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: The Environmental Impact of Implementing CO2 Capture Process in Power Plants: Effect of Type of Fuel and Energy Demand

Carolina Mora-Morales[1] [2] [3] Juan Pablo Chargoy-Amador;2 Nelly Ramirez-Corona,1 Eduardo Scinch ez-Ramirez[3] and Juan Gabriel Segovia-Hernandez[3] *


Global warming is currently recognized as a major environmental problem that affects humans worldwide (McCarthy et al., 2002; O'Neill and Oppenheimer, 2003). The high CO, concentrations and continuous emissions tend to deteriorate the environment. Currently, CO, is produced by several industrial processes, such as the combustion of fossil fuels, to produce electricity and in the transport sector. Recently, the Energy Information Administration of the United States (EIA) reported that global CO, emissions will glow at an average rate of 0.6% from 2015 to 2040, compared to the 1.3% growth from 1990 to 2015. The total amount of CO, emissions continues to grow, especially in developing countries, including China and India. This is due to the growing economy which results in an increase in the country’s energy demand. The general combustion reaction for hydrocarbons can be represented by equation (1), where it is the molar ratio of air required in excess of stoichiometric oxygen required.

Studies that have analyzed the environmental effect of greenhouse gases consider that CO, contributes 60% of the effects of global warming (Olajire, 2010). The intergovernmental panel on climate change

(IPCC) lias predicted that the atmosphere could contain up to 570 ppm of CO,, causing a remarkable increase in the world temperature of approximately 1.9 °C and an increase in sea levels of 3.8 m by 2100 (Olajire, 2010). Moreover, other studies forecast rises in temperatures in a range of 2-4 °C (Godard, 2008), on the other hand, the IPCC also predicts CO, concentration of about 705 ppm by 2100 and over 900 ppm by 2200 in the A1B scenario (A future world of veiy rapid economic growth, low population growth and rapid introduction of new and more efficient technology).

A special report from the IPCC on CO, capture and storage reports global emissions in the year 2000 of 23.5 GT, attributing more than 60% to 4942 electricity production stations that issued about 10.5 GT/ year of CO,. The remaining 40% of the emissions were due to the transport sector and the rest from other sectors, such as buildings, industry and so on. For example. Figure 1 shows an average measure of global CO, emissions.

Considering the aforementioned, the production of greenhouse gases due to electric generation is of relevant importance.

Combined cycle thermoelectric plants are systems that jointly produce electricity and thermal energy from a single fuel. In combined cycles, the fuel, mainly natural gas, is injected into a mixture with ah' to a turbine where combustion takes place. The kinetic force of the combustion gases causes the turbine to turn, and taking advantage of the movement in an alternator, electricity is produced. The heat that prer ails in the exhaust gases of the turbine is used to boil water through a heat exchanger and steam generator. The steam produced is used in a conventional thermal cycle to move another turbine and generate electricity by turning another alternator. The advantage of these over conventional plants is that they take better advantage of the energy produced in the boiler by burning the fuel, thus achieving greater efficiencies and, in turn, having lower CO, and NOx emissions (Franco and Giannini, 2005).

Currently, electricity from power plants represents a mam source of energy around the globe. For example, in the United States, the electricity generation from coal and natural gas is in the three major categories along with nuclear energy and renewable energy. Specifically, within the fossil fuels, natural gas is the largest source (about 32% in 2017). Natural gas is used directly to produce steam or even to operate a gas turbine to generate electricity. An example of this type of thermal power plant is the one of Iligau in the Philippines, which has an installed capacity of 1,251 MW and is the plant with the highest thermal efficiency in the world thanks to the use of type G gas turbines produced by Mitsubishi Heavy Industries, Ltd. (Tsutsumi et al., 2003). Table 1 shows some numerical advantages of using combined cycle.

On the other hand, in the USA, coal was the second energy source (about 30% hi 2017), in the same sense as natural gas, coal is almost all used in coal-fired power plants which use a turbine to generate electricity. Finally, petroleum was in 2017 the source with less than 1% of use in the U.S. In the same way as previous examples, residual fuel and petroleum coke are used in steam turbines. Note in Figure 2, the electricity generation by major source from 1950 to 2017 in the U.S.

Currently, the options to reduce total CO, emissions can be summarized in three options: (1) enhance conversion efficiency: (2) use a low/carbon-free fuel, and (3) improve CO, capture. The first option requires the efficient use of energy. The second requires a radical change in current fuels, for example, hydrogen or renewable energies. The thud option involves the development of technology to improve CO, capture. Note, a combination of these three options is probably the best choice, rather than a single one.

CO, Capture Technologies and Life Cycle Assessment

The CO, cap true of a gaseous effluent is an essential parameter for the viability of coal and CO, capture plants. Freund (1996) showed that capture technologies for emissions generated by electricity generation can be categorized via these three options: Pre-combustion, oxyfuel combustion and post-combustion. The selection of the appropriate method depends on the concentration of CO, in the gas stream, the gas pressure in the stream and the type of fuel. Below is a brief analysis of each alternative.

Global C0 emissions and Global Greenhouse Gas emissions by sector Partially extracted from C2ES (2017)

Figure 1. Global C02 emissions and Global Greenhouse Gas emissions by sector Partially extracted from C2ES (2017).

Table 1. Advantages of using combined cycles (Tsutsumi et al., 2003).

Combined cycles

Conventional process

Energetic Efficiency



CO, Emissions

360 g CO,/kWh

850 g CO,/kWh

Water Consumption

435 mVh (400 MW)

875 m3/h (400 MW)

Electricity generation by several sources in the U.S

Figure 2. Electricity generation by several sources in the U.S.

Pre-combustion capture

In pre-combustion capture, the fuel reacts with oxygen or air, and in some cases with steam, to produce mainly carbon monoxide. This process is known as gasification, partial oxidation or reforming. The mixture of CO and H, is passed through a catalytic reactor where the CO reacts with steam resulting in CO, and more H,. The CO, is separated and the H, is used as fuel in a gas turbine in a combined cycle plant. This technology is usually useful for coal gasification (IGCC), however, it can also be applied to liquid or gaseous fuels. Typically, the reaction for IGCC is shown in equations (2)-{4).

Oxyfuel combustion

Oxyfuel combustion is, in fact, a modified post-combustion method. The fuel is burned with ahnost pure oxygen instead of air, which results in high concentrations of CO, in the gas flow. Operationally speaking, if the fuel is burned in pine oxygen, the temperature of the flame is likely to be excessively high, so there is the possibility of recycling the CO, rich combustion gas to the burner to make the flame temperature similar to that obtained in a combustion chamber with conventional air.

The advantage of oxygen combustion is that the gas effluent can reach a concentration higher than 80%, thus, only a simple CO, purification is required. Additionally, NOx formation is suppressed. On the other hand, the great disadvantage of oxyfuel combustion is the large amount of pure oxygen that is needed.

Post-combustion capture

The capture of CO, in post-combustion involves the separation of CO, from a gas stream produced by the combustion of some fuel. The post-combustion capture is a separation process and, in several aspects, has characteristics similar to gas desulfurization (FGD), which is widely used to capture the SO, in gas effluents from power plants where coal and oil are burned. The low concentration of CO, in the gas effluents of power plants (typically between 4% and 14%) means, operationally, that a large amount

Block diagrams illustrating post-combustion, pre-combustion and oxyfuel combustion techniques

Figure 3. Block diagrams illustrating post-combustion, pre-combustion and oxyfuel combustion techniques.

of gas volume is processed, and consequently, the size of the equipment is large and comes with a high capital cost.

The capture of CO, in post-combustion is a significant challenge due to the low partial pressures of CO, in the gas stream. Additionally, the relatively high gas outlet temperature offers an additional challenge. On the other hand, a clear disadvantage of the low concentration of CO, is that, for its capture, powerful solvents must be used and, subsequently, the solvents must be regenerated by investing a certain amount of energy. Figure 3 shows the difference between the three alternatives already mentioned.

2.3.1 Chemical absorption

A typical chemical absorption process consists of an absorber and a separator where the absorbent is regenerated. In a chemical absorption process for CO, capture, the gas effluent enters the bottom of an absorber and comes into contact in countercurrent with a CO, absorber. After the absoiption process, the gas effluent enters a separator for thermal regeneration. After regeneration, the CO, burner is returned to the absorber for reuse. The pure CO, is released from the separator to be subsequently compressed and transported. The operating pressure is about 1 bar and the operating temperatures of the absorber and separator are generally in the range of 40 °C to 60 °C and 120 °C to 140 °C, respectively. Theoretically, the minimum energy required for the recovery of CO, from a gas effluent and its subsequent compression is approximately 0.396 GJ/ton (Yu et al., 2012), considering compression of 150 bar. Therefore, there is a great opportunity to improve the absoiption efficiencies, as well as the regeneration of the solvent. Currently, several authors have reported data associated with regeneration energy, for example Versteeg and Rubin (2011) and Jilvero et al. (2011) reported an energy regeneration between 2.2-2.8 GJ/tonCCh using NH3 (10 °C), in the same sense, Mirfendereski and Geuzebroek (2009), reported 2.33 GJ/tonCCh using CANSOLV.

The advantage of a chemical absoiption is that it is currently the technology with the highest maturity for the capture of CO, and has been commercialized for several years. Another advantage of this technology is that the retrofitting process is quite adequate for existing power plants.

Regarding absorbents, alkauolamines are widely used for CO, capture. The structure of the alkanolamines (including their primary, secondary and tertiary variants) is that they contain at least one OH group and one amino group, for example, monoethanolamine (MEA), diethanolamine (DEA) and N-methyldiethanolamine (MDEA). The reactivity of said amines to CO, follows the primary, secondary and tertiary order, for example, the reaction constants for CO, are 7000, 1200 and

3.5 mVs/kmol for MEA. DEA and MDEA at 25 °C, respectively (Sada et al., 1976). On the contrary, the loading capacity for a tertiary amine is approximately 1 mole of CO, per mole of amine, a greater number compared to primary and secondary amines that report load capacities between 0.5-1 mole of CO, per mole of amine. Table 2 shows the type of alkanolamines used in the capture of CO,, highlighting monoethanolamine, 2-(2aminoethylaminp) ethanol (AEEA), Piperazine (PZ), N-methyldiethanolamine (MDEA). 2-amino-2-methyl-l-propanol (AMP) and dietliylenetriamine (DETA).

In general, the absorption/separatiou process is a process with a certain energy cost. According to Rochelle et al. (2009). the price per ton of CO, is in the range of 52 to 77 S/Tco. On the other hand, the energy needed to capture CO, in a conventional coal-buming power plant is between 3.24 and 4.2 GJ/ton (McCarthy et ah, 2002). In this process, most of the energy consumed is associated with the regeneration of the absorbent, approximately 60%. In this way, a point of opportunity to reduce energy expenditure would be to impl or e the operation of the separator.

Table 2. Physicochemical properties of the common alkanolammes used as absorbents.








MW (g/mol)







Density (g'cm3)







Boiling Pomt (K)







Vapor Pressure (393 K) (kPa)







Solubility (293 K)

Freely soluble

Freely soluble

14 wt%

Freely soluble

Freely soluble

Freely soluble

CO, Absortion capacity (mol of CO,/mol of absorbent)






Life cycle assessment

The capture and use of CO, (CCU) and its potential environmental benefits are now gaining attention (Cokoja et ah, 2011; MacDowell et ah, 2010; Plasseraud, 2010). The capture of CO, and the subsequent use of CO, as an alternative source of carbon promises a reduction both in greenhouse gases and in fossil fuel depletion (Peters et ah, 2011; Quadrelli et ah. 2011). However, both the capture and subsequent activation of CO, is an operation with considerable energy requirements, indirectly causing emissions of greenhouse gases. In this way, the intuitive benefit of CO, capture and reuse is apparently not so clear and analysis needs to be done in a critical and systematized manner. Moreover, as mentioned earlier, the regeneration of the solvent plays a main role in the energy requirements, so in the same sense, the solvent chosen plays the same role in the life cycle assessment. On the other hand, due to the greenhouse gas emissions, the fuel burned in the power plant also plays a significant role.

A systematic and standardized way to evaluate the environmental impact of both processes is a life cycle assessment (LCA), which will be described in the section below. LCA is the methodology used to measure the potential environmental impact of any product, process or system, from raw materials extraction to end of life stage (IHOBE, 2009).

According to ISO 14040, LCA has 4 phases: Goal and scope definition, inventory analysis, impact assessment, and interpretation. In the first one, the products to be studied shall be clearly defined in terms of the function that the product performs. The second, inventory analysis, involves data collection and calculation procedures to quantify the consumption of energy, raw material, air emissions, water discharges, and solid wastes. The next phase is impact assessment, where the results of the inventory analysis are added up into environmental impacts using common equivalent units; for example, burning a fuel in a given process can be associated with effects on the impact categoiy of global warming, which are measured in kilograms of CO, equivalent. The fourth phase of an LCA is an interpretation, where the results obtained should be analyzed in order to establish understandable recommendations and decision arguments.

Next, the four stages (Figure 4) involved in LCA study are presented (IHOBE, 2009).

With all this background, in the present chapter, the environmental impact of different scenarios of thermoelectric plants coupled to CO, capture processes will be analyzed with a reactive absoiption and desoiption system using monoethanolamine (MEA) as a liquid solvent. The scenarios to be evaluated include the use of four different fuels: Biogas, coal, natural non associated gas and associated gas; as well as variants in the combined cycle to analyze the effect of the processes with constant fuel flow and constant energy demand.

LCA steps (ISO 14040:2006)

Figure 4. LCA steps (ISO 14040:2006).

  • [1] ; Departamento de Ingemeria Quimrca, Alunentos у Ambiental, Universidad de las Americas Puebla. ExHda. Santa CatarinaMartir s/n, San Andres Cholula, Puebla, Mexico, 72820. Email: This email address is being protected from spam bots, you need Javascript enabled to view it
  • [2] Centro Analisrs de Ciclo de Ada у Diseno Sustentable (CADIS), Bosques de Bohemia 2, No. 9, Bosques del Lago,Cuautitlan Izcalli, Estado de Mexico, Mexico, 54766. Email: This email address is being protected from spam bots, you need Javascript enabled to view it
  • [3] Departamento de Ingemeria Quimica, Universidad de Guanajuato, Nona Alta s/n, Guanajuato, Gto., 36050, Mexico. * Conesponding author: This email address is being protected from spam bots, you need Javascript enabled to view it
  • [4] Departamento de Ingemeria Quimica, Universidad de Guanajuato, Nona Alta s/n, Guanajuato, Gto., 36050, Mexico. * Conesponding author: This email address is being protected from spam bots, you need Javascript enabled to view it
  • [5] Departamento de Ingemeria Quimica, Universidad de Guanajuato, Nona Alta s/n, Guanajuato, Gto., 36050, Mexico. * Conesponding author: This email address is being protected from spam bots, you need Javascript enabled to view it
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