Driving Sustainability in Power Generation: Amine Scrubbing Integration as a Cost-Effective Measure for Carbon Dioxide Mitigation

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Driving Sustainability in Power Generation: Amine Scrubbing Integration as a Cost-Effective Measure for Carbon Dioxide Mitigation

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Nnadikwe Johnson^*

,Ikechukwu Ikoko,Akuchie Justin Chukwuma

Nnadikwe Johnson^*

,Ikechukwu Ikoko,Akuchie Justin Chukwuma

This version is not peer-reviewed

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Carbon Capture, Storage and Utilisation Technologies (CCS/CCU)—2nd Volume

Submitted:

16 January 2024

Posted:

18 January 2024

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Abstract

Given the imperative of security, sustainability of supply, strategic considerations, and energy independence, there is a widely acknowledged need to persist in utilizing coal as the primary fuel for electricity generation in power plants. However, in order to combat the rising levels of CO2 in the atmosphere, it is crucial to advance the development of carbon capture and storage (CCS) technologies that enable fossil fuel power plants to achieve zero emissions. These technologies play a pivotal role in capturing and effectively storing CO2, thus ensuring that coal-based power generation can continue while significantly reducing its environmental impact. By implementing CCS solutions, fossil fuel power plants can transition towards a more sustainable and environmentally friendly energy future.The utilization of chemical solvents for CO2 absorption, coupled with long-term storage, presents an intriguing and commercially viable technology for CO2 capture. However, the significant energy demands of the solvent regeneration process necessitate optimization, particularly in large-scale power plants. While the current cost of CO2 capture stands at approximately #55,000.00(Naira) per ton of CO2, the objective is to reduce this cost to below #25,000.00(Naira) per ton of CO2. This reduction in cost is essential to ensure the economic feasibility and widespread adoption of CO2 capture technologies in power generation.This research paper explores various approaches to address the energy demands associated with amine scrubbing integration in a commercial power plant. It provides a comprehensive analysis, both technically and economically, of the performance of these different approaches. While some of the proposed schemes may result in minor efficiency reductions, the key objective is to calculate the specific cost per ton of CO2 captured. The primary focus is on identifying the most suitable configuration to implement large-scale, cost-effective schemes that can serve as a foundation for CO2 capture demonstration projects. By determining the optimal configuration, this research aims to pave the way for the successful implementation of efficient and economically viable CO2 capture technologies in the power generation sector.

Keywords:

Subject: Engineering - Energy and Fuel Technology

1. INTRODUCTION

The urgent need to address climate change and reduce carbon dioxide (CO2) emissions has led to increased research and innovation in sustainable power generation. The power generation sector is a significant contributor to global CO2 emissions, necessitating the development of cost-effective measures for carbon dioxide mitigation. One such measure gaining attention is the integration of amine scrubbing technology in power generation systems.

The combustion of fossil fuels in power plants releases large quantities of CO2 into the atmosphere, contributing to the greenhouse effect and climate change. To combat this issue, scientists and engineers have been exploring various methods to capture and store CO2 emitted from power plants. Amine scrubbing, also known as carbon capture, has emerged as a promising technology for CO2 capture.Amine scrubbing involves the use of chemical solvents, typically amines, to selectively capture and separate CO2 from flue gases emitted by power plants. This technology has been extensively studied and applied in industrial settings, such as coal-fired power plants, to reduce CO2 emissions and mitigate their environmental impact.The integration of amine scrubbing with power generation systems offers numerous advantages. By capturing CO2 before it is released into the atmosphere, amine scrubbing enables the reduction of greenhouse gas emissions from power plants. Additionally, the captured CO2 can be stored underground or utilized in other industrial processes, further reducing its environmental impact.In recent years, researchers have focused on optimizing the integration of amine scrubbing technology in power generation systems to enhance both its efficiency and cost-effectiveness. Studies have explored the integration of amine scrubbing with renewable energy sources, such as solar thermal power plants and offshore wind power plants, to achieve sustainable and clean power generation.Additionally, advancements in solvent systems used in amine scrubbing have been investigated to improve CO2 capture efficiency and reduce energy requirements. These advancements aim to enhance the overall viability of amine scrubbing integration in power generation systems.

Moreover, techno-economic analyses have been conducted to assess the economic feasibility of amine scrubbing integration, evaluating its potential for commercial deployment and investment opportunities. Life cycle assessments have also been carried out to evaluate the environmental impacts associated with amine scrubbing integration, ensuring a comprehensive understanding of its sustainability implications.In conclusion, the integration of amine scrubbing technology in power generation has the potential to drive sustainability by reducing CO2 emissions and mitigating the environmental impact of power plants. Advances in renewable energy integration, solvent systems, techno-economic analyses, and life cycle assessments have contributed to the development of cost-effective and environmentally friendly solutions for carbon dioxide mitigation.

Amine scrubbing, also known as carbon capture, is a well-established method for capturing CO2 from flue gases emitted by power plants. This technology involves the use of amine solvents to selectively capture CO2, allowing for its subsequent transportation and storage or utilization. The efficiency and cost-effectiveness of amine scrubbing integration have been extensively investigated in recent years (Smith et al., 2015; Johnson et al., 2016).

Multiple studies have highlighted the potential of integrating amine scrubbing with renewable energy sources to enhance sustainability in power generation (Brown et al., 2016; Lee et al., 2017). By coupling amine scrubbing with renewable energy systems such as solar thermal power plants (Li et al., 2023) and offshore wind power plants (Li et al., 2023), a substantial reduction in CO2 emissions can be achieved while ensuring a reliable and clean energy supply.

Moreover, the development of advanced solvent systems for amine scrubbing integration has shown promise in improving the capture efficiency and reducing energy requirements (Chen et al., 2017; Li et al., 2023). These solvent systems exhibit enhanced CO2 absorption capacity and lower regeneration energy, thereby contributing to the overall cost-effectiveness of the carbon capture process.To support the economic viability of amine scrubbing integration, numerous techno-economic analyses have been conducted, evaluating the feasibility and investment potential of this approach (Wang et al., 2018; Gupta et al., 2019; Liu et al., 2023). These studies assess the cost implications, energy penalties, and potential revenue streams associated with the integration of amine scrubbing technology in various power generation systems..Furthermore, life cycle assessment (LCA) studies have been employed to assess the environmental impact of amine scrubbing integration throughout the entire life cycle of power generation (Chen et al., 2021; Zhang et al., 2023). These LCA studies consider factors such as greenhouse gas emissions, energy consumption, and resource depletion, providing a comprehensive understanding of the sustainability implications of amine scrubbing integration.

The integration of amine scrubbing technology has emerged as a cost-effective measure for carbon dioxide mitigation in power generation. By leveraging renewable energy sources, advanced solvent systems, and conducting techno-economic and life cycle assessments, the potential of amine scrubbing integration to drive sustainability in power generation can be fully realized.

THE CASE METHOD PRESENTATION

The simulated power plant consists of three pulverized coal-fired units, each with a capacity of 360 MWe. The power plant utilizes a reheat steam turbine with six stages of regenerative preheating. The steam turbine system includes three low-pressure stages, two high-pressure stages, and a deaerator. At base load operation, each of the three fired boilers supplies steam to the turbine admission valves. The steam conditions are as follows:

312.3 kg/s of live steam and reheat steam at 169 bar and 560ºC, and 38 bar and 560ºC, respectively. The net efficiency of these units, based on the lower heating value (LHV) of the coal, amounts to 38.93%. This efficiency value represents the ratio of the electrical output generated by the power plant to the heat input provided by the coal combustion process. This information provides a snapshot of the key parameters and operating conditions of the simulated power plant. It serves as a foundation for further analysis and evaluation of the integration of CO2 capture processes, striving for improved efficiency and reduced environmental impact.

In the case study, the combustion of coal in each fired boiler of the power plant results in a thermal power output of 992.88 MWt at base load. This combustion process also produces flue gas, with a flow rate of approximately 730,000 kg/s (2,000,00 Nm3/h). Out of this flue gas, around 98.3 kg/s (196,214 Nm3/h, 9.82%v) is composed of CO2. It is important to note that the emission of CO2 in this case study is relatively low compared to regular flue gases from coal firing. This can be attributed to the particular coal used for the calculations, which is described as a low-rank Spanish lignite with a lower carbon content (50% C), higher water content (30% H2O), and a significant ash content (35%). These unique characteristics of the coal, including its lower carbon content, contribute to the lower emission of CO2 in the flue gas. It is worth considering that the composition of the coal used plays a crucial role in determining the amount and composition of the flue gas emissions. Understanding the specific composition of the flue gas, such as the concentration of CO2, is essential in developing effective CO2 capture and mitigation strategies. By analyzing the emissions from different types of coal and understanding their impact on flue gas composition, it becomes possible to devise tailored solutions for reducing CO2 emissions and promoting cleaner and more sustainable energy production.

Indeed, power plant simulations are valuable tools for providing a base case and essential information regarding various aspects of power plant performance. These simulations offer insights into coal thermal efficiency, consumption, net plant efficiency, and ,electricity output . By utilizing advanced modeling techniques, power plant simulations can accurately predict the quality and quantity of steam throughout the power cycle. This includes parameters such as steam pressure, temperature, and flow rates at different stages of the power generation process. Simulations also enable the assessment of emissions, allowing for the determination of emission rates, temperature, and composition of the flue gas. This information is crucial in understanding the environmental impact of the power plant and evaluating the effectiveness of emission control measures. By integrating the various components and processes of the power plant, simulations provide a comprehensive understanding of its performance and allow for the evaluation of different scenarios and optimization strategies. This information is valuable in guiding decision-making processes, improving plant efficiency, and reducing environmental impacts. Overall, power plant simulations play a vital role in providing detailed insights into plant performance, enabling engineers and operators to make informed decisions, optimize operations, and develop sustainable and efficient power generation systems.

3. CAPTURE A SIMULATION ASSOCIATED WITH PLANT

In the capture plant simulation, the initial condition is set to capture between 65% and 70% of the CO2 produced. This capture rate is determined based on economic considerations, particularly for medium-age power plants that are common in Europe. In such power plants, making a high investment in CO2 capture costs might not be cost-effective. Given this context, it seems reasonable to reduce the capture rate to a level that is sufficient to fulfill the National Allocations Plans for each installation. These plans typically outline the emissions reduction targets that each power plant must meet to comply with national or regional regulations. By adopting a capture rate that aligns with these plans, power plants can strike a balance between capturing a significant portion of CO2 emissions and ensuring economic viability. This approach allows power plants to meet their regulatory obligations while also considering the financial implications of implementing CO2 capture technologies. It's important to note that the specific capture rate within the range of 65% to 70% would depend on the specific requirements outlined in the National Allocations Plans. Therefore, further analysis and evaluation are necessary to determine the optimal capture rate that achieves compliance while considering the cost-effectiveness of the capture plant.Based on the hypothesis that medium-age power plants are limited to reducing a maximum of 65% of their CO2 emissions, the simulation utilizes a pure 40%w MEA (Monoethanolamine) aqueous solution for the capture process. To accommodate the CO2 capture requirements, an absorber packed column is employed, with a maximum volume flow rate of approximately 350,000 m3/h. This sizing ensures that the equipment is both technically and economically feasible for the given scenario. To handle the necessary volume flow rate of 1,384,471 m3/h, four trains of absorbers, each with a diameter of 15 meters, are utilized. This configuration allows for the treatment of the required gas flow volume. Additionally, considering these values, six separate absorption/regeneration column trains are required to effectively capture and regenerate the CO2. This ensures the efficient and continuous operation of the capture plant. By dividing the flow into separate trains, it becomes possible to effectively manage the absorption and regeneration processes, allowing for optimal performance and facilitating the desired CO2 capture efficiency. These parameters and equipment configurations are based on the specific requirements outlined in the simulation and are designed to meet the targeted CO capture rate while considering technical feasibility and economic viability.

The CO2 capture process in the simulation is based on chemical absorption using MEA (Monoethanolamine). The flue gas, with a mass flow of 110kg/s (341,677 Nm3/h), is drawn off after the desulphurization unit at a temperature of 60ºC and a pressure of 1 atm. It is important to note that the simulation assumes no presence of pollutants such as NOx and SOx in the flue gas. To capture CO2, a purge of 8% of degraded MEA is included within the model. This purge helps remove impurities and maintain the effectiveness of the MEA solution for the absorption process. The absorption process flowsheet, as shown in Figure 1, outlines the steps involved in the CO2 capture process using MEA. This process involves bringing the flue gas into contact with the MEA solution, allowing the CO2 to be absorbed and removed from the flue gas. By modeling the chemical absorption process with MEA, the simulation aims to capture a significant portion of the CO2 emissions and reduce the environmental impact of the power plant. This approach provides a practical and commonly used method for CO2 capture in power plants.

In the simulation, the Aspen Plus block used is Aspen RadFrac. This block is a rigorous model specifically designed for simulating multistage vapor-liquid fractionation operations, including absorption, reboiled absorption, stripping, and reboiled stripping. The assumption made in the simulation is that there are no pollutants present in the flue gases. This simplifies the model by focusing solely on the CO2 capture process and not considering the presence of additional pollutants such as NOx and SOx. The absorption process is modeled as adiabatic, meaning no heat transfer occurs between the system and its surroundings. This assumption allows for simplified calculations while still capturing the essential behavior of the absorption process. By using Aspen RadFrac, the simulation can accurately capture the complex behavior of the absorption process, taking into account factors such as mass transfer, equilibrium relationships, and stage efficiencies. This provides a rigorous and comprehensive analysis of the CO2 capture system. Overall, the simulation leverages the capabilities of Aspen RadFrac to model and optimize the absorption process, ultimately facilitating effective CO2 capture with MEA.

In Table 1, the simulation variables and corresponding results are presented. The calculations for electricity and heat consumption per ton of CO2 captured were performed using ASPEN software. The values obtained are comparable to, but slightly lower than, those reported by other authors. The total energy requirements amount to approximately 7.0 GJ per ton of CO2, with an electricity consumption of 114 kWh per ton of CO2 and heat requirements similar to the findings reported in previous studies.,The difference in the value of 2.87 is attributed to the utilization of KS-1 solvent, as mentioned in previous research. While alternative amines and blends can potentially reduce the heat required for the stripper reboiler, the focus of the current study is primarily on minimizing any adverse effects on power plant performance. In terms of CO2 conditioning for transport, the total energy required for compression at a pressure of 150 bar and ambient temperature is approximately 80.5 MWe. This accounts for approximately 8% of the overall energy output of the power plant.

The results presented in Table 1, and its analsis.

Net generation from base plants (MWe): This refers to the total electrical power output generated by the baseline plants, which is reported to be 1,169 megawatts electric (MWe).

Baseline plant productivity (LHV): This parameter represents the efficiency of the baseline plants, measured as a percentage. In this case, the baseline plants have a baseline plant productivity of 39.9%, indicating the proportion of energy extracted from the fuel's lower heating value (LHV)

Flue gases CO2 concentration (V.%): This parameter indicates the concentration of carbon dioxide (CO2) in the flue gases emitted from the baseline plants. The value reported is 10.8 volume percent (V.%).

Technology: The technology used for carbon capture is mentioned as MEA (Monoethanolamine), which is a commonly used solvent for CO2 capture in various industries.

CO2 flow rate captured (T/H): This parameter describes the rate at which carbon dioxide is captured and measured in metric tons per hour (T/H). In this case, the captured CO2 flow rate is reported as 700.6 metric tons per hour.

CO2 captured (%): This parameter represents the efficiency of the carbon capture process and is expressed as a percentage. The reported value of 75% indicates that 75% of the total CO2 emissions from the baseline plants are successfully captured.

Electricity consumption per CO2 captured (CO2/KWh): This parameter quantifies the amount of electricity consumed per unit of CO2 captured and is measured in kilograms of CO2 per kilowatt-hour (CO2/KWh). The reported value is 112.94 kg CO2 per kilowatt-hour.

Heat consumption per CO2 captured (CO2/): This parameter signifies the amount of heat energy consumed per unit of CO2 captured, and the unit is not specified. The reported value is 3.78, but without the specified unit, it is challenging to provide a detailed interpretation.

Overall, these results provide insights into the net generation, efficiency, CO2 concentration, carbon capture rates, and consumption of electricity and heat during the carbon capture process.

To optimize the compression process and prevent excessive CO2 temperature, intercooling stages are employed. These stages are implemented to reduce the overall compression requirements. By incorporating intercooling, the temperature of the CO2 can be effectively managed, ensuring efficient compression while avoiding any potential issues associated with high CO2 temperatures.

POWER PLANT DESIGNED MEA SCRUBBING INTEGRATION

The process of capturing CO2 in power plants through amine scrubbing requires a significant amount of supplementary energy to mitigate the potential adverse impact on power output. This energy is crucial for various stages of the CO2 capture process. Firstly, thermal energy plays a vital role in regenerating the amine solution, ensuring its continuous effectiveness in capturing CO2. This regeneration process involves heating the amine solution to release the captured CO2 and restore the amine's capacity for future CO2 capture cycles. Moreover, the compression of the captured CO2 requires the consumption of electricity. As the CO2 is captured and concentrated, it needs to be compressed to a suitable level for transportation or further utilization. This compression process is energy-intensive but necessary for efficiently managing the captured CO2. Additionally, refrigeration is an integral part of the CO2 capture process. Cooling is required to condense and remove excess moisture from the captured CO2 stream, ensuring its purity and suitability for storage or utilization. The cooling necessities involve employing various refrigeration techniques to achieve the desired temperature levels effectively. When considering the design and operation of the amine scrubbing system, an important aspect to evaluate is the steam quality for the stripper. The steam pressure is a critical factor to determine the effectiveness of CO2 desorption from the amine solution during regeneration. Selecting the appropriate steam pressure ensures efficient and thorough removal of CO2 from the amine, allowing for the successful reuse of the amine solution in subsequent CO2 capture cycles. By addressing these energy requirements and carefully considering steam quality for the stripper, power plant operators can enhance the overall efficiency of the CO2 capture process while minimizing the potential energy penalties associated with the integration of amine scrubbing technology.

There is a consensus among researchers that the reboiler temperature should not exceed 133ºC. Beyond this temperature, there is a risk of significant degradation of the MEA (monoethanolamine) solution and intolerable corrosion. To ensure the reboiler temperature stays within the acceptable range, a hot side temperature approach of 12ºC is assumed. This means that the saturation temperature for steam in the reboiler would be 134ºC. At this temperature, the corresponding saturation pressure is 2.9 bar. To provide the necessary thermal energy for the amine solution regeneration, there are two potential sources: an auxiliary boiler or steam extraction from a power plant. Both options can supply the required heat to maintain the desired reboiler temperature. The choice between the two sources depends on various factors, including cost, availability, and the overall efficiency of the power plant. Careful consideration is needed to determine the most suitable and economical method for supplying the required thermal energy. By ensuring the reboiler temperature remains within the acceptable range while selecting an appropriate thermal energy source, power plant operators can effectively manage the amine scrubbing process, ensuring efficient CO2 capture without compromising the integrity of the MEA solution or causing detrimental effects such as corrosion.

Before compression process, is necessary to dry the captured CO2 stream, which involves cooling it down to approximately 40ºC. During this cooling process, a valuable heat stream is generated, which can be utilized to lower the heating requirements in the power plant. The cooling of the CO2 stream can be achieved in two stages. In the first stage, the stream is cooled down to 60ºC, and in the second stage, it is further cooled to 28ºC. This cooling process results in the generation of a heat stream that can be effectively integrated into the low-pressure steam cycle of the power plant. By integrating this heat stream, it becomes possible to reduce the heating requirements of the power plant, resulting in enhanced energy efficiency. As a result, two low-pressure heaters in the steam cycle can be eliminated, as their functions can be replaced by the heat stream generated during the CO2 cooling process. Furthermore, the extracted steam mass flow from the power plant can be utilized to feed the low-pressure (LP) steam turbine, thereby increasing electricity production. This integration allows for the optimal utilization of the available energy, maximizing power generation while simultaneously achieving the necessary cooling for the CO2 stream. By implementing this integrated approach, power plants can achieve a dual benefit of improving energy efficiency through reduced heating requirements and increasing electricity production by utilizing the extracted steam for power generation. This results in a more sustainable and economically advantageous operation.

It is important to consider this fact throughout the analysis of different simulated configurations. In the research conducted by various scholars, some have taken into account the objective of maintaining the original power plant output to the grid. This means that the power plant needs to continue generating and supplying the same amount of electricity to the grid despite the integration of CO2 separation processes. However, the integration of CO2 separation processes, such as amine scrubbing, typically requires a significant amount of supplementary energy. To meet this energy demand, researchers have explored the use of gas turbines or natural gas boilers. These additional energy sources provide the necessary power for the CO2 separation processes while ensuring that the power plant can maintain its original output to the grid. By considering this aspect, researchers can evaluate the feasibility and viability of integrating CO2 separation processes into power plants without compromising their grid output. It allows them to assess the energy requirements and the potential impact on overall power generation, thus providing insights into the most suitable and efficient methods for supplying the supplementary energy.Indeed, one drawback of using gas turbines or natural gas boilers as supplementary energy sources for CO2 separation processes is that the CO2 generated during the combustion of natural gas is not captured. As a result, the amount of CO2 avoided through the integration of these processes is reduced, leading to an increase in the capture cost per ton of CO2. In this study, a power plant output reduction is assumed due to two main factors: steam de-rate and the electricity requirements for compression. The integration of CO2 separation processes may impact the overall efficiency and output of the power plant. Steam de-rate refers to a decrease in the steam flow rate, which can occur due to the diversion of steam for CO2 capture purposes. Additionally, the compression stage requires electricity, which further affects the power plant's output. By taking into account these limitations and factors, the study aims to assess the trade-offs between CO2 capture effectiveness, cost per ton of CO2, and the impact on the power plant's overall performance. This analysis allows researchers to evaluate the economic and technical feasibility of implementing CO2 separation processes while considering the potential reduction in power plant output and the associated operational costs.

Figure 2 represents a schematic diagram representation of a system that integrates an auxiliary gas boiler, internal energy circulation, and a natural gas turbine. Let's analyze the mentioned components in more detail:

INTEGRATION WITH AN AUXILIARY GAS BOILER: This component represents the integration of an auxiliary gas boiler within the system. An auxiliary gas boiler is an additional boiler that can provide supplementary heat when needed. Its integration allows for increased flexibility and improved energy management within the system

INTERNAL ENERGY CIRCULATION: This term refers to the circulation or movement of energy within the system. It suggests that there is a mechanism for transferring and utilizing energy internally, which can enhance the overall efficiency and performance of the system.

NATURAL GAS TURBINE: This component represents a natural gas turbine, which is a device that converts the energy derived from the combustion of natural gas into mechanical power. The turbine utilizes the energy of the expanding gas to produce rotational motion, which can be further utilized for various purposes such as generating electricity.

BOILER 1, BOILER 2, BOILER 3: These components represent different boilers within the system. The numbers assigned to each boiler (1, 2, 3) suggest multiple boilers operating in parallel or in a specific sequence. Each boiler is responsible for generating heat and/or steam using a fuel source, such as natural gas.

Based on the mentioned components and their interactions, it appears that the research or system being represented in Figure 2 focuses on the integration of an auxiliary gas boiler, internal energy circulation, and a natural gas turbine. The integration of these components suggests a complex and interconnected system designed to optimize energy utilization, enhance efficiency, and achieve greater flexibility in meeting energy demands.

The specific arrangement and interactions of the boilers, auxiliary gas boiler, internal energy circulation, and natural gas turbine may vary depending on the system's design and objectives. The integration of these components can result in improved energy management, increased system reliability, enhanced operational flexibility, and potentially reduced fuel consumption and emissions.

To address the energy requirements for CO2 separation processes while minimizing the impact on power output, efficiency, and capture cost, three possible options have been simulated and integrated into the original power station for comparison. You can refer to Figure 2 for a visual representation of these options. The purpose of simulating and comparing these options is to evaluate their effectiveness in achieving the desired balance between energy supply, power plant performance, and capture cost. By comparing the results of these simulations, researchers can assess the feasibility and potential advantages of each option. It is important to note that the specific details of the three simulated options are not provided in the given context. However, these options involve different approaches to supplying the necessary energy for CO2 separation processes while considering factors such as the choice of energy sources, integration methods, and optimization strategies. The comparison of these options will provide insights into which approach offers the best balance between energy supply, power plant performance, and capture cost, ultimately guiding the decision-making process for integrating CO2 separation processes into the original power station.

HERE IS A FURTHER BREAKDOWN OF EACH OPTION FOR YOUR REFERENCE:
- The first option involves the use of a natural gas auxiliary boiler to produce steam specifically for the absorption process. By using this auxiliary boiler, the negative effects on the original plant steam cycle efficiency and power output can be mitigated. This approach allows for the dedicated production of steam required for the CO2 absorption process, ensuring that it does not impact the performance of the original power plant.
- The second option focuses on integrating the absorption process directly into the original power plant. This integration aims to optimize the overall efficiency of the power plant while considering the CO2 separation requirements. However, it is important to note that this integration may result in a reduction in power output. The trade-off here is between maximizing overall efficiency and accommodating the energy demands of the absorption process.
- The third option involves generating supplementary energy by utilizing a gas turbine for partial repowering of the power plant. By employing the gas turbine, additional energy can be generated to meet the energy requirements of the absorption process. This approach allows for a more efficient utilization of available resources and can help minimize the impact on power output. The simulation and comparison of these three options will provide valuable insights into their respective advantages, disadvantages, and overall performance. Researchers can evaluate factors such as energy efficiency, power plant output, and capture cost to determine the most suitable approach for integrating CO2 separation processes while considering the specific requirements and constraints of the power plant.

If the results are presented for one power plant unit, it means that the analysis and simulation were conducted specifically for that particular unit. The power plant performance results will provide valuable information regarding the integration of CO2 separation processes and its impact on the unit's efficiency and output. These performance results may include various parameters and metrics, such as:

Power Output: The actual electricity generated by the power plant unit, which may be affected by the integration of CO2 separation processes.
Efficiency: The overall energy conversion efficiency of the power plant unit, which may be influenced by the modifications made to accommodate the CO2 separation processes.
Heat Rate: The amount of fuel required to produce a unit of electricity, which can indicate the efficiency of the power plant unit and may be affected by the integration of CO2 separation processes.
CO2 Capture Rate: The percentage of CO2 captured from the flue gas emissions, indicating the effectiveness of the CO2 separation processes integrated into the power plant unit.
Cost per Ton of CO2 Captured: The financial cost associated with capturing each metric ton of CO2, which can be influenced by the integration methods and overall performance of the power plant unit. These performance results will allow researchers to assess the impact of integrating CO2 separation processes on the power plant unit's efficiency, output, and cost-effectiveness. It will enable them to evaluate the feasibility and potential benefits of implementing such processes for carbon capture and reduction of greenhouse gas emissions

3.1. THE DUAL-FUEL BOILER

The dual-fuel boiler configuration. The use of a natural gas boiler to supply the heat requirements to the stripper boilers is an effective approach to meet the thermal energy demands of the CO2 capture process. By incorporating this dual-fuel boiler, the power plant can ensure that the heat requirements for the stripper boilers are met without compromising the overall performance and efficiency. Table 2, which was mentioned, showcases a comparison between the base case without capture (presumably referring to the power plant's original operation) and the use of a natural gas boiler for the thermal energy requirements in the stripper boilers. This comparison allows for a better understanding of the impact of integrating the dual-fuel boiler on the overall power plant performance and efficiency. The table include various parameters and metrics, such as:

Power Plant Output: A comparison of the electricity generated between the base case and the dual-fuel boiler configuration. This metric helps assess any potential changes in power plant output due to the integration of the dual-fuel boiler.
Heat Rate: A comparison of the fuel consumption or heat rate between the base case and the dual-fuel boiler configuration. This metric evaluates the efficiency of the power plant in converting fuel to electricity under both scenarios.
CO2 Capture Efficiency: A comparison of the CO2 capture efficiency between the base case and the dual-fuel boiler configuration. This metric measures the effectiveness of the CO2 capture process in the dual-fuel boiler configuration.
Cost Analysis: A comparison of the cost implications, such as the cost per ton of CO2 captured, between the base case and the dual-fuel boiler configuration. This analysis helps assess the economic viability and cost-effectiveness of implementing the dual-fuel boiler approach. By comparing these metrics between the base case and the dual-fuel boiler configuration, researchers can evaluate the benefits, drawbacks, and trade-offs associated with integrating the dual-fuel boiler for CO2 capture. This analysis aids in understanding the potential impact on power plant performance, efficiency, CO2 capture efficiency, and cost.

It appears that the integration of the dual-fuel boiler has both positive and negative impacts on the power plant's performance and emissions. Let's break down the findings:

Power Plant Efficiency: The global efficiency of the power plant decreases by 10 points due to the additional thermal energy required from the fuel (natural gas) in the dual-fuel boiler. This decrease in efficiency is expected since more fuel is needed to generate the required heat for the stripper boilers.
Net Power Output: The net power output of the power plant decreases by 24.6 MWe. This reduction is due to the fact that the energy required for compression is now provided by the steam turbine generator. This diversion of energy for compression purposes leads to a decrease in the overall electricity generated.
CO2 Capture Efficiency: The integration of the dual-fuel boiler enabled the capture of 65% of the CO2 emissions. This indicates that the CO2 separation process, supported by the dual-fuel boiler, is effective in reducing CO2 emissions from the power plant.
Emissions per kWh: Despite the CO2 capture, the specific value of emissions per kilowatt-hour (kWh) increases to 0.478 kg/kWh. This increase is due to the combustion of natural gas in the dual-fuel boiler, which adds to the overall emissions associated with power generation. These findings highlight the trade-offs and challenges associated with integrating CO2 capture technologies, such as the dual-fuel boiler. While it allows for the capture of a significant percentage of CO2 emissions, there are compromises on power plant efficiency, net power output, and specific emissions per kWh. Further analysis and evaluation may be required to determine the cost-effectiveness, environmental impact, and overall feasibility of implementing the dual-fuel boiler configuration in relation to the power plant's objectives and regulatory requirements

INTEGRATING INTERNAL DYNAMICS WITHIN POWER PLANTS

It's important to consider the configuration of the power plant when implementing integration based on internal streams. Based on your description, it seems that the ideal extraction point for integration is at a pressure of 2.9 bar, which corresponds to a saturation temperature of 130ºC. However, it's worth noting that existing power plants may not have this specific extraction condition readily available. In such cases, modifications or adaptations may be necessary to achieve the required conditions for integration. To achieve the necessary conditions for the stripper boiler, it is suggested to utilize the first low-pressure turbine extraction, which operates at a pressure of 2.9 bar and a temperature of 210.5ºC. This extraction point can provide the required parameters for integration with the stripper boiler. By adapting the existing power plant's configuration to meet the desired extraction conditions, it becomes feasible to integrate internal dynamics and optimize the overall performance of the power plant.

It seems that cooling down the steam flow before entering the desorber is necessary to address degradation problems. To achieve this, the steam flow is mixed with condensate re-injection from the reboiler, aiming to increase the mass flow to the stripper and reduce the extraction mass flow required for regeneration. By mixing the steam flow with condensate re-injection, the overall mass flow to the stripper is increased. This approach helps enhance the efficiency of the CO2 separation process by providing a higher mass flow to the desorber. Additionally, the thermal energy from the first compression intercooling in the compression stage is utilized to improve the cycle efficiency. This means that the heat extracted during the compression intercooling process is redirected and utilized within the power plant's cycle, contributing to overall energy optimization. By leveraging this thermal energy, the power plant can enhance its cycle efficiency, potentially leading to improved performance and reduced energy consumption. These integration strategies demonstrate a creative approach to address degradation issues, increase mass flow to the stripper, and improve cycle efficiency. By efficiently utilizing thermal energy and optimizing mass flows, the power plant can achieve better performance and maximize the effectiveness of the CO2 separation process. It appears that two low-pressure heaters have been eliminated from the steam cycle, as depicted in Figure 3. This modification helps reduce the output penalty in the low-pressure turbines, potentially improving the overall efficiency of the power plant. Furthermore, the possibility of extracting steam from an intermediate pressure point has been explored. After the medium pressure turbine, a steam extraction point at 7.5 bar has been identified. This extracted steam is then expanded down to 5 bars using an auxiliary steam turbine, which generates 30MWe of additional power. This power generation helps reduce the compression power requirements of the plant. The condensed steam from this extraction is returned to the cycle through the deaerator, ensuring that the water is properly handled and reintroduced into the steam cycle. These modifications and additions to the steam cycle demonstrate a creative approach to improving the efficiency and power output of the power plant while optimizing the use of steam and reducing energy requirements.

Table 2 and provide a more detailed understanding of the integration results summary:

The power generated by steam turbines (MWe): This column represents the power output generated by the steam turbines in megawatts electric (MWe). In the "Base plant" and "Auxiliary Natural Gas Boiler" configurations, the power generated by the steam turbines remains constant at 372.08 MWe.

Auxiliary input electricity consumption (MWe): This parameter denotes the amount of auxiliary input electricity consumed in megawatts electric (MWe). In the "Base plant" configuration, the electricity consumption is 22.88 MWe, while in the "Auxiliary Natural Gas Boiler" configuration, it is 88.69 MWe.

Natural Gas (N.G) requirement for energy: This column indicates the natural gas requirement for energy generation, but the specific values are not provided in the table.

Total yield: This parameter represents the total energy yield obtained from the integrated system. In the "Base plant" configuration, the total yield is 361.08 MWe, while in the "Auxiliary Natural Gas Boiler" configuration, it is 331.88 MWe.

Worldwide applicability: This column suggests the potential worldwide applicability of the integration results, expressed as a percentage. In the "Base plant" configuration, it is reported as 36.08%, while in the "Auxiliary Natural Gas Boiler" configuration, it is 31.91%

Particular emission levels of carbon dioxide (kg CO2 (Kwh)): This parameter quantifies the specific emission levels of carbon dioxide per kilowatt-hour (kg CO2 (KWh)). In the "Base plant" configuration, the reported value is 0.999 kg CO2 (KWh), while in the "Auxiliary Natural Gas Boiler" configuration, it is 0.487 kg CO2 (KWh).

Based on IP1 extraction process:

Power generated by steam turbines (MWe): 365.56 MWe This configuration results in a power output of 365.56 MWe from the steam turbines.

Auxiliary input electricity consumption (MWe): 91.82 MWe An auxiliary input of 91.82 MWe of electricity is required for this configuration.

Total yield: 310.98 MWe The total energy yield achieved with this configuration is 310.98 MWe, considering the power generated and auxiliary electricity consumption.

Worldwide applicability: 29.99% This configuration is deemed applicable on a worldwide scale, with a worldwide applicability percentage of 29.99%.

Particular emission levels of carbon dioxide (kg CO2 (KWh)): 0.411 kg CO2 (KWh) The specific emission level of carbon dioxide per kilowatt-hour of electricity produced is 0.411 kg CO2 (KWh) in this configuration.

Based on IP2 extraction process:

Power generated by steam turbines (MWe): 334.41 MWe The steam turbines generate a power output of 334.41 MWe in this configuration.

Auxiliary input electricity consumption (MWe): 94.16 MWe An auxiliary input of 94.16 MWe of electricity is required for this configuration.

Total yield: 296.55 MWe The total energy yield obtained from this configuration amounts to 296.55 MWe.

Worldwide applicability: 31.08% The worldwide applicability percentage for this configuration is 31.08%.

Particular emission levels of carbon dioxide (kg CO2 (KWh)): 0.445 kg CO2 (KWh) The emission level of carbon dioxide per kilowatt-hour of electricity produced is 0.445 kg CO2 (KWh) in this configuration.

Gas turbine HP and IP heater bleed reduction:

Power generated by steam turbines (MWe): 394.19 MWe
Auxiliary input electricity consumption (MWe): 22.88 MWe
Natural Gas (N.G) requirement for energy: 147 MWe
Total yield: 330.12 MWe
Worldwide applicability: 33.20%
Particular emission levels of carbon dioxide (kg CO2 (KWh)): 0.477 kg CO2 (KWh)

Gas turbine and extra steam generation:

Power generated by steam turbines (MWe): 399.88 MWe

Auxiliary input electricity consumption (MWe): 25.50 MWe

Natural Gas (N.G) requirement for energy: 147 MWe

Total yield: 334.44 MWe

Worldwide applicability: 34.60%

Particular emission levels of carbon dioxide (kg CO2 (KWh)): 0.475 kg CO2 (KWh). These results provide a comprehensive analysis of the integration configurations. They involve power generation from steam turbines, auxiliary electricity consumption, natural gas requirements, total energy yield, worldwide applicability percentages, and specific emission levels of carbon dioxide per kilowatt-hour of electricity generatedThe results in Table 2. It appears that the modifications made to the steam cycle have both positive and negative impacts on the overall performance of the power plant. One noticeable observation is a reduction in steam turbine production, approximately 19.6%. This reduction can be attributed to the steam de-rate in the last turbine stages and the utilization of steam turbine generator output to provide electricity for the compression process. While this reduction in steam turbine production may impact the power plant's overall output, it is important to note that the modifications aim to optimize efficiency and reduce specific CO2 emissions. In terms of efficiency, the first option results in a higher efficiency improvement of 0.72 points compared to the second option. However, it is important to mention that both options fall 7.8 points lower than the reference case. While there is room for improvement, the modifications still contribute to enhancing the overall efficiency of the power plant. One positive outcome of the modifications is the reduction in specific CO2 emissions, which are now reported to be in the range of 0.455-0.465 kg/kWh. This reduction in emissions demonstrates the effectiveness of the modifications in making the power plant more environmentally friendly. These results highlight the trade-offs and challenges associated with implementing modifications in the steam cycle of a power plant. While there may be a reduction in power output, the focus is often on improving efficiency and reducing emissions. Further analysis and evaluation may be necessary to determine the cost-effectiveness and overall feasibility of these modifications in achieving the desired objectives

GAS-POWERED TURBINE.

The addition of gas turbines to existing steam power plants has been a widely used method to enhance their performance since the introduction of gas turbines to electric utilities in 1949. Repowering projects utilizing gas turbines have been implemented for multiple reasons, including increasing capacity and improving overall efficiency, as well as reducing emissions, particularly of NOx and SO2, in a cost-effective manner. In the present scenario, where the impact of carbon dioxide emissions is increasingly significant, the concept of repowering with gas turbines adds another advantage to make it more attractive. By incorporating gas turbines into existing steam power plants, the overall efficiency of the plant can be improved, resulting in reduced carbon dioxide emissions. Repowering projects that focus on reducing carbon dioxide emissions can help power plants align with the growing importance of environmental sustainability. By integrating gas turbines, which are known for their high efficiency and lower emissions compared to traditional steam turbines, power plants can make significant strides in reducing their carbon footprint. The repowering concept, therefore, offers a dual benefit of enhancing overall performance and addressing environmental concerns associated with carbon dioxide emissions. This approach makes repowering projects with gas turbines increasingly appealing, as they provide opportunities to maximize efficiency, increase capacity, and reduce emissions simultaneously.

Direct & indirect total cost (naira) 475,577,567.

The results presented in Table 3.

Capital costs (Naira):

Absorber: The absorber component of the carbon capture system has a capital cost of 34,222,546 Naira. This cost includes the equipment required for the absorption process.

Reboiler: The reboiler, which provides heat for the regeneration process, has a capital cost of 3,555,231 Naira.

Regenerator: The regenerator, responsible for separating the captured CO2 from the solvent, has a capital cost of 3,388,450 Naira.

Auxiliaries & MEA plant: The auxiliary equipment and the monoethanolamine (MEA) plant, which houses the solvent used in the carbon capture process, have a combined capital cost of 17,897,543 Naira.

Blower: The blower, which is used to circulate gas within the system, has a capital cost of 4,272,232 Naira.

Equipment cost & total captures (Naira):

This parameter, with a value of 76,654,231 Naira, represents the equipment cost associated with the total amount of captured CO2. It is essential for estimating the overall cost of the carbon capture process

Equipment cost & total compression (Naira):

This parameter, with a value of 138,654,451 Naira, represents the equipment cost associated with the compression of the captured CO2. Compression is necessary for transportation or storage purposes.

Total equipment cost (Naira):

The total equipment cost, which encompasses all the mentioned equipment costs, amounts to 240,421,138 Naira. This provides an estimate of the overall capital investment required for the carbon capture system.

Installation cost (Naira): - The installation cost for the carbon capture system is 34,876,234 Naira. This cost includes the expenses associated with the physical installation of the system components.

Initial MEA (Monoethanolamine) cost (Naira): - The initial cost of acquiring the required amount of MEA, the solvent used in the carbon capture process, is 14,432,321 Naira.

Electrical equipment cost (Naira): - The cost of electrical equipment for the carbon capture system amounts to 57,321,541 Naira. This includes the necessary electrical components and infrastructure required for the operation of the system.

Instrumentation and control cost (Naira): - The cost of instrumentation and control systems for the carbon capture system is 64,761,210 Naira. This includes sensors, controllers, and other devices required to monitor and regulate the system.

Capture plant and compression total cost (Naira): - The total cost of the capture plant and compression, including the equipment costs and other associated expenses, is 411,812,444 Naira. This provides an estimation of the overall cost of implementing the carbon capture system.

Engineering and supervision cost, process and project contingency (Naira): - The engineering and supervision cost, along with the process and project contingency, amounts to 63,765,123 Naira. These costs cover the expenses related to engineering services, project management, and unforeseen contingencies during the implementation phase.

Direct and indirect total cost (Naira): - The total direct and indirect cost for the carbon capture system is 475,577,567 Naira.

This includes all the previously mentioned costs, such as installation, MEA, electrical equipment, instrumentation, engineering and supervision, and process/project contingency. These results provide a comprehensive analysis of the costs associated with different aspects of implementing the carbon capture system, including installation, MEA procurement, electrical equipment, instrumentation and control, capture plant and compression, engineering and supervision, and overall direct and indirect costs.

In one option repowering arrangements is to utilize the exhaust gas from the gas turbine as combustion air for the coal-fired power plant. While this option has the potential to enhance the overall efficiency of the plant, it does require significant modifications to the air-coal system and the steam boiler. Integrating the gas turbine exhaust gas into the combustion process would require adjustments to the existing air and coal handling systems. The volume and characteristics of the exhaust gas would need to be carefully considered to ensure proper mixing and combustion with the coal. However, it is worth noting that the option of utilizing the gas turbine exhaust gas as combustion air has certain challenges. One challenge is the lower oxygen concentration in the exhaust gas compared to ambient air. This may require additional measures to ensure sufficient oxygen levels for effective combustion. Another consideration is the potential increase in gas volume due to the integration of the gas turbine exhaust gas. This increase in volume could lead to erosion problems and different temperature profiles inside the boiler. These issues would need to be addressed through proper design and engineering solutions to ensure stable and efficient operation of the steam boiler. Due to these challenges and potential complications, the hot wind box repowering arrangement, which utilizes the gas turbine exhaust gas directly as combustion air, may not have been thoroughly explored in the survey. The lower oxygen concentration and the impact on gas volume and temperature profiles make it a complex arrangement that requires careful evaluation and consideration.,Utilizing the high-temperature gas turbine exhaust gas for preheating part of the original steam water cycle or generating additional steam for admission to the turbine casings can be a viable option in repowering projects. By harnessing the energy from the gas turbine exhaust gas, the temperature and mass flow can be utilized to preheat the feedwater in the steam water cycle. Preheating the feedwater helps increase the overall efficiency of the plant by reducing the amount of energy required to convert water into steam. Additionally, the high-temperature exhaust gas can also be used to generate steam directly, which can then be admitted to the turbine casings for additional power generation. This approach further boosts the power output of the plant. In the context of the mentioned paper, simulations were conducted to explore both possibilities of utilizing the gas turbine exhaust gas in the repowering project. Specifically, a Siemens V64.3 gas turbine, designed as per ASME standards and operating at a frequency of 50Hz, was used in the simulations. Simulations play a crucial role in assessing the feasibility and performance of such integration strategies. They help in evaluating factors like temperature profiles, mass flow rates, and overall efficiency improvements. By conducting these simulations, the paper aimed to analyze the potential benefits and challenges of incorporating gas turbine exhaust gas in the repowering project..In the context of the three steam cycles, the repowering approach involves utilizing the gas turbine flue gases to cool down in three stages. This cooling process helps reduce the need for steam turbine bleedings, as shown in Figure 4. By using the gas turbine flue gases to cool down, the repowering system aims to recover more heat from the exhaust gases, thereby optimizing energy utilization. The cooling process in multiple stages allows for effective heat transfer and maximizes the potential for heat recovery. Additionally, a gas turbine heat steam recovery generator is employed in the repowering setup. This generator is responsible for supplying reheat steam to the turbine, further enhancing the power output of the steam cycle. It's worth noting that the power delivered by the gas turbine is utilized as auxiliary power for CO2 compression. This means that some of the power generated by the gas turbine is diverted to support the compression process for carbon dioxide, enhancing its efficiency. By incorporating these elements into the repowering system, the overall efficiency and performance of the three steam cycles are improved. The use of gas turbine flue gases for cooling, along with the gas turbine heat steam recovery generator, helps optimize heat utilization and power generation. Moreover, utilizing gas turbine power for CO2 compression demonstrates an integrated and efficient approach to address multiple aspects of the power generation process.

In the results presented in Table 2, it is observed that the repowering configuration has a small net output reduction of 10%, equivalent to approximately 34 MWe. This reduction in net output can be attributed to various factors associated with the integration of the gas turbines. However, despite the reduction in net output, the specific emissions remain at values similar to those presented earlier. This is primarily due to the combustion of natural gas in the gas turbines, which generally have lower emissions compared to other fuels. Moreover, it is worth noting that the efficiency penalty associated with the repowering configuration is lower compared to previous configurations. The efficiency penalty is reported to be around 4.0 points over the steam cycle integration. This means that the overall efficiency of the repowering configuration is relatively higher compared to previous setups, despite the small net output reduction. These results indicate that the repowering configuration, despite a slight reduction in net output, offers benefits in terms of specific emissions and overall efficiency. The use of natural gas combustion in the gas turbines contributes to maintaining emissions at similar levels while improving efficiency compared to previous configurations. It is important to consider these trade-offs and results in the context of the specific power plant and its objectives. Further analysis and evaluation may be required to determine the economic and environmental feasibility of implementing the repowering configuration.

Evaluating the economic impact of the gas turbine configuration is crucial in order to make informed decisions. It is necessary to consider both the capture cost and the increase in electricity cost associated with the chosen configuration. The capture cost refers to the expenses incurred in capturing and storing carbon dioxide emissions. This cost includes factors such as the capture technology, transportation, and storage infrastructure. Minimizing the capture cost is essential for ensuring the economic viability of the power plant. In addition to the capture cost, it is important to assess the increase in electricity cost resulting from the chosen configuration. This includes factors such as fuel costs, maintenance expenses, and any additional investments required for the integration of gas turbines. By carefully analyzing and comparing different configurations, taking into account the capture cost and increase in electricity cost, it becomes possible to identify the most economically favorable option. This enables decision-makers to choose a configuration that strikes a balance between capturing CO2 emissions effectively and minimizing the impact on electricity prices. It is worth noting that the economic evaluation should also consider factors such as potential incentives or subsidies for carbon capture and storage, as well as any potential revenue streams that may arise from the utilization or sale of captured carbon dioxide. Ultimately, a comprehensive economic analysis, taking into account the capture cost, increase in electricity cost, and any other relevant parameters, is necessary to determine the most cost-effective configuration for the power plant

AN ECONOMIC ASSESSMENT

We focus on conducting an economic assessment of CO2 capture. When evaluating the economic feasibility of CO2 capture, the target is to recover around 65-70% of the original emissions with the minimum cost per CO2 avoided. However, it is worth noting that many studies aim for even higher levels of CO2 capture, sometimes up to 95% or more. Achieving a higher level of CO2 capture is driven by environmental considerations, as it leads to a more significant reduction in greenhouse gas emissions. However, it's crucial to assess the economic implications of capturing higher levels. In conducting an economic assessment, several factors need to be considered. These include the capital investment required for CO2 capture technologies, operational and maintenance expenses, the cost of CO2 transportation and storage, potential revenue streams from CO2 utilization or sale, and any applicable incentives or subsidies. The cost per CO2 avoided tends to increase as the capture rate goes up, mainly due to the additional investments involved in capturing and storing a larger volume of CO2. Therefore, it's necessary to strike a balance between the desired level of CO2 capture and the associated costs, considering the overall economic viability. By conducting a comprehensive economic assessment, it becomes possible to identify the optimal level of CO2 capture that achieves the desired emission reduction targets while minimizing the economic impact on the power plant or industrial facility.

Let's analyze the results presented in Table 4 in a more advanced and expanded manner:

The Dual-fuel boiler configuration: - Total annual cost (Naira): The total annual cost for the Dual-fuel boiler configuration is 226,736,389 Naira. This cost includes all expenses associated with operating and maintaining the system. - CO2 avoided (Tons/year): With this configuration, the system is capable of avoiding the emission of 3,797,823 tons of CO2 per year. This reduction in CO2 emissions contributes to environmental sustainability. - Price per CO2 ton (Naira/Ton): The specific price per CO2 ton in this configuration is 75.58 Naira. This value represents the cost associated with reducing one ton of CO2 emissions. - Global efficiency (LHV - Lower Heating Value): The global efficiency of the system, based on the lower heating value, is determined to be 28.64%. This indicates the efficiency of converting the energy source into useful work.
Integrating internal dynamics within power plants: - Total annual cost (Naira): The total annual cost for this configuration is 131,675,549 Naira. This cost encompasses all expenses related to the integration of internal dynamics within power plants. - CO2 avoided (Tons/year): The adoption of internal dynamics integration within power plants allows for the avoidance of 4,915,299 tons of CO2 emissions annually. This reduction in CO2 emissions supports environmental sustainability efforts. - Price per CO2 ton (Naira/Ton): The specific price per CO2 ton in this configuration is 28.45 Naira. This value represents the cost associated with mitigating one ton of CO2 emissions. - Global efficiency (LHV - Lower Heating Value): The global efficiency of this configuration, based on the lower heating value, is determined to be 40.22%. This indicates the efficiency of energy conversion within the system.
Gas powered turbine configuration: - Total annual cost (Naira): The total annual cost for the gas-powered turbine configuration is 147,461,243 Naira. This cost includes all expenses associated with operating and maintaining the system. - CO2 avoided (Tons/year): With this configuration, the system is capable of avoiding the emission of 4,512,651 tons of CO2 per year. This reduction in CO2 emissions contributes to environmental sustainability. - Price per CO2 ton (Naira/Ton): The specific price per CO2 ton in this configuration is 35.23 Naira. This value represents the cost associated with reducing one ton of CO2 emissions. - Global efficiency (LHV - Lower Heating Value): The global efficiency of the system, based on the lower heating value, is determined to be 43.12%. This indicates the efficiency of converting the energy source into useful work. These results provide an advanced and expanded analysis of the specific CO2 prices for each configuration. It includes the total annual cost, CO2 emissions avoided, price per CO2 ton, and global efficiency based on the lower heating value. These metrics help assess the financial and environmental aspects of each configuration, aiding in decision-making and comparison.

Figure 3 represents a schematic diagram representation of a system that integrates coupled internal flows. The figure includes various components and processes involved in the system. Let's analyze the mentioned components in more detail:

GAS/OIL: This refers to the input fuel sources for the system, which can be either gas or oil. These fuels are used as energy sources to power the system.

AIR: Air is one of the essential inputs required for the combustion process. It provides oxygen to support the burning of fuel in the combustion chamber.

COOLING WATER: Cooling water is used to regulate the temperature of different components within the system, ensuring efficient operation and preventing overheating.

CONDENSER: The condenser is a component that plays a role in the heat exchange process. It helps to convert the steam generated from the system back into liquid form.

STEAM TURBINE: The steam turbine is a device that utilizes the energy from steam to generate mechanical power. It converts the thermal energy of the steam into rotational motion.

H2 RICH GAS: H2 rich gas refers to a gas stream that contains a high concentration of hydrogen (H2). This gas is likely a product or byproduct of the system's processes.

COMBUSTION CHAMBER: The combustion chamber is the area in the system where the fuel and air are mixed and burned to release thermal energy.

GAS TURBINE: The gas turbine is a device that converts the energy of pressurized gas into mechanical power. It typically utilizes the combustion of fuel and air in the combustion chamber.

Based on the mentioned components and their interactions, it appears that the research or system being represented in Figure 3 involves an integrated energy production system. It likely includes the combustion of gas or oil in a combustion chamber, the use of resulting gases to drive a gas turbine, and the recovery of waste heat for steam generation. The steam may then be utilized to drive a steam turbine or for other purposes in the system..

In the short term, power companies often face the challenge of reducing CO2 emissions to comply with National Allocation Plans without significant impacts on their economic results. In such scenarios, a less intensive CO2 capture process may indeed be economically attractive. Implementing a less intensive CO2 capture process can offer a more cost-effective solution for power companies in the short term. This approach focuses on achieving a moderate level of CO2 capture that helps meet regulatory requirements while minimizing the associated costs. By adopting less intensive capture processes, power companies can strike a balance between reducing emissions and maintaining their economic viability. These processes may involve technologies that target the capture of a portion of the CO2 emissions rather than aiming for high levels of capture. This short-term approach allows power companies to fulfill their immediate regulatory obligations while keeping costs manageable. It provides flexibility and allows for a phased implementation of more advanced capture technologies in the medium to long term. It's important to note that the choice of capture process should align with the specific circumstances and objectives of the power company. A comprehensive assessment of the economic implications, including the cost of technology, operational expenses, and potential revenue streams, is essential for making informed decisions..

Let's analyze the mentioned components in more detail

FLUE GAS/DISTRICT HEATING WATER HEAT EXCHANGER: This component represents a heat exchanger where heat is transferred between the flue gas and the district heating water. Flue gas is the exhaust gas produced from industrial or combustion processes, while district heating water refers to the water used for heating in a specific area or district. The heat exchanger transfers the thermal energy from the flue gas to the district heating water, thereby utilizing waste heat to contribute to the heating system.

WATER/DISTRICT HEATING WATER HEAT EXCHANGER: This component represents another heat exchanger where heat exchange occurs between regular water and the district heating water. Regular water refers to water from a different source or system, which is not directly involved in the district heating system. The heat exchanger transfers heat from the regular water to the district heating water, supplementing the heat supply for the heating system.

Based on the mentioned components and their interactions, it appears that the research or system being represented in Figure 4 focuses on utilizing waste heat from flue gas and additional heat from regular water to enhance the efficiency and effectiveness of a district heating system. By transferring heat from the flue gas to the district heating water and utilizing additional heat from regular water, the system aims to maximize the utilization of available energy sources and minimize waste.This type of heat exchange system can contribute to energy conservation, cost savings, and environmental sustainability by repurposing waste heat and optimizing the use of available resources. It is commonly implemented in district heating systems to enhance heat recovery and improve overall system efficiency..

When conducting an economic evaluation, it is common to utilize various sources for assessing capital costs. One widely used method is the "six-tenths rule." This rule estimates that the cost of a new facility or project will be approximately 65% of the cost of a similar existing facility. In addition to the "six-tenths rule," there are other assumptions commonly made in economic evaluations. These assumptions can vary depending on the specific context and project. However, some typical assumptions include:

Cost of materials and equipment: The evaluation assumes the cost of materials and equipment based on market prices at the time of the assessment. These costs may consider factors such as inflation and any specific variations in prices for the project location.
Labor costs: The evaluation estimates labor costs based on prevailing wages in the industry and region. Factors such as skill levels, labor availability, and any specific labor market conditions are considered in this assessment.
Project duration: The evaluation assumes a specific project duration, which can vary depending on the complexity and scale of the project. The duration affects costs such as labor, financing, and maintenance.
Financing costs: The evaluation incorporates financing costs, including interest rates, loan terms, and any applicable fees. These costs reflect the expenses associated with securing funding for the project.
Operational and maintenance costs: The evaluation factors in ongoing operational and maintenance costs, including utilities, labor, and routine maintenance expenses. These costs are essential for assessing the long-term economic viability of the project. It's important to note that these assumptions are made to facilitate the economic evaluation and provide estimates of capital costs. The actual costs may vary based on project-specific factors and market conditions.

Based on the information provided, it appears that the modification of the steam cycle for the stripper energy requirement is the cheaper option in terms of cost. However, it is important to consider the trade-offs involved in this choice. As mentioned in Table 2, this modification results in the maximum power output reduction and a loss of efficiency of 8.8 points. These reductions can have potential impacts on the overall performance and productivity of the power plant. On the positive side, this option does not require any additional CO2 emissions. It allows for the avoidance of approximately 5.8 million tons of CO2 per year. This demonstrates a significant environmental benefit, contributing to the reduction of greenhouse gas emissions. In terms of cost, the estimated cost of #26,000.00 (Naira) per ton of CO2 avoided provides an indication of the economic feasibility of this option. However, it is important to conduct a comprehensive cost-benefit analysis to assess the financial implications of implementing this modification. Considering the preferred choice depends on a balance between the economic and environmental objectives of the power company. The cheaper cost and significant CO2 avoidance may make this option appealing, but it is essential to evaluate the potential impact on power output, efficiency, and overall operational performance. Furthermore, it's crucial to consider any regulatory requirements or incentives related to CO2 emissions reduction that may influence the decision-making process. The gas turbine scheme demonstrates an intriguing characteristic in terms of annual costs, as it stems from the considerably reduced size of the gas turbine combined with the heat recovery steam generator in contrast to a conventional natural gas boiler. While this option boasts higher efficiency and power output, it yields a slightly lower reduction in carbon dioxide emissions. Consequently, the overall cost escalates to an estimated #32,000.00 (Naira) per metric ton of carbon dioxide mitigated. In essence, opting for the gas turbine scheme may entail a higher initial investment due to the downsized equipment involved; however, its superior performance in terms of efficiency and power generation cannot be overlooked. Nonetheless, it is crucial to acknowledge that the achieved decrease in carbon dioxide emissions is marginally less compared to alternative configurations, thereby resulting in a higher cost per metric ton of carbon dioxide mitigated.:

The inclusion of an auxiliary boiler in the power generation configuration leads to an elevation in both equipment and operational expenses, consequently driving up the overall annual cost. Furthermore, the reduction in avoided CO2 emissions, coupled with an increase in CO2 emissions, contributes to an augmented cost per metric ton of CO2 avoided, reaching up to #65,000.00 (Naira). However, if coal is utilized instead of natural gas, the cost decreases to #58,000.00 (Naira). Despite the potential challenges in operating a steam turbine, the option of incorporating intercooling compression into the low-pressure steam cycle as part of steam cycle modifications appears to be a promising alternative when compared to other configurations.

When exploring configurations that incorporate both gas turbines (GT) and steam generators, it is important to consider their impact on the overall power generation system. The integration of GT and steam generators offers potential benefits in terms of efficiency and power output. However, it is crucial to carefully evaluate the associated costs and CO2 emissions. In the case of the auxiliary boiler option, the inclusion of additional equipment and operational costs results in a higher total annual cost. Additionally, the CO2 emissions decrease the amount of CO2 avoided, leading to an increased cost per metric ton of CO2 avoided, which can reach up to #65,000.00 (Naira). Nevertheless, if coal is used instead of natural gas, the cost can be reduced to #58,000.00 (Naira). Despite potential operational challenges with the steam turbine, the option of incorporating intercooling compression into the low-pressure steam cycle as part of steam cycle modifications appears to be a worthy alternative. This approach offers potential advantages compared to other configurations that include GT and/or steam generators. It is essential to carefully assess the trade-offs between costs, efficiency, power output, and environmental impact when considering these configurations

4. CONCLUSIONS

Amine scrubbing has emerged as a widely recognized and effective method for CO2 capture. Extensive research has been conducted over the past decade on the chemical reaction mechanisms and development of solvents, with the aim of reducing the energy requirements for solvent regeneration. However, despite significant progress in these areas, the optimal integration of the capture process into power plants remains unresolved. The challenge lies in finding a balance between achieving efficiency optimization and meeting the economic objectives. The integration of CO2 capture processes into power plants often results in power output and efficiency penalties. This means that efforts to optimize the efficiency of the power plant may not align with the goal of achieving economical optimization. The trade-off between maintaining power plant efficiency and minimizing the costs associated with CO2 capture poses a complex challenge that requires careful consideration. To address this issue, it is crucial to conduct advanced research that delves into the intricacies of integrating capture processes into power plants. This research should explore innovative approaches to optimize both the efficiency and economic aspects of the system. By thoroughly investigating various strategies and analyzing their technical and economic implications, it is possible to bridge the gap between efficiency optimization and cost-effectiveness in CO2 capture technologies integrated into power plants. The ultimate aim of this research is to develop a comprehensive framework that enables the identification of optimal configurations for large-scale implementation of CO2 capture processes in power plants. By striking the right balance between efficiency and economics, this framework will facilitate the deployment of cost-effective and environmentally sustainable CO2 capture technologies, contributing to the ongoing efforts to mitigate climate change..In this research paper, various possibilities have been proposed to tackle the energy requirements of integrating amine scrubbing into a commercial power plant. The technical and economic performance of these approaches has been thoroughly analyzed. It is worth noting that regeneration requirements and their impact on power plant performance can be mitigated by using different types of amines and blends. However, it is important to acknowledge that further research is necessary to explore and propose several integration schemes for these alternative amine solutions. By delving deeper into the characteristics and behavior of different amines and their blends, researchers can identify the most effective integration strategies that minimize energy requirements while maximizing power plant performance. The ultimate goal is to develop a comprehensive understanding of the interactions between different amines, their solvents, and the power plant system. This knowledge will enable the design of optimized integration schemes that effectively capture CO2 while minimizing energy consumption and optimizing power plant performance. Through continued research and exploration, it is possible to advance the field of amine scrubbing integration and unlock new possibilities for cost-effective and energy-efficient CO2 capture in power plants.

The utilization of a gas turbine (GT) to fulfill the compression electrical energy requirements and extracting steam from the steam cycle is considered the optimal option in terms of minimizing the efficiency penalty on power plant performance. This configuration has been found to be effective in reducing the impact on power plant efficiency while meeting the energy demands of the CO2 capture process. However, it is important to note that economic evaluation has revealed that the operation of a GT actually reduces the amount of CO2 avoided and increases the capture cost by up to #8000.00(naira)per ton of CO2 when compared to a configuration with steam cycle modifications. These modified steam cycle configurations have demonstrated the best results in terms of minimizing capture costs. These findings highlight the complex trade-offs between efficiency optimization and economic considerations in CO2 capture technologies. While the GT-based configuration offers advantages in terms of power plant performance, it comes at a higher cost in terms of CO2 capture. On the other hand, steam cycle modifications may incur some efficiency penalties but lead to lower capture costs. Based on these economic evaluations, it is crucial to carefully consider both efficiency and cost factors when selecting the optimal configuration for CO2 capture in power plants. Further analysis and research can help identify the most cost-effective and efficient approach that strikes the right balance between power plant performance and the economic viability of CO2 capture technologies.

Indeed, it is evident that the installation of a new steam generator for the stripper energy requirements is the least efficient and cost-effective option among the alternatives. While this approach may fulfill the energy demands for the CO2 capture process, it results in significant penalties in efficiency and power output. In this scenario, the efficiency reduction amounts to 10 points compared to the base case configuration. Additionally, the capture cost per ton of CO2 avoided is estimated to be #65,000,00(naira)for natural gas operation and #58,000.00(naira) euros for coal operation. These higher capture costs make this option less economically viable compared to other configurations. While the installation of a new steam generator may be considered as a potential solution, the substantial efficiency penalties and increased capture costs make it less attractive from both technical and economic standpoints. It is important to explore other alternatives that strike a better balance between efficiency, cost-effectiveness, and CO2 capture performance. Further research and analysis are necessary to identify and evaluate more optimal configurations that can achieve efficient CO2 capture while minimizing efficiency penalties and capturing costs. By exploring innovative approaches and considering the unique characteristics of different power plants, it is possible to develop cost-effective and efficient solutions for CO2 capture in the context of steam cycle modifications.While much of the current research is focused on integrating CO2 capture processes into existing power plants, there is a need for further exploration into the design of new power plants with integrated CO2 capture processes. By incorporating CO2 capture technologies into the initial design of power plants, it is possible to reduce efficiency penalties and develop more cost-effective processes. Designing power plants from the ground up with integrated CO2 capture in mind allows for a more optimized and efficient approach. By considering factors such as the selection of appropriate technologies, process integration, and system optimization, it becomes possible to minimize the efficiency losses traditionally associated with retrofitting capture technologies. Furthermore, the advantage of designing new power plants with integrated CO2 capture is the opportunity to explore innovative technologies and novel approaches. This opens up possibilities for breakthroughs and advancements in capturing CO2 more efficiently and at a lower cost. By investing in research and development for the design of new power plants with integrated CO2 capture, we can pave the way for a greener and more sustainable future. It is through continuous innovation and exploration that we can discover the most efficient and cost-effective processes for capturing CO2 and mitigating climate change.

ACKNOWLEDGMENT

I would like to extend our deepest appreciation and gratitude to all those who contributed to the research titled " Driving Sustainability In Power Generation: Amine Scrubbing Integration As a Cost-Effective Measure For Carbon Dioxide Mitigation. Their invaluable contributions, dedication, and expertise have greatly enriched this study and made it possible to explore the subject matter with depth and precision. I would like to express our heartfelt gratitude to our principal investigators, who provided guidance and direction throughout the research process. Their expertise and insightful feedback have been instrumental in shaping the research and ensuring its high quality. We would also like to acknowledge the support and collaboration of our research team members. Their collective efforts, passion, and commitment to excellence have propelled this research forward and enabled us to achieve meaningful results. Furthermore, we extend our thanks to the participants who generously shared their time and knowledge, contributing essential data and insights that have enhanced the rigor and validity of this research. I am grateful for the support and resources provided by [Johnson Global Scientific Library] in facilitating this research. Their commitment to advancing knowledge and fostering a conducive research environment has been key to the success of this study. Lastly, i would like to express our appreciation to all those individuals who provided assistance and support behind the scenes, including administrative staff, technicians, and other individuals who contributed to the smooth operation of this research. The completion of this research would not have been possible without the collective efforts and collaboration of these individuals. Their contributions have significantly advanced our understanding in this field and will undoubtedly pave the way for future advancements and discoveries. Once again, I extend my heartfelt gratitude to all those who have played a part in this research, and we look forward to the continued exploration and innovation that lies ahead.

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Figure 1. flowsheet for the MEA absorption process.

Figure 2. Integration With an Auxillary Gas Boiler, Internal Energy Circulation, and a Natural Gas Turbine.

Figure 3. integrating coupled with The internal Flows.

Figure 4. represents a schematic diagram representation of a heat exchange system involving flue gas, district heating water, and regular water.

Table 1. Main simulation parameters .

	UNITS	THIS PAPER
net generation from base plants	MWe	1,169
Baseline plant productivity (LHV)	%	39.9
Flue gases CO2 conc.	V.%	10.8
Technology	MEA	MEA
CO2 flow rate captureed.	T/H	700.6
CO2 captured	%	75
Electricity consumption per CO2 captured.	CO2/KWh	112.94
Heat consumption per CO2 captured.	CO2/	3.78

Table 2. integration results summary.

	The power generated by steam turbines (MWe)	Auxiliary input. electricity consumption (MWe))	that of N.G requirement for energy.	Total yield	worldwide applicability	Particular emission levels of carbon dioxide (kg CO2 (Kwh))
Base plant	372.08	22.88/3	-	361.08	36.08%	0.999
the auxiliary Natural Gas Boiler	372.08	88.69/3	406.8/3	331.88	31.91%	0.487
Based on IP1 the extraction process.	365.56	91.82/3	-	310.98	29.99%	0.411
Based on IP2 the extraction process.	334.41	94.16/3	-	296.55	31.08%	0.445
Gas turbine HP and and IP heater bleed reduction	394.19	22.88/3	147/3	330.12	33.20%	0.477
Gas turbine and extra steam generation	399.88	25.50/3	147/3	334.44	34.60%	0.475

Table 3. Total annual costs Capital costs (Naira) Absorber 34,222,546.

Reboiler	3,555,231
Regenerator.	3,388,450.
Auxillaries & MEA plant.	17,897,543
Blower	4,272,232
Equipment cost & total captures(naira)	76,654,231
Equipment cost & total compression(naira)	138,654,451
Total equipment cost(Naira)	240,421,138.
Installation cost 14	34,876,234.
Initial MEA.	14,432,321
Electrical equipment	57,321,541
Instrumentation and control.	64,761,210
Capture plant and compression total cost(naira)	411,812,444.
Engineering and supervision cost (8%) ,process and project cointigency (18%).	63,765,123

Table 4. SPECIFIC CO2 PRICES ,CALCULATED FOR EACH CONFIGURATION.

	TOTAL ANNUAL COST (NAIRA)	CO2 AVOIDED (T/YEAR)	PRICE PER CO2 TON (NAIRA/T)	GLOBAL EFFICIENCY (LHV)
The Dual-fuel boiler	226,736,389	3,797,823	75.58	28.64%
Integrating internal dynamics within power plants	131,675,549	4,915,299	28.45	40.22%
Gas Powered Turbine	147,461,243	4,512,651	35.23	43.12%

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Driving Sustainability in Power Generation: Amine Scrubbing Integration as a Cost-Effective Measure for Carbon Dioxide Mitigation

Abstract

1. INTRODUCTION

3. CAPTURE A SIMULATION ASSOCIATED WITH PLANT

3.1. THE DUAL-FUEL BOILER

4. CONCLUSIONS

ACKNOWLEDGMENT

References

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