*3.1. Oxy-Combustion Carbon Capture*

In this method, fuel is burnt in almost pure oxygen rather than air. Flue gas produced in this process is mainly a mixture of water and carbon dioxide. In a conventional power plant, fuel is combusted in air and the nitrogen of the air acts as a temperature moderator. As there is no N2 present in the combustor of oxy fuel combustion, the flame temperature becomes too high. To keep the temperature within the limit, recycled CO2 is passed to the combustor with pure oxygen. Another way to keep the flame temperature in the desired range is to inject steam in the combustion chamber [87].

After combustion, water is removed from the product by condensation [5]. The captured CO2 is purified and compressed to supercritical condition for transporting or using again in the cycle. A flow sheet of the oxy fuel combustion concept is shown in Figure 11.

**Figure 11.** Flowsheet of oxy fuel combustion technology for power generation with CO2 capture [5].

Since the properties of CO2 and N2 are di fferent, the reaction pathway and combustion characteristics di ffer in oxy combustion from conventional air-fuel combustion [88]. These anomalies in the combustion characteristics demand in-depth research to understand and utilize this method.

Oxy fuel combustion has additional advantages compared to conventional combustion. There remains a large amount of N2 in a conventional air firing system. Nitrogen consumes a lot of heat before being released to the environment, but in oxy combustion, this bulk N2 is absent in the combustion environment. Due to the absence of nitrogen, there is no or much less production of NOx in this process. There are no other significant pollutants in the products of combustion. The oxy fuel combustion technique is therefore a less expensive method compared to the previously discussed carbon capture technologies.

The main disadvantage of this method is the high operational cost for producing O2 and pressurizing CO2 after combustion [89]. One of the main challenges of this method is to produce oxygen with high purity at a reasonable expense. Wu et al. [90] summarized di fferent work done on the separation process of oxygen from the air for use in oxy fuel combustion. They argue that membrane methods are more economical and simpler compared to the cryogenic method. The authors also suggested that adsorption technology is not ye<sup>t</sup> updated to implement on large scales. Rather, a chemical looping air separation method is highly promising to become a more e fficient and cost-e ffective technique for implementation in oxy fuel combustion.

A lot of research is ongoing to understand and improve the oxy-combustion method. Boiler design may be improved to enable more compact equipment with a deep understanding of oxy fuel combustion [91]. Knowledge of the combustion procedures will be necessary for this. With the use of a compact boiler, the cost of power generation can be reduced. This process helps reduce the amount of flue gas and thus the heat loss from the flue gas stream. It also reduces SOx and NOx emissions and improves combustibility. It has the potential to be more economical than other conventional processes.

The application of burning a fuel in pure oxygen was first done for di fferent industrial processes. Later Abraham et al. [92] suggested this method as a solution to provide a large amount of CO2 for oil recovery, but recycled flue gas was not used in that time. Later, the idea of using recycled flue gas was applied to produce a high purity CO2 stream to use in oil recovery. It was also seen that this method could decrease the environmental impacts of fossil fuel power plants [93]. It can be applied with coal and natural gas. When this method is applied to coal, it can be classified as either an oxy-pulverized coal process or an oxy coal fired boiler process. In the case of natural gas, it can be classified as a CO2-based cycle or water-based cycle [94].

For a conventional power plant using pulverized coal combustion, the concentration of CO2 in the flue gas is relatively low (12–16%v dry basis). In the case of an oxy pulverized coal boiler, the air is replaced with pure oxygen. This results in a flue gas containing a high concentration of CO2 (65–85%v dry basis) [94]. Rohan et al. [95] discussed the impact of Sulphur in oxy PC combustion. They reported that ash collection, furnace, CO2 compression, transportation, and storage might be a ffected by Sulphur. If the recycle stream is taken before the flue gas clean up, it will increase the concentrations of the impurities, especially SOx, in the furnace. The emission of SO2 in oxy fuel combustion is lower than in air-combustion because of the retention of Sulphur in ash.

In comparison with other systems, Chen et al. [96] found that an oxy fuel system shows 1–5% less loss of e fficiency than post combustion capture. The pressurized system gains around 3% more efficiency. Though the ASU requires more power in a pressurized system, it saves greater power during compression of CO2. Chen et al. [96] also concluded that absorptivity and emissivity of the flue gases increase due to higher partial pressure in oxy fuel combustion. The optimized ratio of the recycle stream primarily depends on the type of fuel, the arrangemen<sup>t</sup> of the heat recuperator and the strategy of recycling. They found no influence of the oxy fuel environment on the devolatilization process of the solid fuel. Another finding is that ignition delay is longer in the combustion environment of an oxy fuel system than that of a conventional system.

Some researchers have investigated the e ffect of recycled CO2 on the combustion environment. The burning velocity or speed of the propagation of a flame could decrease due to the incorporation of CO2 instead of N2 in the combustion environment [97]. Oh and Noh [98] examined the flame speed in an Oxy fuel environment in the atmospheric condition with a rich and lean fuel mixture. It was found that the speed of a methane flame in the oxy fuel environment is faster than that in an air-fuel environment which is contradictory to the results of Ref. [97]. Chen suggested that this discrepancy may result from the di fferent prototypes used in these studies [97]. In previous research, the flame temperature was lower in the oxy fuel environment than the air-fuel environment, whereas in later research it was higher in the oxy fuel environment.

Mazas et al. [99] investigated the e ffect of water vapor on the speed of flame propagation [100]. They observed that with an increase in the molar fraction of steam, the flame velocity would decrease quasi-linearly, even at a high rate of dilution. The reduction in the burning velocity was larger for air combustion than oxy fuel combustion with the increase of the molar steam fraction. The e ffect of the equivalence ratio, CO2 fraction, and pressure on the speed of oxy-methane flame was experimentally and numerically investigated by Xie et al. [100], who found that an increase in the CO2 fraction would reduce the flame speed in CH4/O2/CO2. Due to the presence of CO2 in the oxy fuel environment, the radiation e ffect of CH4 was much stronger.

Another important combustion parameter is the maximum flame temperature. Since the function of CO2 in the combustor of oxy fuel environment is to control temperature, the temperature of the flame

drops when CO2 is added, but it has been shown that this decrease in temperature is not linear [97]. This is because the thermal e ffects are stronger at higher CO2 concentrations. Wang et al. [88] examined the chemical and physical e ffects of CO2 to find the dominant e ffect for determining the maximum flame temperature. They used di fferent mole fractions of water and carbon dioxide in a counterflow oxy fuel combustion using methane as fuel. The maximum flame temperature was not a ffected because of the lower di ffusion coe fficient of CO2, but a significant di fference was observed in the temperature profile. They also noticed that the presence of H2O did not have much influence on the maximum flame temperature. Pressure may also a ffect the maximum flame temperature. Seepana and Jayanti [101] numerically investigated the e ffect of pressure varying between 0.1 and 3 MPa in an oxy fuel environment. Their results indicated that the flame temperature would increase with an increase in the pressure, rapidly at first and then gradually. Low NOx oxy fuel flame was found at high pressure with increased oxygen dilution.

Limited research has been conducted to improve understanding of the e ffect of ignition, flame stability, and flame extinction in an oxy combustion environment. Koroglu et al. [102] conducted a detailed experiment with methane to study ignition in an oxy fuel environment. They used a shock tube facility to do this experiment. The pressure was varied from 1 to 4 atm with temperature ranging from 1577 K to 2144 K. Their results revealed that the ignition delay would be longer when methane is burned in an O2/CO2 environment than in an O2/N2 environment due to the participation of CO2 in chemical reactions, higher heat capacity, and di fferent collision e fficiency. A similar experiment was performed by Pryor et al. [103] at high pressure ranging from 6 to 31 atm and temperature varying between 1300 K and 2000 K. Using a sensitivity analysis, the authors showed that CO2 could slow down the overall rate of reaction and increase the time of ignition delay.

Several research works have been done to determine the flammability of oxy methane flames. With the addition of CO2, upper flammability decreases dramatically whereas it does not a ffect the lower flammability significantly [104]. An addition of steam also has an influence on the flammability limit of oxy combustion flame. The flammability limits become broader with the addition of CO2 which is attributed to the lower heat capacity of steam compared to the supercritical CO2 [97]. Some of the main studies on oxy fuel combustion are listed in Table 5.


**Table 5.** Some of the important studies on oxy combustion carbon capture.

A novel approach for power generation using oxy fuel combustion was proposed by Allam et al. [107]. The proposed Allam cycle is basically a Brayton cycle operating pressurized supercritical CO2 as the working fluid. The heat capacity of the high-pressure CO2 is much higher than low-pressure CO2. The Allam cycle uses this distinct thermodynamic property of CO2. Since CO2 is used as a working fluid in this cycle, there is no need to vaporize and condense water for the cycle. A high-pressure combustor burns the fuel in pure oxygen and produces a feed stream with pressure ranging from 200–400 bar. This stream is expanded in a single turbine with a pressure ratio ranging from 6 to 12. The heat of the high-temperature exhaust of the turbine is transferred to a high-pressure recycled CO2 stream in a recuperator. The recycled stream is sent back to the combustor to control the turbine inlet temperature. With the help of theoretical analysis, the authors reported a (LHV-based) thermal efficiency of 59% for the cycle operating on natural gas and 52% when the cycle uses coal as the fuel while capturing CO2 inherently. A schematic of the Allam cycle operating on natural gas and coal as fuel is shown Figures 12 and 13, respectively.

The construction of a 50 MWth demonstration plant operating on natural gas fired Allam cycle has just been completed in La Porte, Texas. A commercial 300 MW plant is in the planning stage to demonstrate the advantage of this cycle [114]. Since no extra measures are needed for capturing CO2, this method is expected to produce electricity at a cost much lower than other conventional power plants using CCS.

As a new and potentially viable method to reduce carbon dioxide emissions from fossil fuel power plants, research is ongoing to optimize the parameters of the Allam cycle. The efficiency of this cycle is sensitive to the turbine inlet temperature and pressure, turbine outlet pressure, temperature difference on the hot side of the primary heat exchanger and the performance of the air separation unit of the cycle. Figure 14 depicts a distribution of the total power production of the turbine for the natural gas-fired Allam cycle. A similar graph is presented in Figure 15 which shows various losses as a percentage of the fuel thermal input. The figures are constructed using the simulation results of Mitchell et al. [116].

**Figure 12.** Schematic of the Allam power cycle operating on natural gas as fuel [107].

**Figure 13.** Schematic of the coal-fired Allam power cycle [115].

**Figure 14.** Distribution of the turbine power production in the natural gas-fired Allam cycle.

The power requirement of the CO2 pressurization is the largest; it consumes about one-fifth of the turbine gross power. The second largest power-consuming component is the ASU, which requires 12% of the turbine power production. The fuel compressor requires ~1% of the turbine power. The total penalty is 34% so that 66% of the turbine gross power is transmitted to an electric generator as the net power output. From Figure 15, 12.4% of the fuel energy is discharged to the surroundings in the form of waste heat so the gross cycle efficiency is 87.6%. The total penalties account for 29.6% of the fuel thermal input which upon subtracting from the gross efficiency, the net cycle efficiency is found to be 58%. The cycle developers have also examined employing two turbines in the cycle. They have reported a noticeable increase in the power output while the capital cost increased a little.

**Figure 15.** Distribution of the thermal energy input within the Allam cycle. The figures across the chart represent the percentage of the thermal input.

There are also some other power cycles that run on the oxy fuel combustion concept. Clean Energy Systems [117] proposed a cycle which uses water instead of recycled flue gas to control the turbine inlet temperature. Fuel is combusted with an oxidant in a high-pressure combustor in the presence of supercritical steam. The hot gas is then expanded in three different turbines with reheating between them. This cycle is considered by CES as a long-term solution to use in the oxy combustion process with natural gas. A schematic of the proposed cycle is shown in Figure 16.

**Figure 16.** Schematic diagram of a supercritical CES cycle.

### *3.2. Chemical Looping Combustion (CLC)*

Chemical looping combustion is a novel process in the field of carbon capture. This method has the potential to be the most e fficient and a low-cost process for capturing carbon dioxide from fossil fuel power plants. IPCC identified this method as one of the cheapest technologies for carbon capture [93]. It has the inherent advantages of CO2 separation with a minimum energy requirement.

There is no direct contact between the air and fuel which is why it is also known as unmixed combustion [118]. Instead of air, an appropriate oxygen carrier brings oxygen from the air to fuel [119]. Two fluidized bed reactors are used in this process. One is known as the air reactor and the other as the fuel reactor. A schematic of the process is shown in Figure 17. A solid oxygen carrier is circulated between these two reactors. The solid oxygen carrier is oxidized in the air reactor. After oxidation, the carrier goes to the fuel reactor. Fuel is oxidized in the fuel reactor while the oxygen carrier is being reduced. The corresponding chemical reaction can be written as follows [120]:

Fuel reactor: (<sup>2</sup>*n* + *m*)*MyOx* + C*n*H2*m* → (<sup>2</sup>*n* + <sup>1</sup>)*MyOx*−<sup>1</sup> + *m* H2O + *n*CO2 Air Reactor: *MyOx*−<sup>1</sup> + 1 2O2 → *MyOx*

**Figure 17.** Schematic of the chemical looping combustion process [120].

After the completion of the fuel oxidation, the metal oxygen carrier is circulated back to the air reactor [120]. CO2 and water are produced in the fuel reactor. CO2 can be easily separated by condensing H2O and then sequestered or used for other purposes. After oxidizing the oxygen carrier, the remaining air contains only nitrogen and unreacted oxygen. As they are not harmful to the environment, they can be released without further processing. Syngas produced from gasification of coal is used in the fuel reactor when coal is as the main fuel. A schematic layout of a power plant using chemical looping combustion with syngas from coal is shown in Figure 18.

Here, Ni reacts with high-pressure air in reactor 2 to form NiO and to remove oxygen from the air. Then, NiO is separated from the air. The hot and high-pressurized nitrogen-rich stream is passed through a turbine to generate power. NiO is passed to reactor 1 where it is reduced and the fuel is oxidized into CO2 and H2O. This high-pressure and high-temperature CO2 and H2O streams are used to produce steam for additional power generation. After that, CO2 is captured by condensing H2O from the stream. Reduced NiO forming Ni is returned to the air reactor to repeat the cycle.

Despite the novelty of the CLC process, this method has certain challenges. For example, the design of the reactor with two separated reaction zone is one of the main challenges. A CLC reactor system with two interconnected fluidized bed is shown in Figure 19. Here, the oxygen carrier should circulate between the zones, but the gas streams should not be leaked into one to another. The first continuous operation of this type of reactor was achieved with a 10 kW prototype at Chalmers University of Technology [122]. It showed a stable operation with 99.5% fuel conversion e fficiency at ambient pressure. There was no significant gas leakage. There are also some other approaches in the design of the reactor. Shimomura [123,124] proposed a reactor with a rotating reactor wheel. Air and fuel were

to be fed at separate compartments of the wheel. They considered an adsorbent wheel which would use Li4SiO4 based absorbent. Ivar et al. [125] worked on developing novel concepts of reactor. Their initial testing showed that the mixing of air and fuel could only be avoided partly. A steam stream was employed as a gas wall between the fuel and air. The flue gas in this experiment contained 85% CO2 after steam removal.

**Figure 18.** Layout of a power plant using chemical looping combustion with NiO and syngas [121].

**Figure 19.** A CLC reactor with two interconnected fluidized beds [126].

The thermal efficiency of a combined cycle power plant equipped with CLC was found to be around 52–53% with respective operating temperature and pressure of 1200 ◦C and 13 atm in the air reactor. Implementation of CLC yields 3–5% higher efficiency than other carbon capture methods [127]. A 2.8% higher thermal efficiency was found for a CLC-IGCC power plant compared to an IGCC using physical absorption for carbon separation. Also, the CLC allowed for 100% capture of carbon dioxide while the physical absorption yielded 85% capture from the IGCC plant [122].

An important aspect of research in the CLC field is to find a suitable oxygen carrier that would have a high fuel conversion ratio, a good stability, and a high oxygen transport capacity [122]. Various materials are being tested for this purpose. Materials with reactivity above or near their melting point should not be used as the oxygen carrier because they would have to undergo a cyclic operation at a high temperature. Along with the reactivity, thermal stability, toxicity, and cost should be considered when choosing an oxygen carrier [128]. Some of the most likely elements to use as oxygen carrier are iron, copper, manganese, and nickel. They should be combined with inert materials like alumina, silica, titanium oxide etc. [122]. Lyngefelt et al. [129] tested more than 290 di fferent particles as oxygen carrier including active oxides of copper, nickel, manganese, and iron. A conversion e fficiency of 99.5% was attained in a 10 kW prototype reactor. In another experiment, 99% conversion e fficiency was gained when NiO/MgAl2O4 was used as an oxygen carrier [130].

Another significant factor for better e fficiency is the temperature of the air reactor. The temperature of the air reactor can be compared with the turbine inlet temperature of a conventional power plant [122]. The reaction that takes place in the air reactor is endothermic whereas the reaction at the fuel reactor can be endothermic or exothermic. Rehan et al. [131] examined a multi-stage chemical looping combustion for combined cycle. They found that at an oxidation temperature of 1200 ◦C, a CLC combined cycle would operate at achieved 52% e fficiency without reheating. The same power plant exhibited 51% efficiency at 1000 °C and 53% e fficiency at 1200 °C reactor temperature when a single stage reheat was employed. However, employing a double stage reheat did not improve the e fficiency over the single reheat system. Zhu et al. [132] compared the performance of an IGCC with chemical looping and calcium looping processes. They concluded that the CLC based technology exhibits higher e fficiency (39.78%) than the pre-combustion capture with physical absorption (36.21%) and calcium looping (37.72%). The payback period of the above three capture methods was estimated to be 13.45 years, 13.21 years and 17.25 years, respectively.

### **4. Comparison of the Methods**

Carbon capture requiring separation of CO2 is an age-old process and it has reached a certain maturity with various established full-scale application. A lot of experimental and numerical modeling studies have been done on these processes. The main advantage of post combustion capture is its easy integration capability with the existing power plants, but the partial pressure and concentration of CO2 are very low in the flue gases. For transportation and storage of CO2, a minimum concentration should be reached. The required extra energy and extra costs of carbon capture to attain a minimum required concentration are significantly high.

When using chemical absorption process for the separation, degradation of the solvent and severe corrosion of the used equipment take place. Therefore, a huge cost for solvents and other equipment becomes necessary for this process to make CO2 ready for transportation and storage. These may increase the cost of producing electricity around 70% [118]. Research is ongoing for new solvents to reduce the cost of carbon capture. Large equipment size results in the high capital and operating cost in this method.

Pre-combustion carbon capture is mostly used in process industries. There are also full-scale CCS plants in some industries which use this method [11]. The amount of CO2 is much higher in the gas mixture in this process than the conventional flue gas mixture. Due to the higher pressure and lower gas volume, less energy is required in this process compared to post combustion capture, but still, the energy penalty is high. Precombustion is mainly used in integrated gasification combined cycle technology. This technology demands a huge auxiliary system for smooth operation. Therefore, the capital cost of this system is too high compared to other systems.

On the other hand, carbon capture processes without requiring separation are comparatively novel in power generation. There is no full-scale operational plant based on these processes. There are some pilot scale operation and some subscale demonstration plants under development using oxy fuel combustion [10,30,94]. The most promising step regarding oxy fuel combustion is the 50 MWth demonstration power plant built in Texas by Net Power using the concept of Allam cycle. It will ensure near zero emission. This method has some other advantages like reduction in equipment size, compatibility with various kinds of coals, and no need for an onsite chemical plant [10].

The process, however, requires a large amount of high purity oxygen. Therefore, an energy-intensive ASU is needed for oxygen production. Membrane-based technology for air separation may compete with cryogenic ASU through a higher degree of integration into the power cycle [133]. Due to this ASU and CO2 compression unit used in this process, net power output decreases significantly. Along with these, there are some technical uncertainties that demand more research to understand the full-scale operation. However, since no extra cost is required for CO2 separation, this process remains a promising one to produce electricity at a lower cost while confirming near zero emission.

The CLC process for carbon capture is still in the preliminary stage. It has not been implemented on a commercial level yet. Further research is required to take advantage of this method. Due to the absence of flame, no NOx is produced thermally and the outlet stream of air reactor is harmless for the environment [93]. Developing a proper oxygen carrier to use in CLC will make it more attractive than other processes.

A comparison of the thermal efficiency of power plants with different CO2 capture processes is provided in Table 6. The efficiencies shown in the table are based on the lower heating value of the fuel. Bituminous coal is considered for coal-based power plants due to its extensive use in power production [30]. The Selexol process is taken into consideration for precombustion carbon capture in an IGCC GE type gasifier. In the case of chemical looping combustion, ilmenite was used as oxygen carrier for coal-based power production whereas Nickel Aluminum oxide was used for natural gas-based power production [134,135].


**Table 6.** Efficiency comparison of power generation with different carbon capture processes [30,107,134,135].

When coal is used as a fuel, the CLC exhibits the same efficiency as the base combustion technology using pulverized coal without any capture. Reduction in the efficiency is the highest in pre-combustion carbon capture. Post combustion and oxy combustion carbon capture show an almost similar drop in efficiency. An interesting observation in this comparison is the efficiency of the Allam cycle. The targeted efficiency of the Allam cycle is almost the same as the reference power plant efficiency without capture. If this cycle can be implemented commercially at a larger scale, the overall power generation efficiency will increase while ensuring total carbon capture.

When natural gas is used as fuel, the pre-combustion carbon capture shows a 14% drop in the efficiency from the reference powerplant whereas the post combustion carbon capture shows an 8% drop. The traditional oxy combustion process exhibits an efficiency of 44.7%. Chemical looping combustion indicates only a 4% drop in efficiency from the reference plant. The Allam cycle shows an extraordinary performance whose efficiency happens to be over 3 percentage points higher than that of the reference combined cycle without CO2 capture.

From the e fficiency comparison of Table 6, it may be concluded that the chemical looping combustion and the Allam cycle are expected to be the leading technologies in the near future for fossil fuel-based power generation. The 50 MWth Allam cycle provides the basis for deployment of large-scale facilities. Currently, 300 MW natural gas-fired plants are under development. The chemical looping method is not ye<sup>t</sup> technologically ready to implement on an industrial basis. The method is still in the investigation stage. More experimental data are necessary before large-scale commercialization.

Conventional carbon capture process results in the reduction of e fficiency. More fuel is burnt per unit of electricity production due to this ine fficiency which leads to more production of CO2. Also, the processes used for capturing carbon dioxide may a ffect the environment in di fferent ways other than direct emission of CO2. For example, di fferent substances used for separating and capturing CO2 may have undesired e ffect on the human body and environment. Using a solid sorbent covered with coating was experimented to reduce the formation of dust from the substance [136]. This could also reduce the capacity of the substance to capture carbon dioxide. Also, stripping of organic solvent from membranes and sorbents is suggested to prevent undesired odor. Before employing carbon capture, it should be ensured that reducing CO2 is not being achieved at the cost of other environmental impacts.

Life cycle assessment of the plants is necessary to properly understand environmental impacts of the carbon capture methods. Schreibar et al. [7] used the life cycle assessment (LCA) methodology for post combustion carbon capture using MEA whose impact on the environment and human health was investigated for five power plants. The global warming potential (GWP), human toxicity potential (HTP), acidification potential (AP), photo oxidant formation potential, eutrophication potential (EP) were considered as impact categories. As expected, GWP was much lower with MEA compared to the power plants without capture whereas HTP was three times higher with MEA plants. Schreibar et al. [7] concluded that upstream and downstream processes such as emissions from fuel and material supply, waste disposal, and waste water treatment influence the environmental impact measures for power plants with carbon capture. Viebahn et al. [137] revealed about a 40% increase in AP, EP, HTP when post combustion carbon capture was implemented in a power plant.

A similar result was found by Veltman et al. [138]. They showed that a power plant with post combustion capture yields a 10 times increase in toxic impacts on freshwater compared to a plant without capture. Impacts on other categories were negligible. Degradation of MEA resulted in the emission of ammonia, acetaldehyde, and formaldehyde. Cuellar et al. [139] compared life cycle environmental impacts of carbon capture and storage with carbon capture and utilization. GWP with utilization was much greater than that with storage. The highest reduction of GWP was found for pulverized coal and IGCC plants employing the oxyfuel capture method as well as combined cycle gas turbine plants equipped with a post combustion capture technology.

Pehnt et al. [140] showed that a conventional power plant operating on coal with post combustion carbon capture would result in an increase in the environmental impact in almost all categories except GWP. Solvent degradation and energy penalty due to CO2 capture process are the main reasons for this increase. Precombustion capture showed a decrease in all the environmental impact categories compared to a conventional power plant. They identified oxyfuel combustion as the most potential process to reduce all the environmental impact categories if co-capture of other pollutants can be achieved.

Nie et al. [141] investigated comparative environmental impacts of post combustion and oxy fuel combustion carbon capture. Their analysis showed that almost all environmental impact categories except GWP would increase with post combustion carbon capture. The same is true for oxyfuel combustion except GWP, AP and EP. However, the amount of increase of these impact categories was found to be less in oxyfuel combustion compared to the post combustion carbon capture. No LCA analysis was found for chemical looping combustion and the newly proposed Allam cycle based on oxyfuel technology.
