtration system (such as the ESP in this paper) to achieve similar particulate matter levels as those attained with wet scrubbers are much higher (see Table 4 and Table 5). Simultaneously, the variations for the ESP options exhibit a similar pattern concerning specific capital costs and the same emission characteristics as the wet scrubbers. As mentioned above, this behavior is attributed to the volumetric effect associated with the preset of operating at winter (high-load and peak) modes. However, wet scrubbers generally are considerably more effective and yield fewer by-products.

The total emissions obtained (reduction by 61.5 kton) are 69% lower than the recorded overall emissions in 2021. This indicates that, with the most viable approach (conversion to a limestone-based WFGD at CHP plant #5 and modernization to install a hybrid filter at CHP plants #4 and #5), the emissions produced to meet the complete energy demand (heat and power) of the city consumers are 56% lower than the current level generated solely to meet electrical consumption. Additionally, there is an option to generate 50 kton of emissions per year using the baghouse and combined filters, which is only 25% lower than the total emissions projected for the plants in 2026.

The observed patterns and trends in this study provide valuable insights into optimizing capital costs and emission reduction strategies for the district energy company. The distinction between the minimum and maximum capital costs associated with different filtration systems highlights a significant consideration in decision-making. The prevalence of higher capital costs with wet scrubbers universally suggests a need for a nuanced evaluation of plant-specific requirements and conditions. This points to the importance of tailoring filtration solutions to the unique characteristics of each CHP plant to achieve optimal cost-effectiveness.

A noteworthy observation from this study is the consistent increase in particulate matter concentrations after employing hybrid filters compared to baghouse filters. This finding prompts further investigation into the trade-offs between filtration efficiency and specific capital costs. The comparison of ESPs with wet scrubbers indicates that achieving similar particulate matter levels incurs higher specific capital costs for ESPs. This trend underscores the significance of choosing filtration technologies that balance efficiency and cost-effectiveness, considering both capital costs and emission reduction capabilities.

The comprehensive analysis of total emission reductions, accounting for different scenarios and plant-specific strategies, adds depth to the discussion. The identified approach of converting to a limestone-based WFGD at CHP plant #5 and modernizing with a hybrid filter at CHP plants #4 and #5 stands out as the most viable option. The substantial reduction in total emissions by 61.5 kton, representing a 69% decrease from the recorded overall emissions in 2021, emphasizes the effectiveness of the proposed strategy. Furthermore, comparing emissions produced to meet the complete energy demand of the city consumers against those generated solely for electrical consumption highlights the significant impact on environmental sustainability.

In broader terms, these findings contribute to the growing body of knowledge on sustainable energy practices. This study provides practical insights for the local district energy company and serves as a reference for other similar contexts. The observed patterns and trends underscore the importance of context-specific evaluations in selecting filtration technologies and emission reduction strategies, aligning with the global trend towards environmentally conscious and economically viable energy solutions. As industries worldwide strive to meet emission targets and enhance sustainability, this study’s generalizable patterns offer valuable guidance for optimizing energy systems on a broader scale.

5. Conclusions

This paper evaluates the comprehensive composition of pollutants emanating from a plant during coal firing to assess the environmental impact of a CHP plant undergoing reconstruction. Various options exist to seamlessly integrate new eco-friendly technologies with existing facilities, including shifting to gas and heavy oil as backup alternatives or installing enhanced flue gas treatment facilities, particularly in cases where the conversion to liquid fuel cannot be practically integrated into an existing DH plant.

The presented findings unveil that the concurrent operation of an electrostatic precipitator and a baghouse filter (scenario #2) results in an annual 82% reduction in emissions. This effect is further pronounced due to the extended lifespan of the bags, beyond the year 2024, provided that the normal operating conditions detailed above are adhered to. The total particle mass concentrations in the large-scale coal-fired boiler upstream after the ESP are anticipated to fall within a range similar to the typical emissions from wood-fired grate boilers [1], albeit 10.5 times lower than the previous levels.

Future fuel and filtering equipment prices play a pivotal role in determining the economic advantages of integrated ash removal units. Integrating multiple technologies in a single unit is crucial for enhancing the quality of DeNO_x, DeSO₂, and DeCO₂ removal processes. The conversion to a wet scrubber at CHP plant #5 and the modernization required for installing a hybrid filter at CHP plants #4 and #5 appear to be the most viable options, incurring a capital expenditure of EUR 14.2 billion. The modernization of baghouse filters (EUR 5.0 billion) and the subsequent integration process with WFGD (EUR 20 billion) are also studied to compare overall feasibility.

In conclusion, implementing eco-friendly technologies, such as the concurrent operation of an electrostatic precipitator and a baghouse filter as presented in scenario 2, emerges as a highly effective strategy for mitigating the environmental impact of coal-fired CHP plants undergoing reconstruction. The substantial 82% reduction in emissions, especially when compared to pre-upgrade levels, underscores the transformative potential of advanced flue gas treatment facilities. The extended lifespan of the baghouse filter further enhances the longevity of emission control measures, ensuring sustained benefits beyond 2024. These outcomes emphasize the practical feasibility and substantial positive impact of integrating cutting-edge technologies, thereby setting the stage for a more sustainable and environmentally friendly future for CHP plants.

Looking ahead, it is imperative for policymakers, industry stakeholders, and environmental advocates to collaboratively prioritize and incentivize the adoption of advanced flue gas treatment technologies in the broader energy sector. Future initiatives should focus on fostering research and development in sustainable energy sources to gradually transition away from coal-fired operations. In addition, ongoing efforts to monitor and regulate emissions should be intensified to ensure compliance with environmental standards and to promote a continuous improvement mindset within the industry.