Economic Evaluation of Carbon Capture and Utilization Applying the Technology of Mineral Carbonation at Coal-Fired Power Plant

Abstract

Based on the operating data of a 40 tCO₂/day (2 megawatt (MW)) class carbon capture and utilization (CCU) pilot plant, the scaled-up 400 tCO₂/day (20 MW) class CCU plant at 500 MW power plant was economically analyzed by applying the levelized cost of energy analysis (LCOE) and CO₂ avoided cost. This study shows that the LCOE and CO₂ avoided cost for 400 tCO₂/day class CCU plant of mineral carbonation technology were 26 USD/MWh and 64 USD/tCO₂, representing low LCOE and CO₂ avoided cost, compared to other carbon capture and storage CCS and CCU plants. Based on the results of this study, the LCOE and CO₂ avoided cost may become lower by the economy of scale, even if the CO₂ treatment capacity of the CCU plant could be extended as much as for similar businesses. Therefore, the CCU technology by mineral carbonation has an economic advantage in energy penalty, power plant construction, and operating cost over other CCS and CCU with other technology.

1. Introduction

Carbon dioxide (CO₂) emissions in the atmosphere from anthropogenic activities continue to grow worldwide [1,2,3], as CO₂ emissions in the period 2010 to 2014 grew about 31.9 to 35.5 GtCO₂ per year, an average rate of 2.75% per year [4], escalating global warming. Various studies have been made to mitigate carbon emission to hold average global warming below 2 °C above pre-industrial levels [5,6]. Carbon capture and storage (CCS) and carbon capture and utilization (CCU) are evaluated by the International Energy Agency (IEA) and U.S. Energy Information Administration (EIA) as two of the most cost-effective methods for climate change mitigation among various technologies [7]. CCS permanently captures and stores CO₂ to reduce greenhouse gas from coal-fired power plants or cement manufacturing facilities [8]. CCU involves chemical reaction, converting CO₂ into valuable chemical compounds [9].

CCU by mineral carbonation technology, also called CO₂ mineralization, is a less explored method of sequestering CO₂ compared to other CCS methods, such as geological sequestration [10,11,12], ocean disposal [13,14,15], and biological fixation [16,17,18]. Mineral carbonation involves the chemical conversion of CO₂ to solid inorganic carbonates permanently fixing carbon with a negligible risk of return to the atmosphere without having a great impact on the surrounding environment and ecosystems [19,20].

As CCS and CCU are relatively recent technologies, their effectiveness still needs to be analyzed. Large-scale CCS projects were mostly based on enhanced oil recovery, whereby CO₂ is used to obtain the last remains of an oil field by injection of gaseous, liquid, or supercritical CO₂ into subsurface reservoirs inducing the geological storage of CO₂ in porous rocks, which was proved to be effective for cutting the CO₂ emission but still remains to be studied for their cost-effectiveness compared to others technologies [21,22,23]. Also, IEA has published a research report, “cost and performance of carbon dioxide capture from power generation, IEA, 2011,” comparing the economic feasibility of CCS-applied technologies (post-combustion, pre-combustion, oxy-combustion) between the levelized cost of energy analysis (LCOE) and CO₂ avoided cost [24]. The economic evaluation of CCS has been made on the assessment method of the expectation of the energy penalty for applying CCS technology [25], comparing LCOE and CO₂ avoided cost for applied CCS technology (supercritical, ultra-supercritical, integrated gasification combined cycle (IGCC), oxy-combustion, natural gas combined cycle (NGCC)) at power generation on economic aspects [26].

On the other hand, the economic evaluation of CCU focused on sales profit from selling CO₂ compounds produced from applying CCU technology or on the life cycle assessment (LCA) [27]. One analyzed a manufacturing technology of high-valued compounds, sodium bicarbonate (NaHCO₃), through carbon dioxide carbonization, and the result of the internal rate of return for 20 years was 67.2% [28]. Techno-economic assessment of CO₂ utilization was studied by applying LCA of the Canadian emerald energy from a waste facility [29]. LCA conducted for a comprehensive analysis of the climate change mitigation potential of CCU, in applying fields such as fertilizer process [30], CO₂-based polymers used as raw materials for plastics [31], chemical industry [32], and electrocatalytic conversion of CO₂ into commercially-valued products, including carbon monoxide, methane, and methanol [33,34,35].

Most CCS economic evaluation of power generation uses LCOE and CO₂ avoided cost, with the CCS technology by applying the energy penalty when constructing the power generation plant [36,37]. As mentioned previously, CCU economic evaluation focuses on the sales revenue of the resulting CO₂ compounds from the technology [29,38,39]. LCOE represents the average revenue per unit of electricity generated that would be required to recover the costs of building and operating a generating plant during an assumed financial life and duty cycle, CO₂ captured cost is calculated by comparing a capture plant to any reference plant, and CO₂ avoid cost is derived from the equalization of the net present values of costs of the power plant with and without CCUS technology [40].

Based on the operating data and input cost of a 40 tCO₂/day (2 megawatt (MW)) class CCU pilot plant at a coal-fired power plant, the scaled-up 400 tCO₂/day (20 MW) class CCU plant at 500 MW coal-fired power plant was economically analyzed by applying the LCOE and CO₂ avoided cost, considering the energy penalty. Moreover, the CCU technology in this study, utilizing the resulting compounds as construction ingredients, has insufficient economic evaluation and comparative studies according to applied technology on the economic evaluation results [19,41]. Here, we have calculated the LCOE and CO₂ avoided cost for mineral carbonation, resulting in 26 USD/MWh and 64 USD/tCO₂ each, and conducted comparative studies with other CCS and CCU technologies, which were higher cost for each factor.

To remind, this paper is structured as follows: Section 2 introduces the methods and technology of applied examination, with the detailed explanation of the components and the process; Section 3 gives detailed information on the experiment results with the analysis of LCOE and CO₂ avoided cost; Section 4 shows the comparison of the economic analysis between the applied technology in this study and other CCU technologies, and also include sensitivity analysis; Section 5 addresses the conclusion on the applied CCU technology.

The following subjects were considered to increase the accuracy of this research, and a comparative analysis was conducted between the resulting economic outcomes and other CCS or CCU references.

• Considering the energy penalties resulting from the CCU plant at a 500 MW coal-fired power plant.
• Application of the actual operational data of a 40 tCO₂/day (2 MW) class pilot plant installed at a 500 MW coal-fired power plant.
• Application of the actual operational data of the captured CO₂ amount collected through a 40 tCO₂/day (2 MW) class continuous-capture-process.
• For the 400 tCO₂/day (20 MW class) CCU plant installed at a 500 MW coal-fired power plant that manages the economic evaluation, apply the estimated price of equipment based on the actual preliminary design.
• By applying the levelized cost of energy analysis (LCOE), compare the “CO₂ avoided cost” and “CO₂ captured cost” in similar businesses.
  • LCOE = Σ ((Investment cost _t + Operation maintenance cost _t + Fuel cost _t + Power plant abolition cost _t)×(1 + r)^-t)/(Σt(Power generation _t ×(1 + r)^-t))
  • CO₂ capture cost [USD/tCO₂] = (LCOE)_CCS − (LCOE)_ref/(tCO₂/MWh)_captured
  • CO₂ avoid cost [USD/tCO₂] = (LCOE)_CCS − (LCOE)_ref/(tCO₂/MWh)_CCS

2. Materials and Methods

2.1. Applied Technology

Mineral carbonation process can effectively utilize the industrial CO₂ emissions to form various products and carbonate precipitates, as it is a thermodynamically favorable reaction. The mineral carbonation using alkaline solid wastes has merits of low feedstock cost and availability near the source of CO₂ [27]. The utilization process for this study, CCU of mineral carbonation technology, produces construction ingredients from converting the CO₂-captured compounds to CaCO₃ through the direct reaction of CO₂ in the flue gas at the coal-fired power plant.

This technology operates a 40 tCO₂/day (2 MW) class CCU pilot plant at a coal-fired power plant in Korea from November 2017. Inserted partial flue gas, emitted from the power plant duct into the CCU plant, produce CO₂-captured compounds (CaCO₃), and unreacted CO₂ returns to the power plant duct to maintain the CO₂ concentration below 1% in the atmosphere. The applied technology and main equipment configuration are as follows (Figure 1,

Table 1. 40 tCO₂/day class CCU pilot plant components.

Classification	Components
Facility name	Direct CO2 capture-process pilot plant
Facility capacity	7000 Nm3/h
CO2 removal amount	40 ton/day
Monitored CO2 removal amount	25.94 ton/day
CaCO3 production	61.80 ton/day
Measured CO2 content in CaCO3 production	38.29% (TGA analysis)
Measured electric power consumption (Real data)	0.8 MW
Main equipment	Agent supply system	After storing mineral powder and slag powder, provide a quantitative influx into the reaction agent dissolved tank, and dissolve it for (30–40) min. → Mix (30–40) min for all of the CaO to react → Transport steam and dust generated from the reaction agent reacting process to the desorption liquid storage tank (no wastewater generation).
	CO2 removal process system	The first removal of CO2 through reacting agent and gas-liquid contact in the first reaction tower. → Discharge after removing residual CO2 with the reacting agent in the secondary reaction tower. → Supplement from the secondary reaction tower by the CO2-captured transfer pump of the first reaction tower when the chemical agents in the first reaction tower reach below pH 8.5, while reacting with CO2 in the emission gas. Real-time monitoring and analysis of CO2 concentration by CO2 analyzer installed before and after the reaction tower duct. Real-time monitoring and control from the main computer by measuring the temperature, flow rate, flux, and flow pressure.
	Captured CO2 treatment system	Some of the generated CO2-captured compounds are used as the ingredient of construction materials (bricks, cements block, and so forth) after the dehydrating process in a dehydrator. The remaining undehydrated CO2-captured compounds are used as reagent, such as a desulfurization agent. → Effluent from the dehydration process is used as the full chemical reagent manufacturing water, and the deficiency is supplemented with water. → The dehydrated cake is placed in a ton bag for a certain time, and then taken out.

):

2.2. Applied Scale and Process

The applicable field scale for this study, a 400 tCO₂/day class CCU plant, can be designed by knowing the actual amount of reduced CO₂ from the operating 40 tCO₂/day class CCU pilot plant, and modifying the operational problems from the pilot plant. Based on this scaled-up field scale plant, the economic evaluation was conducted for a 400 tCO₂/day class CCU plant. The scaled-up preliminary design of the 400 tCO₂/day class CCU plant is as follows (

Table 2. Preliminary design outline of the 400 tCO₂/day class CCU plant.

Classification		Project Outline
Project name		Preliminary design of a demonstration plant of the 400 tCO2/day class direct CO2 capture-removal process
Location		Local power plant, cement or steel manufacturing plant
Facility capacity		60,000 Nm3/h
CO2 removal amount		400 tCO2/day
Task range	Mechanical field	Preliminary design of machinery, such as ingredients and chemical reagent supply facility, CO2 removal reacting facility, CO2-captured treatment facility, and other process facilities.
	Electric measurement and control field	Preliminary design of electric measurement and control field, such as motor control center (MCC) module, electric panel, and process measuring instrument.

, Figure 2):

Therefore, the applied facility and process of this study are as follows (

Table 3. Description of the 400 tCO₂/day class CCU plant.

Classification		Contents
Facility capacity		60,000 Nm3/h (15,000 Nm3/h × 4 series)
Operating time		24 h/day, 350 days
Construction period		36 months
Treatment process	Chemical reagent supply facility	Ingredient storage room/ingredient input hopper/ingredient transfer conveyor/ingredient supply conveyor/ingredient supply SILO/ingredient input conveyor/reactant dissolution tank/reactant transfer pump/reactant storage tank/reactant supply pump/liquid catalyst storage tank/liquid catalyst supply pump
	CO2 removal reacting facility	Emission gas cooling tower/cooling tower circulation pump/emission gas pressurized blower/reaction tower/reaction tower circulation pump/reaction tower transfer pump of CO2-captured
	CO2-captured treatment facility	CO2-captured settling tank/sediment collector/sediment outlet/sediment transfer pump/supernatant treating tank/supernatant reuse-pump/sediment storage pit/drying bed
	Other facility	Supernatant storage tank/water storage tank/process liquid supply pump/air compressor/pit pump/bottom drain pump
CO2-captured compounds treatment plan		Precipitate the CO2-captured in settling tank, supernatant overflows into the supernatant treating tank, and reuse it as process liquid. The residual sediment is sent to the sediment storage pit, and then stacked on the drying bed by excavator. After the sediments are dried, they are taken out to supply the required site.
Rain water and domestic wastewater treatment plan		Connected treatment of rain water through rain water pipeline into the manufacturing plant rainwater pipeline. Connected treatment of domestic wastewater through wastewater pipeline into the manufacturing plant wastewater pipeline.
Emission gas capture method		Portion of emission gas is captured from the emission gas transfer duct generated during the carbon fuel combustion process.

):

3. Results

3.1. Cost Calculation of a 500 MW Coal-Fired Power Plant

To conduct the economic evaluation by demonstration plant of the 400 tCO₂/day class CCU plant, an economic evaluation of a 500 MW coal-fired power plant was first conducted (

Table 4. Estimated cost of the 500 MW coal-fired power plant.

500 MW Coal-Fired Thermal Power Plant	Applied Value	Unit	Note
Discount rate	7	%	Assumption (IEA data for reference)
Load factor	85	%	3 year average of Domestic power plant
Plant lifetime	25	Year	Assumption (IEA data for reference)
Capacity	500	MW	Assumption
Annual generated electricity	3,570,000	MWh/year	500 MW × 85% × 350 day × 24 h
Thermal efficiency	40	%	Assumption (IEA data for reference)
Equipment cost	875	USD/kW	Assumption (construction cost of domestic power plant)
Annual fixed cost	4	Construction cost%	Assumption (IEA data for reference)
Annual variable cost	0.5	Construction cost%	Assumption (IEA data for reference)
Fuel cost	0.83	USD/GJ	Assumption (IEA data for reference)
Capex	437.5	M USD	500 MW × 875 USD/kW
Annual operating & maintain cost	19.7	M USD/year	4.5% × 437.5 M USD
Annual fuel cost	26.8	M USD/year	(3,570,000 MWh/40%) × 3.6 GJ/MWh × 0.83 USD/GJ
Capex (present value (PV)	395.7	M USD	3 year (1st year 10%, 2nd year 30%, 3rd year 60%)
Opex (PV)	472.9	M USD	Opex for 25 year
Generated electricity (PV)	36,337,926	MWh	Generated electricity for 25 year

). The applying assumptions are based on the applied data of IEA economic evaluation, and the information provided by the actual domestic power generation companies.

3.2. Cost Calculation for the 400 tCO₂/day Class CCU Plant

The additional capex for installing the 400 tCO₂/day class CCU plant at the 500 MW coal-fired power plant is based on the 2018 price level, which was also applied for the preliminary design of the 400 tCO₂/day class CCU plant. The information on additional construction costs is as follows (

Table 5. Construction cost for the demonstration plant of the 400 tCO₂/day class CCU plant.

Construction Cost	Applied Value	Unit	Note
Mechanical construction	6.0	M USD	Preliminary design report
Electric construction	1.6	M USD	Preliminary design report
Civil/architectural construction	10.2	M USD	Preliminary design report
Total construction cost	17.8	M USD	Preliminary design report

):

The additional opex for installing the 400 tCO₂/day class CCU plant at the 500 MW coal-fired power plant is based on the 2018 electric and water cost, which was also applied for the preliminary design of the 400 tCO₂/day class CCU plant. The information on additional operating costs is as follows (

Table 6. Annual opex for the 400 tCO₂/day class CCU plant.

Classification	Item	Price Unit	Unit	Usage	Total Amount (USD)
Labor costs	Operator	2500	USD/man month	32 people, 12 months	960,000
Electric power cost	Contract power	8.18	USD/kw/month	60,000	490,500
	Electric power consumption	0.075	USD/kw × h	22,400,880	1,689,361
Sub Total					2,179,861
Reagent cost	Calcium hydroxide	75	USD/ton	0	0
	Fly ash	4.17	USD/ton	363,672	1,515,300
	Liquid catalyst	416.7	USD/ton	763	318,000
Sub Total					1,833,300
Water cost	Basic fee	49.2	USD/ton/month	12	590
	Usage fee	0.78	USD/m3	385,200	301,740
Sub Total					302,330
Total annual operating cost					5,275,491

):

3.3. Economic Evaluation Method and Cost Calculation of the CCU Plant

3.3.1. Economic Evaluation Method for the 500 MW Coal-Fired Power Plant Including the 400 tCO₂/day Class CCU Plant

Based on Section 3.1 and Section 3.2, the following considerations are needed to calculate the cost of the 500 MW coal-fired power plant including a demonstration plant with a 400 tCO₂/day class CCU plant.

• Energy penalty caused by the installation of a CCU facility
• Increase in the construction cost according to the increased facility capacity by the energy penalty

First, to calculate the energy penalty by the installation of a CCU plant, the actual measured electric power consumption of the 40 tCO₂/day class CCU pilot plant was applied. The electric power consumption per hour of the 40 tCO₂/day class CCU pilot plant was 0.8 MW. Accordingly, the power consumption for the 400 tCO₂/day class CCU plant was analyzed to consume 4 MW power by applying the “6–10 power rule.” Approximate costs can be obtained if the cost of a similar item of different size or capacity is known. The “6-10 power rule,” also called 0.6 rule or six tenth rule, is used for scale-up of the capacity-cost when analyzing the plant economics. This rule has its origins in the relationship between the increase in equipment cost (C) and the increase in capacity (V) given by C₁/C₂ = (V₁/V₂)^α, where α denotes the scale coefficient. The value of α = 0.6 refers to equipment such as tanks and pipes which give significant economies of scale [42]. The electric power consumption for the basic design of the 400 tCO₂/day class CCU plant was 3.1 MW. The “6–10 power rule” was applied to the relationship between the capacity and the electric power consumption at the 400 tCO₂/day class CCU plant and the electric power consumption for the basic design. In this regard, the cost analysis was conducted by applying 4 MW, a conservative energy penalty.

Therefore, to secure the sufficient capacity of 500 MW coal-fired power plants, it should be designed as 504 MW in consideration of the energy penalty, which is calculated to be (504 − 500)/504 × 100 = 0.8%.

Additional cost is incurred, as the installation of a 504 MW coal-fired power plant increases the power generation capacity owing to the energy penalty. The additional cost was recalculated according to the “6–10 power rule,” which is used for scale-up of the capacity-cost in economic evaluation.

3.3.2. Cost Calculation of the 500 MW Coal-Fired Power Plant Including 400 tCO₂/day Class CCU Plant

The cost of the 500 MW coal-fired power plant including 400 tCO₂/day class CCU plant is presented in

Table 7. Cost of the 500 MW coal-fired power plant with 400 tCO₂/day class CCU plant.

500 MW + CCU Coal-Fired Power Plant	Applied Value	Unit	Note
Discount rate	7	%	Assumption (see IEA data)
Load factor	85	%	Application of 3 year averagefor domestic power companies
Plant lifetime	25	year	Assumption (see IEA data)
Energy penalty	0.8	%	Calculation form 3.3
Capacity (with CCU)	504	MW	Calculation form 3.3
CCU additional capacity	4	MW	Calculation form 3.3
Net capacity	500	MW	--
Annual generated electricity	3,598,560	MWh/year	504 MW × 85% × 350 days × 24 h
Thermal efficiency	40	%	Assumption (see IEA data)
Capital expenditure (CAPEX)	875	USD/kw	Assumption [43]
Annual fixed operating expenditure (OPEX)	4	Construction cost%	Assumption (see IEA data)
Annual variable OPEX	0.5	Construction cost%	Assumption (see IEA data)
Fuel cost	0.83	USD/GJ	Assumption (see IEA data)
CAPEX	439.95	M USD	437.5 M USD × ((504/500)^0.7)
Annual OPEX	19.80	M USD/year	4.5% × 439.95 M USD
Annual fuel cost	27.00	M USD/year	3,598,860 MWh/40% × 3.6 GJ/MWh × USD/GJ
Annual emitted CO2	3,400,000	tCO2/year	Actual data of 500 MW domestic coal-fired thermal power plant
Levelized cost of energy analysis (LCOE)	23.90	USD/MWh	Calculation
Only CCU CAPEX	17.75	M USD	Amount statement of the CO2 direct capture removal process (400 tCO2/day)
Only CCU OPEX	5.25	M USD/year	Only cost applied among construction design report of the direct CO2 capture removal process (400 tCO2/day)
CAPEX including CCU (PV)	413,916,667	USD	3 year (10% for first year, 30% for second year, 60% for third year)
OPEX including CCU (PV)	537,750,000	USD	Including 25 year of operating and disposal costs
Generated electricity(PV)	36,328,630	MWh	Generated electricity for 25 years

[43]. Further detailed data can be found in Table S1.

3.4. Calculation of CO₂ Captured and Avoided Cost

3.4.1. CO₂ Captured Efficiency and Utilization Rate

The captured efficiency was calculated based on the actual data of a currently running 40 tCO₂/day class CCU pilot plant. The utilization rate was calculated through this captured efficiency. The following data is measured data at the site of the 40 tCO₂/day class CCU pilot plant, and the continuously measured data for more than 20 h in normal operation was applied. The measured data utilized the real-time continuously measured on-site data of flow rate, and CO₂ concentration in the inlet and outlet. The following is the monitoring results from the real-time measuring instrument along the time sequence for every hour from 05/29 14:00 to 05/30 12:00 (Figure 3 and Figure 4).

To calculate the utilization rate of the CCU plant, it is necessary to convert the power generating capacity of the 400 tCO₂/day class CCU plant. Accordingly, by applying the actual data from a domestic coal-fired power plant, the capacity of the CCU plant was converted based on the captured CO₂ amount that could be treated based on the amount of greenhouse gas emissions at the 500 MW coal-fired power plant. A domestic coal-fired power plant emits 6800 tCO₂ per 1 MW. Moreover, a 400 tCO₂/day class CCU plant captures CO₂ of 20 MW power generation capacity. The captured efficiency was 85.71% and the utilization rate was 4% for a 400 tCO₂/day class CCU plant among the 500 MW coal-fired power plant emitted CO₂. As a result, the captured CO₂ utilization rate by a CCU plant was calculated to be 3.43%.

3.4.2. Calculation of the CO₂ Avoided Cost

The “CO₂ avoided” was calculated using the analyzed data from Section 3.4.1. The CO₂ avoided is the amount of avoided (reduced) CO₂ by operating the CCU plant. The following are the CO₂ avoided value (

Table 8. CO₂ avoided of the 400 tonCO₂/day class CCU plant.

Calculation of CO2 Avoided	Applied Value	Unit	Note
Coal-fired power plant without CCU
Capacity	500	MW
Annual generated electricity	3,570,000	MWh/year	500 MW × 85% × 350 day × 24 h
Annual emitted CO2	3,400,000	tCO2/year	Actual data of 500 MW domestic coal-fired thermal power plant
CO2 emission factor	0.9524	tCO2/MWh	CO2 emission/generated electricity
Coal-fired power plant with CCU
Energy penalty	0.8	%	Calculated in Section 3.3.
Capacity (with CCU)	504	MW
Annual emitted CO2	3,598,560	MWh/year	500 MW × 85% × 350 day × 24 h
CO2 emission factor	0.9524	tCO2/MWh
CO2 captured and utilization rate	3.43	%	CO2 captured efficiency (85.71%) × (20 MW/500 MW)
CO2 emission	3,427,200	tCO2/year	Generated electricity × CO2 emission factor (Korea)
CO2 captured and utilization amount	117,504	tCO2/year	CO2 emission × CO2 captured and utilization rate
CO2 emission without CCU	3,400,000	tCO2/year	Actual data of 500 MW domestic coal-fired power plant
Net CO2 emission	3,309,696	tCO2/year	CO2 emission–CO2 capture and utilization amount
CO2 avoided	90,304	tCO2/year	CO2 emission without CCU–net CO2 emission

):

As calculated in the above table, the CO₂ avoided was calculated to be 90,304 tCO₂/year compared to the former coal-fired power plant by the introduction of a 20 MW CCU plant, which can process 400 tCO₂/day (

Table 9. CO₂ avoided cost and LCOE.

Classification	Applied Value	Unit	Note
Coal-fired plant without CCU
Current construction cost	395.67	M USD
Current operation cost	472.92	M USD	On a 25 year basis
Current electric power generation cost	36,337,926	MWh	On a 25 year basis
LCOE	23.90	USD/MWh
Coal-fired plant with CCU
Current construction cost	413.92	M USD
Current operation cost	537.75	M USD	On a 25 year basis
Current electric power generation cost	36,628,630	MWh	On a 25 year basis
LCOE	25.98	USD/MWh
CO2 avoided cost	63.67	USD/tCO2

):

4. Discussion

4.1. Comparative Analysis with Other Studies

To sum up, the economic analysis results show that when CO₂ content is 3.43% of captured and utilization, the captured and recovery emission is 117,504 tCO₂/year, LCOE as 26 USD/MWh, and CO₂ avoided cost as 64 USD/tCO₂.

Table 10. Comparison of avoidance cost of CO₂ and similar businesses.

Emitting Source		Generated Emissions [tCO2/year]	CO2 Captured and Utilization Rate [%]	Captured, Recovery Emissions [tCO2/year]	LCOE [USD/MWh]	CO2 Avoided Cost [USD/tCO2]
Coal-fired thermal power plant, Republic of Korea (mineral carbonation of this study)		3,427,200	3.43	117,504 (Captured efficiency 85.71%)	26	64
CCS	IGCC + CCS, US, 2015, FOAK [11]	4,245,600	90	3,819,360	141	97
	NGCC + CCS, US, 2015, FOAK [11]	1,971,000	90	1,769,520	78	89
	PC supercritical. CCS, US, 2015, FOAK [11]	4,677,840	90	4,204,800	124–133	74–83
CCU	Coal-fired power plant (500 MW, 2010, recovery by dry sorbent) [20]	4,090,625	80	3,272,500	32.46	Capture cost 28.15
	Coal-fired power plant (2010, US) [9]	-	85–100	-	Included in avoidance cost	Capture cost 43–58
	Aluminum production (2013, Norway) [21]	-	-	Capture rate of 85%	-	Capture cost 80–105
	Coal powered (UK, 600 MW, mineral carbonation) [22]	Approx. 4,000,000	85%	3,400,000	-	86–140

compares the economic analysis of this study and other CCS or CCU technology. Different CCS technologies at coal-fired power plants such as IGCC + CCS, NGCC + CCS, PC supercritical, etc., which can capture and utilize 90% of CO₂, as compared to have higher LCOE and CO₂ avoided cost, considering the cost for the processes like CO₂ compression, refinement, transport, and storage. Among CCU technologies in Table 10, the Coal-fired power plant (500 MW, 2010, recovery by dry sorbent), Coal-fired power plant (2010, US), and Aluminum production (2013, Norway) were calculated to have smaller LCOE and CO₂ avoided cost than the studied mineral carbonation because they only included the refinement and compression process of CO₂ and did not consider the CO₂ utilization cost. By comparing with a similar study, Coal powered (UK, 600 MW, mineral carbonation), our study resulted to be more economic.

Additionally, for precise comparison, they should be compared with the same capacity and CO₂ captured efficiency. However, this study shows the economic analysis results of a 20 MW CCU facility, handling 400 tCO₂/day based on the operating CCU plant. Therefore, the reliability lowering assumption, such as capacity expansion, and capture amount increase, was not included.

4.2. Sensitivity Analysis

The sensitivity of LCOE and CO₂ avoided cost, which were results from the economic analysis, was analyzed as the initial conditions changed (Figure 5). The sensitivity of LCOE was analyzed according to the alternation of capital expenditure (CAPEX) and operating expenditure (OPEX) cost and the sensitivity of CO₂ avoided cost was analyzed according to the change in CO₂ captured and utilization rate, and energy penalty (Figure 5a). Figure 5b illustrates when CAPEX was altered $\pm$10%, LCOE was $\pm$6.55% altered, and the $\pm$10% OPEX alternation resulted in $\pm$ 5.65% alternation of LCOE. $\pm$10% change of energy penalty and CO₂ captured and utilization rate resulted $\pm$0.71% and −9.09~11.11% alternation of CO₂ avoided cost each. LCOE was most affected by the CAPEX and the OPEX also effected the LCOE as it is linked with CAPEX. CO₂ captured and utilization rate affected the CO₂ avoided cost the most, showing greater sensitivity than by the effect of energy penalty alternation.

The sensitivity analysis represented that the CO₂ avoided cost of the mineral carbonation technology in this study, was greatly affected by the CO₂ captured and utilization rate; however, owing to the low energy penalty of this study, the energy penalty had little impact.

5. Conclusions

Using LCOE and CO₂ avoided cost, the economic assessment was conducted for the mineral carbonation CCU technology at the coal-fired thermal power plant, which produces CaCO₃ through direct reaction with CaO without refinement or compression process for CO₂ in the flue gas. In order to increase the accuracy and reliability of this analysis, based on the actual operating data of the 40 tCO₂/day class CCU pilot plant, the scaled-up 400 tCO₂/day CCU plant factors were used. Furthermore, the additionally generated power capacity from the CCU facility energy penalty was also considered for the economic analysis including coal-fired power plant construction and operating cost. The utilization rate for the CO₂ capture of the CCU plant in this study is 3.43%, which represents a lower capacity of CCU compared to similar businesses and the CO₂ avoided cost for the 400 tCO₂/day class CCU plant applying mineral carbonation technology was 64 USD/tCO₂, representing low avoided cost, compared to similar scaled CCS and other CCU plant. However, according to the sensitivity analysis, LCOE was greatly affected by CAPEX, showing 6.55% variation, and CO₂ captured and utilization rate was the biggest effect to cause variation to the CO₂ avoided cost. Based on this study, the CO₂ avoided cost may become lower by the economy of scale, even if the CO₂ treatment capacity of the CCU plant could be extended as much as similar businesses. This suggests that CCU technology by mineral carbonation has an economic advantage in energy penalty, power plant construction, and operating cost over other CCS and CCU with other technology.

Also, this economic analysis is based on the actual operation data of CCU plant and has a relatively small CCU plant capacity compared to other studies. Therefore, there is a limitation that CO2 captured and utilization rate is low. However, with further research, we plan to conduct economic analysis on actual large scaled CCU plant and plan to contribute to commercialization of CCU technology.