A coal-fired power plant integrated with biomass co-firing and CO₂ capture for zero carbon emission

Abstract

A promising scheme for coal-fired power plants in which biomass co-firing and carbon dioxide capture technologies are adopted and the low-temperature waste heat from the CO₂ capture process is recycled to heat the condensed water to achieve zero carbon emission is proposed in this paper. Based on a 660 MW supercritical coal-fired power plant, the thermal performance, emission performance, and economic performance of the proposed scheme are evaluated. In addition, a sensitivity analysis is conducted to show the effects of several key parameters on the performance of the proposed system. The results show that when the biomass mass mixing ratio is 15.40% and the CO₂ capture rate is 90%, the CO₂ emission of the coal-fired power plant can reach zero, indicating that the technical route proposed in this paper can indeed achieve zero carbon emission in coal-fired power plants. The net thermal efficiency decreases by 10.31%, due to the huge energy consumption of the CO₂ capture unit. Besides, the cost of electricity (COE) and the cost of CO₂ avoided (COA) of the proposed system are 80.37 $/MWh and 41.63 $/tCO₂, respectively. The sensitivity analysis demonstrates that with the energy consumption of the reboiler decreasing from 3.22 GJ/tCO₂ to 2.40 GJ/ tCO₂, the efficiency penalty is reduced to 8.67%. This paper may provide reference for promoting the early realization of carbon neutrality in the power generation industry.

Graphical abstract

Keywords

coal-fired power plant / biomass co-firing / CO₂ capture / zero carbon emission / performance evaluation

1 Introduction

Carbon dioxide produced from fossil fuels is a major source of greenhouse gases, leading to a range of global problems, such as temperature warming and climate change [1]. As the largest carbon footprint in the world, China has pledged to peak CO₂ emissions by 2030, and achieve carbon neutrality by 2060, which are of great significance to the decarbonization process of the world [2,3]. To achieve carbon mitigation, great efforts have been made by the Chinese government, such as accelerating the exploitation of renewable energy, whose proportion in the power sector has been increasing rapidly since the 12th Five Year Plan [4]. The annual growth rate runs over 15% for the installed capacity of solar and wind power units, ranking first worldwide in the past ten years [5]. Although renewable energy grows at such a spectacular rate, its electric power generation still accounts for a limited share of electricity supply in China. In 2019, the installed capacity of solar and wind power units accounted for 10.2% and 10.4% of the installed gross capacity, while the electric energy production of solar and wind power plants accounted for 3.1% and 5.5% of the total power generation, respectively [6]. Moreover, it is difficult to make renewable energy as an alternative in peak load regulation of the electricity grid, because of its intermittency.

By contrast, the development of coal-fired power plants is strictly controlled in China in recent years, which still accounts for 59.2% of the installed gross capacity and 68.9% of the electricity production in China in 2019 [7]. In addition, coal-fired power plants as the baseload undertake the mission of peak load regulation for the power grid as well [8]. In view of this, coal-fired power plants are expected to continuously play a fundamental role in electricity generation in China and it would be advantageous if the coal-fired power plants, as the main peak-regulating alternative of the power grid, could achieve zero CO₂ emission, or even negative emission.

A lot of work has been done to achieve zero CO₂ emission of coal-fired power plants. Presently, there are three main methods available to reduce carbon footprint. The first one is the improvement of the thermal efficiency of the power unit. The improvement of thermal efficiency can reduce the consumption of fossil fuels and thus realize lower CO₂ emissions while supplying the same amount of electricity [9]. However, the component performance and system integration of existing coal-fired power stations have reached a high level, which makes it difficult to significantly improve the energy efficiency [10,11]. In addition, the improvement of thermal efficiency has a limited effect on the realizing of zero CO₂ emission. The second one is the adoption of the carbon dioxide capture technology. As a mature technology, CO₂ capture has received considerable attention due to its high CO₂ capture rate, excellent emission reduction effect, and greater commercial application potential [12]. But it is hard to achieve full removal, and the cost of power generation will rise rapidly as the capture rate increases [13]. Moreover, the energy consumption of the removal process is huge, which leads to a significant reduction of thermal efficiency by 12–15 percentage points in power plants [14–16]. The 90% capture rate is generally considered to be economical and reasonable [17,18]. The last one is the adoption of the co-firing technology of coal and biomass. As known, living biomass plants absorb CO₂ from the atmosphere through photosynthesis [19]. Therefore, its use in energy production is considered carbon-neutral, because it is widely believed to consume the same amount of CO₂ in growing as it does in combustion [20,21]. If a certain amount of biomass is used instead of fossil fuels to generate electricity, the amount of CO₂ emitted from fossil fuels can be reduced [22]. While the biomass co-firing in coal-fired thermal power plants provides a number of advantages, it has a negative impact on facilities as well, such as the corrosion of the boiler and the deposition of ash [23]. Thus, it is an inevitable choice to reduce the adverse effects by controlling the biomass mixing ratio, resulting in the fact that zero CO₂ emission cannot be achieved by biomass co-firing alone.

Since it is hard to achieve zero carbon emission of coal-fired power plants by only one method because of the high energy consumption of the CO₂ capture process and the limitation of the biomass mixing ratio, the combination of various CO₂ reduction schemes has, thus, attracted much attention and many scholars have proposed some good ideas. Bhuiyan and Naser [24] built a small-scale furnace to simulate the co-firing of coal and biomass under the condition of oxygen fuel, highlighting the possible environmental impact of different fuel fires and the heat transfer characteristics of the small furnace. Zhao et al. [25] researched the effective utilization of co-firing fly ash, which could be used as a stable CO₂ absorber in coal-fired power plants. Schakel et al. [26] conducted a life cycle assessment of CCS with biomass co-firing to examine the environmental impacts, resulting in the fact that while the reduction of climate change potential is subsistent, the Bio-CCS increases the environmental impact in other categories, such as ionizing radiation, terrestrial ecotoxicity, and metal depletion. Yang et al. [27] developed 10 life-cycle evaluation models, based on the GaBi software and the integrated environmental control model, to quantify the co-firing ratio and the effects of performance parameters of different power plants on various environmental impact categories. Ruhul Kabir and Kumar [28] compared the environmental performances of nine biomass/coal co-firing pathways, concluding that densification of biomass can produce significant environmental advantages.

Previous researches gave a large number of talented viewpoints on the improvement of the efficiency and the effect on the environment. However, much less literature has discussed the application of biomass co-firing in a real coal-fired power plant with the CO₂ capture system. Due to the carbon-neutral property of biomass, an actual coal-fired power plant integrated with biomass co-firing and CO₂ capture can indeed achieve zero carbon emission. Thus, it is necessary to examine the influence of system integration on power plants, and the changes of the system performance due to the biomass mixing and the CO₂ capture. Besides, the existing research about the integration with the biomass co-firing and the CCS system is mostly related to the qualitative analysis at the point of zero carbon emission, but less attention has been paid to the quantitative analysis of the point at which the carbon neutrality is achieved and the effects of various factors (such as biomass mass mixing ratio, CO₂ capture rate) on carbon neutrality.

In view of this, based on a typical coal-fired power plant, the biomass co-firing technology and the CO₂ capture technology were adopted to realize zero carbon emission. First, the system was proposed, which includes a coal-fired power plant, a CO₂ capture unit, and a biomass co-combustion unit. Next, according to the real data, the thermodynamic and tech-economic performances of the integrated system are quantitatively analyzed to reveal the carbon mitigation potential. Finally, the sensitivity analysis is conducted to show the effect of the main parameters on the emission performance, the thermal performance, and the economic performance, such as the net power output, the efficiency penalty, the cost of electricity (COE), and the cost of the CO₂ avoided (COA).

2 System description

2.1 Reference coal-fired power plant

A typical 660 MW supercritical coal-fired power plant without CO₂ capture has been selected for case study, as shown in Fig. 1. The power generation system mainly consists of a supercritical once-through boiler, a steam turbine, a generator, and a set of regenerative systems. The fuel combusts in the boiler and releases chemical energy to heat the working fluid for the steam turbine. The generated main steam expands in the HPT first to generate electric power and then is sent back to the boiler for reheating before continuously expanding in the IPT and LPT. The exhausted steam from the LPT is cooled down to its liquid state in the condenser [29]. After heated by the regenerative heaters (RHs), which consist of three high-pressure heaters, four low-pressure heaters, and a deaerator (DEA), the condensed water is sent back to the boiler for recycling. The basic parameters of the reference coal-fired power plant and the heat regeneration system are listed in Tables 1 and 2.

2.2 Carbon dioxide capture unit

Carbon dioxide capture units are widely used due to their compatibility with the existing fossil fuel consumption systems [30]. Monoethanolamine-based (MEA-based) CO₂ capture as depicted in Fig. 2 is used in this paper, because it is more mature and widely used [31]. All the flue gas out of the boiler is delivered to the flue gas desulfurization (FGD) unit and is cooled down to 40°C–50°C before entering the absorber through the booster fan. Then, the desulfurized flue gas is reacted with the MEA solution with a mass fraction of 30%. The treated flue gas is released from the top of the absorber.

The rich solution is pumped to the lean-rich heat exchanger from the bottom of the absorber. After heat exchange, it enters the stripper and is heated to 130°C for CO₂ desorption. The captured CO₂ from the stripper is cooled to 99°C and the moisture is removed to improve the CO₂ concentration in the condenser and separator (SP). After being separated from the stripper, CO₂ needs to be compressed to 8.0 MPa by multistage compressors (CP) for transportation and storage. In the CO₂ compression process, the temperature of the compressed CO₂ is reduced to 38°C by the interstage cooling. The lean solution is pressured by a pump (P2) to the lean-rich heat exchanger and then cooled to a specified temperature by a cooler before entering the absorber.

2.3 Biomass co-firing unit

Due to the carbon neutrality of biomass fuel, co-firing of coal and biomass can reduce CO₂ emissions produced by carbon contained in biomass [32]. In general, there are three basic co-firing operations of biomass materials in coal-fired power plants, i.e., direct co-firing, indirect co-firing, and parallel co-firing [33,34]. This paper selects direct co-firing for system integration on account of its better flexibility with coal-fired power plants. The direct co-firing adopts the common pulverization of the biomass and coal, and the injection of the pulverized mixing fuel into the existing pulverized coal pipelines [35].

2.4 Proposed system

Figure 3 demonstrates that the proposed system consists of a conventional coal-fired system (Fig. 1), a biomass co-firing unit, and a CO₂ capture unit (Fig. 2).

Before CO₂ capture, the flue gas removes NO_x, ash, toxic particles, SO₂, and other toxic gases by passing through a selective catalytic reduction (SCR), an electrostatic precipitator (ESP), and a flue gas desulfurization (FGD) successively [36]. The flue gas leaving the desulfurization unit is compressed by the booster fan and then enters the absorber column, CO₂ condenser, multistage compressors, and intercoolers successively.

The thermal energy consumed by the reboiler is supplied by the steam drawn from the exhaust steam of the IPT. The thermodynamic performance parameters of extraction steam can reach 0.45–1.06 MPa and 270°C, which are obviously higher than the steam required for absorber regeneration (about 0.42 MPa and 144°C). Therefore, the extraction steam with high pressure and high temperature first goes through the pressure reducing valve to reduce the pressure to 0.42 MPa, and then mixes with the low-temperature condensate from the outlet of the reboiler to reduce the steam temperature to 144°C. Then, the mixed steam enters the reboiler for heat exchange and becomes liquid at a temperature of 125°C. Part of the condensate after heat exchange is used to cool down the extraction steam from the IPT, and the rest flows into the entrance of RH5.

In this system, the carbon dioxide capture unit not only consumes a lot of thermal energy, but also releases large amounts of low-temperature heat, such as the CO₂ condenser in the desorption tower, and the multistage compressor intercoolers. For a typical 600 MW coal-fired power plant with a 90% CO₂ capture efficiency, the heat released in the CO₂ condenser and CO₂ multi-stage compression intercoolers can reach 80 MW and 40 MW, respectively. If this low-temperature heat can be used efficiently, the energy consumption of the whole system will be significantly reduced.

As can be observed in Fig. 3, the condensed water out of the condensate pump is divided into two parts. One part enters HE1 and HE2, and the other part continues to flow through the original low-pressure regenerative heater (RH6–8). Finally, both parts of the condensed water join at the entrance of RH5. Thus, it can be seen that the integrated scheme can partly replace the original sixth to the eighth low-pressure regenerative heaters. Consequently, the extraction steam entering the sixth to the eighth regenerative heaters decreases significantly, and the power output of the system is boosted remarkably.

3 Thermodynamics and emission performance analysis

3.1 Fundamental assumptions

The reference coal-fired power plant and the proposed system were evaluated, and their performances were compared. To control calculation variables, it is essentially assumed that thermal efficiencies of the boilers and turbines are the same in the two schemes; the fuel energy inputs of the two systems remain constant; the entire flue gas stream enters the absorption tower, and about 90% of CO₂ is captured [37]; and the biomass fuel is the straw of wheat, the main grain crop in north China. The analysis data for coal and biomass are summarized in Table 3 .

3.2 System simulation

In this paper, ASPEN Plus is used for the calculation of the CO₂ capture, and EBSILON Professional is adopted for the calculation of the biomass co-firing and generation processes. ASPEN Plus is a large-scale and general-purpose process simulation software for chemical process design, steady-state simulation, and optimization [38]. EBSILON Professional is specialized and widely used in the field of the design, simulation, and optimization of power plants [39]. Based on the components of the selected coal and biomass, the parameters of the flue gas from the electrostatic precipitator (ESP) are obtained, as tabulated in Table 4.

According to the composition and performances of the flue gas, the CO₂ capture and compression processes are simulated in the Aspen Plus, and the overall required regeneration heat for CO₂ capture process is obtained. As for the CO₂ capture process simulation, the Amine package/Li-Mather method is implemented, and the block models “RadFrac” are selected for the absorber and the stripper. In the proposed system, considering that the regeneration heat is supplied by the steam drawn from the exhaust steam of the IPT, the mass flow rate of the steam can be calculated by the EBSILON Professional. Based on the design data of the reference coal-fired power plant (given in Tables 1 and 2), the energy consumed by the reboiler, and the low-temperature waste heat recycled from the CO₂ capture and compression process, the whole steam Rankine power cycle is simulated in the EBSILON Professional, and the electricity output is obtained.

3.3 Results and analysis

Through the simulation of the proposed system, the biomass mass mixing ratio is obtained when the CO₂ emission rate is zero. The biomass mass mixing ratio is defined as the ratio of the mass of biomass to the total mass of the fuel. The preliminary results show that the CO₂ emission rate is zero when the biomass mass mixing ratio is 15.40% and the CO₂ capture rate is 90%. Besides, the simulation suggests that the energy consumption of the CO₂ capture system in the proposed system is 3.2 GJ/tCO₂. When other biomass is used in the co-firing, the HHV and the component of the biomass have effects on the biomass mass mixing ratio and the energy consumption of the CO₂ capture system.

The main data of the reference coal-fired power plant and the proposed system under the zero CO₂ emission scenario are given in Table A1 of Appendix A. The thermodynamic performances of the reference coal-fired power plant and the proposed system are evaluated, as presented in Table 5. The fuel energy inputs of the two systems remain constant, while the fuel input rates are slightly different due to the calorimetric value difference between the coal and biomass fuel. The gross power output decreases sharply from 660.00 MW to 562.59 MW due to the huge energy consumption of CO₂ capture, although a lot of surplus energy is recovered from the CO₂ capture process in the proposed system. In particular, 410.35 MW of heat is consumed for solvent regeneration in the proposed system, and the auxiliary power consumption increases from 33 MW to 86.86 MW. Consequently, the net power output decreases from 627.00 MW to 475.74 MW, and the net thermal efficiency falls from 42.74% to 32.43%, which means an efficiency penalty of 10.31 percentage points for CO₂ capture. The efficiency penalty is lower than that of a normal power plant (about 12–15 percentage points) with CO₂ capture, showing that the integration of the proposed system, in which the low-temperature waste heat from the CO₂ capture process is recycled to heat the condensed water, can indeed improve the efficiency of the system [14–16].

To evaluate the performance of carbon emission, the CO₂ emission rate (gCO₂/kWh) and COA rate (gCO₂/kWh) are selected as evaluation criteria in this paper. The CO₂ emission rate is the amount of CO₂ produced when generating 1 kWh of electricity. The COA rate is the reduction of CO₂ emission rate of the proposed system compared with the reference coal-fired power plant.

Figure 4 illustrates the CO₂ emission of the reference coal-fired power plant and the proposed system under the zero CO₂ emission scenario. The CO₂ produced rate in the proposed system is 1073.27 g/kWh, which is 1.32 times of that in the reference coal-fired power plant, due to the additional energy consumption of the CO₂ capture unit in the proposed system. For the reference coal-fired power plant, without the CO₂ capture unit and the biomass co-firing unit, all the CO₂ produced is discharged into the atmosphere, thus the CO₂ emission rate is equal to the CO₂ produced rate. In the proposed system, 10% of CO₂ is produced by burning biomass (approximately 107.33 gCO₂/kWh), which comes from the atmosphere and is also carbon neutral. The remaining 90% of CO₂ is absorbed by the CO₂ capture unit (approximately 965.94 gCO₂/kWh), which means that the CO₂ emission is zero and the zero carbon emission of the proposed system is achieved.

4 Economic analysis

A preliminary economic analysis of the reference coal-fired power plant and the proposed system is conducted in this section. The COE and the COA are selected as the criteria for evaluating the efficiency and cost penalties of the power plant. The major assumed parameters for COE and COA calculation are listed in Table 6.

The COE can be calculated as

(1)\mathrm{COE=}\frac{\mathrm{[CRF}\times \mathrm{TPI+OMC+FC]}}{W},

where CRF is the capital recovery factor, related to the discount rate (k) and the lifespan of equipment (n), calculated by \mathrm{CRF}={\displaystyle \frac{k\times {(\mathrm{1}+k)}^n}{{(\mathrm{1}+k)}^n-\mathrm{1}}}; TPI represents the values of total plant investment (M$); OMC represents the annual operating and maintenance costs (M$), fixed at 4% of the total plant investment (TPI) per year [42]; W represents the annual electricity production (MWh); and FC represents annual fuel costs (M$), which can be calculated as

(2)\mathrm{FC=}{C}_{\mathrm{coal}}\times m_{\mathrm{coal}}+C_{\mathrm{biomass}}\times m_{\mathrm{biomass}},

where C_coal and C_biomass are the prices of the coal and biomass, $/GJ LHV; and m_coal and m_biomass are the annual consumption of coal and biomass, GJ LHV.

The COA is the incremental COE divided by the difference in CO₂ emission intensities between the proposed power plant and the reference power plant, which can be presented as

(3)\mathrm{COA}={\displaystyle \frac{{\mathrm{COE}}_{\mathrm{pro}}-{\mathrm{COE}}_{\mathrm{ref}}}{E_{\mathrm{ref}}-E_{\mathrm{pro}}}},

where COE_ref is the COA in the reference power plant ($/MWh), COE_pro is the COA in the proposed system ($/MWh), E_ref means the mass flow rate of the emitted CO₂ to the atmosphere in the reference power plant (gCO₂/kWh), E_pro means the mass flow rate of the emitted CO₂ to the atmosphere in the proposed system (gCO₂/kWh).

The specification of the economic analysis is provided in Table 7. The TPI of the reference power plant is 355.28 M$, which is estimated according to the cost of typical 660 MW coal-fired power generations in China during 2018, whose specific investment cost is 538.31 $/kW [43]. Integrated with the CO₂ capture unit and biomass co-firing unit, considering the cost of the CO₂ transport and storage, the TPI of the proposed system has reached up to 685.58 M$, which is 330.30 M$ higher than that of the reference power plant, while the SPI increases to 1441.11 $/kW [44]. Specific additional components in the proposed system contain CO₂ capture unit, CO₂ compression trains, heat exchangers, biomass mixing facilities, and pipelines, CO₂ transportation and storage, whose specific investment cost is 116.20 M$, 31.22 M$, 2.18 M$, 1.88 M$, 1.74 M$, and 177.07 M$, respectively [45–47].

In addition, the CO₂ emission rate and CO₂ capture rate of the reference power plant are 811.21 gCO₂/kWh and 0 gCO₂/kWh, and those of the proposed system are 0 gCO₂/kWh and 811.21 gCO₂/kWh, as can be noticed in Table 7. After system integration, the COE of the proposed system is 80.37 $/MWh, with an increase of 33.76 $/MWh compared with the reference power plant, because of the obvious decrease in the net power output. Meanwhile, due to the CO₂ capture unit, the COA in the proposed system is 41.63 $/tCO₂. The COA is lower than that of a normal coal-fired power plant with CO₂ capture unit, showing that the proposed system not only can achieve zero carbon emission, but also can reduce the COA of the system [48,49].

In summary, although the TPI, COE, and COA of the integrated system are increased, the zero CO₂ emission of the coal-fired power plant is achieved, which reflects the advantage of the system integration.

5 Sensitivity analysis

For the proposed system, the dominant parameters are the CO₂ capture rate and the biomass mass mixing ratio which are associated with the CO₂ emission rate. Besides, the energy consumption of the reboiler, the biomass price, the efficiency penalty, and the total plant investment have significant effects on the performance of the system. Thus, the sensitivity analysis is performed in three aspects, including the emission performance, the thermal performance, and the economic performance.

5.1 Emission performance

In this section, the variation of the CO₂ emission rate with different CO₂ capture rates and biomass mass mixing ratios are analyzed, as displayed in Fig. 5. With the same biomass mass mixing ratio, the CO₂ emission rate decreases with the increase of the CO₂ capture rate. At the same CO₂ capture rate, the CO₂ emission rate decreases with the increase of biomass mass mixing ratio.

Point A in Fig. 5 denotes the reference coal-fired power plant without a CO₂ capture unit, in which, the value of the CO₂ emission rate is approximately 811.21 gCO₂/kWh. Point B denotes a typical coal-fired power plant with the post-combustion MEA CO₂ separation technology. The CO₂ capture rate is around 90%, and the CO₂ emission rate is approximately 107.33 gCO₂/kWh. Therefore, it is impossible to eliminate CO₂ emission completely only by the CO₂ capture unit.

Point C denotes a typical coal-fired power plant integrated with the biomass co-firing technology. In this case, the biomass mass mixing ratio is around 30%, and the CO₂ emission rate is approximately 647.62 gCO₂/kWh. Therefore, due to the limitation of the biomass mass mixing ratio with consideration of the corrosion of the boiler and the deposition of ash, zero CO₂ emission cannot be achieved by biomass co-firing alone.

Point D means that, when the biomass mass mixing ratio and the CO₂ capture rate can reach 15.4% and 90% separately, the CO₂ emission rate of the proposed system can actually achieve 0 gCO₂/kWh. The same is true at Point F (at a biomass mass mixing ratio of 30% and a CO₂ capture rate of 79.3%). Therefore, the real zero CO₂ emission for a coal-fired power plant can be achieved through a suitable combination of biomass mass mixing ratio and CO₂ capture rate.

Point E denotes the “negative emission” of the integrated system. In this case, with a 30% biomass mass mixing ratio and a 90% CO₂ capture rate, the CO₂ emission rate is approximately ‒115.0 gCO₂/kWh, which means that the proposed system can recycle 115.0 g of CO₂ from the atmosphere when generating 1 kWh electric energy. In fact, in the proposed system, the “negative emission” can be achieved in the area below the DF line. For example, when the CO₂ capture rate is 90%, with the biomass mass mixing ratio higher than 15.4%, or when the biomass mass mixing ratio is 30%, with the CO₂ capture rate higher than 79.3%, the “negative emission” can be achieved.

5.2 Thermal performance

The energy consumption of the reboiler has an important effect on the thermal performance of the plant. The range of energy consumption change is set from 3.22 GJ/t to 2.40 GJ/t [50]. Figure 6 exhibits the variation of extraction steam flow rate for reboiler and low-pressure turbine inlet pressure with the energy consumption of reboiler.

As can be seen in Fig. 6, with the energy consumption of the reboiler decreasing from 3.22 GJ/t to 2.40 GJ/t, the extraction steam flow rate decreases from 165.07 kg/s to 120.10 kg/s, which means that more working fluids could expand continuously in the low-pressure turbine to generate electric power. Meanwhile, the inlet steam pressure is improved, rising from 0.48 MPa to 0.64 MPa, leading to an increase in the low-pressure turbine efficiency.

Figure 7 manifests the variation of the net power output and the efficiency penalty of the power plant when the energy consumption of the reboiler changes. With the energy consumption of the reboiler decreasing from 3.22 GJ/tCO₂ to 2.40 GJ/t CO₂, the net power output of the plant increases from 475.74 MW to 499.81 MW, with an increasing ratio of about 5.10%. Therefore, the efficiency penalty is reduced, from 10.31% to 8.67%, with a decreasing ratio of about 15.91%.

5.3 Economic performance

In this section, in order to explore the economic performances of the integrated system, the variation of COE and the COA with the biomass mass mixing ratio (BMMR), the biomass price (BP), the efficiency penalty (EP), and the TPI under different conditions are analyzed. In the sensitivity analysis of the economic performance, the range of change is set from –40% to 40%, the change range is 10% [51].

Figure 8 illustrates the variations of COE and COA with biomass price at different biomass mass mixing ratios when the CO₂ capture rate is set as a constant (90%), and the total plant investment is 685.58 M$. As shown in Fig. 8(a), the COE rises with the increase of biomass price. When the biomass mass mixing ratio is 0, the COE keeps unchanged, because the biomass price has no influence on the COE without mixing and burning. As the biomass mass mixing ratio increases, the impact of the biomass price on COE increases. In addition, the COE at different biomass mass mixing ratios will intersect together with a common biomass price of 3.69 $/GJ, meaning that with the specific biomass prices, the power generation cost of biomass is the same as that of coal.

As shown in Fig. 8(b), the rising tendency of the COA in response to the biomass price is the same as the COE. Without co-firing of biomass and coal, the COA is constant. Compared with the case of 10%, 20%, and 30% mixing ratios, as the biomass mass mixing ratio rises, the impact of biomass price on COA increases. It also can be found that the biomass co-firing unit can significantly improve the COA, thus as the biomass mass mixing ratio increases, the COA decreases.

Figure 9 shows the variation of COE and COA with efficiency penalty and total plant investment at different mixing ratios. For each set of curves, the CO₂ capture rate is set as a constant (90%), and the biomass price is 4.74$/GJ.

As EP or TPI increases, both the COE and COA experience a significant rising. Figs. 9(a) and 9(c) show that with the increasing of the BMMR, the COE has a remarkable rising, when the price of biomass is higher than that of coal. It can be seen from Figs. 9(b) and 9(d) that the increasing of BMMR significantly reduces CO₂ emissions, thus COA will be significantly reduced.

The sensitivity analysis of the economic performance is given in Table 8. As can be seen, the parameters which have effects on the COE are the BMMR, the BP, the EP, and the TPI from small to large; the parameters which have effects on COA are the BP, the EP, the BMMR, and the TPI from small to large.

In this paper, the policy support of the Chinese government for carbon mitigation was not considered. In the future, the COE and COA will likely be further reduced by the new CO₂ reduction subsidies or tax breaks.

6 Conclusions

To achieve zero carbon emission of coal-fired power plants, a promising route is proposed, i.e., the integration of a coal-fired power plant with biomass co-firing and CO₂ capture. Thermodynamic, emission, and economic evaluations are conducted to reveal the advantages of the promising system. The following conclusions can be drawn:

Through the integration of the CO₂ capture technology and a biomass co-firing with a coal-fired power plant, a zero carbon emission system can be obtained. When the CO₂ capture rate is 90% and the biomass mass mixing ratio is 15.40%, the CO₂ emission of the coal-fired power plant can reach zero.

The thermodynamic performance analysis indicates that compared with the reference coal-fired power plant, the net power output of the proposed system decreases from 627.00 MW to 475.74 MW due to the huge energy consumption of the CO₂ capture unit. The net thermal efficiency decreases from 42.74% to 32.43%, meaning an efficiency penalty of 10.31 percentage points, which is lower than that of a normal 600 MW power plant whit CO₂ capture.

The economic analysis suggests that due to the system integration of the proposed system, the total plant investment is increasing from 355.28 M$ to 685.58 M$. The COE and the COA of the proposed system are 80.37 $/MWh and 41.63 $/tCO₂, respectively.

The sensitivity analysis reveals that with the biomass price, the total plant investment, and the efficiency penalty increasing, the COE and the COA have a significant rising. Meanwhile the rising of the biomass mass mixing ratio will lead to the increase of COA and the decrease of COE. Besides, with the energy consumption of the reboiler decreasing from 3.22 GJ/tCO₂ to 2.40 GJ/ tCO₂, the efficiency penalty is reduced to 8.67%.

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