Experimental Study on Ammonia Co-Firing with Coal for Carbon Reduction in the Boiler of a 300-MW Coal-Fired Power Station

Engineering ›› 2024, Vol. 40 ›› Issue (9) :247 -259. DOI: 10.1016/j.eng.2024.06.003

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2024-02-07	2024-06-04	2024-11-11

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Abstract

To reduce CO₂ emissions from coal-fired power plants, the development of low-carbon or carbon-free fuel combustion technologies has become urgent. As a new zero-carbon fuel, ammonia (NH₃) can be used to address the storage and transportation issues of hydrogen energy. Since it is not feasible to completely replace coal with ammonia in the short term, the development of ammonia-coal co-combustion technology at the current stage is a fast and feasible approach to reduce CO₂ emissions from coal-fired power plants. This study focuses on modifying the boiler and installing two layers of eight pure-ammonia burners in a 300-MW coal-fired power plant to achieve ammonia-coal co-combustion at proportions ranging from 20% to 10% (by heat ratio) at loads of 180- to 300-MW, respectively. The results show that, during ammonia-coal co-combustion in a 300-MW coal-fired power plant, there was a more significant change in NO_x emissions at the furnace outlet compared with that under pure-coal combustion as the boiler oxygen levels varied. Moreover, ammonia burners located in the middle part of the main combustion zone exhibited a better high-temperature reduction performance than those located in the upper part of the main combustion zone. Under all ammonia co-combustion conditions, the NH₃ concentration at the furnace outlet remained below 1 parts per million (ppm). Compared with that under pure-coal conditions, the thermal efficiency of the boiler slightly decreased (by 0.12%-0.38%) under different loads when ammonia co-combustion reached 15 t·h⁻¹. Ammonia co-combustion in coal-fired power plants is a potentially feasible technology route for carbon reduction.

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Coal-fired boiler / Coal mixing with ammonia / Ammonia-coal co-firing / Nitrogen oxide (NO_x) / CO₂ reduction / Boiler thermal efficiency

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Qifu Lin, Wangping Sun, Haiyan Li, Yangjiong Liu, Yuwei Chen, Chengzhou Liu, Yiman Jiang, Yu Cheng, Ning Ma, Huaqing Ya, Longwei Chen, Shidong Fang, Hansheng Feng, Guang-Nan Luo, Jiangang Li, Kaixin Xiang, Jie Cong, Cheng Cheng. Experimental Study on Ammonia Co-Firing with Coal for Carbon Reduction in the Boiler of a 300-MW Coal-Fired Power Station. Engineering, 2024, 40(9): 247-259 DOI:10.1016/j.eng.2024.06.003

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1. Introduction

As a major global energy consumer, China accounted for approximately 30% of global carbon emissions in 2021, with a total of around 10 billion tons [1]. Because of the nation’s abundant coal resources and limited oil and gas reserves, coal-fired power plants have been the predominant source of energy supply in China [2]. Therefore, reducing carbon emissions from coal-fired power plants is essential in order for China to achieve its dual carbon goals. Developing low-carbon or zero-carbon fuels is a solution that can address carbon emissions from coal-fired power plants at the source. As a new type of zero-carbon fuel, ammonia (NH₃) has a similar heat value to coal. Since it is currently not feasible to fully replace coal with ammonia in the short term, co-firing ammonia in coal-fired boilers is considered to be a fast and feasible decarbonization technology route [3], [4], [5], [6], [7]. However, ammonia fuel is rich in nitrogen elements, and its combustion can easily generate fuel-type NO_x, making the generation and emission characteristics of NO_x during coal-ammonia co-firing a focal point of research.

Various researchers have conducted a series of experiments and simulations on the impact of coal-ammonia co-firing on NO_x emissions, with a primary focus on the influence of factors such as the ammonia blending ratio, ammonia injection position and method, air staging, and excess air coefficient on NO_x emissions. Yamamoto et al. [8] found that, when ammonia gas was injected from the side wall of a 760-kilowatt-thermal (kW_th) single-burner horizontal coal powder furnace, the NO_x concentration was lower than that under pure coal conditions. Tamura et al. [9] studied ammonia co-firing in a 1.2-MW_th single-burner horizontal furnace and found that, by optimizing the direction and flow rate of ammonia injection, low NO_x emissions and high coal combustion efficiency were achieved. Research conducted by IHI Corporation in Japan on a 10-MW_th single-burner test furnace [10], [11] showed that, under ammonia-coal co-firing conditions, NO_x emissions exhibited a non-monotonic change, with an initial decrease followed by an increase with increasing burnout air rate; however, the emissions monotonically increased with an increase in the excess air coefficient. Similar findings were obtained by Niu et al. [12], who studied ammonia co-firing in a 40-MW_th single-burner industrial coal powder furnace. Using the Chemkin zero-dimensional model and a detailed chemical reaction mechanism, Ishihara et al. [13], [14] simulated and analyzed the effects of different ammonia injection positions and blending ratios on NO_x emissions from a 1000-MW coal-fired boiler. Their research revealed that, when ammonia gas is injected into the flame zone of the burner, lower NO_x emissions can be achieved compared with pure-coal combustion, while introducing ammonia gas into the burnout zone significantly increases NO_x emissions. NO_x emissions are lower than those of pure coal when the ammonia blending ratio is less than 20%; they increase monotonically when the blending ratio is between 20% and 60%, and decrease when the blending ratio continues to increase to 80%. There have been limited studies on ammonia co-firing in industrial boiler-scale applications. In 2017, the Mizushima Power Plant in Japan achieved ammonia-coal co-combustion in a 156-MW coal-fired unit using the existing bio off-gas (BOG) burner, demonstrating the technical feasibility of ammonia-coal co-firing in power plant boilers [15]. However, this experiment had a low co-firing ratio and a small number of operational burners. Further experimental investigations are still needed to explore the feasibility and compatibility of ammonia-coal co-firing with multiple burners and in complex combustion flow fields.

In summary, the existing experimental studies on the co-combustion of ammonia and coal have mainly focused on low-capacity test furnaces with a single burner, where the test furnaces’ parameters, structural parameters, and system complexity differ significantly from those of power plant boilers. Therefore, this study takes a 300-MW coal-fired power plant boiler as the research object. By adding a high-capacity ammonia supply system and multiple pure-ammonia burners, the co-firing of ammonia and coal at corresponding ratios of 20%-10% (based on heat) is achieved under unit loads of 180- to 300-MW, respectively. Through boiler co-firing experiments, the influence of the boiler’s operating oxygen content, ammonia injection position, unit load, and ammonia blending ratio on its NO_x emission characteristics and NH₃ burnout characteristics is studied. In addition, the impact of ammonia co-combustion on the boiler’s heat transfer and thermal efficiency is investigated. This study provides valuable guidance for the development of ammonia co-combustion technology in power plant boilers and for carbon reduction in coal-fired power plants.

2. Experimental system and conditions

In order to conduct experimental research on ammonia co-combustion in a power plant boiler, modification of Boiler No. 3 at the Wanneng Tongling 300-MW coal-fired power plant was carried out. The maximum stable ammonia supply capacity of Boiler No. 3 was achieved at 20 t·h⁻¹. As shown in Fig. 1, the modified ammonia co-combustion system included an ammonia tank, a liquid ammonia pipeline, a large-scale ammonia gasifier, an ammonia gas buffer tank, a gas ammonia pipeline, a pure ammonia burner, a measurement and diagnostic system, and other auxiliary systems.

2.1. Large-scale ammonia gasification and supply system

There are three large horizontal liquid ammonia storage tanks in the common ammonia storage area at the Wanneng Tongling power plant, with each tank having a capacity of 80 m³. The maximum total storage capacity for liquid ammonia is 84 t (Fig. 2). A liquid ammonia transfer pump was installed in the common ammonia area, and an ammonia evaporator was added to the side of Boiler No. 3, with a rated evaporation capacity of 20 t·h⁻¹. The evaporator is a horizontal shell and tube heat exchanger designed with a two-stage heat exchange system. It utilizes auxiliary low-pressure steam from the power plant (1.2 MPa, 220 °C) and circulating water (0.6 MPa, 30 °C) as heat sources, with a primary focus on using the circulating water for heat exchange. The liquid ammonia/ammonia gas flows through the shell side, while the circulating water and steam flow through the tube side, ensuring that the evaporator can achieve the rated evaporation capacity within an ambient temperature range of 5-35 °C. The liquid ammonia in the three ammonia storage tanks is pumped into the large-scale evaporator, where it is vaporized into ammonia gas at a pressure of 0.5 MPa and a temperature of 25 °C. The gas then enters the pre-buffer tank of Boiler No. 3 and is subsequently injected into the boiler for co-combustion with coal powder. The flow path of the co-firing ammonia gas is as follows: liquid ammonia storage tank→ammonia transfer pump in the ammonia area→liquid ammonia evaporator→ammonia buffer tank→pre-supply ammonia main pipe→ammonia burners.

2.2. Boiler and ammonia co-firing system

Boiler No. 3 at the Wanneng Tongling power plant is an HG-1025/18.2-YM6 subcritical, once-intermediate reheating, intermediate storage-type, controlled circulation drum boiler designed and manufactured by Harbin Boiler Factory. It is a single-furnace π-type boiler with rounded-corners combustion and swing burners. There are 16 primary air nozzles (burners) in total, arranged in four corners × four layers, and eight main oil guns (1.2 t·h⁻¹ each) in total arranged in four corners × two layers, with four micro oil guns (100 kg·h⁻¹ each) installed inside the B layer burner. There are 20 secondary air nozzles arranged in four corners × five layers, eight tertiary air nozzles arranged in four corners × two layers, and 12 high-level burnout air nozzles arranged in four corners × three layers. The main design parameters of the boiler are provided in Table 1.

^aQ_net,ar = 18 920 kJ·kg⁻¹, low heating value (LHV); where Q_net,ar is calorific value of the designed coal type and ar is as received basis.

For this research, a new pure ammonia burner was developed (Fig. 3) to achieve the co-combustion of coal powder and ammonia gas in the furnace of the boiler. The pure ammonia burner is a direct-flow type, with ammonia gas injected from the central pipe and radially arranged branch pipes. The auxiliary combustion air is provided by the primary air (300 °C). Based on the existing layout of the burners in Boiler No. 3, four pure ammonia burners were installed between the C- and D-layer coal powder burners, and another four burners were installed between the F-layer secondary air and the upper tertiary air. The two layers of pure ammonia burners are located at elevations of 22.662 and 25.815 m, respectively. As shown in Fig. 4, the lower layer of pure-ammonia burners is located in the middle part of the main combustion zone, while the upper layer is located in the upper part of the main combustion zone. Each of the four lower pure-ammonia burners has a rated design output of 1.6 t·h⁻¹, while each of the four upper pure-ammonia burners has a rated design output of 3.0 t·h⁻¹. When all the pure-ammonia burners are operating simultaneously, the maximum ammonia flow capacity exceeds 18 t·h⁻¹. Both layers of ammonia burners use hot air for combustion assistance, with an excess air coefficient of 0.2-1.2. Due to factors such as the arrangement of the secondary air ports and tertiary air ports in the burner area, imperfect sealing and air leakage after the low-nitrogen modification of the upper secondary air ports in the furnace, and the “bottom-up” fuel delivery principle and equal air distribution in the boiler, there are significant differences in the air-to-fuel ratio and ammonia-to-air ratio in the two layers of ammonia burner areas during actual operation.

2.3. Experimental conditions and measurement diagnosis system

The coal used in this experiment was bituminous coal, and the ammonia used was industrial-grade ammonia. The fuel parameters are shown in Table 2, and the conditions of the ammonia co-firing combustion test are shown in Table 3. The unit’s power generation load was set at 180-, 240-, and 300-MW, respectively. Under different loads, the boiler oxygen concentration was controlled within the ranges of 2.8%-7.3%, 2.7%-4.3%, and 1.8%-3.3%, respectively. The maximum amount of ammonia co-firing was 18 t·h⁻¹. Prior to ammonia injection, the operation modes of the coal powder burners were the B/C layer + A1/A3, A/B/C layer + D1/D3, and A/B/C/D layer. With an increase in the addition of ammonia, to ensure that the total heat input of the boiler remained unchanged under the 180-MW load the A3 coal powder burner was withdrawn when the ammonia addition was between 6.4 and 10.0 t·h⁻¹, and the A1/A3 coal powder burner was withdrawn when the ammonia addition was between 15 and 18 t·h⁻¹. Under the 240-MW load the D3 coal powder burner was withdrawn when the ammonia addition was between 6.4 and 10.0 t·h⁻¹, and the D1/D3 coal powder burner was withdrawn when the ammonia addition was between 10 and 15 t·h⁻¹. Under the 300-MW load the coal powder burner remained in operation, and the coal feeding rate was reduced by lowering the speed of the feeder corresponding to the fourth layer of the coal powder burner.

Fig. 1 shows the positions of various measurement points during the experiment. The measurement points for flue gas composition included a flue gas measurement point at the furnace outlet and another at the air preheater outlet, which respectively measured NO/CO₂/NH₃/H₂O/O₂ and O₂/CO. The temperature measurement points included measurement points on the metal wall of the upper heating surface of the furnace (separating the screen superheater and final stage reheater, as shown in Fig. 5), a measurement point for the flue gas temperature at the furnace outlet, and a measurement point for the flue gas temperature at the air preheater outlet. The measurement parameters and instruments are listed in Table 4. During the measurement process, the ammonia analyzer activated the heating function to ensure that the temperature of the gas being measured was equal to or higher than 220 °C, thus preventing water vapor from condensing in the pipeline.

3. Results and discussion

3.1. Effects of ammonia co-firing on NO_x emission

3.1.1. Effects of boiler excess oxygen

The operating oxygen concentration of the boiler is an important parameter that affects the combustion efficiency of the coal powder and ammonia fuel. Fig. 6 shows the variation in the NO_x emissions at the furnace outlet with respect to the boiler’s operating oxygen concentration under pure-coal conditions and coal-ammonia co-firing conditions. The data in Fig. 6 was measured through the distributed control system (DCS) while the boiler was operating continuously. The time interval between each data point is 10 s. In Fig. 6(a), the operating condition lasted for 38 min, with a total of 226 data points collected. In Fig. 6(b), the operating condition lasted for 17 min, with a total of 104 data points collected. From Fig. 6, it can be observed that the NO_x emissions value at the furnace outlet increases with an increase in the boiler’s operating oxygen concentration, and this increase is faster when ammonia is mixed with the coal. More specifically, under a load of 300-MW, when the operating oxygen concentration increases from 1.8% to 3.2%, the average concentration of NO_x increases by only around 60 mg·Nm⁻³ (N represents normal condition) during pure-coal combustion. However, with an ammonia mixing rate of 6.4 t·h⁻¹, the increase in the average concentration of NO_x is more than 150 mg·Nm⁻³. According to the fitted results in the figure, the amplitude of the NO_x change under the ammonia-mixed condition is more than twice that under the pure-coal condition. In addition, the minimum value is lower than that during pure-coal combustion.

According to research by Hayakawa et al. [16], the concentration of NO_x in the combustion products varies greatly when the chemical equivalence ratio φ of NH₃ combustion is between 0.9 and 1.1. This is because NH₃ contains a large amount of nitrogen and, when φ = 0.9-1.0, a large amount of NO_x is easily generated in the high-temperature flame. Once φ exceeds 1.0, the excess ammonia in rich combustion has a strong reducing effect on NO_x, leading to a significant decrease in NO_x concentration.

In this experiment, when the unit load was 300-MW and the ammonia injection rate was 6.4 t·h⁻¹, the overall equivalence ratio φ of the ammonia-coal mixture in the main combustion zone was calculated based on the oxygen content and burnout air ratio, ranging from 1.06 to 1.14. Although this value is greater than 1, the combustion speed of gaseous ammonia (as a fuel) is much higher than that of the main component (i.e., coke) in the combustible coal particles, which results in fluctuations of the local equivalence ratio φ around 1. It is only when the oxygen content is sufficiently low (around 2.4% in this experiment) that a reducing atmosphere will be formed near the ammonia burner, leading to a significant reduction in NO_x concentration. Therefore, compared with coal combustion, the flue gas NO_x emissions from ammonia combustion are more sensitive to the oxygen content. As a result, controlling the oxygen content is particularly crucial in boiler co-firing with ammonia.

3.1.2. Effects of ammonia injection positions

In this experiment, two layers of pure ammonia burners were installed at different heights in the boiler furnace to verify the effects of ammonia injection in the middle part of main combustion zone and in the upper part of the main combustion zone on NO_x generation. Fig. 7 shows the respective effects of ammonia injection in the middle part of the main combustion zone and in the upper part of the main combustion zone on the exhaust gas NO_x emissions at a unit load of 180-MW. The upper ammonia burner had a rated flow rate of 3.0 t·h⁻¹ per unit, while the lower ammonia burner had a rated flow rate of 1.6 t·h⁻¹ per unit. During the experiment, the actual flow rate of each unit for both the upper and lower ammonia burners was set to 1.6 t·h⁻¹ (total flow rate of 6.4 t·h⁻¹), ensuring consistent individual ammonia flow rates for the upper and lower layers. Throughout the experiment, the air-to-ammonia ratio for both the upper and lower layers was 0.2, with a primary air velocity of 23 m·s⁻¹. The ammonia injection velocity for the lower layer was 60 m·s⁻¹, while that for the upper layer was 32 m·s⁻¹. A total of 45 data points were collected. As shown in Fig. 7, under the same boiler operating oxygen concentration, ammonia combustion performed better in the lower burner than in the upper burner, with an average reduction of around 100 mg·Nm⁻³ in NO_x emissions when injecting ammonia in the lower burner. The reasons for the different performance of the upper and lower ammonia burners were analyzed, as follows:

(1) Different oxygen concentrations. The lower ammonia burner is located in the middle part of the main combustion zone, which has an overall reducing atmosphere with a relatively low oxygen concentration near the ammonia burner. On the other hand, the upper ammonia burner is located in the upper part of the main combustion zone, where multiple secondary air ports (including those with poor sealing due to cooling requirements) and tertiary air carry a large amount of air into the furnace. Moreover, during low-load combustion, the burnout zone moves downward, resulting in a relatively high oxygen concentration in that area.

(2) Different combustion forms. In the middle part of the main combustion zone, where the lower ammonia burner is located, a significant amount of volatiles from coal powder are released. Both the volatiles and the ammonia gas undergo gas-phase reactions, weakening the oxygen depletion effect of the ammonia and greatly reducing the rate of NO_x formation. On the other hand, in the upper part of the main combustion zone, where the upper ammonia burner is located, the primary reaction is the heterogeneous combustion of a large number of coke particles, which has a slower reaction rate than ammonia combustion. The localized high air-to-ammonia ratio near the nozzle of the upper ammonia burner results in the promotion of NO_x formation.

3.1.3. Effects of loads and ammonia supply

Fig. 8 shows the variation trend in the furnace outlet NO_x emissions with increasing ammonia injection rates (0-18 t·h⁻¹) under loads of 180-, 240-, and 300-MW. During pure-coal combustion, the furnace outlet NO_x emissions under loads of 180-, 240-, and 300-MW ranges within 299-337, 285-326, and 318-360 mg·Nm⁻³, respectively. The basic emissions value of the furnace outlet NO_x is the lowest under a unit load of 240-MW. This is because, in comparison with a unit load of 300-MW, the furnace temperature is slightly lower under a unit load of 240-MW, which may result in relatively less thermal NO_x formation. Compared with a unit load of 180-MW, the operating oxygen concentration under a unit load of 240-MW is lower, leading to lower fuel-NO_x formation. After ammonia injection, the NO_x emissions exhibits different trends with increasing ammonia injection rates at different loads. More specifically, under a unit load of 180-MW, the NO_x emissions increases monotonically with increasing ammonia injection rates. Under a unit load of 240-MW, compared with pure-coal combustion, the NO_x emissions value is slightly lower when 6.4 t·h⁻¹ of ammonia is injected, and it increases by around 100-150 mg·Nm⁻³ when 10 t·h⁻¹ of ammonia is injected. However, when 15 t·h⁻¹ of ammonia is injected, the NO_x emissions show a decreasing trend. Further increasing the ammonia injection rate to 18 t·h⁻¹ results in a differentiated trend, depending on the operating oxygen concentration. When the oxygen concentration is 3.0%, NO_x emissions continues to decrease, while the NO_x emissions increases at oxygen concentrations of 3.3%-3.6%, compared with injecting 15 t·h⁻¹ of ammonia. Under a unit load of 300-MW, when the oxygen concentration is below 2.4%, injecting 6.4 t·h⁻¹ of ammonia results in similar or lower NO_x emissions values compared with those from pure-coal combustion. At an oxygen concentration of 2.7%, there is a slight increase in NO_x emissions, and injecting 10 and 15 t·h⁻¹ of ammonia leads to an increasing trend in NO_x emissions. When injecting 18 t·h⁻¹ of ammonia, the trend in NO_x emissions changes consistently with the range of 0-6.4 t·h⁻¹. At lower oxygen concentrations (≤ 2.4%), NO_x emissions decreases or remains stable, while at higher oxygen concentrations (≥ 2.7%), NO_x emissions continues to increase.

The above phenomena can be explained by the fact that ammonia injection increases fuel-type NO_x formation but may also play a role in reducing NO_x. At a reasonably operated oxygen concentration for a unit load of 240- or 300-MW, injecting 6.4 t·h⁻¹ of ammonia in the lower burner or injecting 15 t·h⁻¹ (ammonia mixing rate of 12.3%) or 18 t·h⁻¹ (ammonia mixing rate of 11.8%) in both the upper and lower burners results in a decrease in NO_x. This is because the ammonia gas, with a low excess air coefficient, enters the furnace and changes the fuel-to-air equivalence ratio in the burner region, where the excess ammonia plays a role in high-temperature reduction [17], [18]. The reaction equation is NH₃ + NO → N₂ + H₂O + 0.5H₂. This reaction typically occurs in oxygen-free or extremely low oxygen environments between 1200 and 1600 °C, which is consistent with the atmosphere in the primary combustion zone of the furnace. It should be noted that this reaction is different from the selective non-catalytic reduction (SNCR) reactions (4NH₃ + 4NO + O₂ → 4N₂ + 6H₂O and 4NH₃ + 2NO + 2O₂ → 3N₂ + 6H₂O), which occur in a weakly oxidizing environment at temperatures between 850 and 1100 °C. The reason for the increase in NO_x when injecting 18 t·h⁻¹ of ammonia in some cases under a range of oxygen concentrations from 3.3% to 3.6% and a unit load of 240-MW may be the downward movement of the burnout air, which results in a shorter residence time of flue gas in the re-burning zone and less effective air staging compared with that under a unit load of 300-MW. Moreover, with an increasing ammonia injection rate, more unburned ammonia enters the burnout zone, leading to increased NO_x formation. Under a unit load of 180-MW, due to the higher overall operating oxygen concentration of the boiler, ammonia combustion remains dominant, resulting in a monotonically increasing trend in NO_x emissions. In summary, under suitable conditions, ammonia burners at different positions in units under loads of 240- and 300-MW can exhibit high-temperature reduction. During ammonia combustion, the lower burner plays a primary role in reduction; as the ammonia injection rate increases, the furnace outlet NO_x emissions increases until the upper burner begins to contribute to reduction, causing the NO_x emissions to decrease.

In this experiment, the furnace outlet NO_x concentrations of the Wanneng Tongling power plant Boiler No. 3 under loads of 300- and 240-MW, with a maximum ammonia co-firing rate of 18 t·h⁻¹, were both within 500 mg·Nm⁻³. Under a unit load of 180-MW, with the same ammonia co-firing rate, the furnace outlet NO_x concentration was within 700 mg·Nm⁻³, which did not exceed the treatment range of the existing selective catalytic reduction (SCR) system.

A comparison showed that the NO_x emissions from both the pure-coal combustion and ammonia co-firing in this experiment were higher than the results from the 40-MW_th boiler test conducted by Niu et al. [12]. The reasons for this difference may be as follows:

(1) The 40-MW_th tangentially fired hot water boiler used by Niu et al. [12] had a smaller furnace volume and lower thermal load, resulting in a lower furnace temperature and combustion intensity, which led to less thermal NO_x formation.

(2) In the test conducted by Niu et al. [12], there was a high ammonia escape rate, which promoted the reduction reaction between the unburned NH₃ and NO.

(3) In the present experiment, the air staging effect was not significant under low-load conditions.

3.2. Effects of ammonia co-firing on the concentrations of NH₃, H₂O, and CO₂

The influence of different ammonia blending levels on the concentrations of NH₃, H₂O, and CO₂ emissions at the furnace outlet is shown in Fig. 9. The figure shows the average values of H₂O, NH₃, and CO₂ concentrations in the flue gas at the tail end, obtained from multiple experiments conducted at different operating oxygen levels for 300-, 240-, and 180-MW. The measured values for each experiment were converted to 6% O₂ base. The fluctuations in the tail oxygen content result in fluctuations in the measured concentrations of each component, which are plotted on the graph in the form of error bars. As shown in Fig. 9, under all ammonia blending conditions, the ammonia concentration at the furnace outlet is below 1 ppm, which is comparable to the ammonia concentration in pure-coal combustion conditions. This finding indicates that strong combustion or reduction reactions occur after the introduction of ammonia into the boiler, resulting in extremely low ammonia escape rates such that nearly complete combustion is achieved. This value is much lower than the experimental results obtained by Niu et al. [12] on a pilot-scale boiler, which may be attributed to the fact that—compared with the pilot-scale boiler—the high-temperature zone in a large-scale power plant boiler is larger, leading to a longer residence time for ammonia in the furnace and facilitating the ammonia’s complete combustion and reduction reactions. Therefore, it can be concluded that maintaining a certain operating load in a coal-fired power plant boiler during ammonia blending combustion ensures that the furnace temperature remains at a high level, allowing the ammonia to burn completely. Moreover, compared with pure-coal combustion conditions, the reduction in coal consumption after ammonia blending leads to a monotonic decrease in CO₂ concentration at the furnace outlet, resulting in significant CO₂ emission reductions. Furthermore, as the combustion of ammonia generates a large amount of water, the H₂O concentration at the furnace outlet increases monotonically with an increase in the ammonia blending level.

3.3. Effects of ammonia co-firing on boiler heat transfer

Radiative heat transfer and convective heat transfer are the main heat exchange pathways in boilers, and the distribution of heat between them is closely related to the properties of fuel and combustion products. Fig. 10, Fig. 11, Fig. 12 present a comparative analysis on the variation in the upper partition screen superheater (radiative heating surface) and the final-stage reheater wall temperature (convective heating surface) under ammonia blending conditions compared with those under pure-coal combustion conditions for a 180-, 240-, and 300-MW unit load. This analysis indirectly reflects the changes in heat transfer distribution on the boiler heating surfaces. From Fig. 10, it can be observed that, under a low load (180-MW), compared with pure-coal combustion conditions, the wall temperature of the partition screen superheater generally decreases after ammonia blending, while the wall temperature of the final stage reheater generally increases. The magnitude of these temperature variations differs with different levels of ammonia blending. As the ammonia blending level increases, the decrease in the wall temperature of the partition screen superheater first increases and then decreases, while the increase in the wall temperature of the final stage reheater gradually intensifies. The reasons are as follows: On the one hand, after ammonia blending, the amount of coal entering the furnace is reduced, which weakens the radiative characteristics of the fly ash, coke, and other particles and gases in the combustion products, leading to a decrease in radiative heat transfer. Meanwhile, the increased water vapor content in the flue gas increases the flue gas volume flow rate, velocity, and internal energy carried by the flue gas, resulting in an increase in convective heat transfer. The theoretical flue gas volume for coal combustion in this experiment is 0.287 Nm³·MJ⁻¹, while the theoretical flue gas volume for pure ammonia combustion is 0.342 Nm³·MJ⁻¹. On the other hand, as the ammonia blending level increases from 6.4 to 18.0 t·h⁻¹, the upper ammonia burners gradually come into operation, and the lower (A layer) coal powder burners gradually withdraw, causing the flame center to move upward relative to pure-coal combustion, which leads to an increase in the wall temperature of the radiative and convective heating surfaces in the upper furnace. The change in heat transfer characteristics due to the variation in combustion products after ammonia blending may have a greater impact than the flame center movement, resulting in the aforementioned results.

As shown in Fig. 11, Fig. 12, at 240-MW, with an increase in the ammonia co-firing ratio, there is a slight rise in the wall temperature of the separator screen superheater, while the wall temperature of the final-stage reheat increases more significantly. From Fig. 11, it can be seen that, under a load of 300-MW, there is no significant change in the wall temperature of the heating surfaces with increasing ammonia blending level compared with the pure-coal combustion conditions. The reasons for this may be as follows: Firstly, at 240- and 300-MW, the coal consumption entering the boiler increases, and the flame temperature in the furnace is high. The weakening of radiation from fly ash, coke, and other particles and gases caused by ammonia blending is limited, and the increase in flue gas volume flow rate is also limited. As a result, the changes in radiative and convective heat transfer caused by the variation in combustion products after ammonia blending are relatively small. Secondly, at 240-MW, despite the withdrawal of the D-layer coal powder burner, the ammonia burner operates synchronously, resulting in little change in the flame center. At 300-MW, all four layers of coal powder burners are operational, and increasing the ammonia co-firing ratio does not alter the position of the flame center. This indicates that, under high loads, the current proportion of ammonia co-firing has almost no effect on the heat distribution inside the furnace. Further investigation is needed to understand the impact of a higher proportion of ammonia co-firing on heat distribution on the heating surface under high loads.

Fig. 13 illustrates the variation in the de-superheating water and outlet steam temperature of the superheaters and reheaters with the ammonia co-firing rate under different loads. As shown in Fig. 13(a), at a load of 180-MW, as the ammonia co-firing rate increases, the de-superheating water of the superheaters increases. The outlet steam temperature of the partition screen reheater shows a decreasing trend, while those of the rear screen reheater and final superheater slightly increase overall. When the ammonia co-firing rate reaches 18 t·h⁻¹, the de-superheating water of the superheaters increases by nearly three times. The changes in the outlet steam temperature of the superheaters correspond to the trends in the metal wall temperature. The de-superheating water of the reheaters remains relatively stable. With an increasing ammonia co-firing rate, the outlet steam temperatures of the screen reheater and final reheater show an overall upward trend. When the ammonia co-firing rate reaches 18 t·h⁻¹, the outlet steam temperature of the final reheater increases by 24 °C. It can be observed that, as the ammonia co-firing ratio increases, the convective heat transfer in the boiler significantly increases, which contributes to the increase in the reheated steam temperature. The increase in the de-superheating water quantity in the superheaters is within the design range and ensures safe operation of the superheater wall temperature. In Fig. 13(b), under a load of 240-MW, with an increasing ammonia co-firing rate, the outlet steam temperatures of the partition screen reheater, rear screen reheater, and final reheater slightly increase compared with those under the pure-coal condition, with an increase of less than 5.5 °C in the outlet steam temperature of the final reheater. The de-superheating water quantity in the superheaters doubles compared with that under the pure-coal condition, and the outlet gas temperatures of both the screen reheater and the final reheater increase by less than 14 °C. In Fig. 13(c), under a load of 300-MW, with an increasing ammonia co-firing rate, the outlet steam temperature of each heat exchanger stage remains almost unchanged, and there is only a small variation in the de-superheating water and reheater de-superheating water.

To further explore the changes in heat transfer during ammonia blending combustion, Fig. 14 analyzes the variation in flue gas temperature at the furnace outlet (inlet of the screen reheater) and the outlet flue gas temperature of the air preheater before and after co-firing. It can be observed that, under a low load (180-MW), as the ammonia blending level increases, the influence of the weakening of the radiative characteristics and flame center movement due to combustion product changes leads to a significant increase in the flue gas temperature at the furnace outlet (up to 50 °C), while the flue gas temperature at the air preheater outlet shows no significant change. This finding indicates that, under low load conditions, there is a change in the heat transfer distribution in the boiler, with a significant increase in convective heat transfer. Under a high load (240- or 300-MW), as the ammonia blending level increases, the increase in the gas temperature at the furnace outlet flue is relatively small (up to 16 °C), and the gas temperature of the outlet flue only slightly increases (up to 2 °C). It can be seen that the current proportion of ammonia blending under high load conditions has a minimal impact on the heat transfer distribution on the heating surfaces.

In summary, under the unit load and co-firing ratio of this test unit, there was no significant change in the outlet flue gas temperature of the air preheater, indicating that the existing heating surfaces in the boiler could meet the heat transfer requirements without the need for modification.

3.4. Effects of ammonia co-firing on boiler thermal efficiency

In order to analyze the impact of ammonia blending on the thermal efficiency of the boiler, this study compared and analyzed the boiler thermal efficiency under different loads (180-, 240-, and 300-MW) for pure-coal conditions and ammonia blending conditions (with a fixed ammonia flow rate of 15 t·h⁻¹). The boiler’s operating oxygen levels were controlled at 4.2%, 3.5%, and 2.3%, respectively, for different loads. The boiler thermal efficiency (ƞ) was calculated using the reverse equilibrium method as described in Ref. [19]:

(1)$ \eta=100-\left(q_{2}+q_{3}+q_{4}+q_{5}+q_{6}\right)$

where q₂, q₃, q₄, and q₅ represent the heat loss of the flue gas (%), the unburned gas (%), the unburned solid (%), and the boiler radiation (%), respectively; q₆ represents the physical heat loss of the ash residue (%).

When determining the boiler input heat, only the lower heating value of the fuel entering the furnace is considered. In the calculations, the original coal and NH₃ were converted into a new fuel based on the heat ratio of ammonia and coal. The excess air coefficient α_py was calculated using the simplified formula α_py = 21/(21 - C_O2), where C_O2 represents the oxygen content in the flue gas at the air preheater outlet. The experimental baseline temperature was 25 °C. The mass ratio of fly ash to bottom ash was 90% and 10%, respectively. The flue gas temperature was adjusted based on the design inlet temperature of the air preheater.

The formula for calculating the boiler heat loss q₅ is as follows: q₅ = q₅^eD^e/D, where q₅^e represents the heat loss at the rated evaporation capacity of the boiler, D^e is the rated evaporation capacity of the boiler, and D is the evaporation capacity of the boiler under the experimental conditions. As shown in Fig. 15, the boiler thermal efficiency slightly decreases during ammonia co-combustion compared with pure-coal conditions, with a decrease ranging from 0.12% to 0.38%.

To further analyze the slight decrease in boiler thermal efficiency during co-combustion, Table 5 provides detailed information on the various heat losses under different conditions. As shown in the table, the unburned gas heat loss q₃ is 0 under all conditions because the CO volume fraction in the flue gas at the air preheater outlet is zero, and the NH₃ concentration is negligible (less than 1 ppm). The heat loss q₅ of the boiler remains essentially unchanged before and after the addition of ammonia under the same load because the evaporation capacity D of the boiler remains essentially constant under the same load before and after ammonia addition. The magnitude of the heat loss q₅ of the boiler under different loads depends on the evaporation capacity D of the boiler under the experimental load.

A comparison of the ammonia-blending conditions with the pure-coal conditions under different loads showed that the flue gas heat loss q₂ and the unburned solid heat loss q₄ increased by a range of 0.04%-0.18% and 0.11%-0.23%, respectively. However, the physical heat loss of the ash residue q₆ decreased by a range of 0.015%-0.033%. The flue gas heat loss q₂ consists of the dry flue gas heat loss and the steam heat loss in the flue gas. A comparison of the dry flue gas heat loss and the steam heat loss for coal firing versus ammonia-coal co-firing under different conditions is provided in Fig. 15. It can be observed that the dry flue gas heat loss decreases after ammonia blending, while the steam heat loss increases, with a more significant increase in the steam heat loss, resulting in a slight increase in flue gas loss. The main reason for the decrease in the dry flue gas heat loss is that the flue gas temperature remains relatively unchanged (within −1 to 2 °C) after ammonia blending, while the volumetric flow rate of the dry flue gas decreases. The increase in steam heat loss is due to a significant increase in the volume fraction of H₂O in the flue gas after ammonia blending. The increase in unburned solid heat loss after ammonia blending is mainly attributed to the increase in unburned carbon (UC) content in the fly ash (as shown in Fig. 16). The reasons are as follows:

(1) The homogeneous reaction rate between the gaseous fuel NH₃ and O₂ is much faster than that between the solid-fuel coke and O₂. Therefore, after NH₃ injection, there is a competitive reaction between NH₃ and coke in the main combustion zone, leading to an increase in unreacted coke.

(2) Under a high load of 300-MW, the oxygen level in the main combustion zone is lower compared with that under the low-load condition of 180-MW due to a lower oxygen concentration after air staging. Consequently, the amount of unreacted coke in the main combustion zone is higher under a high load. In addition, when NH₃ is injected, it undergoes an oxygen scavenging reaction with the unreacted coke, leading to a significant increase in the carbon content of the unburned fly ash under the high-load conditions of 300-MW ammonia-injected operation. After ammonia blending, the heat provided by the NH₃ replaces a portion of the coal, resulting in a decrease in the coal feed rate. This leads to a decrease in the mass percentage of ash content for the converted new fuel and hence to a reduction in the physical heat loss of the ash residue q₆.

4. Conclusions

After retrofitting a 300-MW coal-fired unit with ammonia co-firing, ammonia co-firing tests were conducted at a proportion of 20%-10% (based on heat) from a load range of 180-300-MW. The influence of the boiler’s operating oxygen concentration, the ammonia injection position, the unit load, and the ammonia co-firing rate on the characteristics of the NO_x emissions were studied. In addition, the impact of ammonia co-firing on the boiler’s heat transfer and thermal efficiency was investigated. The main results and conclusions are as follows.

(1) Compared with pure-coal combustion, the exhaust gas NO_x is more sensitive to changes in the boiler’s operating oxygen concentration in the context of ammonia co-firing. Furthermore, parameters such as the ammonia injection position, unit load, and ammonia co-firing rate can affect the equivalence ratio of ammonia combustion at the outlet of the pure-ammonia burners. When operating in a rich combustion state, high-temperature reduction in the furnace is activated, decreasing the emissions of the exhaust gas NO_x to even lower than those under pure-coal combustion. For example, by only operating the ammonia burners in the middle part of the main combustion zone, increasing the unit load and ammonia injection rate can reduce the emissions of the exhaust gas NO_x.

(2) Under loads ranging from 180- to 300-MW, when the ammonia co-firing rate varies from 0 to 18 t·h⁻¹, the ammonia escape from the boiler outlet remains below 1 ppm, indicating good ammonia combustion.

(3) Under a low load (180-MW) during ammonia co-firing, due to the weakening of particle radiation and gas radiation intensity and the upward shift of the flame center, the heat transfer in the boiler shows a trend of reduced radiative heat transfer and increased convective heat transfer. Under a high load (240- or 300-MW), with the current ammonia co-firing rate (maximum 18 t·h⁻¹), the change in heat transfer in the boiler is relatively small. Under the unit load and co-firing ratio used in this experiment, the heating surfaces of the boiler can meet the heat transfer requirements without the need for modification.

(4) Compared with pure-coal conditions, ammonia co-firing leads to a slight increase in the sensible heat loss from water vapor and solid unburned losses in the flue gas after ammonia co-firing. This results in a slightly lower thermal efficiency of the boiler (a decrease of 0.12%-0.38%). However, under the experimental conditions in this study, the impact of ammonia co-firing on the boiler’s thermal efficiency is minor.

Acknowledgments

This work was supported by the National Key Research and Development Program of China (2023YFB4005700, 2023YFB4005705, and 2023YFB4005702-03), the Academy-Local Cooperation Project of the Chinese Academy of Engineering (2023-DFZD-01), the National Natural Science Foundation of China (52207151), the Natural Science Foundation of Anhui Province (2208085QA29), the University Synergy Innovation Program of Anhui Province (GXXT-2022025), and the independent project of the Energy Research Institute of Hefei Comprehensive National Science Center (Anhui Energy Laboratory; 22KZZ525, 23KZS402, 22KZS301, and 22KZS304).

Compliance with ethics guidelines

Qifu Lin, Wangping Sun, Haiyan Li, Yangjiong Liu, Yuwei Chen, Chengzhou Liu, Yiman Jiang, Yu Cheng, Ning Ma, Huaqing Ya, Longwei Chen, Shidong Fang, Hansheng Feng, Guangnan Luo, Jiangang Li, Kaixin Xiang, Jie Cong, and Cheng Cheng declare that they have no conflict of interest or financial conflicts to disclose.

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