Reforming Natural Gas for CO₂ Pre-Combustion Capture in Trinary Cycle Power Plant

Abstract

Today, most of the world’s electric energy is generated by burning hydrocarbon fuels, which causes significant emissions of harmful substances into the atmosphere by thermal power plants. In world practice, flue gas cleaning systems for removing nitrogen oxides, sulfur, and ash are successfully used at power facilities but reducing carbon dioxide emissions at thermal power plants is still difficult for technical and economic reasons. Thus, the introduction of carbon dioxide capture systems at modern power plants is accompanied by a decrease in net efficiency by 8–12%, which determines the high relevance of developing methods for increasing the energy efficiency of modern environmentally friendly power units. This paper presents the results of the development and study of the process flow charts of binary and trinary combined-cycle gas turbines with minimal emissions of harmful substances into the atmosphere. This research revealed that the net efficiency rate of a binary CCGT with integrated post-combustion technology capture is 39.10%; for a binary CCGT with integrated pre-combustion technology capture it is 40.26%; a trinary CCGT with integrated post-combustion technology capture is 40.35%; and for a trinary combined-cycle gas turbine with integrated pre-combustion technology capture it is 41.62%. The highest efficiency of a trinary CCGT with integrated pre-combustion technology capture is due to a reduction in the energy costs for carbon dioxide capture by 5.67 MW—compared to combined-cycle plants with integrated post-combustion technology capture—as well as an increase in the efficiency of the steam–water circuit of the combined-cycle plant by 3.09% relative to binary cycles.

1. Introduction

1.1. The Problem of Increasing Energy Efficiency and Environmental Safety of Electricity Production at Combined-Cycle Plants

In recent decades, the world community has paid increased attention to the issues of reducing emissions of toxic substances and carbon dioxide into the atmosphere by the economic sector [1,2]. In order to improve the environmental safety of modern enterprises, research and development of new technologies for preventing the formation and capture of harmful emissions are actively carried out. However, despite certain successes in the implementation of methods for reducing emissions of nitrogen oxides, sulfur, and ash [3,4], reducing carbon dioxide emissions in industry is still difficult for technical and economic reasons.

The energy sector is one of the main sources of greenhouse gas emissions. For example, according to the latest data in the Russian Federation, the production of electric and thermal energy (Figure 1) accounts for 34.7% of all anthropogenic emissions of carbon dioxide into the atmosphere, which makes it extremely important to improve environmental safety at thermal power plants [5].

In thermal power engineering, a steam turbine unit (STU), gas turbine unit (GTU), and combined-cycle gas turbine unit (CCGT) are used. According to the statistical data given in

Table 1. Energy efficiency and specific carbon dioxide emissions data for thermal power plants.

Unit	Efficiency, %	Direct CO2 Emissions, g CO2/kWhel
Gas turbine unit	35.5	566
Steam turbine unit	38.4	524
Combined-cycle gas turbine	51.3	392

, in the Russian Federation, carbon dioxide emissions at combined-cycle power plants are 132 g CO₂/kWh_el lower than at steam turbine power plants, and the net efficiency is 12.9% higher [6,7]. It is worth noting that the use of technologies for capturing carbon dioxide from flue gases for the listed power plants will lead to a significant decrease in their energy efficiency by 8–12%. Given the importance of saving fuel in electricity generation, it is advisable to consider modifications of energy-efficient Brayton–Rankine cycles when developing low-carbon energy complexes [8].

Despite the fact that the efficiency of CCGT units reaches record values, the potential for increasing their energy efficiency is significant. In particular, additional generation of electric energy is possible due to the utilization of heat from flue gases in the organic Rankine cycle (ORC). The working environment for these cycles is a low-boiling coolant with a critical temperature from 30 °C to 290 °C. However, due to the low thermal potential of the waste heat, the energy efficiency of the ORC does not exceed 15%, which gives an increase in the net efficiency of a trinary CCGT unit of no more than 2–3% [9,10,11,12].

Also, the utilization of flue gas heat in the organic Rankine cycle allows for the use of an advanced regeneration system in a steam turbine power plant. For example, in article [9], it was established that for a trinary power unit with a temperature and pressure of combustion products at the gas turbine inlet equal to 1060 °C and 1.09 MPa, the utilization of the low-potential heat of exhaust gases using the organic Rankine cycle achieves a net efficiency of 51.3%. This value is higher than the efficiency of modern dual-circuit CCGT units by 0.4% and single-circuit CCGT units by 2.1%, which is due to a decrease in heat losses in the condenser due to the implementation of an advanced regeneration system in the steam–water circuit.

1.2. Methods of Capturing Carbon Dioxide at Thermal Power Plants

To minimize energy costs for the own needs of binary and trinary combined-cycle power plants, it is necessary to develop highly efficient methods for capturing carbon dioxide. Currently, two main methods are used to reduce carbon dioxide emissions in the production of electricity (Figure 2): before (pre-combustion capture) and after (post-combustion capture) the combustion of fuel [13].

The capture of CO₂ after fuel combustion is carried out from flue gases using special devices. This method is the most common in modern thermal power engineering due to its technological simplicity and low cost of the carbon dioxide removal process. When capturing carbon dioxide after fuel combustion at modern energy facilities, the most commonly used methods are cryogenic, membrane, and absorption capture of carbon dioxide [14,15,16,17,18,19].

It is worth noting that the most widely used technology in industry is the chemical absorption of flue gases. At present, promising reagents for chemical absorption [18,19] are solutions based on amines: monoethanolamine (MEA), n-methyldiethanolamine (MDEA), and dimethylethanolamine (DMEA). In [18], it was found that for carbon dioxide capture, based on the parameters of mass transfer, absorption capacities, and cyclic capacity, the solutions based on monoethanolamine are most suitable.

In these units, the process of carbon dioxide capture occurs using an absorption reaction with monoethanolamine. After that, the absorbent regeneration reaction takes place in the desorber and the absorbed carbon dioxide is released, which is sent for disposal. The main advantage of MEA is a high degree of capture (88–98%) with low energy costs for its own needs (4–6 MJ/kg CO₂) [20]. Other features of the absorption unit include the following: carbon dioxide purification in a wide range of partial pressures, increased chemical stability, and high reactivity. The disadvantages of this solvent are absorbent losses, surface corrosion, and high separation costs [21,22].

Based on the data presented in

Table 2. Comparison of energy and environmental characteristics of post-combustion CO₂ capture technologies.

Parameter	Method CO2 Capture
	Absorption	Membranes	Cryogenic Separation
Cost energy, MJ/kg CO2	4–6	0.5–6	6–10
Degree CO2 capture, %	88–98	80–90	>95

, it can be concluded that, of all the previously considered technologies of post-combustion, the most energy-efficient and environmentally friendly is the installation of monoethanolamine cleaning of exhaust gases.

One promising way to reduce CO₂ emissions is to remove it from the fuel (coal, oil, or natural gas) before combustion, resulting in hydrogen as the final fuel [13]. The main commercial technologies for producing hydrogen from methane are currently steam methane reforming (SMR); autothermal methane reforming (ATR); chemical looping reforming (CLR).

Based on the data presented in

Table 3. Comparison of energy and environmental characteristics of different methane reforming methods.

Unit	SMR	ATR	CLR
Levelized cost of production LCOH, USD/kgH2	1.07–2.26	1.70–2.31	3.31
Efficiency, %	85	87	75
Specific direct emission, kg CO2eq/kgH2	1	1.27	1.01
Air separation unit required	No	Yes	Yes

, the steam methane reforming unit also has 21.3% less specific direct emissions with approximately the same efficiency value relative to the values obtained using the autothermal methane reforming unit [23,24,25]. In the SMR process, steam reacts with natural gas at high temperatures (650–900 °C) and moderate pressures (1.5–2 kg·f/cm²) in the presence of a nickel-containing catalyst (up to 20% Ni as NiO). Only steam and thermal energy are required to separate hydrogen from the carbon base in methane.

1.3. Current State of Combined-Cycle Power Systems with Integrated Steam Methane Reforming Units

There are many scientific papers devoted to the development of binary combined-cycle gas turbines with an integrated methane steam reforming unit [26,27,28,29]. For example, in article [27], the authors considered a combined-cycle gas turbine with an integrated methane steam reforming unit (Figure 3) for generating electricity and hydrogen fuel, which is built into the gas–air circuit at the outlet of the gas turbine. Using a remote combustion chamber, the combustion products are heated to a temperature of 800–1000 °C and sent to the reformer. To reduce losses with exhaust gases, the STU is designed without a regeneration system, due to which the exhaust gas temperature is 140 °C. The fuel heat utilization coefficient of this power plant varies from 56.2% to 64.1% depending on the temperature at the inlet of the gas turbine, which varies in the range from 1200 °C to 1600 °C. It is worth noting that in this article, hydrogen fuel is burned in the combustion chamber, which is why the combustion products consist of water vapor but carbon dioxide emissions occur in the steam methane reforming unit.

There is also a variant of a combined-cycle plant with an integrated steam methane reforming unit (Figure 4) where steam shift reactions occur only in a high-temperature reactor, and all remaining associated gases are sent to a remote combustion chamber. It is worth noting that this technology allows for a partial reduction in carbon dioxide emissions by cleaning flue gases using monoethanolamine absorption. In the joint production of hydrogen fuel and electricity, the heat utilization coefficient of the developed unit varies from 57% to 70% [28].

The articles [29,30] consider the thermal scheme of a combined-cycle plant with steam methane reforming (Figure 5), which is used only for the production of electric power. The reformer itself, as in the articles considered earlier, is located at the outlet of the gas turbine. Hydrogen produced in the reformer is supplied after the absorber to the combustion chamber and the reformer furnace. It is worth noting that steam for the steam reforming reaction is taken from the extraction of the high-pressure turbine. Excess heat from the reformer is utilized by heating the condensate, which is taken after the condenser, to the temperature of the feedwater. At a temperature at the outlet of the reformer equal to 1368 °C, the net efficiency of this plant is 46.1%.

The previously considered options include only binary CCGT units, however, a developed system for regenerating the steam–water circuit of trinary CCGT units will significantly increase the energy efficiency of the thermal power plant. As a result, the goal of this work is to develop a process flow chart and a mathematical model of a trinary combined-cycle plant with an integrated methane steam conversion unit as well as an analytical comparison of the results obtained with existing binary units.

2. Study Object

To compare trinary and binary power plants with carbon dioxide capture technologies of post-combustion capture and pre-combustion capture, the following cycles were considered:

(1)

Binary combined-cycle gas turbine with monoethanolamine cleaning of exhaust gases (Figure 6);

(2)

Trinary combined-cycle gas turbine with monoethanolamine cleaning of exhaust gases (Figure 7);

(3)

Binary combined-cycle gas turbine with integrated steam methane reforming unit (Figure 8);

(4)

Trinary combined-cycle gas turbine with integrated steam methane reforming unit (Figure 9).

2.1. Trinary and Binary Power Plants with Carbon Dioxide Capture Technologies for Post-Combustion Capture

The binary CCGT with mono ethanolamine exhaust gas cleaning shown in Figure 6 operates as follows. Air enters the inlet of the air compressor (AC), where the process of compression of the working medium takes place. A smaller part of the compressed flow of the working medium is directed to the compressor extractions for cooling the hot tract parts of the gas turbine (GT). The main part of the airflow at the outlet of the compressor is fed to the combustion chamber (CC), which also receives fuel pre-compressed in the fuel compressor (FC). As a result of fuel combustion, the temperature of the working medium increases significantly, which then enters the inlet of the gas turbine. The potential energy of high-temperature gases is converted into mechanical energy of rotation of the rotor of the gas turbine, located on the same shaft as the electric generator (EG), which serves to generate electricity. The exhaust gases from the gas turbine exhaust are then fed to the waste heat boiler, which produces superheated steam to feed the steam turbine unit. The exhaust gases in the waste heat boiler successively wash the tube bundles of the heating surfaces of the superheater (SH), evaporator (EV), economizer (EC), and gas condensate heater (GCH). At the outlet of the waste heat boiler, the exhaust gases are released into the atmosphere. The steam produced in the superheater is directed to the inlet of the high-pressure section of the steam turbine (HPT). Having performed useful work, the steam from the exhaust of the high-pressure section of the steam turbine is partially directed to the deaerator. Most of the steam enters the low-pressure turbine (LPT), a heat drop occurs in it, and then is directed to the condenser (C). The resulting condensate is directed to the condensate pump (CP), compressed in it, and then directed to the gas condensate heater, the inlet temperature of which is maintained constant by the recirculation pump (RP). The preheated working medium is directed to the deaerator (D), heated in it to the saturation temperature due to the heat of the steam, purified from harmful non-condensable gases, and then fed to the input of the feed pump (FP), operated by an electric drive. Compressed feed water at the outlet of the feed pump is directed to the economizer, in which it is heated to a temperature close to the saturation temperature. Then, the heated feed water is directed to the evaporator drum with natural circulation, in which the separation of the steam phase is carried out. Saturated water from the drum passes the surfaces of the evaporator and part of the working medium is converted into steam. Then, the steam–water mixture enters the drum, where the steam is separated. Saturated steam at the outlet of the evaporator drum enters the superheater. The second electric generator, located on the same shaft as the steam turbine, is used to generate electricity.

To reduce carbon dioxide emissions, a CCGT scheme with mono ethanolamine cleaning of exhaust gases is traditionally used. The combustion products after the reformer enter the lower part of the absorption column and an amine solution and make-up water are fed to the upper part of this column. Then, rising in the absorption column, the gas is washed by an amine solution, which absorbs carbon dioxide. The purified gas exits from the upper part of the column, and saturated amine enters the lower part of the column. Saturated amine then enters the pump, which feeds it to the recuperator. In the recuperator, saturated amine is heated by regenerated amine and enters the upper part of the regeneration column, which consists of an adsorber, condenser, and reboiler. In the regeneration column, the solution separates carbon dioxide from amine. A reboiler is installed at the bottom of the column, which evaporates the solution and supplies heat for the separation process. A condenser is installed at the top of the regeneration column, which cools the flow and separates vapors from the condensate. The flow is then cooled again and separated in a separator, after which, the vapors with a high carbon dioxide content are removed and the condensate is fed to the inlet of the regenerated amine pump. The regenerated amine after the reboiler is fed to the inlet of the hot flow of the recuperator, and after cooling, it is fed to the inlet of the regenerated amine pump, in addition, additional amine is also fed there.

To reduce losses in the condenser and increase the efficiency of the steam–water circuit in the trinary combined-cycle plant, an advanced regeneration system is used (Figure 7). With the help of the first and second low-pressure heaters (LPH-1; LPH-2) and the high-pressure heater (HPH), the feedwater temperature is increased, which allows for increasing the average integral temperature of heat supply. However, with an increase in the feedwater temperature, the temperature of the exhaust gases increases and the efficiency of the waste heat boiler decreases. The increased amount of heat lost with the exhaust gases can be usefully utilized in the organic Rankine cycle, which is a low-boiling cycle with heat recovery at the outlet of the condenser, operating on freon R245fa.

The Rankine cycle works as follows: The hot stream transfers heat in the utilizer (U) and is sent to the mono ethanolamine flue gas cleaning unit. The heat is absorbed by the working fluid of the cycle, which, after heating in the utilizer, expands in the carbon dioxide turbine (CT), performing the work; then, it transfers the residual energy in the recuperator and enters the condenser, where, cooling to the saturation line and passing from the vapor phase to the liquid, it transfers heat to the cold source of the cycle. The condensed medium is compressed in the carbon dioxide pump (CD), heated in the recuperator, and enters the utilizer.

2.2. Trinary and Binary Power Plants with Carbon Dioxide Capture Technologies for Pre-Combustion Capture

Figure 8 and Figure 9 show the process flow diagrams of binary and trinary energy cycles operating on hydrogen fuel. Hydrogen is produced using a steam methane conversion unit, the reformer of which is integrated into the gas–air tract of the combined-cycle plant before entering the waste heat boiler.

To produce hydrogen, steam is taken from the high-pressure cylinder at a pressure of 2.2 MPa and then mixed with methane, which has been preheated to 450 °C in the high-temperature reactor. The synthesis gas formed during the steam reforming reaction of methane is heated to a temperature of 850 °C using the heat generated by the afterburning of oxygen in the combustion products in the hydrogen furnace of the reformer to a temperature of 875 °C. The synthesis gas, consisting mainly of carbon dioxide, carbon monoxide, water vapor, CH₄, and hydrogen, then enters the high-temperature (HTR) and low-temperature (LTR) reactors, where the hydrogen content in the gas increases due to the catalytic reaction of carbon monoxide with water vapor. After that, after cooling in the heat exchanger–cooler (HE), moisture is removed from the synthesis gas in the cooler–separator (CS), and removal of the heat from the process is carried out by pumping circulating water. Synthesis gas is sent to the absorption unit (A), where carbon dioxide is removed from the flow, which is sent to disposal sites using a multi-stage compressor with intermediate cooling. As a result, highly purified hydrogen is obtained at the outlet of the steam methane reforming unit, which is sent to the combustion chamber and to the refractor furnace. Heat is utilized from the HTR, LTR, and HE using feed water collected after the feed pump. Steam after the HTR is heated to a temperature of 515 °C, after which it is sent to the high-pressure cylinder. The initial data used to model the proposed technological solutions are presented in

Table 4. Initial data for modeling binary and trinary combined-cycle gas turbines.

Parameter	Meaning
Method of Capturing Carbon Dioxide	MEA	SMR
Outside air temperature, °C	15
Outside air pressure, kPa	101.3
Pressure of combustion products at the outlet of the combustion chamber, kPa	1060
Temperature of combustion products at the outlet of the CC, °C	1060
Mass flow compressor air, kg/s	500
Fuel supplied to the CC	CH4	H2
Temperature of synthesis gas at the reformer outlet, °C	-	850
Synthesis gas pressure at the reformer outlet, kPa	-	1060
Reboiler share	0.7	-
Outlet saturated amine pump pressure, kPa	110	-
Reflux fraction in the condenser	0.5	-
Underheating at the hot end of the superheater, °C	20
Steam temperature at the outlet of the waste heat boiler, °C	515
Underheating at the cold end of the evaporator, °C	10
Underheating at the economizer inlet, °C	10
Underheating at the deaerator inlet, °C	10
Temperature in the condenser, °C	30
Deaerator pressure, kPa	120
Hydraulic losses in heaters, %	5
Internal efficiency of feed, condensate, circulation pumps, %	85
Dryness level at the outlet of the steam turbine, %	90
Heat losses in heat exchangers, %	1
Underheating in high-pressure heater, °C	1.5
Underheating in low-pressure heater, °C	5
Cooling water temperature before feed pump, °C	15
Relative internal efficiency of gas turbine, %	89
Hydraulic pressure loss in the combustion chamber, %	3
Distribution of cooling flow in the first two stages, %/%	70/30
Mechanical efficiency, %	99
Efficiency of electric generator, %	99
Working environment of the organic Rankine cycle	R245fa
Temperature in the ORC cycle condenser, °C	30
Minimum temperature pressure in the waste heat recovery unit, °C	5
Internal relative efficiency of pump/compressor, %	85
Internal relative efficiency of turbine, %	85
Efficiency of electric generators and electric motors, %	99
Mechanical efficiency, %	99
Steam dryness level at turbine outlet, %	90

.

3. Methodology

The developed cycles were modeled using the algorithm shown in Figure 10. The mathematical model of the CCGT was divided into a gas turbine unit, a steam turbine unit, and an organic Rankine cycle. A monoethanolamine purification unit is used to remove carbon dioxide using post-combustion technology, and an integrated steam methane reforming unit is used for post-combustion. The carbon storage unit is used to bury carbon dioxide. In a CCGT with an integrated steam methane reforming unit, heat losses occur in the steam–water circuit associated with steam extraction from the ST but excess heat is also supplied to the STU, which is removed from the heated syngas.

The power of a combined-cycle plant is calculated using Formula (1):

$$N_e^{CCGT}=N_{GTU}+N_{STU}+N_{ORC},$$

(1)

where $N_{GTU}$ is the electrical power of the gas turbine unit, MW; $N_{STU}$ is the electrical power of the steam turbine unit, MW; $N_{ORC}$ is the electrical power of the organic Rankine cycle, MW.

The capacity of the combined-cycle plant’s own needs is calculated using Formula (2):

$$N_{ON}^{CCGT}=N_{ON}^{GTU}+N_{ON}^{STU}+N_{ON}^{ORC},$$

(2)

where $N_{GTU}$ is the energy costs for the own needs of the gas turbine unit, MW; $N_{STU}$ is the energy costs for the own needs of the steam turbine unit, MW; $N_{ORC}$ is the energy costs for the own needs of the organic Rankine cycle, MW.

Electricity losses for the own needs are calculated based on Equation (3):

$$N_{ON}^{Capture}=N_{SMR}^{ON}+N_{MEA}^{ON}+N_D,$$

(3)

where $N_{SMR}^{ON}$ is the energy costs for the own needs of the steam methane reforming unit, MW; $N_{SMR}^{ON}$ is the energy costs for the own needs of the monoethanolamine exhaust gas cleaning unit, MW; $N_D$ is the energy costs for CO₂ disposal.

The net efficiency for binary and trinary cycles with carbon dioxide capture systems is calculated using Formula (4):

$${\mathsf{\eta }}_{NET}^{GTU}={\displaystyle \frac{N_e^{CCP}-N_{ON}^{CCP}-N_{ON}^{Capture}}{B\cdot Q_l^h}},$$

(4)

where $B$ is the mass flow rate of methane; $Q_l^h$ is the lower calorific value of methane.

Modeling of the process flow diagrams of binary and trinary CCGTs with minimal carbon dioxide emissions was performed using the Aspen Plus program [31], which has found wide application in the calculations of processes in energy and petrochemical complexes and is often used in modeling carbon dioxide capture plants. Thermophysical properties of substances were determined using the NIST REFPROP database [32].

When modeling trinary and binary combined-cycle gas turbines with carbon dioxide capture, the following were applied:

-

Absence of chemicals under burning during the fuel combustion process;

-

No pressure loss in pipelines;

-

When fuel is distilled, no nitrogen oxides are formed.

The combustion process in the combustion chamber and reformer furnace proceeds according to Equation (5) for methane and Equation (6) for hydrogen:

$${\mathrm{C}\mathrm{H}}_4+2\cdot {\mathrm{O}}_2={2\cdot \mathrm{H}}_2\mathrm{O}+{\mathrm{C}\mathrm{O}}_2$$

(5)

$$2\cdot {\mathrm{H}}_2+{\mathrm{O}}_2={2\cdot \mathrm{H}}_2\mathrm{O}$$

(6)

The heat balance of the combustion chamber (7) is calculated from the sum of the heat of the combustion reaction of the fuel and the physical heat of the fuel and oxidizer:

$$B_f·\left(Q_l^h+h_f\right)+G_{air}{h}_{air}=\left(G_{air}+B_f\right)h_{CP}$$

(7)

where $B_f$ and $G_{air}$ are the fuel and oxidizer consumption in the combustion/afterburning chamber, kg/s; $Q_l^h$ is the lower calorific value of methane, kJ/kg; $h_f$, $h_{air}$ are the specific enthalpy of fuel and oxidizer entering the combustion chamber, kJ/kg; $h_{CP}$ is the specific enthalpy of combustion products, kJ/kg.

The net power of the gas turbine plant was determined using Formula (8):

$$N_{GTU}=\left(N_{GT}-N_{AC}\right)\cdot {\eta }_m\cdot {\eta }_{eg}-N_{FC}\cdot {\eta }_m\cdot {\eta }_{ed}$$

(8)

where $N_{GT}$ and $N_{AC}$ are the turbine and compressor power, defined as the sum of the power of a group of stages, kW; $N_{FC}$ is the power of the booster fuel compressor, kW; ${\eta }_m$, ${\eta }_{eg}$ and ${\eta }_{ed}$ are the mechanical efficiency of the electric generator and electric drive, respectively.

The mathematical model of the gas turbine developed in Aspen Plus is shown in Figure 11.

In the reformer of the steam methane reforming unit (Figure 12), the reaction of methane oxidation with vapor (3) takes place, and in the high-temperature reactor, the reaction of the water shift takes place, which are calculated based on Formulas (9) and (10), respectively [33]:

$$\mathrm{C}{\mathrm{H}}_4+{\mathrm{H}}_2\mathrm{O} \leftrightarrow \mathrm{C}\mathrm{O}+3{\mathrm{H}}_2 ; ∆{\mathrm{H}}_0=206.2 {\displaystyle \frac{\mathrm{k}\mathrm{J}}{\mathrm{m}\mathrm{o}\mathrm{l}}}$$

(9)

$$\mathrm{C}\mathrm{O}+{\mathrm{H}}_2\mathrm{O} \leftrightarrow \mathrm{C}{\mathrm{O}}_2+{\mathrm{H}}_2 ; ∆{\mathrm{H}}_0=-41.2 {\displaystyle \frac{\mathrm{k}\mathrm{J}}{\mathrm{m}\mathrm{o}\mathrm{l}}}$$

(10)

It is worth noting that the excess heat, which occurs during cooling of the synthesis gas, is sent to the steam turbine unit and is calculated using Formula (11):

$$Q_{stu}=Q_{HTR}+Q_{LTR}+Q_{HE}$$

(11)

where $Q_{HTR}$ is the thermal power HTR that is usefully utilized in STU, kW; $Q_{LTR}$ is the thermal power LTR that is usefully utilized in STU, kW; $Q_{HE}$ is the thermal power HE that is usefully utilized in STU, kW.

The heat balance (12) of the heat exchange surfaces of the waste heat boiler is determined as follows:

$$\left(G_{air}+B_f\right)\cdot \left({h_{\mathrm{g}}}^{\prime }-{h_{\mathrm{g}}}^{″}\right)=\phi \cdot G_{\mathrm{w}}\cdot \left({h_w}^{″}-{h_w}^{\prime }\right)$$

(12)

where ${h_{\mathrm{g}}}^{\prime }$ and ${h_{\mathrm{g}}}^{″}$ are the mass enthalpy of gases at the inlet and outlet of the waste heat boiler section, kJ/kg; ${h_w}^{″}$ and ${h_w}^{\prime }$ are the mass enthalpy of water/steam at the outlet and inlet of the section, kJ/kg; $G_{\mathrm{w}}$ is the flow rate of water/steam, kg/s; $\phi$ is the heat conservation coefficient, which characterizes heat losses to the environment.

When calculating the net power of the steam turbine plant shown in Figure 13, Formula (13) was used:

$$N_{STU}=\left(N_{HPT}+N_{LPT}\right){\eta }_m\cdot {\eta }_{eg}-{\displaystyle \frac{\left(N_{CP}+N_{FP}+N_{RP}\right)}{{\eta }_m\cdot {\eta }_{ed}}}$$

(13)

where $N_{HPT}$ and $N_{LPT}$ are the power of the groups of stages of the HPC and LPC, kW; $N_{CP}$, $N_{FP}$, and $N_{RP}$ are the power of the condensation, feed, and recirculation pumps, kW.

When calculating the net power of the organic Rankine cycle, shown in Figure 14, Formula (14) was used:

$$N_{OCR}=N_{FT}-N_{FP}$$

(14)

where $N_{FT}$ and $N_{FP}$ represent the power of the freon turbine and pump, respectively, kW.

Monoethanolamine purification (Figure 15) from carbon dioxide in the regeneration column is carried out by absorption [34], in which three main stages can be distinguished. In the first stage, carbamate is formed from monoethanolammonium according to Formula (15):

$${2\mathrm{N}\mathrm{H}}_2{\mathrm{C}\mathrm{H}}_2{\mathrm{C}\mathrm{H}}_2\mathrm{O}\mathrm{H}+{\mathrm{C}\mathrm{O}}_2\leftrightarrow {\mathrm{C}\mathrm{H}}_2{\mathrm{C}\mathrm{H}}_2\mathrm{O}\mathrm{H}\mathrm{N}\mathrm{H}\mathrm{C}\mathrm{O}\mathrm{O}{\mathrm{C}\mathrm{H}}_2{\mathrm{C}\mathrm{H}}_2\mathrm{O}\mathrm{H}{\mathrm{N}\mathrm{H}}_3$$

(15)

The carbamate undergoes hydrolysis by a slow reaction according to Formula (16), during which bicarbonate and a molecule of free mono ethanolamine are formed.

$${\mathrm{C}\mathrm{H}}_2{\mathrm{C}\mathrm{H}}_2\mathrm{O}\mathrm{H}\mathrm{N}\mathrm{H}\mathrm{C}\mathrm{O}\mathrm{O}{\mathrm{C}\mathrm{H}}_2{\mathrm{C}\mathrm{H}}_2\mathrm{O}\mathrm{H}{\mathrm{N}\mathrm{H}}_3+{\mathrm{H}}_2\mathrm{O}\leftrightarrow {\mathrm{C}\mathrm{H}}_2{\mathrm{C}\mathrm{H}}_2\mathrm{O}\mathrm{H}\mathrm{N}{\mathrm{H}}_2+{\mathrm{C}\mathrm{H}}_2{\mathrm{C}\mathrm{H}}_2\mathrm{O}\mathrm{H}{\mathrm{N}\mathrm{H}}_3{\mathrm{H}\mathrm{C}\mathrm{O}}_3$$

(16)

The resulting monoethanolamine again reacts according to Formula (17):

$${\mathrm{C}\mathrm{O}}_2+{\mathrm{C}\mathrm{H}}_2{\mathrm{C}\mathrm{H}}_2\mathrm{O}\mathrm{H}\mathrm{N}{\mathrm{H}}_2+{\mathrm{H}}_2\mathrm{O}\leftrightarrow {\mathrm{C}\mathrm{H}}_2{\mathrm{C}\mathrm{H}}_2\mathrm{O}\mathrm{H}{\mathrm{N}\mathrm{H}}_3{\mathrm{H}\mathrm{C}\mathrm{O}}_3$$

(17)

4. Results

To compare the thermodynamic characteristics of binary and trinary combined-cycle power plants with post-combustion carbon dioxide capture technologies, a capture and pre-combustion capture analysis was carried out with specific values relative to the total supplied thermal power. It is worth noting that for combined-cycle power plants with post-combustion carbon dioxide capture technology, the captured heat supply is carried out in the combustion chamber, for pre-combustion capture, this is carried out in the combustion chamber and reformer furnace.

According to the results of thermodynamic analysis of the binary CCGT with MEA, it was found that the gas turbine unit, taking into account electromechanical losses, generates 139.9 MW of electric energy, which is 32.34% of the total thermal power supplied to the CCGT. After that, the thermal power of the exhaust gases from the gas turbine, equal to 283.4 MW, is utilized in the steam–water circuit. However, due to the heat losses in the condenser, equal to 139.7 MW, and heat losses with the exhaust gases, equal to 58.7 MW, only 81 MW of electric energy is generated in the steam turbine. Taking into account the auxiliary needs of the steam turbine unit, which are spent on condensation and feed pumps, this value decreases to 79 MW. As a result, taking into account all the previously mentioned energy losses, the efficiency of the steam–water circuit of the CCGT is 36.01%.

It is worth noting that the losses with the exhaust gases in the waste heat boiler are associated with the high temperature of the exhaust gases, equal to 145 °C. Deeper cooling of the exhaust gases in binary combined-cycle plants is simply impossible due to the heating of the condensate in the low-pressure regeneration system and the deaerator to 106 °C. Figure 16 shows the energy diagram of a binary combined-cycle plant.

The total generation of electric energy in the gas–air and steam–water circuit is 218.5 MW, which is 50.52% of the heat supplied to the cycle. At the same time, 40 MW of thermal energy is required to remove carbon dioxide, and 9.6 MW for disposal. As a result, the energy efficiency of the CCGT with MEA is 39.10%. Figure 17 shows a diagram of the in-house needs for the removal and disposal of carbon dioxide in a binary combined-cycle plant with mono ethanolamine cleaning of flue gases.

The results of modeling a trinary CCGT with monoethanolamine cleaning of exhaust gases enabled us to establish that the presence of a developed regeneration system allows us to reduce losses in the STU condenser by 30.6 MW, i.e., by 7.07% of the total thermal power supplied to the CCGT. As a result, this leads to the fact that the efficiency of the steam–water circuit of the CCGT increases by 3.09% and is 39.10%. However, due to the presence of a developed regeneration system, losses with exhaust gases at the outlet of the waste–heat boiler increase by 38.6 MW relative to a binary CCGT with MEA. This effect is associated with an increase in the feedwater temperature by 34 °C, due to which the temperature of the exhaust gases at the outlet of the waste–heat boiler increases to 205 °C.

To utilize 97.2 MW of low-potential heat in trinary cycles, an organic Rankine cycle is used in the utilization turbine from which 15.5 MW of electric energy is generated. When taking into account the in-house needs that are spent on the operation of the utilization pump, this value decreases to 13.2 MW. It is worth noting that the temperature of the working medium at the inlet to the utilization turbine is 190 °C, due to which large losses in the condenser are observed in the low-boiling cycle, equal to 54.7 MW.

During the thermodynamic analysis, it was established that due to the deeper utilization of the available trinary combined-cycle gas turbine thermal energy, the temperature of the exhaust gases decreases to 80 °C, which reduces the losses with exhaust gases at the outlet of the gas–air circuit of the power unit by 31.9 MW relative to the binary combined-cycle gas turbine. Figure 18 shows the energy diagram of the trinary combined-cycle gas turbine.

The gross cycle power is 224.4 MW. The combustion product consumption is 508.7 kg/s, which is identical to the combustion product consumption in a binary combined-cycle plant, and due to this, the energy costs for carbon dioxide removal and disposal remain unchanged. As a result, the net efficiency of the trinary combined-cycle plant is 40.35%. Figure 19 shows the diagram of the in-house needs for carbon dioxide removal and disposal of a trinary combined-cycle plant with monoethanolamine purification.

Hydrogen fuel is produced using an integrated steam methane reforming unit in a binary combined cycle (Figure 20). To ensure the endothermic reforming reaction, the combustion products at the gas turbine outlet are heated from 535 °C to 875 °C using a reformer furnace, which supplies 160 MW of additional thermal energy to the CCGT cycle. To increase the thermal power supplied to the cycle, the fuel consumption in the CCGT power cycle is increased by 3.19 kg/s compared to combined-cycle units with monoethanolamine flue gas cleaning. As a result, 66.97% of the total heat supplied to the cycle is supplied to the combustion chamber and 34.12% to the reformer furnace.

The simulation results showed that a total of 402.9 MW of thermal energy is supplied to the steam methane reforming unit, of which only 218.8 MW is used to heat the synthesis gas to a temperature of 850 °C. At the same time, 27.1 MW of heat is lost in the steam reforming process, and the remaining heat, equal to 191.7 MW, is usefully utilized in the steam turbine cycle, which leads to an increase in steam consumption in the steam turbine by 1.92 times (61.05 kg/s).

After the first selection, 51.99 kg/s of steam is selected from the steam turbine for the steam reforming reaction in the reforming unit. A total of 51.99 kg/s of make-up water is supplied to the condenser, which, after heating in the regeneration system to a temperature of 107 °C, is sent to utilize excess heat in the steam methane reforming unit. The above factors determine the increase in capacity in the steam cycle by 11.38 MW relative to the binary unit with MEA, while the operation of the steam methane reforming unit requires 2.8 MW of electric energy for the SMR’s own needs and 14.3 MW for carbon dioxide disposal. As a result, the efficiency of the power unit relative to the binary steam–gas cycle with monoethanolamine flue gas cleaning increases by 1.16% and amounts to 40.26%. The energy diagram of a binary CCGT that takes into account the costs of the steam conversion of methane is shown in Figure 21.

Thermodynamic analysis of the trinary combined-cycle gas turbine with integrated steam reforming unit (Figure 22) showed that utilization of 191 MW of synthesis gas heat allows for increasing the available capacity of the steam turbine by 19.2 MW relative to the binary combined-cycle gas turbine with integrated steam reforming unit. This increase is because, due to the developed regeneration system, losses in the condenser are reduced by 6.69 MW, from which the efficiency of the trinary combined-cycle gas turbine with integrated steam reforming unit increases by 0.16% relative to the binary unit.

The net capacity of the trinary CCGT with an integrated steam methane reforming unit is 250.7 MW. The combustion product consumption is 505.6 kg/s, which is identical to the combustion product consumption in a binary combined-cycle gas turbine with an integrated steam methane reforming unit, due to which the energy costs for the removal and disposal of carbon dioxide remain unchanged. It is worth noting that the losses for the SMR’s own needs and the disposal of carbon dioxide do not change relative to the combined binary combined-cycle gas turbine with steam methane reforming. As a result, the efficiency of the power unit increases by 1.27% and amounts to 41.62% (Figure 23).

Comparison of the results of this study of the four considered process flow charts of combined-cycle plants with minimal emissions of harmful substances into the atmosphere allows us to conclude that the transition of a binary combined-cycle plant from monoethanolamine cleaning of exhaust gases to hydrogen combustion with fuel production using a steam methane reforming unit allows us to increase the efficiency by 1.16%, and for a trinary combined-cycle plant by 1.27%. The difference in energy efficiency of 0.11% is due to the fact that the thermal energy supplied to the cycle is utilized in a more energy-efficient steam–water circuit with a developed regeneration system, which allows us to reduce thermal energy losses in the condenser of the trinary cycle by 6.69 MW relative to binary combined-cycle plants. As a result, due to the steam methane reforming unit in the binary combined-cycle plant, an additional 16.2 MW is generated. In a trinary installation, due to the reduction in losses in the capacitor, this value increases by 0.6 MW and equals 16.8 MW.

The results of the comparison of the energy efficiency of trinary and binary combined-cycle gas turbines with integrated carbon dioxide capture systems are presented in Figure 24. The most efficient cycle is the trinary combined-cycle gas turbine with a net efficiency of 41.62%. This efficiency is achieved by reducing the costs of the carbon dioxide capture system’s own needs by 5.67 MW relative to combined-cycle gas turbines with mono ethanolamine flue gas cleaning. This is due to the absence of additional costs for mono ethanolamine desorption using a reboiler, which consumes 40 MW of electrical energy.

With an increase in energy efficiency by 2.53% and an increase in net power by 64.5 MW, specific CO₂ emission decreases by 1.39 times relative to the binary cycle with MEA. A comparative diagram of the change in specific carbon dioxide emissions when using different technological solutions is shown in Figure 25.

5. Conclusions

In this paper, process flow diagrams and mathematical models of the following combined-cycle plants with carbon dioxide capture technologies for post-combustion and pre-combustion capture are developed:

(1)

Binary combined-cycle plant with monoethanolamine cleaning of exhaust gases;

(2)

Three-stage combined-cycle gas turbine with monoethanolamine cleaning of exhaust gases;

(3)

Binary combined-cycle gas turbine with integrated steam methane reforming unit;

(4)

Trinary combined-cycle gas turbine with integrated steam methane reforming unit.

Based on the results of mathematical modeling of process flow diagrams of combined-cycle power plants with a temperature and pressure at the inlet of the gas turbine equal to 1060 °C and 1.09 MPa, energy diagrams were compiled; based on this, it was established that when switching from a binary combined-cycle plant with monoethanolamine cleaning of exhaust gases to a binary combined-cycle plant with an integrated steam methane reforming unit, the net efficiency increases by 1.16%. This is due to the following reasons:

(1)

During the cooling of synthesis gas in a steam methane reforming unit, 27.1 MW of thermal energy is lost in the cooler–separator but during monoethanolamine cleaning of exhaust gases, 40 MW of electrical energy must be spent on heating the amine in the reboiler;

(2)

When switching from a binary combined-cycle plant with MEA to a binary combined-cycle plant with an integrated SMR unit, energy losses for carbon dioxide disposal increase by 4.7 MW, which is associated with an increase in carbon dioxide emissions by 33% due to an increase in fuel consumption by 3.19 kg/s;

(3)

For the steam reforming reaction to take place, 52 kg/s is removed from the steam turbine, however, due to the fact that when utilizing 191.7 MW of thermal energy, 61 kg/s of steam is generated—which is sent to the steam turbine unit—the net capacity of the steam turbine unit increases by 16.2 MW.

A comparative analysis of the energy and thermodynamic characteristics showed that the transition from a binary to a trinary combined-cycle gas turbine with monoethanolamine cleaning of exhaust gases leads to an increase in net efficiency by 1.25%. This is due to the following reasons:

-

An increase in total losses in the condensers of the steam turbine and the central heating system by 24.2 MW;

-

An increase in the total own needs of the steam-turbine unit and the central heating system by 1.4 MW;

-

A reduction in losses with exhaust gases at the outlet of the gas–air circuit of the combined-cycle power plant by 31.7 MW;

-

An increase in the net capacity of the combined-cycle power plant by 5.4 MW.

The simulation results allowed us to establish that the transition of a binary combined-cycle plant with an integrated SMR unit to a trinary combined-cycle plant with an integrated SMR unit allows us to utilize 191.7 MW of thermal energy removed from the reformer in a more efficient steam–water circuit with an advanced regeneration system, the efficiency of which is 0.16% higher than that of a steam–water circuit without an advanced regeneration system. As a result, the increase in steam consumption in the steam turbine by 61 kg/s leads to the fact that in a binary combined-cycle plant with an integrated SMR unit an additional 15.2 MW is generated, and in a trinary combined-cycle plant with an integrated SMR unit this generates an additional 16.8 MW relative to a combined-cycle plant with a MEA. The increase in net electric power in a trinary CCGT unit with an integrated SMR unit by 1.6 MW results in an increase in efficiency by 1.36% relative to a binary combined-cycle plant with an integrated SMR unit.

Thus, it has been established that the highest energy efficiency is observed in a three-stage combined-cycle gas turbine unit with an integrated steam methane reforming unit, the net efficiency of which is 41.62%, while this technical solution has the lowest specific carbon dioxide emissions, equal to 23.4 g/kW·h.