Study on the biomass-based integrated gasification combined cycle with negative CO2 emissions under different temperatures and pressures

Energy 179 (2019) 571e580

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Study on the biomass-based integrated gasification combined cycle with negative CO2 emissions under different temperatures and pressures Yanlei Xiang, Lei Cai*, Yanwen Guan, Wenbin Liu, Tianzhi He, Juan Li School of Environmental Science and Engineering, Huazhong University of Science and Technology, Wuhan, 430074, PR China

a r t i c l e i n f o

a b s t r a c t

Article history: Received 5 March 2019 Received in revised form 15 April 2019 Accepted 2 May 2019 Available online 9 May 2019

To reduce the carbon emissions in power sector, a biomass-based integrated gasification combined cycle (BIGCC) with oxy-fuel combustion is proposed. The syngas generated from biomass gasification is burned under oxy-fuel atmosphere for power generation, and CO2 in the flue gas is captured by merely cooling. Thus, the negative CO2 emissions are realized considering the carbon neutral character of biomass. The effects of gasification temperature and pressure on syngas composition and system performance are investigated. The results show that rising pressure and temperature lead to lower H2 and CO production, while CO2 and CH4 generation are enhanced with higher pressure and lower temperature. The system efficiency increases with the pressure rise, while it fluctuates with the temperature variation. The optimum temperature and pressure of gasification is 1000
C and 3.5 MPa. The corresponding energy and exergy efficiency is 35.41% and 31.21%. The thermodynamic analysis is carried out for each subsystem. The energy loss and exergy destruction is 76.2% and 55.4% for gasifier and 21.8% and 31.3% for HRSG. Considering the unavoidable energy and exergy consumption in gasification, the system optimization can be concentrated on HRSG. The efficient power generation and significant carbon emissions reduction are achieved in the proposed system. © 2019 Elsevier Ltd. All rights reserved.

Keywords: Biomass gasification Combined cycle Negative carbon emissions Energy Exergy

1. Introduction With the development of society, concerns over environmental problems rapidly increase. Global warming is acknowledged as a primary environmental problem as a result of greenhouse gas emissions from human activities [1]. Since the industrial revolution, the demand of electricity has been steadily increasing. Fossil fuel is the most commonly used fuel for power generation, and it results in a huge amount of CO2 emissions [2]. CO2 is a typical greenhouse gas which accounts for 76% of total greenhouse gas emissions [1]. It is predicted that the planet's average temperature will increase 1.8
Ce5.8
C by the end of the twenty-first century if the current trend of CO2 emission levels remains stable [3]. The warming climate is expected to have far-reaching influences on the environment and ecosystem degradation and the sustainable

* Corresponding author. E-mail address: [email protected] (L. Cai). https://doi.org/10.1016/j.energy.2019.05.011 0360-5442/© 2019 Elsevier Ltd. All rights reserved.

development of economy and society [4,5]. To avoid the continue of global warming, it is noted by the Paris Agreement that the temperature increase threshold below 2
C, or even more ambitious 1.5
C. Thus, stronger efforts are needed to meet the requirement, and two approaches are generally used in power generation systems, which are the main sources of CO2 emissions: (1) replace the fossil fuels with renewable energy sources; (2) integrate the Carbon Capture and Storage (CCS) technologies into power plants [6]. Among all the renewable energy sources, biomass is particularly attractive for power generation for its abundant resources, wide distribution, carbon neutral characteristic and great development potential [7,8]. The thermal treatment mode is capable of transforming biomass into valuable energy, and gasification is a promising option [9,10]. Biomass gasification converts organic materials into syngas, and it can be used directly as fuel source for power generation. Among the biomass-to-electricity conversion technologies, biomass-based integrated gasification combined cycle (BIGCC) is a potential method due to its high fuel conversion efficiency and power generation efficiency [11e13]. However, the current BIGCC plant is only in the medium level and there is a lack

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of system analysis. Therefore, some researchers have developed relevant models to study the system performance. Corti and Lombardi [14] built a BIGCC model by means of Aspen Plus, and the performance analysis and life cycle assessment were carried out. Bhattacharya et al. [15] conducted a thermodynamic analysis on a BIGCC plant with supplementary biomass firing. Meanwhile, the optimization of the plant parameters was pointed out to satisfy different technical considerations. Soltani et al. [16] studied a gas turbine combined cycle with gasified biomass external firing, and three sets of operating parameters were considered in a detailed case study. However, the related theoretical analysis is still not sufficient for the large-scale application, and further study on BIGCC system is necessary. During biomass gasification process, the gasifying agent is an important factor for the production of syngas [17e19]. Steam gasification is recognized as one of the most promising technology for hydrogen and high heating value syngas production from solid fuels [20,21]. However, the key challenge is the necessity to provide the heat needed in the gasification process. The potential solution is the oxygen-blown gasification [20]. The heat released from the exothermal oxidation reactions can be utilized, and the autothermal system is realized. Besides, the pressure and temperature are another two key parameters for gasification process. Many researchers have carried out some investigations indicating the effects of these factors on biomass gasification [22e25]. However, there are few studies exploring these effects when biomass gasification is coupled with power plant. CCS technologies are technically feasible methods to significantly reduce CO2 emissions from power generation [26]. Generally, there are three methods for CCS: post-combustion carbon capture, oxy-fuel combustion and pre-combustion carbon capture [27e29]. Sheikh et al. [30] introduced the pre-combustion carbon capture technology into BIGCC system to reduce the CO2 emissions. It was found that the effect of carbon capture level on the total product value was negligible. Carpentieri et al. [31] selected the chemical absorption technology for carbon capture in BIGCC plant, and the results showed great feasibility of this system configuration. Cormos et al. [32] investigated two different carbon capture technologies: pre-combustion capture using a physical solvent and post-combustion capture using a chemical solvent. The results indicated that the pre-combustion carbon capture method was more appropriate than post-combustion capture. In comparison to pre-combustion and post-combustion carbon capture, oxy-fuel combustion could be directly introduced into power plants with low risk inherent [33,34]. Thus, oxy-fuel combustion is considered one of the most potential approaches to capture CO2 in power plants [35]. Nevertheless, few study has covered the oxy-fuel combustion integrated BIGCC system. In this paper, an integrated system of oxy-fuel combustion and BIGCC plant is proposed. To maintain the N2-lean atmosphere throughout the whole process, the steam separated from combustion flue gas and O2 are employed as gasifying agent. The effects of gasification temperature and pressure on the overall performance of the integrated system are investigated, and the optimum operating parameters are identified. Furthermore, the system is evaluated by an energy and exergy based thermodynamic analysis. Different modules of the integrated system were studied respectively to find out where the large energy loss and exergy destruction occur. The results of this work lay a theoretical foundation for the establishment of a similar system. Meanwhile, considering the neutral character of biomass, the proposed BIGCC system can result in negative net carbon emissions and may therefore provide an important technology option for meeting current greenhouse gas stabilization targets.

2. System modelling and thermodynamic method 2.1. Gasification modelling and validation The biomass gasification process was modeled by Aspen Plus. The biomass gasification unit consisted of a downdraft gasifier and a cyclone, which is used to remove particulate, tar and sulphur compounds. The gasification process was divided into four different reaction zones, including decomposition, pyrolysis, combustion and gasification, to match the temperature change inside the gasifier [36e38]. These four zones were characterized by different operating temperatures. The model flow sheet is shown in Fig. 1. The raw material was put into the DECOMPOSITION module to calculate the elemental yield. The temperature was set to 300
C [39]. In this module, the non-conventional solid component is converted to conventional elements, such as O2, H2, S, C, N2 and ash with external FORTRAN code. The product of this module then entered PYROLYSIS block. The chemical equilibrium was assumed in the simulation, solved by the minimization of the Gibbs free energy. The hypothesis was justified due to the high residence time of the downdraft gasifiers [36]. The process was carried out under a temperature of 600
C. The outlet stream of this block was mainly composed of H2, CO, CO2, CH4, H2O, H2S and char [37], and it was sent to COMBUSTION module. The char was partially burnt by O2 in gasifying agents [7,36,37], and the reaction heat was supplied for the endothermic gasification reactions. The temperature was up to 1000
C [36,37]. Subsequently, the reduction process was performed and the unreacted char was assumed to only consist of carbon in the GASIFICATION block, and the temperature was 820
C [40]. The outlet stream proceeded into CYCLONE, where the ash and unreacted char was separated out. Syngas was thus formed. The QMIXER module calculated the thermal balance of these four processes in gasification, and it was assumed that all the blocks worked under isothermal conditions [40]. Different pressures and temperatures are tested in the GASIFICATION block to explore the effects of the two factors on the performance of the system. The present gasification model has been validated against the data in Refs. [40e42] under different conditions. The input parameters and results were displayed in Table 1. Comparing the results in reference and this work, it can be speculated that the gasification model in this work was reasonable and reliable. The current model was employed to predict syngas composition under different gasification conditions. 2.2. Power generation modelling and assumptions The configuration of power generation and carbon capture system is exhibited in Fig. 2. The syngas with a high temperature generated in gasifier entered the Pre-heater to preheat the gasifying agent, which includes H2O and O2. The temperature of syngas dropped and was sent to the compressor, where the pressure rose to combustion level. The pressurized syngas was injected into the combustor and mixed with O2 and recycled CO2 from the flue gas. The combustion gas with a high pressure expanded in the gas turbine to the ambient pressure to generate power. The frame F gas turbine with unit capacity higher than 200 MW was used in this work. The exhaust gas still had a relatively high temperature, and its thermal energy was recovered in a heat recovery steam generator (HRSG). The configuration of steam cycle was shown in Fig. 3. The temperature of outlet stream of HRSG was low enough and the steam was condensed. The splitter 1 was a gas-water separation block (SEP), where the liquid water was separated from the flue gas. The dry flue gas mainly composed of CO2 was sent to carbon

Y. Xiang et al. / Energy 179 (2019) 571e580

573

Fig. 1. Flowsheet of biomass gasification unit.

Table 1 The validation data of the present gasification model. Item

Barisano et al. [40]

Gasification T/
C Gasification P/MPa Equivalence ratio Steam/biomass (kg/kg) Gas composition (%v, dry gas)

810 0.1 0.21 0.4 30e33 28e32 22e27 9e11

H2 CO CO2 CH4

This work

Meng et al. [41]

32.8 29.8 24.3 9.8

775 0.1 0.38 1.13 22.0 25.2 40.5 8.8

This work

Di Marcello et al. [42]

This work

25.3 23.6 38.3 9.4

840 0.13 0.31 1.0 37.0 15.0 42.0 6.0

34.3 18.2 38.9 7.6

Fig. 2. Schematic diagram of the proposed system.

Fig. 3. Configuration of the three-pressure reheat steam cycle [44].

capture process. The first step of carbon capture was pressurization. The CO2-enriched flue gas was compressed to a pressure a little higher than the triple point pressure. Then the pressurized stream went to the pre-cooler, and the temperature decreased. The cooled flow entered the CO2 condenser, and CO2 in the flue gas was condensed into liquid. In the splitter 2, the non-condensable gases, such as N2 and excess O2 were discharged from the top, while the liquid CO2 from the bottom. Subsequently, the liquid CO2 was

divided into two parts. One part was recycled to moderate the combustion temperature, and the other was stored. At this point, the negative CO2 emissions was achieved with a view to the neutral character of biomass. The liquid CO2 for combustion control was firstly pumped in a CO2 pump, and the pressure increased to combustion pressure. Prior to recycling to the combustor, CO2 proceeded to the pre-cooler to provide cold energy to the pressurized flue gas, and the temperature rose to normal temperature.

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Water passed through bottom discharge of splitter 1, and was divided into two streams. One stream was directly drained out, and the other was employed as gasifying agent. The high-concentration O2 was split into two parts. One part was used as combustion oxidant, and the other as gasifying agent. The gasifying agent, H2O and O2 was preheated by hot syngas before entering the gasifier. The temperature of gas turbine exhaust gas exceeded 600
C, which enabled the use of three-pressure reheat HRSG [43]. The layout of steam cycle was displayed in Fig. 3 [44]. The flue gas exhausted from the gas turbine flowed through the high pressure (HP) superheater, the HP evaporator, the medium pressure (MP) superheater, the HP economizer, the LP superheater, the MP evaporator, the MP economizer, the low pressure (LP) evaporator and the LP economizer successively. The exhaust steam of LP turbine was condensed in the condenser. Subsequently, water was pressurized in the LP pump, and then preheated in the LP economizer. Next, the preheated water was split into three streams and pressurized to three different pressures by different feed water pumps. The water streams with different pressures then proceeded to different heat exchangers to be heated to superheated steam. The HP superheated steam expanded in the HP turbine to generate electricity. The exhaust steam of HP turbine was reheated before mixing with the MP superheated steam. Afterwards, the MP steam expanded in the MP turbine, and the outlet stream mixed with the LP superheated steam prior to expanding in the LP turbine. The Aspen Plus software was adopted for simulation of power generation system. The property method, PENG-ROB was selected for the parameter calculation under the design conditions [45]. Some parameter settings were summarized in Table 2. The first and second laws of thermodynamics were employed to study the proposed power plant. the following assumptions were made for the process modelling and simulation [46]: 1. The system reached a steady state and steady flow. 2. The pressure drops in the piping network and the heat transfer losses in the heat exchangers were ignored. 3. The effects of kinetic and potential energies were neglected compared to thermal energy. 4. The ambient temperature and pressure were 15
C and 101.3 kPa.

Exl ¼

X X mi exi  mi exi þ Exq  W

(2)

out

in

where, Enl is the energy loss and Exl is the exergy destruction due to the irreversibility associated with chemical reaction, heat transfer and mixing in a block; mi, hi and exi represents the mass flow rate, specific mass enthalpy and the specific mass exergy of the inlet/ outlet stream; Q is the net heat flow rate of the subsystem and W is the net power generation of the block; Exq denotes the exergy transfer with the heat Q input into the unit, and it can be written as Eq. (3).

Exq ¼ ð1  T0=TÞQ

(3)

The specific mass exergy includes the physical and chemical parts as shown in Eq. (4) [52].

exi ¼ exph þ exch

(4)

where, exph and exch represents the physical and chemical exergy, respectively. The former one can be calculated using Eq. (5) when neglecting the kinetic and the potential exergy changes, while the latter one can be calculated with Eq. (6) [53].

exph ¼ ðh  h0 Þ  T0 ðs  s0 Þ exch ¼

X

ni exch;i þ RT0

X

(5) ni  lnni

(6)

where, h and h0 is the specific enthalpy of a stream under actual and environmental conditions, respectively; s and s0 represents the specific entropy of a stream at actual and environmental conditions, respectively; ni denotes the molar fraction of the gas species “i” in the mixture; exch, i is the specific chemical exergy of component “i”, and it is listed in Table 3 [54,55]; R is the gas constant, which is 8.314 J/(mol K). The energy efficiency and the exergy efficiency of the subsystem can be calculated using Eqs. (7) and (8), respectively [56].



len ¼ Enout;sub Enin;sub 2.3. Energy and exergy analysis



For an open system operating at a steady state, the energy and exergy balance can be expressed as Eqs. (1) and (2), respectively [51].

Enl ¼

X X mi hi  mi hi þ Q  W in

out

(7)

(1)

lex ¼ Exout;sub Exin;sub

(8)

where, Enin, sub and Enout, sub represents the total energy input and output of a subsystem, respectively; Exin, sub and Exout, sub denotes the total exergy input and output of a subsystem, respectively. The overall energy efficiency is defined as the ratio of the net power generation to the lower heating value of the biomass, as written in Eq. (9).

Table 2 Parameter settings. Biomass Pre-heater Gas turbine

Steam turbine CO2 capture Pump Compressor

Feed stream flow rate (kg/s) Hot-inlet/cold-outlet temperature difference (
C) Combustion efficiency (%) Excess O2 beyond the stoichiometric ratio (%) Combustion temperature (
C) Combustion pressure (MPa) Isentropic efficiency HT/MT/LT Inlet pressure HT/MT/LT (MPa) Carbon capture pressure (MPa) Condensation temperature (
C) Efficiency (%) Efficiency (%)

30.0 5.0 99.0 [46] 2.0 [47] 1400.0 [48] 3.5 [49] 0.92/0.84/0.90 [50] 12.5/1.9/0.37 [49] 0.7 55 80.0 [47] 88.0 [47]

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Table 3 The standard chemical exergy of the components [54,55]. Component

Standard chemical exergy (kJ/kmol)

Component

Standard chemical exergy (kJ/kmol)

H2O (liquid) H2O (vapor) CO CO2

3.12 11.71 275.43 20.14

O2 N2 H2 CH4

3.97 0.69 238.49 836.51

hen ¼

Wnet  100% mbiomass LHV

(9)

where, mbiomass is the mass flow rate of biomass; LHV denotes the lower heating value of biomass; Wnet is the net power output of the integrated system, and it can be calculated with Eq. (10).

Wnet ¼ WGT þ WST  WO2  Wcom  Wc

(10)

where, WGT and WST represents the power generation of gas turbine and steam turbine, respectively; WO2 is the power consumption for O2 production, which is 812 kJ/kg [47]; Wcom is the total compression work consumed in the system; Wc is defined as the power consumption of cold energy required for CO2 condensation, and the cold energy efficiency ratio is assumed to be 2.1 [57]. The global exergy efficiency is defined as follows:

hex ¼

Wnet  100% mbiomass exbiomass

(11) Fig. 4. Variation of LHV of syngas with S/B under different gasification pressures.

where, exbiomass denotes the specific mass exergy of biomass, which can be calculated with Eq. (12) [58].

exbiomass ¼ 1:047HHV

3.1. Effects of gasification temperature and pressure on system performance

(12)

3. Results and discussion The proximate and ultimate analyses of biomass used in this part are displayed in Table 4 [40]. In steam-included biomass gasification, steam to biomass ratio (S/B) is an important parameter. Considering that the amount of syngas varied with different steam input, the LHV of syngas of per kilogram or cubic meter is not able to illustrate the total LHV of syngas directly used as fuel. Thus, the total LHV of syngas under different S/Bs and gasification pressures are studied, and the results are displayed in Fig. 4. The O2 input into the gasifier is adjusted under different conditions to meet the selfheating requirement. It can be observed that the increase of S/B results in a rise in the LHV of the generated syngas under different gasification pressures. However, the higher S/B value means higher concentration of steam in the flue gas. It was found that the optimum steam mass fraction in the flue gas is 0.3, and the efficiency of conventional combined cycle will decline with the further increase [59]. In this way, the S/B is set to 0.5 to ensure the optimal steam mass fraction in the flue gas in this work.

Fig. 5 depicts the effects of different gasification temperatures and pressures on the syngas composition. As seen from Fig. 5(a), the mole fraction of H2 in the syngas drops with the increase of pressure under different gasification temperatures. When the temperature is lower than 1000
C, the mole fraction of H2 shows an obvious decline with pressure ranging from 0.1 MPa to 0.5 MPa. As the pressure further increases, the H2 molar fraction decreases as well, but the curves become smooth, especially under relatively low temperatures. It is almost stable with pressure varying from 1.5 to 3.5 MPa and temperature of 600
C and 700
C. When the temperature is 1000
C, the H2 mole fraction and pressure are approximately linearly dependent. Besides, the molar fraction of H2 generally increases with a rising temperature, while the condition under 0.1 MPa is an exception. It grows at first but drops when the temperature exceeds 900
C with the pressure constant of 0.1 MPa, which is similar to the results obtained by Ramzan et al. [60] and Tan and Zhong [61]. Under higher gasification pressure, the H2 mole fraction shows a significant rise as the temperature increases from 600
C to 1000
C. The molar fraction of CO exhibits a similar trend with that of H2. The difference lies in the variation with the pressure of 0.1 MPa. As can be observed in Fig. 5(b), the CO molar fraction continues to increase with the temperature rise. The

Table 4 Biomass characteristics [40]. Proximate analysis, dry basis (wt%)

Ultimate analysis, dry basis (wt%)

Fixed carbon Volatile matter Ash

18.2 80.6 1.2

Lower heating value (LHV) (MJ/kg)

18.0

C H O N Ash

47.9 6.3 44.3 0.3 1.2

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Fig. 5. Syngas composition with various gasification temperatures and pressures.

variation tendencies of CO2 and CH4 molar fraction with different pressures at various temperatures are similar, which increases with the augment of pressure but decline with the increase of temperature. Meanwhile, the variation against the pressure is more evident when the pressure is lower than 0.5 MPa. The growth becomes slower under higher gasification pressure. With respect to the effect of temperature, higher temperature results in falling generation of CO2 and CH4. Note that the dependent variables are very close at 900
C and 1000 when the pressure stays constant of 0.1 MPa. It can be concluded that the syngas composition is more sensitive to pressure variation under relatively low pressures. As for temperature, when it exceeds 900
C, the syngas composition shows little difference with the temperature rise. Furthermore, the variation of molar fraction of the examined components is approximately proportional to the change of pressure at high temperature, e.g. 1000
C. In summary, higher pressure decreases H2 and CO concentrations and increases CO2 and CH4 concentra^telier principle. Higher temtions, which is consistent with Le Cha perature favors the production of CO, but reduces those of CO2 and CH4 according to the gasifier chemistry [60]. With regards to H2 production, it increases and reaches a peak before dropping with the rise of temperature. In the proposed system, the syngas compression is required when the gasification pressure is lower than that of combustion, which is constant of 3.5 MPa. Meanwhile, different gasifying temperatures result in different inlet temperatures of the syngas compressor, which has a further influence on compression. Thus, the gasifying pressure and temperature has important roles for syngas compression work. The relationship between gasification pressure and the compression work of syngas at various temperatures is shown in Fig. 6. Higher gasification temperature and lower pressure result in a compression work rise. Note that the curve gradually becomes smooth with the increase of pressure. To maintain a constant combustion temperature, which is set to

1400
C considering the maximum temperature that the state-ofthe-art frame F gas turbines could withstand [62e65], different amounts of recycled CO2 are required under different gasification conditions. Considering the same biomass material, S/B, inlet temperature and pressure of gas turbine, the recycled CO2 flow rate is the only factor that affects the gas turbine and steam turbine power generation. In this way, the power generation of gas turbine and steam turbine share a similar variation tendency theoretically. Fig. 7 shows the power production of gas turbine and steam turbine under different gasification pressures and temperatures, respectively. The outputs of gas turbine as well as steam turbine decrease with the pressure rise at a given temperature. As aforementioned, the sharp variation takes place at relatively low pressures.

Fig. 6. Syngas temperatures.

compression work

versus

gasification

pressure

at

different

Y. Xiang et al. / Energy 179 (2019) 571e580

577

Fig. 7. Power generation versus gasification pressure and temperature.

Generally, the increasing temperature leads to a rising power of gas turbine and steam turbine, however some differences occur when the temperature is relatively high. As can be seen from Fig. 7, the turbine power generation exhibits a minimum value at a pressure of 3.0 MPa when the temperature reaches up to 900
C. As the pressure further increases, the power generations of gas turbine and steam turbine tend to rise. When the pressure is 3.0 MPa, the highest power output is obtained at 800
C. The fluctuations of power output with temperature under relatively high pressures are resulted from gasification process, where different amounts of O2 are required and the syngas with different composition and heating value is produced. Meanwhile, it is evident that the system power production is less affected by temperature under higher pressure. The net energy and exergy efficiencies of the proposed system under different gasification conditions are shown in Fig. 8. It can be seen that the system efficiency drops with the temperature rise when the gasification pressure is lower than 1.5 MPa, which indicates the dominant role of syngas compression work. The energy efficiencies and exergy efficiencies at various temperatures show little difference when the pressure is 1.5 MPa. At this point, the effect of syngas compression is counterbalanced by turbine generation. If the pressure gets higher, the efficiency fluctuates with the temperature change. To be exactly, the optimum temperature is 1000
C, 800
C, 800
C and 1000
C when the pressure is 2.0 MPa, 2.5 MPa, 3.0 MPa and 3.5 MPa, respectively. The efficiency monotonically increases with the increase of pressure at relatively low temperatures. As the temperature reaches 900
C or even higher, the increasing tendency of efficiency with rising pressure is corrupted at 3.0 MPa, where the efficiency shows a decrease, and it is

consistent with the trend displayed in Fig. 7. On the whole, the highest energy and exergy efficiencies are acquired at 1000
C and 3.5 MPa, which are 35.41% and 31.21%, respectively, and the carbon capture rate reaches up to 96.7%. The comparisons among different BIGCC systems with CCS in respect to different CCS technologies, energy efficiency and carbon capture rate are illustrated in Table 5. The energy efficiency of the proposed system is 35.4%, slightly lower than that in Ref. [32], which is significantly higher than that of other systems. Great benefit of the proposed system can be observed considering the carbon capture rate. Higher carbon capture rate means higher power consumption. It's worth noting that the highest carbon capture rate is achieved in this work with remarkable energy efficiency. It can be concluded that the oxy-fuel combustion integrated BIGCC is of great significance for efficient power generation and carbon emissions reduction.

3.2. Energy and exergy analysis results The energy and exergy analysis is performed to evaluate the system performance, and the system with gasifying temperature of 1000
C and pressure of 3.5 MPa is used as the benchmark condition. The thermodynamic data of streams in the proposed system is illustrated in Table 6 and Table 7. The integrated system is separated into four subsystems: gasifier, gas turbine, HRSG-steam turbine (HRSG-ST) and carbon capture. The performance of each subsystem is studied and the results are demonstrated in Fig. 9. The energy efficiency of gasifier, gas turbine, HRSG-ST and carbon capture is 59.1%, 95.7%, 35.4% and 99.7%, respectively, while the exergy

Fig. 8. Energy and exergy efficiencies versus gasification pressure and temperature.

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Table 5 Comparison among different BIGCC systems with CCS. Items

FB-Wood [59]

BIGCC in Ref. [34]

BIGCC-R in Ref. [34]

Case 1 in Ref. [32]

Case 2 in Ref. [32]

Proposed system

CCS method Energy efficiency Carbon capture rate

Pre-combustion 28.6% 84.5%

Pre-combustion 28.0% 44.0%

Pre-combustion 25.0% 55.0%

Pre-combustion 35.8% 92.8%

Post-combustion 34.6% 90.4%

Oxy-fuel combustion 35.4% 96.7%

Table 6 Thermodynamic data of the working fluids in gas turbine Brayton cycle (Fig. 2). State

Fluid

T/
C

P/MPa

Flow/(kmol/h)

Molar composition/% H2O

CO

CO2

H2

CH4

O2

N2

1 2 4 5 6 7 9 10 11 12 13 14 15 16 17 18 19 20 21

Syngas Syngas Flue gas Flue gas Flue gas Water Water O2 O2þsteam CO2-rich gas CO2-rich gas CO2-rich gas CO2-rich gas CO2-rich gas CO2-rich gas CO2-rich gas CO2-rich gas O2 O2

1000 522 1400 686 68.4 25 25 25 995 25 194.3 48.9 55 55 55 53.3 189.3 25 422.4

3.5 3.5 3.5 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.7 0.7 0.7 0.7 0.7 3.5 3.5 0.1 0.1

1328.5 1328.5 3083.7 3083.7 3083.7 787.3 199.8 347.0 546.8 2296.4 2296.4 2296.4 2296.4 2179.2 1582.0 1582.0 1582.0 380 380

38.2 38.2 27.5 27.5 27.5 100 100 e 36.5 2.6 2.6 2.6 2.6 2.8 2.8 2.8 2.8 e e

20.0 20.0 e e e e e e e e e e e e e e e e e

23.7 23.7 70.8 70.8 70.8 e e e e 95.1 95.1 95.1 95.1 96.9 96.9 96.9 96.9 e e

11.2 11.2 e e e e e e e e e e e e e e e e e

5.5 5.5 e e e e e e e e e e e e e e e e e

e e 0.3 0.3 0.3 e e 95.0 60.3 0.5 0.5 0.5 0.5 0.1 0.1 0.1 0.1 95.0 95.0

1.4 1.4 1.3 1.3 1.3 e e 5.0 3.2 1.8 1.8 1.8 1.8 0.2 0.2 0.2 0.2 5.0 5.0

Table 7 Thermodynamic data of the working fluids in steam cycle (Fig. 3). State

T/
C

P/MPa

Flow/(kmol/h)

State

T/
C

P/MPa

Flow/(kmol/h)

1 2 3 4 5 6 7 8 9 10

30 100 100 142 250 101 180 210 350 101

0.37 0.37 0.37 0.37 0.37 1.9 1.9 1.9 1.9 12.5

1360 1360 544 544 544 136 136 136 136 680

11 12 13 14 15 16 17 18 19

300 327 600 287 297 550 296 278 45

12.5 12.5 12.5 1.9 1.9 1.9 0.37 0.37 0.08

680 680 680 680 816 816 816 1360 1360

consumed to maintain the operation of gasifier. The lowest efficiency occurs in the HRSG-ST. It is comprehensible because of the low grade property of gas turbine exhaust heat. The steam Rankin cycle is employed in this work to utilize the waste heat. Other methods could be sought for the more efficient utilization. The high efficiencies of gas turbine and carbon capture process show the outstanding performance of oxy-fuel combustion, which further indicate the significance of the study on efficient power generation and carbon emissions reduction. The energy loss and the exergy destruction of each subsystem is defined as the percentage of the energy and exergy loss to those of the integrated system. As can be observed from Fig. 9(b), the energy loss of gasifier, gas turbine,

Fig. 9. Thermodynamic analysis results.

efficiency is 61.5%, 90.3%, 28.1% and 95.9%, respectively according to Fig. 9(a). The efficiency of gasifier is relatively low due to the constraint of self-heating requirement. A large amount of energy is

HRSG-ST and carbon capture process is 76.2%, 1.9%, 21.8% and 0.1%, respectively, and the corresponding exergy destruction rate is 55.4%, 4.7%, 31.3% and 8.6%, respectively. The most energy and

Y. Xiang et al. / Energy 179 (2019) 571e580

exergy losses are found in the gasifier, followed by HRSG-ST. Unavoidable exergy destruction takes place in the gasifier due to the irreversible conversion of biomass into syngas. Consequently, the optimization should be focused on gas turbine waste heat utilization.

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4. Conclusions

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An integrated system of oxy-fuel combustion and BIGCC plant is proposed in this work, and the efficient power generation and negative net carbon emissions are realized. The effects of gasifying temperature and pressure on the syngas composition and system performance are investigated. Besides, the thermodynamic analysis of each subsystem is carried out to evaluate the system. The main findings are summarized as follows:

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(1) The overall energy and exergy efficiencies generally increase with the pressure rise. When the gasifying pressure equals to the combustion pressure, the efficiency reaches the maximum value. It is worth noting that the influence of gasification pressure is more obvious under relatively low pressures. (2) The optimum gasification temperature varies with different pressures. From the global aspect, the highest energy and exergy efficiency, which is 35.41% and 31.21%, respectively, is obtained at 1000
C and 3.5 MPa with 96.7% of the total CO2 captured. (3) The most energy loss and exergy destruction occur in the gasifier, which is 76.2% and 55.4%, respectively. HRSG-ST ranks second, and the energy loss and exergy destruction rate is 21.8% and 31.3%, respectively. Considering the unavoidable energy consumption because of the self-heating requirement and the exergy destruction due to the chemical irreversibility in gasification process, the improvement should be focused on HRSG.

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Acknowledgment This work was supported by the Fundamental Research Funds for the Central Universities (2017KFYXJJ214).

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