Thermodynamic analysis of ammonia co-firing for low-rank coal-fired power plant

ABSTRACT

As one of the largest sources of CO₂ emissions, the integration of non-carbon fuels in coal-fired power plants will significantly impact the global decarbonisation strategy. Hydrogen is a potential non-carbon fuel, and ammonia is a promising hydrogen carrier fuel. In this study, the effect of ammonia co-firing in a low-rank coal-fired power plant is thermodynamically modelled and evaluated in Aspen Plus V12.1. The integrated co-firing system is modelled in two different cases. The first case is made to maintain the combustion process, resulting in constant excess oxygen content in the flue gas. The second case is to minimise the fan modification in the power plant by maintaining the maximum air flow rate. The results show that increasing fraction of ammonia reduced CO₂ and SO_x emissions due to the decreasing coal fraction. NO_x emission proportionally changes with the furnace temperature, which increases at constant excess oxygen case and decreases at constant airflow case. It was also shown that both cases’ boiler efficiency is relatively similar on the same ammonia fraction. The thermodynamic analysis provides an initial assessment of the implementation of ammonia co-firing in coal-fired power plants as an effort of decarbonisation in the energy sector.

KEYWORDS:

• Ammonia co-firing
• coal-fired power plant
• CO₂ emission
• thermodynamics

Nomenclature

Symbols
$A$	=	furnace area
${\overline{\alpha }}_{fu}$	=	average emissivity furnace wall-flame system
$\text{β}$	=	coefficient of average radiation temperature
$HHV$	=	Higher Heating Value
$M$	=	Moisture
$T$	=	adibatic flame temperature
$\psi$	=	thermal efficiency constant
$p$	=	Partial pressure

Subscript
$ar$	=	As received
$adb$	=	Adiabatic flame
$ADP$	=	Acid dew point
$d$	=	dry
$g$	=	Average gas
$FEGT$	=	Furnace exit gas temperature

Abbreviation
HE	=	heat exchanger
WW	=	water wall
RH	=	reheater
ECO	=	economiser
PSH	=	primary superheater
SSH	=	secondary super heater
SEP	=	Vapour–liquid separator
SPLT	=	Split
MX	=	mixer
HPH	=	High-pressure heater
LPH	=	Low pressure heater
HPP	=	High-pressure pump
LPP	=	Low-pressure pump
HPT	=	High-pressure turbine
IPT	=	Intermediate pressure turbine
LPT	=	Low-pressure turbine

1. Introduction

The growing concern about climate change emphasises the importance of a global transition to lower greenhouse gas (GHG) emissions (Pegels and Altenburg 2020). The global response to climate change threats was reflected in the Conference of the Parties 21 (COP21), also known as the Paris Agreement, in 2015, which resulted in a resolution to limit global temperature rise. Seven years after COP21, the COP27 in Sharm El Sheikh, Egypt. in 2022 was held to evaluate implementation. The realisation of a decarbonised society is a significant issue that is being widely debated, and the pressure to decarbonise is increasing in all fields, including the energy sector. Carbon dioxide (CO₂) is the most prominent greenhouse gas (GHG) that affects our climate by generating a greenhouse effect that traps thermal radiation in the Earth’s atmosphere, raising temperatures and fostering adverse impacts such as melting ice caps, rising oceans, and plant loss (IPCC 2018). If emissions continue to climb until 2050, studies anticipate a world average temperature increase of around 1°C leading to 1.5°C (IPCC 2018).

The energy sector is the most significant contributor to GHGs (EPA 2016). Currently, electricity generation by coal combustion, is by far the most dominant use of coal worldwide (Figure 1) accounting for approximately 36.7% of electricity generation or 9914448 GWh (Zhongyang and Michalis 2017; IEA 2021). Given its significant contribution to global emissions, power generation has a lower decarbonisation difficulty than other energy services (Davis et al. 2018). Therefore, the non-carbon fuel integration in the coal-fired power plant as one of the major power generation facilities will significantly impact the global decarbonisation strategy. From an economic and technical point of view, the integration of non-carbon fuel shall be performed gradually, allowing the existing facilities to be used with modifications.

Figure 1. Electricity production in the world (IEA 2021).

Among non-carbon fuels, hydrogen has a number of benefits, including high combustion performance, a broad range of production and utilisation methods, and high conversion efficiency (IEA 2019; Nikolaidis and Poullikkas 2017; Møller et al. 2017). While hydrogen has a very high gravimetric energy density (a lower heating value of 120 MJ/kg), it has an incredibly low volumetric energy density of only 0.0108 MJ/L (ambient conditions). As a result, hydrogen must be stored efficiently in various ways, including compressed, liquid, hydrides, adsorption, and reformed fuels.

Liquid hydrogen, methyl-cyclohexane, and ammonia have been studied as hydrogen carriers; techniques for utilisation are already developed (Juangsa et al. 2018; Iki et al. 2015; Valera-Medina et al. 2018; Valera-Medina et al. 2015). Ammonia has significant advantages in the well-established storage system and its direct utilisation as a fuel in the combustion system. The International Energy Agency (IEA) report on the strategies for renewable energy utilisation in the industrial sector also concluded that ammonia is one of the most attractive energy carriers with significant economic advantages (Philibert 2017). In addition, ammonia has the least cost for transportation either by ship or pipeline (The Royal Society 2020). Thus, ammonia carries great potential with promising applications in energy systems due to its high gravimetric and volumetric hydrogen densities, excellent storability, and carbon-free (Aziz, TriWijayanta, and Nandiyanto 2020).

Aside from being a potential fuel in the combustion system, ammonia has been used as one of the most important chemical commodities with a mature storage and global distribution network, with increasing importance to critical sectors of global society such as fertiliser production (Wan et al. 2021; Elishav et al. 2020; The Royal Society 2020). In terms of production, ammonia can also be produced exclusively from renewable energy sources, commonly known as green ammonia, triggering exploration as a route to the transition of ammonia as the next sustainable fuel solution for power generation (Flórez-Orrego, Maréchal, and de Oliveira Junior 2019).

Combustion of ammonia is basically the oxidation reaction of ammonia, resulting in nitrogen (N₂) and water (H₂O), as shown in reaction (1). Practically, oxygen content in the air is generally used for oxidiser, resulting in the reaction shown in reaction (2). (1) ${\mathrm{N}\mathrm{H}}_3+0.75{\mathrm{O}}_2\to 1.5{\mathrm{H}}_2\mathrm{O}+{\mathrm{N}}_2$(1) (2) ${\mathrm{N}\mathrm{H}}_3+0.75({\mathrm{O}}_2+3.76{\mathrm{N}}_2)\to 1.5{\mathrm{H}}_2\mathrm{O}+3.32{\mathrm{N}}_2$(2)

However, ammonia combustion has been known to have a higher possibility of NO_x emissions increase. The alternative reaction that can occur during the combustion reaction of ammonia shows that NO species can be produced from ammonia combustion. The following reaction is a simple explanation of how NO can be formed during ammonia combustion, while a details explanation is currently being studied in order to reduce the formation of NO_x during ammonia combustion. (3) ${\mathrm{N}\mathrm{H}}_3+1.25({\mathrm{O}}_2+3.76{\mathrm{N}}_2)\to \mathrm{N}\mathrm{O}+1.5{\mathrm{H}}_2\mathrm{O}+4.7{\mathrm{N}}_2$(3)

In terms of the decarbonisation target, ammonia can help to reduce greenhouse gas emissions from coal-fired power plants through co-firing. While coal is a significant source of carbon dioxide (CO₂) emissions, ammonia does not produce CO₂ when burned. Using ammonia as a fuel source, power plants can reduce their carbon footprint and help achieve decarbonisation goals. Co-firing ammonia with coal in power plants also can help to diversify the fuel source. Ammonia is a fuel that can be produced from various feedstocks, including natural gas, renewable energy sources, and coal. Power plants can reduce their dependence on coal by incorporating ammonia into the fuel mix.

A number of studies of process simulation of ammonia-coal co-firing have been reported Kim, Kwak, and Yang (2021) conducted a process simulation of ammonia-coal co-firing at an 870 MW_e supercritical high-rank coal-fired power plant with constant excess oxygen and found that moisture loss reduces boiler efficiency. 600 MW_e of high-rank coal-power plant has been simulated by Xu et al. (2022). Xu et al. has result of decrease in the flue gas temperature under the excess air constant scenario. The flow rate of air must be reduced to maintained the excess air. Zhang et al. (2020).

Several experiments of ammonia-coal co-firing have been performed and reported. Ammonia and coal combustion in the horizonal test furnace with capacity of 1 MW_th has been done and resulted that the injection positions were found to effect NOx emissions (Yamamoto et al. 2018). Because the minimum NO_x emissions are comparable to coal combustion without ammonia injection, it was assumed that ammonia served as a CO₂-reducing agent as well as a fuel for effective heat release. IHI company has successfully conducted the experiment of ammonia co-combustion in pulverised coal boiler (Nagatani et al. 2020). Experimental results were obtained using a 10 MW_th vertical facility and the experiment was carried out until the ammonia co-firing rate was 20 cal.%. It has been suggested that ammonia co-firing could reduce NO_x emissions compared to coal firing by controlling operating conditions such as ammonia injection velocity or air ratio (Nagatani et al. 2020). Tamura et al. (Tamura et al. 2020) studied ammonia utilisation in a 1.2 MW_th coal-fired furnace and concluded that ammonia could be burnt in a coal-fired boiler without ammonia slip. Various ammonia injection methods have been considered, and sidewall injection has been found to increase NOx emission due to less residence time for NOx reduction. At the large-scale system, Chugoku Electric Power has successfully demonstrated ammonia co-firing in Japan’s Mizushima power plant unit 2 with 156 MW output with a co-firing rate of 0.6% until 0.8% (Yoshizaki 2019). The experiment reduced CO₂ emissions, and the metal temperature of heat exchangers, such as those in the superheater and reheater, remained relatively constant when compared to coal firing. The ammonia was completely burned and complied with the environmental standard (Yoshizaki 2019).

In this work, thermodynamic analysis is performed on ammonia-coal cofiring in coal-fired power plant to provide overall energy balance and initial estimation on ammonia fuel utilisation in coal-fired power plant decarbonisation. The boiler system of a commercial 220 MW_e coal-fired power plant unit was selected as a research project to fill the above research objective. The simulation is carried out with Aspen PLUS V12.1 to understand and draw conclusions about the macro side of ammonia co-firing. The ammonia co-firing rate is varied in two cases, constant excess oxygen and constant airflow rate, in order to find the appropriate coal-fired power plant modification. The acid dew point temperature of the flue gas also estimated to confirm and evalutating Xu et al. (2022).

The first part of this study focuses on the flue gas characteristics of ammonia co-firing in a low-rank coal-fired power plant until 100% of ammonia. The 220 MW of coal-fired power plant with lignite A coal is used as the object of the study. The conditions are similar to study by Xu et al. (2022), which focused on pressured ammonia combustion eventhogh the coal and capacity used is different. Xu et al. (2022) used 600 MW of coal-fired power plant with Subbituminous B coal as fuel. Radiation heat transfer at the boiler is simulated based on the Gurvich method. Boiler efficiency based on ASME PTC 2008 method (ASME 2008) is also be evaluated in order to develop an appropriate scenario of the ammonia co-firing in low-rank coal-fired power plant. Furthermore, the flue gas characteristics and boiler efficiency are compared to the previous study.

2. Method

2.1. General system

Figure 2 shows the basic schematic diagram of the ammonia co-firing system. Three main processes are involved: furnace, steam generator, and gas air heater. Coal and ammonia were combusted in furnace and mixed with hot air. The flue gas from the combustion was utilised as feed of the steam generator. In addition, the flue gas was fed into a gas air heater to raise the temperature of the surrounding air. The ammonia has higher HHV than low-rank coal; therefore, the flue gas was heated the liquid ammonia from atmospheric tank in vapouriser as heat recovery. The ammonia that is injected into the boiler must be a gas phase, so there will be no phase change. In the atmospheric tank, the ammonia is still in the liquid phase. Therefore, a vapouriser is needed. The ammonia is also pressured at 0.2 MPa based on Xu et al. (Xu et al. 2022). The tangential burner boiler with a dimension of 12,400 mm × 12,080 mm with a furnace height of 50,000 mm is used. The combustion mode is a premix, where the coal and ammonia is mixed in one injection.

Figure 2. Schematic diagram of the ammonia co-firing system.

2.2. Detailed system

This section explains a detailed system based on the process flow diagram shown in Figure 3. The system was evaluated through a theoretical calculation and software modelling using Aspen PLUS ver. 12.1 (Aspen Technology, Inc.). To establish the model of the system, the following assumption were employed during the calculation, (1) the combustion process was divided into three sequential steps: pyrolysis of coal, burning, and ash removal; (2) all the blocks were in steady state operation; (3) air, ammonia, and coal were homogeneously mixed in the reactor; (4) elements of O, H, N, and S were vapourised into gas phase, and element of C was converted to pure carbon in the process of coal pyrolysis, while ash did not take part in the chemical reaction during combustion process; (5) carbon was reacted completely; (6) Radiation heat from furnace was used for wall tube completely and secondary superheater partially, (7) no pressure loss and heat loss.

Figure 3. Detailed boiler system of ammonia coal co-firing.

Firstly, the coal was decomposed in the DECOMP block (Ryield) by specifying the yield distribution according to the dry basis of coal ultimate analysis, proximate analysis, and dry basis of the heat of coal combustion. Using Fotran block, the decomposition products of coal, i.e. H₂O, N₂, O₂, S, H₂, Cl₂, C, and Ash were calculated. Simultaneously, the heat of coal breakdown was transferred to the BURN block.

The BURN block (RGibbs) was used to simulate the combustion process of ammonia and coal. RGibbs calculates chemical and phase equilibrium by minimising the system’s Gibbs free energy. The main products of coal-ammonia combustion were H₂O, N₂, O₂, S, H₂, C (solid), CO, CO₂, Cl₂, HCl, NO, NO₂, SO₂, SO₃, and NH₃. Radiation heat from the wall tube and secondary superheater were carried to the BURN block.

In Aspen Plus, the RGibbs reactor uses a Gibbs energy minimisation method to model chemical reactions. To calculate NOx formation from combustion reaction, the RGibbs reactor takes into account the reaction mechanism, thermodynamic properties, and transport properties of the species involved in the combustion process. In general, the formation of NOx (NO and NO2) from combustion reactions is strongly influenced by the temperature and oxygen concentration. Overall, RGibbs reactor in Aspen Plus uses a combination of thermodynamic, kinetic, and transport models to predict the formation of NOx from combustion reactions. Similar method of utilising RGibbs reactor to predict NOx has been done by some researchers in many process simulations of fuel combustion, such as oxy-fuel combustion of coal firing (Pei et al. 2013; Odeh, Okpaire, and Oyedoh 2021), syngas combustion (Ziółkowski et al. 2021), ammonia combustion (Juangsa and Aziz 2019), ammonia-coal combustion (Xu et al. 2022).

The total radiation was divided into wall tube and secondary superheater (Wang et al. 2011). The Gurvich method was used to calculate the total radiation at co-firing as shown as at Equation (4)(4) $Q_{rad}=\sigma {\overline{\alpha }}_{fu}\psi A{T}_g^4$(4) , where ${\overline{\alpha }}_{fu}$ is average emissivity furnace wall-flame system, $\psi$ is thermal efficiency constant, $A$ is furnace area, $T_g$ is average gas temperature, and $\sigma$ is Stefan–Boltzmann constant (Y. Zhang, Li, and Zhou 2016). (4) $Q_{rad}=\sigma {\overline{\alpha }}_{fu}\psi A{T}_g^4$(4) $T_g$ was calculated by Equation (5)(5) $T_g=\text{β}{T}_{adb}+\left(1-\text{β}\right)T_{FEGT}$(5) , where$\text{β}$ is the coefficient of average radiation temperature caused by the effect of soot blowing and heat loss to the atmosphere and $T_{FEGT}$ is the furnace exit gas temperature. $\text{β}$ and $T_{FEGT}$ were iterated until it satisfied the heat mass balance (Bhambare, Mitra, and Gaitonde 2007; Olaleye 2015). (5) $T_g=\text{β}{T}_{adb}+\left(1-\text{β}\right)T_{FEGT}$(5) Then, the ash and gas were separated in the SEPARATE Block (SSplit). The flue gas heated the feed water, and the flue gas then flowed to the Gas-Air Heater to heat the ambient air. After the ambient air was heated, the flue gas was used as heat recovery for heating the liquid ammonia.

Furthermore, the steam generator system is shown in Figure 4. Deaerator is modelled as MX3 and SEP. W-OUT from SSH was fed into two stages HP turbine, then to RH. Four stages IP turbine and three stages LP turbine were used at this power plant. Meanwhile, Four LPH and four HPH were used to recover the heat.

Figure 4. Detailed steam generator system of ammonia coal co-firing.

3. Results and discussion

3.1. Simulation model

The proximate and ultimate analysis of the coal used is shown in Table 1. Meanwhile, the stream data are shown in Table 2. Aspen used the dry-based HHV. Equation (6) is used to change HHV as received to HHV dry based (Aspen Technology 2013). (6) $HH{V}_d={\displaystyle \frac{HH{V}_{ar}}{1-M_{ar}}}$(6)

Table 1. The proximate and ultimate analyses of the pulverised coal.

Proximate analysis (%)				Ultimate analysis (%)						Total sulphur (%)			LHVar/HHVar (MJ/kg)
Mar	ASHar	VMar	FCar	Cd	Hd	Nd	Cld	Sd	Od	Sp	Ss	So
30	5	35	30	63.66	4.79	1.09	0.01	0.31	22.99	0.143	0.020	0.143	16.12/17.58

Table 2. The stream data.

Parameter	Coal	Ammonia	Air	Feed-WA	Feed-WRH
Temperature (°C)	33	33	33	251.38	318.67
Pressure (MPa)	0.101325	0.2	0.101325	12.75	2.68
Mass rate (kg/s)	32.92		223.04	184.17	160.44
Component (%)	Coal	NH3	21% O2 + 79% N2	H2O	H2O

Table 3 shows the simulation result at 100% coal combustion. The total radiation is about 240 MW due to the temperature of AIRHOT (362°C) and temperature of PRODUCT as T_FGET is set about 1200°C (Wang et al. 2011; LAPI ITB 2015). The simulation results of the specified coal-fired power plant were compared with the design specifications to verify the validity of the simulation approach. In Table 4, numerous important boiler and steam generator data are presented, including the temperature of the input and outlet flue gas in the GAH, the gross power output, and the net plant heat rate.

Table 3. Simulation results at 100% coal.

Parameter	AIRHOT	G-1	G-7	W-OUT	WRH-OUT
T (°C)	362.00	1199.80	137.81	535.00	535.00
p (MPa)	0.101325	0.1	0.1	12.75	2.63
	Mass flow (kg/s)	Mass flow (kg/s)	Mass flow (kg/s)	Mass flow (kg/s)	Mass flow (kg/s)
H2O	0.00	19.96	19.96	184.17	160.44
N2	171.09	171.30	171.30	0.00	0.00
O2	51.95	8.29	8.29	0.00	0.00
NO2	0.00	0.00	0.00	0.00	0.00
No.	0.00	0.11	0.11	0.00	0.00
S	0.00	0.00	0.00	0.00	0.00
SO2	0.00	0.14	0.14	0.00	0.00
CO2	0.00	55.00	55.00	0.00	0.00
Total mass flow (kg/s)	223.04	254.81	254.81	184.17	160.44
Volume flow (cum/s)	402.96	1056.00	294.46	4.87	22.30

Table 4. Comparison of the design specifications and the simulation results.

Mainstream parameter	Unit	Design specifications (LAPI ITB 2015)	Simulation results	Relative deviations
Temperature of GAH inlet flue gas	°C	139.00	137.81	0.86%
Temperature of GAH Outlet flue gas	°C	387.10	401.60	3.75%
Gross Power Output	kW	218000	220785	1.26%
Net Plant Heat Rate	kcal/kWh	2328.44	2282.49	1.97%

The maximum relative deviation was 3.75% which occurred on the temperature of GAH outlet flue gas. These deviations occurred due to no heat loss and pressure loss assumption at the boiler. Significant property parameter variations of flue gas were all within the allowable range, showing that the modelling technique and simulation procedure properly reflected the actual boiler system operation (Zhou et al. 2018; Si et al. 2017).

3.2. Effect evaluation on flue gas properties

The airflow rate and air-to-fuel ratio are shown in Table 5. It is found that the airflow rate needed is increased when the ammonia composition in fuel is increased. This phenomenon occurred because the theoretical air needed for the ammonia combustion is higher than the coal. Ammonia combustion has a theoretical air-to-fuel ratio of 6.06, while coal combustion has a theoretical air-to-fuel ratio of 5.65. The AFR of coal used Equation in ASME PTC 4.1 as shown in Equation (7)(7) $AF{R}_{stoic}=\left[\left(11.6C\right)+\left\{34.8\left(H-{\displaystyle \frac{O}{8}}\right)\right\}+\left(4.35S\right)\right]/100$(7) (ASME 1998). Meanwhile, the AFR of the ammonia used stoichiometric calculation from Equation (2)(2) ${\mathrm{N}\mathrm{H}}_3+0.75({\mathrm{O}}_2+3.76{\mathrm{N}}_2)\to 1.5{\mathrm{H}}_2\mathrm{O}+3.32{\mathrm{N}}_2$(2) . This finding differs from the previous ones (Xu et al. 2022; Kim, Kwak, and Yang 2021) because the coal used is different. This study used low-rank coal, whereas previous studies used high-rank coal. It has also been found that at 100% ammonia, the airflow rate required is only 9% higher than for coal-firing. (7) $AF{R}_{stoic}=\left[\left(11.6C\right)+\left\{34.8\left(H-{\displaystyle \frac{O}{8}}\right)\right\}+\left(4.35S\right)\right]/100$(7)

Table 5. Airflow rate and air to fuel ratio at constant excess oxygen scenario.

Co-firing ratio (%mass ammonia)	Air need (tonne/hour)	Air to fuel ratio
0%	802.95	6.78
10%	810.50	6.84
20%	818.10	6.90
30%	825.60	6.97
40%	833.10	7.03
50%	840.60	7.09
60%	848.00	7.16
70%	855.60	7.22
80%	863.10	7.28
90%	870.60	7.35
100%	878.10	7.41

As the rate of ammonia co-firing increases, the adiabatic flame temperature decreases in a constant excess oxygen scenario because ammonia has a lower adiabatic flame temperature than coal. Meanwhile, due to a lack of air, it rises in the airflow rate constant scenario. Following iteration, it was discovered that the temperature of the furnace exit gas increased, as shown in Figure 5 in both scenarios. In the constant excess oxygen scenario, the overall air flow rate is increased with a higher ammonia cofiring ratio. Since the overall radiation is a function of adiabatic flame temperature, an increasing fraction of ammonia results in overall radiation in the constant excess oxygen scenario. In addition, with a higher mass flow rate of flue gas, the flue gas temperature decrease is lower, leading to a higher temperature furnace. Therefore, the furnace exit gas temperature increases even though the adiabatic temperature decreases. Meanwhile, in the constant airflow rate scenario, the increasing adiabatic flame temperature results in a higher furnace exit temperature with a constant mass flow rate of flue gas.

Figure 5. Adiabatic and furnace exit gas temperature with different ammonia co-firing rates. (a) Constant Excess Oxygen; (b) Constant Airflow Rate.

Ammonia co-firing affected significantly the compositions, thermal properties, and flow rates of the flue gas because of the changes in changes in the composition of the fuel stream. The total emission rates of flue gas are shown in Tables 6 and 7 and the NOx and SOx emissions in ppm are shown in Figure 6. Meanwhile, Figure 7 presents the mole fractions of nitrogen, oxygen, carbon dioxide, and water vapour in the flue gas.

Figure 6. NO_x and SO_x emission in ppm. (a) Constant Excess Oxygen Scenario; (b) Constant Airflow Rate Scenario.

Figure 7. Mole fractions of nitrogen, oxygen, carbon dioxide, and water vapour in the flue gas. (a) Constant Excess Oxygen Scenario; (b) Constant Airflow Rate Scenario.

Table 6. The mass flow rate of the entire flue gas and the principal components of the flue gas at the furnace exit under the constant excess oxygen scenario (in tonne/hour).

Item	Co-firing ratio (%mass ammonia)
	0%	10%	20%	30%	40%	50%	60%	70%	80%	90%	100%
H2O	71.87	83.49	95.10	106.72	118.33	129.95	141.56	153.18	164.79	176.41	188.02
N2	616.68	632.11	647.59	662.98	678.38	693.77	709.09	724.57	739.96	755.36	770.75
O2	29.86	30.60	31.36	32.09	32.82	33.56	34.27	35.02	35.75	36.48	37.21
NO2	1.24e-3	1.28e-3	1.3e-3	1.37e-3	1.41e-3	1.46e-3	1.50e-3	1.55e-3	1.59e-3	1.64e-3	1.68e-3
NO	0.39	0.41	0.43	0.45	0.47	0.49	0.51	0.54	0.56	0.58	0.61
SO2	0.51	0.46	0.41	0.36	0.31	0.26	0.20	0.15	0.10	0.05	0.00
SO3	4.68e-3	4.09e-3	3.54e-3	3.02e-e	2.53e-3	2.06e-3	1.61e-3	1.18e-3	7.69e-4	3.76e-4	0.00
CO	2.34e-3	2.29e-3	2.20e-3	2.08e-3	1.92e-3	1.72e-3	1.47e-3	1.18e-3	8.39e-4	4.46e-4	0.00
CO2	197.98	178.18	158.39	138.59	118.79	98.99	79.19	59.39	39.60	19.80	0.00
NH3	0.00	3.98e-11	5.24e-11	6.72e-11	8.43e-11	1.04e-10	1.27e-10	1.52e-10	1.81e-10	2.13e-10	2.49e-10
Total Flue Gas Rate	917.30	925.27	933.28	941.20	949.11	957.03	964.84	972.86	980.77	988.69	996.60

Table 7. The mass flow rate of the entire flue gas and the principal components of the flue gas at the furnace exit under the constant airflow rate scenario (in tonne/hour).

Item	Co-firing ratio (%mass ammonia)
	0%	10%	20%	30%	40%	50%	60%	70%	80%	90%	100%
H2O	71.87	83.49	95.10	106.72	118.33	129.95	141.56	153.18	164.79	176.41	188.02
N2	616.68	626.33	635.98	645.63	655.28	664.93	674.58	684.23	693.89	703.54	713.19
O2	29.86	28.85	27.85	26.84	25.84	24.83	23.83	22.82	21.82	20.81	19.81
NO2	1.24e-3	1.21e-3	1.18e-3	1.14e-3	1.11e-3	1.07e-3	1.04e-3	1.00e-3	9.65e-4	9.27e-4	8.89e-4
NO	0.39	0.39	0.40	0.40	0.41	0.41	0.42	0.42	0.42	0.42	0.42
SO2	0.51	0.46	0.41	0.36	0.31	0.26	0.20	0.15	0.10	0.05	0.00
SO3	4.68e-3	4.00e-3	3.38e-3	2.81e-3	2.29e-3	1.82e-3	1.38e-3	9.84e-4	6.23e-4	2.96e-4	0.00
CO	2.34e-3	2.33e-3	2.29e-3	2.21e-3	2.09e-3	1.92e-3	1.69e-3	1.39e-3	1.02e-3	5.59e-4	0.00
CO2	197.98	178.18	158.39	138.59	118.79	98.99	79.19	59.39	39.60	19.80	0.00
NH3	0.00	4.12e-11	5.62e-11	7.49e-11	9.80e-11	1.26e-10	1.60e-10	2.02e-10	2.51e-10	3.10e-10	3.80e-10
Total Flue Gas Rate	917.30	917.72	918.13	918.54	918.96	919.37	919.79	920.20	920.62	921.03	921.45

The CO2 mass flow rate and mole fraction decreased in both ammonia co-firing scenarios, with the decrease rate likely being the same in both. However, the constant airflow rate scenario has a more decreased rate of CO₂ than the constant excess oxygen scenario. It is caused by less oxygen at the constant airflow rate scenario. NOx emission is significantly affected by fuel-nitrogen (fuel-N) and temperature of combustion. Since ammonia carries a significant amount of nitrogen, an increase in NOx emissions is a natural cause for concern. The NO_x emission increased in constant excess oxygen and decreased in the constant airflow rate scenario. Compared with the experimental by Tamura et al. (2020), the NOx emission increase in constant excess O₂. Consequently, the ASPEN Plus simulation can be considered accurate. The constant airflow rate scenario has less NO_x emission than the constant excess oxygen scenario due to the lower excess oxygen. Lowering the excess oxygen is one of the strategies to reduce the NO_x emissions (Doyle 2009; EPA 1999). The lower excess oxygen also resulted in less fuel NOx from the coal, as shown in research by Lee, Eddings, and Jeon (2012). Therefore, the NO_x is decreased in the constant airflow rate scenario. The SO_x emission decreases in both scenarios due to the S carrier (i.e. coal) is decreased.

When using ammonia as a fuel at a 100% co-firing ratio, the amount of H₂O in the flue gas increases dramatically. In the base case, the H₂O content is 12.7%, but it rises to 26.7% in the constant excess oxygen scenario and 28.6% in the constant airflow rate scenario, representing increases of 110.2% and 125.2%, respectively. This increase is due to the higher hydrogen content in NH₃ compared to coal, which leads to more H₂O formation after fuel oxidation. In the constant airflow rate scenario, the excess oxygen level drops to 1.69% from 2.97%. This indicates that ammonia combustion in the boiler can be achieved without modifying the fan. When ammonia is fired with coal in a constant airflow rate, the amount of nitrogen (N₂) in the flue gas decreases even though ammonia has high nitrogen content. This is because the chemical reaction of ammonia with oxygen produces a mixture of nitrogen and water vapour with a nitrogen to water ratio of 1–3. However, the N₂ content increases in the constant excess oxygen scenario. This is due to the higher amount of N₂ in the air.

The higher the percentage of ammonia co-firing, the higher the temperature rise occurs at each different position of the boiler (Figure 8). The increase of each position has a rising trend from G1 to G6. However, the trend is lower because the ammonia vapourised by flue gas increases when the co-firing rate increases at G7. The increase in temperature is caused by the increase of specific heat capacity at constant pressure at each boiler position (Figure 9) and an increase in flue gas flow rate (Tables 6 and 7)

Figure 8. The temperature of the flue gas stream at different positions in the boiler system. (a) Constant Excess Oxygen Scenario; (b) Constant Airflow Rate Scenario.

Figure 9. The heat capacity of flue gas stream at different positions in the boiler system. (a) Constant Excess Oxygen Scenario; (b) Constant Airflow Rate Scenario.

It is found that Specific heat capacity at constant pressure (Cp) in the constant airflow rate scenario is higher than Cp in the constant excess oxygen scenario, as shown in Figure 9. An increase of Cp is caused by the increase of ammonia and water concentration at flue gas that has higher Cp than other gases content. Therefore, even though the mass rate of flue gas is lower in the constant airflow rate scenario than in the constant excess oxygen scenario, the increase in temperature of flue gas is greater in the constant airflow rate scenario.

Furthermore, the acid dew point of the flue gas is analyzed. The increase of H₂O in flue gas might improve the acid dew point of the flue gas. However, the SO_x content decreases (Tables 6 and 7), and the stack temperature increases, as shown in Figure 8 (G6 for 0% ammonia and G7 for ammonia co-firing). The decrease in SOx content might lead to a decrease in the acid dew point of the flue gas. As shown in Equation (7)(7) $AF{R}_{stoic}=\left[\left(11.6C\right)+\left\{34.8\left(H-{\displaystyle \frac{O}{8}}\right)\right\}+\left(4.35S\right)\right]/100$(7) , the Verhoff and Branchero equation is used to predict the acid dew point of H₂SO₄. The acid dew point of H₂SO₄ is used because it has at least 20°C higher dew point temperature than HNO₃ and H₂SO₃ (Zarenezhad and Aminian 2011)_, and Verhoff and Branchero equation is used due to its consistency (Wei et al. 2017). (8) $T_{ADP}={\displaystyle \frac{1000}{2.9882-0.13761\log P_{H2O}-02674\log P_{SO3}+0.03287\log P_{H2O}\log P_{SO3}}+273.15\left(8\right)}$(8)

Figure 10(a) is shown the acid dew point temperature of the flue gas in both scenarios. The impact of sulphuric acid vapour is more considerable than water vapour. With an increase in ammonia co-firing for low-rank coal boilers, it is possible that the acid dew point problem may not occur. This result is different from Xu et al. (Xu et al. 2022) due to the difference in the coal rank used. Xu et al. used high-rank coal, which led to decreased stack temperature due to its high HHV. This result also concludes that ammonia co-firing is more appropriate for utilisation at low-rank coal-fired power plants.

Figure 10. (a) Acid dew point temperature (b) Overall boiler efficiency; (c) Stack losses due to dry flue gas; (d) Stack losses due to water from fuel.

3.3. Effect evaluation of ammonia co-firing on boiler efficiency

This section discusses the effect of ammonia co-firing on boiler efficiency. The boiler efficiency is calculated based on HHV of coal and ammonia, resulting in decreases when the ammonia co-firing rate is higher. The constant airflow rate scenario has slightly better performance than the constant excess oxygen scenario, as shown in Figure 10(b). The boiler efficiency of both cases is relatively similar as the result of the increased gas flow rate in the constant excess oxygen scenario, while the stack temperature increase in the constant air flowrate scenario. Therefore, it is found that both scenarios can be used in coal power plants. If the fan used in the power plant is a variable speed fan, the constant excess oxygen scenario is better than the constant airflow rate scenario. The constant airflow rate scenario has a challenge of complete combustion due to lower excess oxygen. Based on the calculation, the losses in the boiler are mainly due to stack losses and water from fuel losses.

The thermal stack losses, which represents the losses due to dry flue gas, have a parabolic trend, as shown in Figure 10(c). It is caused by a increase of H₂O content in the flue gas as the ammonia fraction increases, leading to decrease of dry flue gas flow rate. Meanwhile, the stack temperature is higher at higher fraction of ammonia, especially for constant excess O₂ scenario. As the result, the parabolic trend of thermal stack losses is formed by the balance between increasing stack temperature and decreasing flue gas flow rate. The maximum loss of excess oxygen occurs on a 90% ammonia co-firing ratio. Meanwhile, the maximum loss occurs on a 70% ammonia co-firing ratio at the constant airflow rate scenario. This is caused by the H₂O emission of the constant airflow rate being higher than the constant excess oxygen. This result differs from Kim et al (Kim, Kwak, and Yang 2021). Kim et al. have a result of a decrease of stack loss at 0% until 30% ammonia co-firing ratio. Kim et al. used coal with a higher HHV, that is also higher than the HHV of ammonia, resulted in a decreasing trend of stack temperature as ammonia fraction increases. Meanwhile, the stack temperature rises in this study is caused by a lower HHV of coal that is lower than that of ammonia.

Meanwhile, the losses due to water from the fuel are shown in Figure 10(d). This result is similar to Kim et al. The loss due to water from the fuel increases as the ammonia co-firing rate increases. This is because the hydrogen content of ammonia is higher, by about 17% (Cheddie 2012), than that of coal, resulting in higher water content in the flue gas when the fuel is oxidised.

4. Conclusion

Simulation and comparative studies of ammonia-coal co-firing and low-rank coal power plant unit were carried out. The systematic results on the emission rate, thermal properties of the flue gas stream, and boiler system efficiency were obtained. When ammonia is co-fired with coal, CO₂ emissions from conventional coal-fired power plants are reduced. The SO_x emission decreased in both scenarios. Meanwhile, the NO_x emission increased in the constant excess oxygen scenario and decreased in the constant airflow rate scenario. The emission content of H₂O increases in both scenarios as NH₃ has a higher content of hydrogen than coal. Constant excess oxygen scenario needs more airflow rate due to higher AFR of ammonia. Therefore, even though the N₂ emission from NH₃ oxidation is only 25%, the N₂ emission increases in a constant excess oxygen scenario. Meanwhile, the N₂ emission is decreased at a constant airflow rate scenario. It is also found that the ammonia co-firing at low-rank coal-fired power plants may not have a problem with acid dew point temperature due to the higher temperature of the stack.

The temperature of flue gas is affected by the proportion of ammonia used in the co-firing process. As the ammonia ratio increases, the temperature of the flue gas at the same point in the system also rises. This is due to changes in the heat capacity and flow rate of the flue gas.

The boiler efficiency of a CFPP remains similar at different ammonia co-firing ratios. Each scenario can be used depend on the power plant capability. The CFPP has variable speed fan is suggested to used the constant excess oxugen scenario to achieve complete combustion of the fuel. If the variable speed fan cannot achieve the constant excess oxygen scenario or the power plant does not have variable speed fan, the air flowrate constant scenario can be used. However, the complete combustion of the fuel must be considered if used the constant airflow rate scenario. In general, it is more practical to operate a coal-fired power plant with the same excess oxygen levels as in its original coal-fired configuration when co-firing with ammonia. In addition, the off design simulation of the power plant must be considered and the computational fluid dynamic of the boiler must be examined to ensure the ammonia co-firing.

Disclosure statement

No potential conflict of interest was reported by the author(s).

Additional information

Funding

This work was supported by Research and Community Service Program ITB (PPMI) [2022].