Novel post combustion CO2 capture in the coal-fired power plant employing a transcritical CO2 power generation and low temperature steam upgraded by an absorption heat transformer

Energy Conversion and Management 207 (2020) 112542

Contents lists available at ScienceDirect

Energy Conversion and Management journal homepage: www.elsevier.com/locate/enconman

Novel post combustion CO2 capture in the coal-fired power plant employing a transcritical CO2 power generation and low temperature steam upgraded by an absorption heat transformer

T

A.H. Mosaffaa,b, , L. Garousi Farshic ⁎

a

Department of Mechanical Engineering, Azarbaijan Shahid Madani University, Tabriz, Iran Research Institute of Applied Power System Studies, Azarbaijan Shahid Madani University, Tabriz, Iran c Faculty of Mechanical Engineering, University of Tabriz, Iran b

ARTICLE INFO

ABSTRACT

Keywords: CO2 capture unit Absorption heat transformer Transcritical CO2 power generation Coal-fired power plant Heat recovery

This paper deals with a double effect heat transformer-aided carbon dioxide capture unit with transcritical carbon dioxide power generation for a coal-fired steam power plant. In the proposed system a double absorption heat transformer is used to upgrade low energy level steam into high-level and drive carbon dioxide capture unit. Also, a transcritical carbon dioxide power generation that is utilized captured carbon dioxide to generate power and compensate a portion of the required electrical energy of the carbon dioxide capture unit. This system avoids extracting high-grade temperature steam extracted from high-pressure stage of steam turbine and hence overall thermal efficiency of power plant increases compared to the reference systems. Comprehensive thermodynamic and economic evaluations are conducted to reveal the feasibility of the presented system. The results show that the evaporator temperature has the highest effect on net power output. An increase of 10 K in the evaporator temperature from 80 °C to 90 °C, leads to a reduction of 4.9% in generated power. However, a 50% increase in carbon dioxide capture rate from 40% to 90%, leads to a rise of 23.4% in the exergy destruction rate. Moreover, the payback period is approximately 4 years and 6 months.

1. Introduction Recently, the environmental impact is receiving considerable attention as an important factor in the design and evaluating energy systems. The over utilization of fossil fuels can cause a series of ecological problems such as global temperature increase. Therefore, the growth trend of the carbon dioxide emission that has over 50% of the share in greenhouse gases should be changed. The carbon capture process as a CO2 mitigation strategy can play a crucial role in diminishing the growth trend of CO2 emission [1]. Different technology to capture the generated CO2 in industrial processes such as steel [2,3], cement production [4,5] and power plant [6–8] has been investigated by researchers. Aouini et al. [9] presented an experimental study to show the technical feasibility of a CO2 capture unit (CCU) using MonoEthanol-Amine (MEA) solvent fed by waste incinerator flue gas. Spallina et al. [10] assessed techno-economically of different technologies for producing hydrogen from natural gas by using CCU. They indicate that by employing a MEA absorption solvent CCU at the reformer gas stack, the overall CO2 capture efficiencies achieves 85%. Patino et al.

⁎

[11] proposed an integrated cycle, including a natural gas-fueled power plant with a post-combustion CCU and carbon dioxide compression. Their proposed system reduces the mass flow rate of steam in the stripper reboiler by 65.5 kg s−1 and increases the thermal efficiency to 51%. Pan et al. [12] introduced a combined power generation system, including a Kalina cycle, an organic Rankine cycle (ORC) with liquefied natural gas (LNG) cryogenic energy recovering and a CCU. Their system net power output, energy efficiency and quantity of the captured CO2 were 395 kW, 53% and 0.6 ton (ton LNG)−1, respectively, when the system operates at optimum condition. Jiang et al. [13] evaluated thermoeconomically an adsorption-based CCU using activated carbon for a natural gas combined cycle. The comparison results of their proposed system performance with a commercial one show that although the regeneration heat of their system is much higher than those using MEA, the system using activated carbon requires low-level temperature steam to desorb CO2, which can be extracted from the low pressure turbine. Patino and Rivera [14] analyzed a natural gas combined cycle power plant using a CCU and an ORC from environmental and energy points of view. In this case, a stream of hot water is used to evaporate

Corresponding author at: Department of Mechanical Engineering, Azarbaijan Shahid Madani University, Tabriz, Iran. E-mail address: [email protected] (A.H. Mosaffa).

https://doi.org/10.1016/j.enconman.2020.112542 Received 11 November 2019; Received in revised form 24 January 2020; Accepted 25 January 2020 0196-8904/ © 2020 Elsevier Ltd. All rights reserved.

Energy Conversion and Management 207 (2020) 112542

A.H. Mosaffa and L.G. Farshi

Nomenclature a A celectical C e 0 e ĖD eff h i ṁ M n P Q R s T U Ẇ W y X

abs con ev gc gen s turb vg

activity heat transfer area (m2) unit cost of electricity ($ kWh−1) cost ($) specific exergy (kJ kg−1) standard chemical exergy (kJ kmol−1) exergy destruction rate (kW) effectiveness specific enthalpy (kJ kg−1) effective discount rate mass flow rate (kg s−1) molecular mass (kg kmol−1) system lifetime (year) pressure (kPa) heat transfer rate (kW) universal gas constant (kJ kmol−1 K−1) specific entropy (kJ kg−1 K−1) temperature (°C) overall heat transfer coefficient (kW m−2 K−1) power (kW) work (kWh) mole fraction LiBr concentration

Abbreviations AES AF BOS CCU CEPCI CRF DAHT IIC LCOE LMTD MEA NPV O&M SHE SPB

Subscripts 0

absorber condenser evaporator gas cooler generator thermal source turbine vapor generator

Annuity Economic Saving ($ year−1) Annuity Factor Balance Of the System ($) CO2 Capture Unit Chemical Engineering Plant Cost Index Capital Recovery Factor Double Effect Absorption Heat Transformer Initial Investment Cost ($) Levelized Cost Of Electricity ($ kWh−1) Logarithmic Mean Temperature Difference (K) Mono-Ethanol-Amine Net Present Value ($) Operation And Maintenance ($) Solution Heat Exchanger Simple Pay Back (year)

ambient

the ORC working fluid extracted from the low pressure turbine. Their proposed system generates a power output of 381.2 MW with capture of 42.5 kg s−1 of CO2. Bao et al. [15] analyzed a natural gas combined cycle integrating a MEA-based post-combustion CO2 capture, LNG cold energy and two-stage condensation Rankine cycle. The results showed that their proposed system could effectively improve the total efficiency of 2.5% and reduce the energy penalty of 7.9%. Due to the well-developed technologies and low prices, coal has been known as a convenient raw material for power generation in the world [16]. As coal-fired power plants produce up to 40% of total CO2 emissions, employing CCUs for such power plants can diminish CO2 emissions as an indirect strategy. Bin et al. [17] studied economically and experimentally on an industrial-scale CCU plant. The value efficiency of the CO2 capture was obtained by about 85% and also, the steam consumption has the most significant share in the total cost for more than 50%. Zhao et al. [18] proposed an integrated system of solar ORC with a CCU using MEA. Their proposed system can generate power of 2238 GWh with a CO2 emission reduction of 1.98 × 106 tons in a year. Liu et al. [19] used a CCU in a coal-to-methanol plant combined with an ORC. They showed that power generated by ORC is around 4.8 MW, and the payback period of their proposed system is 2.7 years. Zhai et al. [20] proposed three layouts of a solar energy-assisted coalfired power plant with a post-combustion CCU. The results showed that employing a solar energy-assisted system can improve the income of electricity and thermal efficiency compared to the basic coal-fired power plant with CCU. However, the costs of generated electricity and carbon dioxide avoidance decrease and the income in unit investment increases. Wang et al. [21] proposed integrating geothermal energy into a coal-fired power plant with post-combustion CCU and compared the proposed system performance with solar assisted carbon capture plant. The results showed that the generated power of their proposed system is higher than the solar assisted one. An active CCU based on a molten carbonate fuel cell has been studied by Carapellucci et al. [22]. The results showed that integrating the molten carbonate fuel cell

integration with the coal-fired power plant leads to a negative SPECCA index as an environmental performance index. The SPECCA index is the consumed specific energy for carbon dioxide avoided. Olumayegun et al. [23] presented a combined system including supercritical CO2 cycle (instead of coal-fired steam Rankine cycle power plant), coal-fired furnace and a post-combustion CCU. They concluded that with CCU, the efficiency penalty of their proposed system is 2.55% more than that of the supercritical carbon dioxide Rankine power plant. In contrast, the net efficiency of their system is up to 1.31% more than that of the supercritical carbon dioxide Rankine power plant with post-combustion carbon dioxide capture. In a CCU of a coal-fired steam power plant, the energy level mismatching between the CO2 regeneration process and extracted steam from the turbine leads to the considerable exergy destruction. Wang et al. [24] presented a CCU driven by an absorption heat transformer (AHT) to upgrade low-level temperature extracted steam from the turbine into high-level temperature energy. By matching the temperatures in the CO2 regeneration process, the total exergy destruction in the carbon dioxide separation process and steam condensation reduce by 49.5%. Zhang et al. [25] proposed an AHT-aided and CCU using a flash evaporator to diminish the heat consumption of carbon dioxide capture processes. Their proposed system could reduce heat consumption by 100 MJ (ton CO2)−1 and corresponding energy saving was 2.62%. Also, they showed that the payback period of the proposed system is 2.4 years. The CO2 capture process needs considerable electrical energy. For example, the required electrical energy for the CCU of a 350 MW coalfired supercritical Rankine power plant is about 103 MWel [26]. Therefore, the thermal efficiency drops up to 10%. In order to diminish the unfavorable effect of CCU on the thermal efficiency of a coal-fired power plant, a novel integration system is introduced in this paper. To the best of the authors’ knowledge, employing an integrated power generation subsystem to partly cover the aforementioned electrical energy demand has not been reported. The main novelty of the 2

Energy Conversion and Management 207 (2020) 112542

A.H. Mosaffa and L.G. Farshi

proposed system lies in the utilization of a transcritical CO2 power generation system, which recovers the heat of the extracted steam from the coal-fired power plants. This system used high pressure liquid captured CO2 as the working fluid and its power output is employed to partly cover the electrical energy demand of CCU. Moreover, to upgrade low-level thermal energy of flue gas to a high-level temperature required for regenerating of rich solvent in CCU reboiler, the proposed system is adopted to a double effect absorption heat transformer (DAHT). The evaporator of the DAHT is used to partly reject the heat from the transcritical CO2 power generation system. The main objective of this study is to conduct a comprehensive thermoeconomic evaluation to investigate the feasibility of the proposed system from both thermodynamic and economic points of view and the effect of different operating parameters on the system performance.

The CO2-rich solvent is extracted from the bottom of the absorber column and is pumped to the stripper after heating through a heat exchanger. In the stripper column, the CO2 is stripped and the rich solvent is regenerated. The joint reboiler at the bottom of the stripper column evaporates the solution. The required temperature for rich solvent regeneration is about 115 °C–120 °C [24]. For a coal-fired steam power plant, a feasible and traditional way to supply the regeneration thermal energy is extracting steam from the steam turbine. For a 660 MW coal-fired steam power plant, the practical and appropriate position for extracting the steam is from the fifth stage turbine where the steam pressure and temperature are 418 kPa and 257 °C, respectively [25]. But the temperature of extracted superheated steam is significantly higher than the stable operating temperature of MEA. Therefore, extracted steam (point 31) is first introduced into the vapor generator to run transcritical CO2 power generation and regulate its temperature to prevent the decomposition of the MEA. A part of the saturated vapor exiting vapor generator (point 32) flows through the DAHT absorber to upgrade its temperature. It then enters to the reboiler to heat and regenerate the MEA (point 33). After the regeneration process of the MEA in the reboiler, the condensed steam in the liquid state (point 34) is pumped to the deaerator. The captured CO2 from the separator is compressed through a multi-stage compression system to a supercritical condition of 9.13 MPa (point 3).

2. System description Fig. 1 illustrates the schematic of the proposed post-subsystem comprises a CO2 capture unit, a transcritical CO2 power generation system and a double effect absorption heat transformer. 2.1. CO2 capture unit (CCU) In the CCU, the flue gas from the coal-fired power plant is compressed after cooling (process 1–2) and desulfurization process. Then the flue gas stream is cooled before sending it to the bottom of an absorber column. In the top of the absorber column, the stream contacts the counter with a lean solvent. During the chemical reaction process, the carbon dioxide in the flue gas is captured by the lean solvent and clean flue gas (with low CO2 content) is depleted into the atmosphere.

2.2. Transcritical carbon dioxide power generation system The compressed liquid carbon dioxide from the CCU (point 3) is pumped to a high–pressure level (point 4) and heated by a portion of rejected heat from DAHT absorber (point 5) before mixing another high pressure stream of CO2 (point 15). Then mixed stream (point 6)

Fig. 1. Schematic diagram of the DAHT-aided CCU with transcritical CO2 power generation system. 3

Energy Conversion and Management 207 (2020) 112542

A.H. Mosaffa and L.G. Farshi

introduced into the vapor generator to absorb heat from the extracted stream. The supercritical CO2 with high pressure and temperature (point 7) enters the turbine to expand and hence to produce power. The turbine exhaust (point 8) is cooled by DAHT evaporator (point 9) and gas cooler (point 10), respectively and then as the primary flow enters the nozzle of the ejector. The primary flow with high velocity and high vacuum at the nozzle outlet entrains the secondary flow from the separator (point 12). Then the mixed stream is decelerated in the ejector diffuser (point 11). The exited carbon dioxide from the ejector flows through the throttle valve and expands into a two-phase flow. Then the saturated vapor (point 12) and saturated liquid are separated through a separator. A portion of the saturated liquid of CO2 from the separator is pumped (point 14) to supercritical state (point 15) and mixed with stream 6. In contrast, another portion of saturated liquid of CO2 (point 13) is split for transportation.

for each component with inlet and outlet streams, heat transfer and work interactions are respectively as follows:

m inlet

m=0

(1)

outlet

Q

W =

mh outlet

mh

(2)

inlet

Moreover, an exergy balance could be applied to each component to evaluate the exergy destruction rate, ĖD, as follows:

me + Q (1

T0/ Ts ) =

inlet

me + W + ED

(3)

outlet

where e and Ts are the total specific exergy and thermal source temperature, respectively. The total specific exergy of a stream includes physical and chemical exergies. Physical exergy is calculated as follows:

2.3. Double effect absorption heat transformer (DAHT)

ephysical = (h

h 0)

T0 (s

(4)

s0 )

The chemical exergy of a stream does not change from inlet to outlet in each component except in absorber, absorber/evaporator and generator of DAHT. Therefore, the changes of chemical exergy are just taken into account for these components in the simulation (see Section 3.3).

The required heat to regenerate the absorbent (LiBr) in the generator is supplied by flue gas exiting the coal-fired steam power plant (point 1). The superheated refrigerant (water, point 22) is condensed to saturated liquid (point 23) through the condenser where heat is rejected. The saturated liquid of refrigerant is split into two streams. One of them is pumped into the evaporator (point 26) to evaporate the refrigerant (point 27) with an intermediate temperature and pressure. The other one is pumped at high pressure (point 24) and evaporates inside the tubes of the absorber/evaporator (point 25) before entering the absorber where it is absorbed at a high temperature by the strong solution from the generator (point 21). In this process, the delivered heat is rejected to saturated steam (point 32) to upgrade its temperature to the value required by the MEA regeneration. The refrigerant vapor (from the tube side of the absorber–evaporator) is fed to the absorber. The diluted solution from absorber (point 16) is fed to the generator, successively through the solution heat exchanger (SHE) 1 (point 17) and a throttle valve. The solution exiting the generator (point 19) is pumped to absorber pressure (point 20) and then is divided into two streams. One of them flows to absorber to the absorb the refrigerant through the SHE 1, and the other one is fed to the absorber/evaporator successively through the SHE 2 (point 17) and a throttle valve (point 28) to absorb the refrigerant vapor exiting the evaporator. The heat required to evaporate the refrigerant inside the tubes (process 24–25) is delivered by the absorption process in absorber/evaporator and outside the tubes. The week solution from the absorber/evaporator (point 29) is fed to the generator successively through the SHE 2 (point 30) and a throttle valve.

3.1. CCU evaluation The selected CCU uses MEA as a solvent in a mass concentration of 30%. CO2 capture rate of considered CCU is 90% and the heat requirement for MEA regeneration is about 3.0 GJth per ton of CO2 [24]. The typical composition of the flue gas is as follows [27]: H2O: 23 (vol.% wet), CO2: 14.5 (vol.% dry), O2: 6.5 (vol.% dry), SO2: 200 (wet ppm volume) and NOx: 250 (wet ppm volume). For a 660 MW supercritical coal-fired steam power plant, the mass flow rate of flue gas is 80 kg s−1 [25]. It is also assumed that the flue gas enters CCU with a temperature of 130 °C. 3.2. Transcritical CO2 power generation system evaluation Due to the considering losses of the stream inside the turbine and pumps, the isentropic efficiencies of 80% and 70% for turbine and pumps, respectively [28]. In this work, an EES program based on the constant-pressure mixing model is developed to simulate and evaluate ejector performance. This model is widely used for the ejector simulation and has been described by the authors in Ref [29] in detail. The thermodynamic parameters of the transcritical CO2 power generation system are listed in Table 1.

3. Modelling and analysis A comprehensive thermoeconomic model for the various system equipment as well as the entire system, is developed and executed using Engineering Equation Solver (EES) program. Referring to the following simplifying assumptions, a generic methodology is proposed to evaluate technical feasibility based on a 660 MW supercritical coal-fired steam power plant:

Table 1 Operating conditions of transcritical CO2 power generation system.

• The conditions of the reference environmental state are 20 °C and 101.3 kPa, respectively. • Steady-state condition and thermodynamic equilibrium are considered for all components. • The changes in kinetic and potential energies and exergies are neglected. • Pressure drop through the components and in the connection pipes are considered negligible. • The heat losses of components to the environment are negligible.

Parameters

Value

Mass flow rate of the extracted steam, m31 (kPa) Temperature of the extracted steam, T31 (°C) Pressure of the extracted steam, P31 (kPa) CO2 inlet temperature of turbine, T6 (°C) CO2 inlet pressure of turbine, P6 (MPa) CO2 outlet pressure of turbine, P8 (MPa) CO2 outlet temperature of gas cooler, T10 (°C) Back pressure of ejector, P11 (MPa) Pressure of separator, P12 (MPa) Minimum temperature difference of evaporator (°C) Temperature decline of cooling water through the gas cooler (°C) Overall heat transfer coefficient of gas cooler, Ugc (kW m−2 K−1)

61.11 [25] 257 [25] 418 [25] 200 21 9 [28] 40 [28] 7.9 [28] 6.9 [28] 10 10 0.3 [29]

Overall heat transfer coefficient of vapor generator, Uvg (kW m−2 K−1)

The general forms of the mass and energy conservation equations 4

0.3 [29]

Energy Conversion and Management 207 (2020) 112542

A.H. Mosaffa and L.G. Farshi

Table 2 Operating conditions of DAHT [36].

Table 4 Used data in economic analysis [24,29].

Parameters

Value

Parameters

Values

Evaporator temperature, Tev (°C) Absorber temperature, Tabs (°C) Generator temperature, Tgen (°C)

85 155 85

Effective discount rate, i (%) System life time, n (year) Unit electricity cost, celectrical ($ kWh−1) Operational hours in a year (h) Balance of the system, BOS ($) Operating and maintenance cost, O&M ($) LCOEreference ($ MWh−1) Cost of reference plant without CCU ($ kW−1)

0.5 30 0.12 8760 20% of total initial capital cost 1% of total initial capital cost 43.55 2162.8

Overall heat transfer coefficient of vapor generator, Uabs (kW m−2 K−1)

0.5

Condenser temperature, Tcon (°C) Absorber/evaporator temperature, Tabs/ev (°C) Temperature difference in the cold end of absorber (°C) Effectiveness of SHE (%) Overall heat transfer coefficient of evaporator, Uev (kW m−2 K−1) Overall heat transfer coefficient of gas cooler, Ucon (kW m−2 K−1) Overall heat transfer coefficient of gas cooler, USHE (kW m−2 K−1) Overall heat transfer coefficient of gas cooler, Ugen (kW m−2 K−1)

35 120 10 80 1.11 1.75 0.2 0.7

3.3. DAHT evaluation To model the DAHT used in the proposed system, the equations of mass and energy balance are applied to each component as follows: Generator:

m18 X18 = m19 X19 , m18 = m19 + m22

(5)

m1 (h1

(6)

h2) = m18 h18

m19 h19

m22 h22

Absorber:

m21 X21 = m16 X16 , m16 = m21 + m25

(7)

Qabs + m21 h21 + m25 h25 = m16 h16

(8)

Qabs = m32 (h33

h32) + m4 (h5

Fig. 2. Comparison of coefficient of performance of standalone DAHT for the present model and reported data [36].

(9)

h4 )

Table 5 Comparison of specific exergy values with the ones evaluated by Bereche et al. [31].*

Absorber/evaporator: (10)

m28 X28 = m29 X29 , m29 = m28 + m27

m24 (h25

h24) = m19 h19 + m27 h27

(11)

m29 h29

Specific exergy (kJ kg−1)

Evaporator:

m26 (h27

h26) = m8 (h8

(12)

h 9)

Condenser:

m22 (h22

h23) = m37 (h38

(13)

h37)

h22) = m16 (h16

effSHE 1 = (T21

T20)/(T16

h17), m28 (h28

h20) = m29 (h29

T20), effSHE 2 = (T28

T20)/(T29

h30 )

(14)

T20)

(15)

=

0 echemical

+

Present study

Ref. [31]

Deviation (%)

37.8 66.2 87.8 53.08

1.016 6.558 6.558 1.016

55.42 55.42 62.32 62.32

519.4 523.4 630.5 624.2

501.4 506.2 608.7 600.2

3.59 3.39 3.58 3.99

0

0

0 echemical = (1/ MLiBr/water )(ywater × e water + yLiBr × eLiBr )

(17)

distruction echemical = (RT0/ MLiBr/water )(ywater × lna water + yLiBr × lnaLiBr )

(18)

where MLiBr/water is the molar mass of solution, y is the molar fraction, e

(16)

distruction echemical

X (%)

0 distruction and echemical are standard chemical exergy of pure spewhere echemical cies and exergy destruction due to the dissolution process, respectively [30]:

where eff is the effectiveness of SHEs. It should be noted that due to the change of chemical exergy of the solution stream (LiBr/water) from inlet to outlet of the absorber, absorber/evaporator and generator, the exergy analysis of DAHT is important. For the LiBr/water solution, the chemical exergy equation is as follows [30]: LiBr/water echemical

P (kPa)

* T, P and X are the arbitrary temperature, pressure and LiBr concentration of the LiBr/water solution, respectively.

Solution heat exchangers:

m21 (h21

T (°C)

is standard chemical exergy, R is the universal gas constant and a is

Table 3 Capital investment cost functions. Component Turbine

Capital cost function ($)

Reference

3.5 × C0, turblogC0, turb = 2.7051 + 1.4398logWturb

0.1776(logWturb )2

[38]

Pump

1120 × Wpump

0.8

[39]

Evaporator/Condenser

1397 × A0.89

[39]

SHE

Absorber/Generator CO2 Capture Unit

0

[40]

383.5 × A0.65

[41]

16500 × (0.01A)0.6

74.45 × 106 (mcaptured CO2/780000)0.65

5

[42]

Energy Conversion and Management 207 (2020) 112542

A.H. Mosaffa and L.G. Farshi

Table 6 Results of simulation for proposed system. Stream

Fluid

m (kg s−1)

T (°C)

P (kPa)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38

Flue gas Flue gas CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 LiBr/water LiBr/water LiBr/water LiBr/water LiBr/water LiBr/water Water Water Water Water Water Water LiBr/water LiBr/water LiBr/water Steam Steam Steam Water Water Water Water Water

79.31 79.31 16.09 16.09 16.09 59.5 59.5 59.5 59.5 59.5 69.2 9.699 16.09 43.41 43.41 4.187 4.187 10.46 8.439 8.439 3.199 2.024 2.024 0.9883 0.9883 1.036 1.036 5.24 6.276 6.276 61.11 21.93 21.93 21.93 229.2 229.2 121.6 121.6

182.1 130 20 34.45 86.66 65.83 200 127.1 95 40 34.29 28.05 28.05 28.05 57.85 145 115.4 106.8 85 85.07 133 85 35 35.02 115 35.01 85 113 120 100.1 257 134 140 128 20 30 20 30

101.3 101.3 9130 21,000 21,000 21,000 21,000 9000 9000 9000 7900 6900 6900 6900 21,000 169 169 5.627 5.627 169 169 5.627 5.627 169 169 57.81 57.81 169 57.81 57.81 418 303.9 303.9 303.9 101.3 101.3 101.3 101.3

X (%)

0.4778 0.4778 0.5044 0.6254 0.6254 0.6254

0.6254 0.5222 0.5222

h (kJ kg−1)

s (kJ kg−1 K−1)

721.5 661.1 −262.5 −242.9 −118.2 −170.5 87.86 41.74 −1.858 −163 −157.8 −125.6 −217.7 −217.7 −189.9 324.7 254.9 232.2 217.1 217.3 308.7 2659 146.6 146.8 2699 146.7 2651 270.1 261.2 217.1 2977 2726 2739 537.9 83.93 125.8 83.93 125.8

5.283 5.142 −1.605 −1.586 −1.212 −1.362 −0.7071 −0.678 −0.7916 −1.279 −1.254 −1.139 −1.445 −1.445 −1.42 0.9688 0.7965 0.707 0.4631 0.4635 0.7025 8.636 0.505 0.5052 7.183 0.505 7.544 0.6055 0.7584 0.644 7.384 6.988 7.02 1.613 0.2962 0.4365 0.2962 0.4365

Table 7 Share of each subsystem and component in total exergy destruction and total cost. Subsystem/Component

Exergy destruction rate (MW)

Cost (M$)

CO2 Capture Unit Transcritical CO2 Power Generation Vapor Generator Gas Cooler Turbine Others Double Effect Absorption Heat Transformer Generator Absorber Condenser Evaporator Absorber/Evaporator Others

38.49 32.92 30.97 0.92 0.51 0.52 1.96

0.274 3.641 0.795 0.809 1.827 0.209 0.331

1.05 0.56 0.18 0.15 0.002 0.01

0.026 0.071 0.116 0.061 0.034 0.022

Fig. 3. Variations in the net power and exergy destruction rate with CO2 capture rate.

IICtotal =

activity. Detailed information and calculations of chemical exergy of LiBr/water have been presented by Bereche et al. [31]. Table 2 shows the thermodynamic properties of DAHT.

i = component

CEPCI2018 Ci + O& M+ BOS CEPCIref

(19)

where Ci is the purchased cost of each component, O&M is the operating and maintenance cost and BOS is the balance of the system, including the cost of trivial components such as valves, pipes, separator and control system. To consider inflation, the investment capital costs of components are actualized by applying the Chemical Engineering Plant Cost Index (CEPCI2018 /CEPCIref = 581/397 [32]). The purchased cost functions are presented in Table 3. To calculate the heat transfer area of each heat exchanger, the Eq. (20) is applied [33]:

3.4. Economic evaluation To determine the feasibility and economic advantages of the proposed system, a complete economic evaluation is conducted. The total initial capital cost could be defined as follows: 6

Energy Conversion and Management 207 (2020) 112542

A.H. Mosaffa and L.G. Farshi

Fig. 4. Variations in (a) payback period, NPV (b) CO2 avoidance cost and LCOE with CO2 capture rate.

Fig. 6. Variations in (a) payback period, NPV (b) CO2 avoidance cost and LCOE with absorber temperature.

Fig. 5. Variations in the net power and exergy destruction rate with absorber temperature.

Fig. 7. Variations in the net power and exergy destruction rate with evaporator temperature.

A=

saving by the system as follows:

QHE U TLMTD

(20)

AES = Wnet × c electrical

where Wnet and celectrical are the annual net work in kWh and the unit cost of electricity in $ kWh−1. The annuity factor is determined by [34]:

where U and TLMTD are the overall heat transfer coefficient and the logarithmic mean temperature difference of each heat exchangers, respectively. TLMTD is calculated as follows:

TLMTD

Thot ter min al Tcold ter min al = ln( Thot ter min al / Tcold ter min al )

n

IICtotal

[1/(1 + i) k ]

AF = k=0

(21)

(24)

where n and i are the total number of periods and the effective discount rate, respectively. The simple payback (SPB) for the system can then be evaluated as:

where ( Thot terminal = Thot,in Tcold,out ) and ( Tcold terminal = Thot,out Tcold,in ) . In this work, to evaluate the economic performance, the net present value (NPV) method is employed. The NPV could be determined as follows [34]:

NPV = AF × AES

(23)

SPB = IICtotal /AES

(25)

To compare different technologies with CCU over their economic lifetime, the CO2 avoidance cost is widely used as a convenient method. There are various methods used to estimate the CCU CO2 avoidance cost from the industry [35]. Here, the CO2 avoidance cost is calculated

(22)

where AES is the annuity economic saving and AF is the annuity factor. The annuity economic saving is expressed as the overall economic 7

Energy Conversion and Management 207 (2020) 112542

A.H. Mosaffa and L.G. Farshi

as follows [24]:

CO2 avoidance cost (LCOE with CCU LCOEreference)[$kWh 1] = (CO2 emissionreference CO2 emissionwith CCU)[t-CO2 kWh 1]

(26)

where LCOE is the levelized cost of electricity and reference is the power plant without CCU. The relations used to calculate LCOE and capital recovery factor (CRF) are simplified as presented by Eqs. (27) and (28):

LCOE = CRF × (CCCU

Creference)/annual net work [kWh]

CRF = i (1 + i )n /[(1 + i) n

1]

(27) (28)

Table 4 represents the economic parameters used in the simulation. 4. Model verification The developed mathematical model for proposed systems is implemented in EES. The validation for the DAHT model is presented in Fig. 2, in which good agreement is observed between the obtained results for the coefficient of performance of standalone DAHT and reported ones by Wang et al. [36]. Also, to verify the validity of the exergy analysis for DAHT (due to the importance of the chemical exergy change for LiBr/water solution), the obtained specific exergy value of the LiBr/water solution are compared with those reported by Bereche et al. [31] which are listed in Table 5. Moreover, the simulation of the ejector has been validated by the authors in Ref. [37]. 5. Results and discussion

Fig. 8. Variations in (a) payback period, NPV (b) CO2 avoidance cost and LCOE with evaporator temperature.

Based on the operating conditions, a simulation is carried out and the results for the thermodynamic properties of each state are summarized in Table 6. In this case, for a coal-fired power plant, the proposed system performance parameters are obtained as follows: (1) net power generation for compensating a portion of required electrical energy for CCU is 1.223 MW, (2) total exergy destruction rate is 73.4 MW comprises 38.5 MW for CCU and 33 MW for power generation subsystem, (3) net present value and payback period are estimated to be 15.4 M$ and 4.4 years, respectively and (4) the levelized cost of electricity and CO2 avoidance cost are 46.4 $ MWh−1 and 32.3 $ (ton CO2)−1, respectively. The share of each subsystem and their components in the total exergy destruction and the total cost is calculated in detail and is summarized in Table 7. Furthermore, a parametric study is carried out to reveal the effects of the key parameters on the proposed system performance. The selected key parameters that affect on whole of subsystems are carbon dioxide capture rate, the water evaporation temperature in evaporator and absorber temperature. Fig. 3 depicts the effect of carbon dioxide capture rate on the net power and exergy destruction rate. It is evident that increases carbon dioxide capture rate leads to the rises in both net power output and exergy destruction rate as a result of rising in the mass flow rate of captured CO2. Under the given conditions, an increase of carbon dioxide capture rate from 40% to 90%, leads to the rises of 2.1% and 23.4% in net power output and exergy destruction rate, respectively. The variations in economic parameters with carbon dioxide capture rate are presented in Fig. 4. Due to the rising of the mass flow rate of captured CO2 by increasing in carbon dioxide capture rate, the total cost of the proposed system increases. However, an increase in CO2 capturing rate from 40% to 90% leads to an increase of 3.7% in NPV and a decrease of 4.2% in SPB. In this case, CO2 avoidance cost and LCOE decrease by 63.7% and 1.3%, respectively. The effect of absorber temperature on the net power and exergy destruction rate are illustrated in Fig. 5. By rising in the absorber temperature, the temperature of the steam exiting absorber increases. Therefore, the transferred heat from absorber to the captured CO2

Fig. 9. Variations in payback period and NPV with unit cost of electricity.

Fig. 10. Variations in LCOE and NPV with effective discount rate.

8

Energy Conversion and Management 207 (2020) 112542

A.H. Mosaffa and L.G. Farshi

(process 3–4 in Fig. 1) decreases and so turbine inlet temperature reduces. This leads to a decrease in net power output. An increase in absorber temperature from 140 °C to 150 °C, leads to a reduction of 5.2% in net power output. Nevertheless, the exergy destruction rate ignorable increases as a result of a small decrease in net power output. The variations in the economic performance of the proposed system with absorber temperature are shown in Fig. 6. It is obvious that by a reduction in net power output, NPV decreases and payback period increases. Nevertheless, by growth in absorber temperature from 140 °C to 150 °C, the CO2 avoidance cost and LCOE both fall 15.5 $ (ton CO2)−1 and 1.36 $ MWh−1, respectively. Fig. 7 depicts the variation in the thermodynamic performance with the evaporator temperature. An increase in the evaporator temperature leads to the decreases of absorber/evaporator temperature and so absorber temperature. Therefore, transferred heat to the stream 6 decreases. Hence, the turbine inlet temperature and net power output decrease. Under the given condition, by increasing the evaporator temperature from 80 °C to 90 °C, net power output and exergy destruction rate reduce of 4.9% and 0.8%, respectively. Fig. 8 presents the effect of the evaporator temperature on economic performance. By increasing in evaporator temperature, total cost decreases due to the reduction in the generated power. A small decrease in the total cost and a significant reduction in power generation, leads to a reduction in the NPV (5%) while the payback period remains constant. A 10 K increase in evaporator temperature from 80 °C to 90 °C would reduce 2.9% to LCOE and result in a decrease of 38.5% in CO2 avoidance cost. The CO2 avoidance cost would vary from 40.4 to 24.8 $ (ton CO2)−1. Fig. 9 shows the effect of the unit cost of electricity on the payback period and net present value. By increasing the unit cost of electricity, the annuity economic saving increases. Hence, SPB decreases and NPV increases. Under the given condition, an increase in the unit cost of electricity, from 0.8 $ kWh−1 to 0.18 $ kWh−1, leads to an increase of 209.3% in net present value. In this case, the payback period decreases approximately 3 years and 6 months. Fig. 10 depicts the variation of LCOE and NPV with the effective discount rate. It can be seen that the effective discount rate has a big effect on performance parameters. By 0.1 increase in effective discount rate, from 0.05 to 0.15, LCOE increases of 53.9 $ MWh−1 (116.2%) while NPV decreases of 11.3 M$ (73.5%).

energy and a portion of electrical energy of a typical CCU for CO2 emission reduction. Due to the economic benefits and superior thermal performance, this new CO2 capture approach can be used for real applications. CRediT authorship contribution statement A.H. Mosaffa: Conceptualization, Methodology, Software, Validation, Investigation, Writing - original draft, Visualization, Supervision, Project administration. L. Garousi Farshi: Conceptualization, Software, Data curation, Writing - review & editing. Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. References [1] Lee MY, Hashim H. Modelling and optimization of CO2 abatement strategies. J Clean Prod, Elsevier 2014:40–7. https://doi.org/10.1016/j.jclepro.2014.01.005. [2] Chisalita DA, Petrescu L, Cobden P, van Dijk HAJ (Eric), Cormos AM, Cormos CC. Assessing the environmental impact of an integrated steel mill with post-combustion CO2 capture and storage using the LCA methodology. J Clean Prod 2019;211:1015–25. https://doi.org/10.1016/j.jclepro.2018.11.256. [3] Gielen D. CO2 removal in the iron and steel industry. Energy Convers Manag 2003;44:1027–37. https://doi.org/10.1016/S0196-8904(02)00111-5. [4] Liang X, Li J. Assessing the value of retrofitting cement plants for carbon capture: A case study of a cement plant in Guangdong, China. Energy Convers Manag, Pergamon 2012:454–65. https://doi.org/10.1016/j.enconman.2012.04.012. [5] Cloete S, Giuffrida A, Romano MC, Zaabout A. The swing adsorption reactor cluster for post-combustion CO2 capture from cement plants. J Clean Prod 2019;223:692–703. https://doi.org/10.1016/j.jclepro.2019.03.109. [6] Zhu Y, Li W, Li J, Li H, Wang Y, Li S. Thermodynamic analysis and economic assessment of biomass-fired organic Rankine cycle combined heat and power system integrated with CO2 capture. Energy Convers Manag 2019;112310. https://doi.org/ 10.1016/j.enconman.2019.112310. [7] Zhu Y, Li W, Li J, Li H, Wang Y, Li S. Thermodynamic analysis and economic assessment of biomass-fired organic Rankine cycle combined heat and power system integrated with CO2 capture. Energy Convers Manag 2019. https://doi.org/10. 1016/j.enconman.2019.112310. [8] Bonalumi D, Lillia S, Valenti G. Rate-based simulation and techno-economic analysis of coal-fired power plants with aqueous ammonia carbon capture. Energy Convers Manag 2019;199:111966https://doi.org/10.1016/j.enconman.2019. 111966. [9] Aouini I, Ledoux A, Estel L, Mary S. Pilot Plant Studies for CO2 Capture from Waste Incinerator Flue Gas Using MEA Based Solvent. Oil Gas Sci Technol – Rev d’IFP Energies Nouv 2014;69:1091–104. https://doi.org/10.2516/ogst/2013205. [10] Spallina V, Shams A, Battistella A, Gallucci F, Annaland MVS. Chemical Looping Technologies for H2 Production with CO2 Capture. Thermodynamic Assessment and Economic Comparison, in: Energy Procedia Elsevier Ltd; 2017. p. 419–28. https://doi.org/10.1016/j.egypro.2017.03.1184. [11] Esquivel-Patiño GG, Serna-González M, Nápoles-Rivera F. Thermal integration of natural gas combined cycle power plants with CO2 capture systems and organic Rankine cycles. Energy Convers Manag 2017;151:334–42. https://doi.org/10. 1016/j.enconman.2017.09.003. [12] Pan Z, Zhang L, Zhang Z, Shang L, Chen S. Thermodynamic analysis of KCS/ORC integrated power generation system with LNG cold energy exploitation and CO2 capture. J Nat Gas Sci Eng 2017;46:188–98. https://doi.org/10.1016/j.jngse.2017. 07.018. [13] Jiang L, Gonzalez-Diaz A, Ling-Chin J, Roskilly AP, Smallbone AJ. Post-combustion CO2 capture from a natural gas combined cycle power plant using activated carbon adsorption. Appl Energy 2019;245:1–15. https://doi.org/10.1016/j.apenergy. 2019.04.006. [14] Esquivel Patiño GG, Nápoles Rivera F. Global warming potential and net power output analysis of natural gas combined cycle power plants coupled with CO2 capture systems and organic Rankine cycles. J Clean Prod 2019;208:11–8. https:// doi.org/10.1016/j.jclepro.2018.10.098. [15] Bao J, Zhang L, Song C, Zhang N, Guo M, Zhang X. Reduction of efficiency penalty for a natural gas combined cycle power plant with post-combustion CO2 capture: Integration of liquid natural gas cold energy. Energy Convers Manag 2019;198:111852https://doi.org/10.1016/j.enconman.2019.111852. [16] Zhao G, Chen S. Greenhouse gas emissions reduction in China by cleaner coal technology towards 2020. Energy Strateg Rev 2015;7:63–70. https://doi.org/10. 1016/j.esr.2014.08.001. [17] Huang B, Xu S, Gao S, Liu L, Tao J, Niu H, et al. Industrial test and techno-economic analysis of CO2 capture in Huaneng Beijing coal-fired power station. Appl Energy 2010;87:3347–54. https://doi.org/10.1016/j.apenergy.2010.03.007. [18] Zhao L, Zhao R, Deng S, Tan Y, Liu Y. Integrating solar Organic Rankine Cycle into a

6. Conclusion The present work proposed and investigated a DAHT-aided CCU with transcritical CO2 power generation. The innovation of this system lies in the employing transcritical CO2 power generation system to partly cover the required electrical energy demand of CCU and hence increasing the thermal efficiency of a coal-fired steam power plant. In addition, the utilization of DAHT could avoid high-level steam extraction from the high pressure stage of the steam turbine. By parametric study, the following results are obtained:

• CO capture rate, absorber and evaporator temperature are important parameters that affect on system performance. A • 10 K increase in evaporator temperature from 80 °C to 90 °C, leads 2

• •

to a reduction of 4.9% in net power output. In this case, the levelized cost of electricity and CO2 avoidance cost decrease by 2.8% and 38.5%, respectively. A 10 K increase in absorber temperature from 140 °C to 150 °C, leads to a reduction of 2.9% in net power output. In this case, the net present value reduces by 5.3%. A 50% increase in carbon dioxide capture rate from 40% to 90%, leads to the rises of 2.1% and 23.4% in net power output and exergy destruction rate, respectively.

The presented integrated system can provide required thermal 9

Energy Conversion and Management 207 (2020) 112542

A.H. Mosaffa and L.G. Farshi

[19] [20] [21]

[22]

[23]

[24] [25]

[26] [27] [28]

[29]

[30]

coal-fired power plant with amine-based chemical absorption for CO2 capture. Int J Greenh Gas Control 2014;31:77–86. https://doi.org/10.1016/j.ijggc.2014.09.025. Liu X, Liang J, Xiang D, Yang S, Qian Y. A proposed coal-to-methanol process with CO2 capture combined Organic Rankine Cycle (ORC) for waste heat recovery. J Clean Prod 2016;129:53–64. https://doi.org/10.1016/j.jclepro.2016.04.123. Zhai R, Qi J, Zhu Y, Zhao M, Yang Y. Novel system integrations of 1000 MW coalfired power plant retrofitted with solar energy and CO2 capture system. Appl Therm Eng 2017;125:1133–45. https://doi.org/10.1016/j.applthermaleng.2017.07.093. Wang F, Deng S, Zhao J, Zhao J, Yang G, Yan J. Integrating geothermal into coalfired power plant with carbon capture: A comparative study with solar energy. Energy Convers Manag 2017;148:569–82. https://doi.org/10.1016/j.enconman. 2017.06.016. Carapellucci R, Di Battista D, Cipollone R. The retrofitting of a coal-fired subcritical steam power plant for carbon dioxide capture: A comparison between MCFC-based active systems and conventional MEA. Energy Convers Manag 2019;194:124–39. https://doi.org/10.1016/j.enconman.2019.04.077. Olumayegun O, Wang M, Oko E. Thermodynamic performance evaluation of supercritical CO2 closed Brayton cycles for coal-fired power generation with solventbased CO2 capture. Energy 2019;166:1074–88. https://doi.org/10.1016/j.energy. 2018.10.127. Wang D, Li S, Liu F, Gao L, Sui J. Post combustion CO2 capture in power plant using low temperature steam upgraded by double absorption heat transformer. Appl Energy 2018;227:603–12. https://doi.org/10.1016/j.apenergy.2017.08.009. Zhang K, Liu Z, Li Y, Li Q, Zhang J, Liu H. The improved CO2 capture system with heat recovery based on absorption heat transformer and flash evaporator. Appl Therm Eng 2013;61:500–6. https://doi.org/10.1016/j.applthermaleng.2013.07. 043. Simões Van-Dal É, Bouallou C. Design and simulation of a methanol production plant from CO2 hydrogenation. J Clean Prod 2013;57:38–45. https://doi.org/10. 1016/j.jclepro.2013.06.008. Artanto Y, Jansen J, Pearson P, Do T, Cottrell A, Meuleman E, et al. Performance of MEA and amine-blends in the CSIRO PCC pilot plant at Loy Yang Power in Australia. Fuel 2012;101:264–75. https://doi.org/10.1016/j.fuel.2012.02.023. Xia J, Wang J, Zhou K, Zhao P, Dai Y. Thermodynamic and economic analysis and multi-objective optimization of a novel transcritical CO2 Rankine cycle with an ejector driven by low grade heat source. Energy 2018;161:337–51. https://doi.org/ 10.1016/j.energy.2018.07.161. Ipakchi O, Mosaffa AH, Garousi Farshi L. Ejector based CO2 transcritical combined cooling and power system utilizing waste heat recovery: A thermoeconomic assessment. Energy Convers Manag 2019;186:462–72. https://doi.org/10.1016/j. enconman.2019.03.009. Kim DS, Ferreira CAI. A Gibbs energy equation for LiBr aqueous solutions. Int J

Refrig 2006;29:36–46. https://doi.org/10.1016/j.ijrefrig.2005.05.006. [31] Palacios-Bereche R, Gonzales R, Nebra SA. Exergy calculation of lithium bromidewater solution and its application in the exergetic evaluation of absorption refrigeration systems LiBr-H2O. Int J Energy Res 2012;36:166–81. https://doi.org/ 10.1002/er.1790. [32] Nwaoha C, Beaulieu M, Tontiwachwuthikul P, Gibson MD. Techno-economic analysis of CO2 capture from a 1.2 million MTPA cement plant using AMP-PZ-MEA blend. Int J Greenh Gas Control 2018;78:400–12. https://doi.org/10.1016/j.ijggc. 2018.07.015. [33] Mosaffa AH, Hasani Mokarram N, Garousi Farshi L. Thermoeconomic analysis of a new combination of ammonia/water power generation cycle with GT-MHR cycle and LNG cryogenic exergy. Appl Therm Eng 2017;124:1343–53. https://doi.org/ 10.1016/j.applthermaleng.2017.06.126. [34] Yang F, Huang N, Sun Q, Cheng L, Wennersten R. Modeling and techno-economic analysis of the heat pump-integrated PEMFC-based micro-CHP system. Energy Procedia 2018;152:83–8. https://doi.org/10.1016/j.egypro.2018.09.063. [35] Roussanaly S. Calculating CO 2 avoidance costs of Carbon Capture and Storage from industry. CarbonManag 2019;10:105–12. https://doi.org/10.1080/17583004. 2018.1553435. [36] Wang L, Li H, Bu X, Wang H, Ma W. Performance Study of a Double Absorption Heat Transformer. Energy Procedia 2017:1473–82. https://doi.org/10.1016/j. egypro.2017.03.439. [37] Mosaffa AH, Farshi LG. Thermodynamic and economic assessments of a novel CCHP cycle utilizing low-temperature heat sources for domestic applications. Renew Energy 2018;120:134–50. https://doi.org/10.1016/j.renene.2017.12.099. [38] Turton R, Shaeiwitz JA, Bhattacharyya D, Whiting WB. Analysis. Synthesis and Design of Chemical Processes: Prentice Hall; 2018. https://books.google.com/ books?id=ShwUtAEACAAJ. [39] Mosaffa AH, Mokarram NH, Farshi LG. Thermo-economic analysis of combined different ORCs geothermal power plants and LNG cold energy. Geothermics 2017;65:113–25. https://doi.org/10.1016/j.geothermics.2016.09.004. [40] Mosaffa AH, Farshi LG, Infante Ferreira CA, Rosen MA. Exergoeconomic and environmental analyses of CO2/NH3 cascade refrigeration systems equipped with different types of flash tank intercoolers. Energy Convers Manag 2016;117:442–53. https://doi.org/10.1016/j.enconman.2016.03.053. [41] Garousi Farshi L, Mahmoudi SMS, Rosen MA, Yari M, Amidpour M. Exergoeconomic analysis of double effect absorption refrigeration systems. Energy Convers Manag 2013;65:13–25. https://doi.org/10.1016/j.enconman.2012.07.019. [42] Mosaffa AH, Hasani Mokarram N, Garousi Farshi L. Thermoeconomic analysis of a new combination of ammonia/water power generation cycle with GT-MHR cycle and LNG cryogenic exergy. Appl Therm Eng 2017;124:1343–53. https://doi.org/ 10.1016/j.applthermaleng.2017.06.126.

10