The Pathway to a Sustainable Use of Fossil Fuels: Carbon Capture and Refining

1. Introduction

Over time, variations in temperature and weather patterns are referred to as climate change. Global warming and climate change are two of today's most serious environmental issues, with greenhouse gas emissions being the primary cause. These variations could have been artificial or natural. Nevertheless, human endeavours have been generating these shifts fuelling climate change throughout the end of the nineteenth century. The primary activity performed by humans that emits harmful greenhouse gases directly into the atmosphere is the consumption of fossil fuels that include natural gas and coal Figure 1. The main considered gases that cause global warming include carbon dioxide (CO₂) and methane (CH₄).

The continual consumption of fossil fuels is a hindrance to minimizing the phenomenon of global warming through decreasing emissions of greenhouse gases [1]. Carbon dioxide emitted by fossil fuel combustion makes up sixty-five percent of the total amount of greenhouse gases[2]. The increased amount of greenhouse gases (GHGs) in the nearest (troposphere) atmosphere increases the earth's global temperature by trapping heat from the sun. The aforementioned phenomenon is a significant factor contributing to climate change. The contribution of consuming fossil fuels to climate change is obvious, as they emit greenhouse gases, mainly CO₂, into the atmosphere, once burnt. Global net-zero greenhouse gas (GHG) emissions must be achieved in order to meet the Paris Agreement's climate target of keeping global average temperature to well below 2°C and reducing temperature increases to 1.5°C [3].

Despite understanding that the consumption of fossil fuels contributes to climate change and has a number of negative environmental consequences, the vast majority of countries' energy systems, both developed and developing, rely on fossil fuels [4]. Furthermore, fossil fuels are currently the primary sources of energy used in the transportation, industrial, and electrical energy generation sectors, as well as practically all other sectors where energy need to be supplied [5]. To decrease or eliminate the emissions of carbon dioxide (CO2) caused by the consumption of fossil fuels, which could contribute to meeting the Paris Agreement's objective of decreasing greenhouse gas emissions in the atmosphere, low-carbon technologies such as renewable energy sources (RES) and carbon capture, utilization, and storage (CCUS) must be implemented on a wide scale [6]. As a result, numerous European Union (EU) countries, including Norway, Germany, and Denmark, are considering renewable energy options. After a study to determine whether a 100% renewable European power system is achievable by 2050. It was found that a 100% renewable power system will still require a large flexible zero-carbon storage capacity to balance variable renewable energy generation [7]. To tackle this, the world has begun to emphasize carbon capture and utilization technologies together with renewable energy. CCU technologies enable the integration of renewable energies in an energy system through storage and a continuous utilization of fossil fuels as there is no emission.

Carbon capture and utilization is the best technology to halt emissions of CO₂ coming from burning fossil fuels or any carbon-based energy source. It consists of separating CO₂ from industries and energy-related sources and transporting it to a storage location for other applications or long-term isolation from the atmosphere [8]. CCU has the technical potential to serve as a carbon source for chemicals production decoupling the production of chemicals such as methanol and ethanol from fossil fuels, reducing GHG annual emissions by up to 3.5 Gt CO2-eq in 2030 [9]. In addition, it was found that an energy system consisting of fossil fuels, hydrogen, bio-fuels and renewable energy sources could be a good initiative for energy transition and combating climate change [10]. In this present work, an economic feasibility study will be conducted for the implementation of carbon capture and methanation (with green hydrogen) project in a power plant located in Goroubanda, Niamey-Niger, together with a carbon capture simulation via Adsorption process.

2. Materials and Methods

In this work, a feasibility study of decarbonizing a specific power-producing plant located in Goroubanda, Niamey-Niger was conducted through an economic analysis, and a simulation of a carbon capture system. One of the absorption processes was used to absorb CO₂ from exhaust gas generated by combustion in the power plant. The post-combustion CO₂ capture technology was chosen based on the fuel utilized by the plant and the operating conditions of the plant (combustion process for power generation).

2.1. Materials

The main focus of this work was on process simulation and analysis. A combination of software tools and a spreadsheet (Excel) were used as materials to conduct the research. The materials employed are as follows:

○

Excel for the economic analysis of the project and some calculations.

○

Aspen Adsorption software for simulating CO₂ capture system via adsorption phenomena.

○

QGIS software for mapping the study area.

2.2. Methods

2.2.1. Economic Analysis

Economic assessment is a special aspect to analysing the possibility of any technology to be practically applicable. Costs for both operations and investments of the overall project were assessed. According to the ratio factors suggested by Peter and Timmerhaus [11] for fluid processing plants, the total capital investment (CAPEX) was calculated using the methodology bellow, together with the capital investment (x) of the equipment .

$$CAPEX=TDC+TIC$$

(1)

where TDC is the total direct cost and TIC the total indirect cost of goods, summarized in Table 1 and RF is the ratio factor for direct, indirect, and working capital.

Table 1. Capital Expenditure Calculation Formula.

Type	Item(i)	Ratio Factor	Cost(euro)
Direct cost	Purchased equipment(delivered)	1.00	X
	Purchased equipment installation	0.47	X*0.47
	piping	0.36	X*0.36
	Instrumentations and controls	0.68	X*0.68
	Electrical systems	0.11	X*0.11
	Buildings (including services)	0.18	X*0.18
	Yard improvements	0.10	X*0.10
	Service facilities	0.70	X*0.70
Total direct cost			Y=X*3.6
Indirect cost	Engineering and supervision	0.33	Y*0.33
	Construction expenses	0.41	Y*0.41
	Legal expenses	0.04	Y*0.04
	Contractor’s fee	0.22	Y*0.22
	contingency	0.44	Y*0.44
	Working capital	0.89	Y*0.89
Total indirect cost			Z=Y*2.33
Total capital investment (CAPEX)			=Y+Z

Table 1. Capital Expenditure Calculation Formula.

Type	Item(i)	Ratio Factor	Cost(euro)
Direct cost	Purchased equipment(delivered)	1.00	X
	Purchased equipment installation	0.47	X*0.47
	piping	0.36	X*0.36
	Instrumentations and controls	0.68	X*0.68
	Electrical systems	0.11	X*0.11
	Buildings (including services)	0.18	X*0.18
	Yard improvements	0.10	X*0.10
	Service facilities	0.70	X*0.70
Total direct cost			Y=X*3.6
Indirect cost	Engineering and supervision	0.33	Y*0.33
	Construction expenses	0.41	Y*0.41
	Legal expenses	0.04	Y*0.04
	Contractor’s fee	0.22	Y*0.22
	contingency	0.44	Y*0.44
	Working capital	0.89	Y*0.89
Total indirect cost			Z=Y*2.33
Total capital investment (CAPEX)			=Y+Z

Table 2. Operational Expenditure (OPEX)Calculation Formula.

type	Item(j)	Cost
Fix OPEX	Operating labour	5 labours/shift, 3 shift/day
	Supervisory & clerical labour	20% Operating labour
	Maintenance & repairs	3% CAPEX
	Operating supplies	15% M&R
	Catalyst	90€/kg
	Solvent	1€/kg
Variable OPEX	hydrogen	2.34$/kg~2.17€/kg
	Cooling Water	0.025€/ton
	Energy consumption	9.3€/kWh
Total OPEX		= FOPEX + VOPEX

Table 2. Operational Expenditure (OPEX)Calculation Formula.

type	Item(j)	Cost
Fix OPEX	Operating labour	5 labours/shift, 3 shift/day
	Supervisory & clerical labour	20% Operating labour
	Maintenance & repairs	3% CAPEX
	Operating supplies	15% M&R
	Catalyst	90€/kg
	Solvent	1€/kg
Variable OPEX	hydrogen	2.34$/kg~2.17€/kg
	Cooling Water	0.025€/ton
	Energy consumption	9.3€/kWh
Total OPEX		= FOPEX + VOPEX

2.2.2. Aspen Adsorption Simulation

The simulation of CO₂ capture with Aspen Adsorption software was made in three steps with silicate based adsorbent material on a single bed.

○

Creation of the simulation model

After launching Aspen Adsorption, a new simulation model was created. The components used to build up the model are gas feed and product, valves, adsorption bed and cycle organizer.

○

Specification on some parameters

Specifications on feed gas, feed valve, adsorption column, and product valve and gas product were carried out. The specifications were mainly on temperature, pressure, feed property and composition, feed flowrate, bed height and diameter, time taken for each step of the three etc.

○

Running simulation

After the specifications, the simulation was executed by running the established model. The software has calculated and simulated the behaviour of the adsorption process based on the specifications made. The system was controlled by the cycle organizer.

3. Case Study

The Goroubanda diesel-based power plant, located 5km south of Niamey with four 20 MW diesel turbines was built by Sinohydro, which started construction in April 2013. The construction of lines and substations was carried out by the Chinese company TBEA. This plant was built with the aim of improving the power supply of Niamey and reducing dependence on the interconnection with Nigeria.

In addition, with four MAN 18V48/60TS engines already in operation on-site, the installation of another of the same kind has increased the power plant's total capacity by 20 MW, bringing it to more than 100 MW. "After this expansion, the Goroubanda power plant will provide more than 45% of Niger's power generation capacity ’’Saab stated’’[12]. Despite that, Niger remains one of Africa's countries with the lowest electrification rate.

The work presented here aims to create an additional energy generation capacity of the Goroubanda power plant to promote the economic and social development of Niger. As impact, this project may be involved in making the power plant ‘’green’’, reducing CO₂ emissions and help to integrate renewable energy into the Niger’s energy system.

Figure 2. Study area map.

Figure 2. Study area map.

3.1. Economic Analysis

In the economic evaluation of the present project, the following has been determined:

❖

Total CAPEX and OPEX of the project

❖

Levelized cost of the product (LC) and net present value (NPV)

❖

Return on investment, payback period and sensitivity analysis

The methodology used to calculate the CAPEX and OPEX which were used to calculate the remaining parameters was shown in 2.2.1. The cost of the main equipment for CO₂ capturing, methanation and gas upgrading was estimated to be around 28.14M€ and taken reference from a similar project [11]. The annualized CAPEX is calculated by multiplying the CAPEX with the capital recovery factor (CRF) which was calculated the using equation below.

$$CRF={\displaystyle \frac{i{\left(i+1\right)}^n}{{\left(i+1\right)}^n-1}}$$

(2)

Where, n=number of years and i = interest rate.

Table 3. Main equipment of the process.

Main equipment	CO2 capture	CO2 methanation	Gas upgrading
Columns(absorber/stripper)	✓	-	-
Reactor	-	✓	-
Compressors	✓	✓	✓
Turbine	-	✓	-
Heat exchangers (Heaters/coolers)	✓	✓	✓
Flash tanks	✓	✓	-
Membrane	-	-	✓

Table 3. Main equipment of the process.

Main equipment	CO2 capture	CO2 methanation	Gas upgrading
Columns(absorber/stripper)	✓	-	-
Reactor	-	✓	-
Compressors	✓	✓	✓
Turbine	-	✓	-
Heat exchangers (Heaters/coolers)	✓	✓	✓
Flash tanks	✓	✓	-
Membrane	-	-	✓

For estimating the amount of CO₂ that the plant can generate, it is important to know the fuel consumption rate in litters per hour or the specific fuel consumption rate in litres per kilowatt-hour (l/kWh). It was assumed in this work that the fuel consumption rate is at 0.28 l/kWh (The assumption was based on diesel generators used in the power plant). Also, it has to be mentioned that diesel fuel contains approximately 2640 grams of carbon per litre. The combustion process of diesel fuel releases about 2.66 kg of CO₂ for every kilogram of carbon burned.

Hourly fuel consumption calculation:

$$\mathrm{FC}={\displaystyle \frac{power ouput}{specific consumption rate}}$$

(3)

$$={\displaystyle \frac{100}{0.28}}$$

$$\mathit{F}\mathit{C}\mathbf{=}\mathbf{357.14}\mathit{L}\mathbf{/}\mathit{h}$$

Carbon content in the fuel calculation:

$$\mathrm{CC}={\displaystyle \frac{FC\ast CCD}{1000}}$$

(4)

$$={\displaystyle \frac{357.14\ast 2640}{1000}}$$

$$\mathit{C}\mathit{C}\mathbf{=}\mathbf{943.99}\mathit{k}\mathit{g}\mathbf{/}\mathit{h}$$

CO₂ emissions calculation:

$$\mathrm{CO}2\mathrm{e}=Carbon content\ast CO2 emission factor$$

(5)

$$=943.99\ast 2.66$$

$$\mathit{C}\mathit{O}\mathbf{2}\mathit{e}\mathbf{=}\mathbf{2511.26}\mathit{k}\mathit{g}\mathbf{/}\mathit{h}$$

Therefore, this power plant running on diesel fuel with a capacity of 100MW can generate 2511.26kg/h or 2.51 metric tons/hour of CO₂.

3.1.1. CAPEX and OPEX Estimation

The Capital Expenditure and Operational Expenditure Estimation using the formulas given in 2.2.1.

Table 4. CAPEX Calculation.

Items	DC (€)	IC (€)	CAPEX (€)
Total equipment cost	28,140,000	-	28,140,000
Purchased equipment Installation	13,225,800	-	13,225,800
piping	10,130,400	-	10,130,400
Instrumentations and controls	19,135,200	-	19,135,200
Electrical systems	3,095,400	-	3,095,400
Buildings (including services)	5,065,200	-	5,065,200
Yard improvements	2,814,000	-	2,814,000
Service facilities	19,698,000	-	19,698,000
Engineering and supervision	-	33,430,320	33,430,320
Construction expenses	-	41,534,640	41,534,640
Legal expenses	-	4,052,160	4,052,160
Contractor’s fee	-	22,286,880	22,286,880
contingency	-	44,573,760	44,573,760
Working capital	-	90,160,560	90,160,560
Total Cost	101,304,000	236,038,320	337,342,320

Table 4. CAPEX Calculation.

Items	DC (€)	IC (€)	CAPEX (€)
Total equipment cost	28,140,000	-	28,140,000
Purchased equipment Installation	13,225,800	-	13,225,800
piping	10,130,400	-	10,130,400
Instrumentations and controls	19,135,200	-	19,135,200
Electrical systems	3,095,400	-	3,095,400
Buildings (including services)	5,065,200	-	5,065,200
Yard improvements	2,814,000	-	2,814,000
Service facilities	19,698,000	-	19,698,000
Engineering and supervision	-	33,430,320	33,430,320
Construction expenses	-	41,534,640	41,534,640
Legal expenses	-	4,052,160	4,052,160
Contractor’s fee	-	22,286,880	22,286,880
contingency	-	44,573,760	44,573,760
Working capital	-	90,160,560	90,160,560
Total Cost	101,304,000	236,038,320	337,342,320

Based on the capital expenditure records, the calculation of the annualized CAPEX was then proceeded using a discounted cash flow analysis. This analysis incorporates the time value of money by discounting future cash flows to their present value based on an appropriate interest rate. The aim of performing this calculation was to obtain a more accurate representation of the annualized CAPEX, factoring in the opportunity cost of investing in this project. This provided valuable insights for financial planning and decision making. The lifetime of the main equipment was assumed to be 25 years and the interest rate was 8% [13]. Using equation 2, the calculation of CRF was done as follows:

$$={\displaystyle \frac{0.08{\left(1+0.08\right)}^{25}}{{\left(1+0.08\right)}^{25}-1}}$$

$$\mathit{C}\mathit{R}\mathit{F}\mathbf{=}\mathbf{0.093}$$

$$ACAPEX=337342320\ast 0.093$$

$$\mathit{A}\mathit{C}\mathit{A}\mathit{P}\mathit{E}\mathit{X}\mathbf{=}\mathbf{31372835.76} \mathit{€}$$

To calculate the total operating cost, the yearly amount of CO₂ to be collected from the plant needs to be known. For that, two assumptions were supposed to be made. First, it was assumed that the plant works 8 hours per day (this is the standard time of a production shift in Niger) and second, it works 365 days per year. From that, one can conclude that the plant works 2920 hours per year. As mentioned earlier 3.1, this plant can generate 2.51 tons/hour. Considering the assumptions, the plant generates about 7329.2 tons of CO₂ per year.

After knowing the amount of CO₂ to be generated yearly, the amount of hydrogen needed per year needs to be calculated. From the balanced equation of CO₂ methanation with hydrogen, it can be seen that four (4) moles of hydrogen are required to react with one mole of CO₂ to produce one mole of methane.

To calculate the amount of hydrogen needed, one needs to convert the mass of CO₂ to moles using the molar mass of CO₂ (44.01g/mol) and then use the stoichiometric ratio.

Given:

Mass of CO₂=7329.2 tons=7329.2 *1000kg=7329200kg

Molar mass of CO₂=44.01g/mol

Molar mass of H₂=2.02g/mol

Step 1: Conversion of mass of CO₂ to moles

$$n\left(CO2\right)={\displaystyle \frac{m\left(CO2\right)}{M\left(CO2\right)}}$$

(6)

$$={\displaystyle \frac{7329200}{0.044}}$$

$$\mathit{n}\left(\mathit{C}\mathit{O}\mathbf{2}\right)\mathbf{=}\mathbf{166572727.3} \mathit{m}\mathit{o}\mathit{l}\mathit{e}\mathit{s}$$

Step 2: Calculation of moles of hydrogen

$${\displaystyle \frac{n\left(GreenH2\right)}{4}}={\displaystyle \frac{n\left(CO2\right)}{1}}$$

(7)

$$=4\ast \mathrm{n}\left(\mathrm{CO}2\right)$$

$$\mathbf{n}\left(GreenH\mathbf{2}\right)=\mathbf{666290909.1} moles$$

Step 3: Conversation of moles of hydrogen to tons

$$m\left(GreenH2\right)/year=n\left(H2\right)\ast M\left(H2\right)\ast 10^\left(-6\right)$$

(8)

$$=666290909.1\ast 2.02\ast {10}^{-6}$$

$$\mathit{m}\left(\mathit{G}\mathit{r}\mathit{e}\mathit{e}\mathit{n}\mathit{H}\mathbf{2}\right)/\mathit{y}\mathit{e}\mathit{a}\mathit{r}\mathbf{=}\mathbf{1,345.90} \mathit{t}\mathit{o}\mathit{n}\mathit{s}$$

The yearly cost of green hydrogen needed was calculated as follows:

$$Cost\left(GreenH2\right)/year=m\left(GreenH2\right)/year\ast Cost\left(GreenH2\right)$$

(9)

$$=1345.90\ast 2170$$

$$\mathit{C}\mathit{o}\mathit{s}\mathit{t}\left(\mathit{G}\mathit{r}\mathit{e}\mathit{e}\mathit{n}\mathit{H}\mathbf{2}\right)\mathbf{/}\mathit{y}\mathit{e}\mathit{a}\mathit{r}\mathbf{=}\mathbf{2,920,630} \mathit{€}$$

For calculating the cost of catalyst, the daily captured CO₂ needs to be known. As mentioned, the plant generates 2.51 tons/hour which means it generates 20.08tons/day as it works eight (8) hours per day.

Knowing the loading of the catalyst (5%) together with daily mass of CO₂ captured, the mass of the catalyst needed daily can be estimated.

$$m\left(Catalyst\right)=m\left(CO2\right)/day\ast L$$

(10)

$$=20.08\ast 0.05$$

$$\mathit{m}\left(\mathit{C}\mathit{a}\mathit{t}\mathit{a}\mathit{l}\mathit{y}\mathit{s}\mathit{t}\right)\mathbf{=}\mathbf{1} \mathit{t}\mathit{o}\mathit{n}$$

According to Table 2, the price of the catalyst is 90€/kg, which means 90000€/ton. In this work, the catalyst has been assumed to be changed once per year. The cost of the total catalyst needed was multiplied by two (2) to have the yearly cost of the catalyst.

$$Cost\left(catalyst\right)/year=m\left(catalyst\right)/ton\ast Cost\left(catalyst\right)\ast 2$$

(11)

$$=1\ast 90000\ast 2$$

$$\mathit{C}\mathit{o}\mathit{s}\mathit{t}\left(\mathit{c}\mathit{a}\mathit{t}\mathit{a}\mathit{l}\mathit{y}\mathit{s}\mathit{t}\right)\mathbf{/}\mathit{y}\mathit{e}\mathit{a}\mathit{r}\mathbf{=}\mathbf{180,000}\mathit{€}$$

The daily amount of solvent required is calculated using the following formula.

$$m\left(solvent\right)={\displaystyle \frac{daily mass of CO2}{Concentration or mole fraction of CO2 }}$$

(12)

$$={\displaystyle \frac{20.08}{0.12}}$$

$$\mathit{m}\left(\mathit{s}\mathit{o}\mathit{l}\mathit{v}\mathit{e}\mathit{n}\mathit{t}\right)\mathbf{=}\mathbf{167.33} \mathit{t}\mathit{o}\mathit{n}\mathit{s}\mathbf{/}\mathit{d}\mathit{a}\mathit{y}$$

Solvent also was considered to be changed once per year.

$$\mathrm{Cos}\mathrm{t}\left(\mathrm{solvent}\right)/\mathrm{year}=\mathrm{m}\left(\mathrm{solvent}\right)\ast \mathrm{Cos}\mathrm{t}\left(\mathrm{solvent}\right)/\mathrm{ton}\ast 2$$

(13)

$$=167.33\ast 1000\ast 2$$

$$\mathit{C}\mathit{o}\mathit{s}\mathit{t}\left(\mathit{s}\mathit{o}\mathit{l}\mathit{v}\mathit{e}\mathit{n}\mathit{t}\right)\mathbf{/}\mathit{y}\mathit{e}\mathit{a}\mathit{r}\mathbf{=}\mathbf{334,660}\mathbf{€}$$

According to [14], 2.4 kg of water is required for the process of capturing one ton of CO₂. In this work, only the cost of water required for CO₂ capture is considered. The produced water was continuously used for the remaining needs.

$$\mathrm{m}\left(\mathrm{Water}\right)=\mathrm{m}\left(\mathrm{CO}2\right)/\mathrm{day}\ast 2.4$$

(14)

$$=20.08\ast 2.4$$

$$\mathit{m}\left(\mathit{W}\mathit{a}\mathit{t}\mathit{e}\mathit{r}\right)\mathbf{=}\mathbf{48.19} \mathit{k}\mathit{g}$$

$$Cost\left(water\right)={\displaystyle \frac{m\left(Water\right)\ast Cost\left(Water\right)/ton}{1000}}$$

(15)

$$={\displaystyle \frac{48.19\ast 0.025}{1000}}$$

$$Cost\left(Water\right)={\mathbf{1.2010}}^{\mathbf{-}\mathbf{3}}\mathit{€}$$

It was observed by [11], that a total amount of energy of around 0.05MW is required for the methanation of 9.09 tons of CO₂ per hour. Taking that as a reference, the hourly amount of energy needed in this thesis was evaluated as follows:

$$E\left(energy required\right)={\displaystyle \frac{0.05\ast m\left(CO2\right)/hour}{9.09}}$$

(16)

$$E\left(energy required\right)={\displaystyle \frac{0.05\ast 2.51}{9.09}}$$

$$\mathit{E}\left(\mathit{e}\mathit{n}\mathit{e}\mathit{r}\mathit{g}\mathit{y} \mathit{r}\mathit{e}\mathit{q}\mathit{u}\mathit{i}\mathit{r}\mathit{e}\mathit{d}\right)\mathbf{0.014}\mathit{M}\mathit{W}\mathbf{/}\mathit{h}$$

$$Cost\left(ER\right)/year=Energy required\ast Cost\left(energy\right)\ast 8h\ast 365days$$

(17)

$$Cost\left(energy required\right)=0.014\ast 9300\ast 8\ast 365$$

$$\mathit{C}\mathit{o}\mathit{s}\mathit{t}\left(\mathit{e}\mathit{n}\mathit{e}\mathit{r}\mathit{g}\mathit{y} \mathit{r}\mathit{e}\mathit{q}\mathit{u}\mathit{i}\mathit{r}\mathit{e}\mathit{d}\right)\mathbf{/}\mathit{y}\mathit{e}\mathit{a}\mathit{r}\mathbf{=}\mathbf{380184} \mathit{€}$$

Table 5. OPEX Calculation.

FOPEX	Cost (€)
Operating labour	22,824
Supervisory & clerical labour	4,564.8
Maintenance & repairs	941,185.07
Operating supplies	141,177.76
Catalyst	180,000
Solvent	334,660
VOPEX
Hydrogen	2,920,603
Cooling water	0.00120
Energy consumption	380,184
TOPEX	4925,198.63

Table 5. OPEX Calculation.

FOPEX	Cost (€)
Operating labour	22,824
Supervisory & clerical labour	4,564.8
Maintenance & repairs	941,185.07
Operating supplies	141,177.76
Catalyst	180,000
Solvent	334,660
VOPEX
Hydrogen	2,920,603
Cooling water	0.00120
Energy consumption	380,184
TOPEX	4925,198.63

3.1.2. Levelized Cost of the Produced SNG

The cost of the methane gas produced per ton and megawatt-hour has been evaluated considering the operating and fixed expenses using the following formulas:

$$\mathrm{Levelized}\cos \mathrm{t}\mathrm{of}\mathrm{CH}4\left(\mathrm{LC}\right)={\displaystyle \frac{ACAPEX+annual\left(OPEX\right)}{mass\left(methane produced\right)/year}}$$

(18)

$$={\displaystyle \frac{31372835.76+4925198.63}{7329.2}}$$

$$\mathit{L}\mathit{C}\left(\mathit{C}\mathit{H}\mathbf{4}\right)\mathbf{=}\mathbf{4,952.52} \mathit{€}\mathbf{/}\mathit{t}\mathit{o}\mathit{n}$$

To convert tons into megawatt-hours, following conversions have to be done:

1 ton is equal to 1000kg, 1kg of methane is equal to 5.55 MJ and 1 MWh is equal to 3.6 MJ. Therefore, the levelized cost of methane per MWh is calculated as follows:

$$LC\left(CH4\right)/MWh=\left(LC\left(CH4\right)/ton\ast 3.6\right)/\left(1000\ast 55.5\right)$$

(19)

$$=\left(4952,52\ast 3.6\right)/55500$$

$$\mathit{L}\mathit{C}\left(\mathit{C}\mathit{H}\mathbf{4}\right)\mathbf{=}\mathbf{0.32}\mathit{€}\mathbf{/}\mathit{M}\mathit{W}\mathit{h}$$

3.1.3. Calculation of Net Present Value, Return on Investment and Payback Period

A comprehensive financial analysis of the project has been performed, including the calculation of key financial metrics such as net present value, return on investment, and payback period. By evaluating these metrics, it was gained into the project’s profitability, investment efficiency, and time required to recoup the initial investment. This analysis provided a robust financial assessment, helping in making decisions and determining the project’s financial viability. Below are given the different formulas for the calculations and a table summarizing the results obtained using Excel.

$$\mathit{N}\mathit{e}\mathit{t} \mathit{P}\mathit{r}\mathit{e}\mathit{s}\mathit{e}\mathit{n}\mathit{t} \mathit{V}\mathit{a}\mathit{l}\mathit{u}\mathit{e}={\displaystyle \sum }_{n=1}^{25}{\displaystyle \frac{Cash flows}{{\left(\mathrm{i}+1\right)}^n}}-initial investment$$

(20)

$$\mathit{R}\mathit{e}\mathit{t}\mathit{u}\mathit{r}\mathit{n} \mathit{o}\mathit{n} \mathit{i}\mathit{n}\mathit{v}\mathit{e}\mathit{s}\mathit{t}\mathit{m}\mathit{e}\mathit{n}\mathit{t}={\displaystyle \frac{net present value }{initial investment }}\ast 100$$

(21)

$$\mathit{P}\mathit{a}\mathit{y}\mathit{b}\mathit{a}\mathit{c}\mathit{k} \mathit{P}\mathit{e}\mathit{r}\mathit{i}\mathit{o}\mathit{d}={\displaystyle \frac{initial investment }{ annual cash flow}}$$

(22)

Table 6. Results Summary of NPV, ROI, PP.

Net Present Value (€)	Return on investment (%)	Payback Period
45205609.76	13	9.4

Table 6. Results Summary of NPV, ROI, PP.

Net Present Value (€)	Return on investment (%)	Payback Period
45205609.76	13	9.4

3.2. Aspen Adsorption Simulation

Due to its lower energy consumption and less reliance on chemical processes, the adsorption process is currently considered more cost-effective and less pollutant than the absorption approach for carbon capture.

These factors highlight the reasons why in this work it was found important to integrate the Adsorption simulation using aspen adsorption, in the project. The simulation was done with the purpose of replacing the considered carbon capture unit in case it requires more energy input and presents very high pollution.

The simulation was done in a three-step cycle monitored by a cycle organizer on a single bed (This is an ideal way to simulate the adsorption process in Aspen Adsorption software). The first step was adsorption followed by heating for desorption and then cooling, for the bed to restart the adsorption. The process was an adiabatic adsorption of CO₂ on a single bed of Silicate based adsorbent.

Table 7. Feed properties.

Property	Value
Flowrate(kmol/s)	8e-7
Pressure(bar)	10
Temperature(K)	298
Composition (molar fraction)
N2	67%
CO2	12%

Table 7. Feed properties.

Property	Value
Flowrate(kmol/s)	8e-7
Pressure(bar)	10
Temperature(K)	298
Composition (molar fraction)
N2	67%
CO2	12%

Table 8. Summary of the three-step cycle configuration.

	ADSORPTION	HEATING	COOLING
B4	Completely opened	closed	Opened
B5	Opened with a constant flow rate	Opened	Closed
DURATION(MN)	60	80	60

Table 8. Summary of the three-step cycle configuration.

	ADSORPTION	HEATING	COOLING
B4	Completely opened	closed	Opened
B5	Opened with a constant flow rate	Opened	Closed
DURATION(MN)	60	80	60

Figure 3. Process flowsheet of the three-step cycle simulation on a single bed.

Figure 3. Process flowsheet of the three-step cycle simulation on a single bed.

4. Results and Discussion

4.1. Economic Analysis

In the total initial investment of the project, it could be observed that the capital expenditure (CAPEX) is very high compared to operational expenditure (OPEX). This is because the cost of transportation of the main equipment from Germany (as they were considered to be bought there) to Niger is integrated in the ration factor of each unit. The OPEX is also very high comparing to that one (1.71 M€/year) found by [15], just because of cost of green hydrogen 2.9 M€/year is considered in the operating cost. Apart from green hydrogen, all the remaining required inputs were found cheap. In addition, the annualized capital expenditure (ACAPEX) may be seen as very high, which is because of the considered interest rate of 8%. In this work, after the first investment, the OPEX is included in the discounted cash inflow. This means that the cash inflow is discounted in such a way that the operating cost is being taken from it.

The levelized cost of the produced SNG, was very cheap compared to the one found by [16] (about 3.6 M€/ton) after making an economic analysis of the power to gas route in Germany. This fact is also understandable because the cost of SNG in Germany cannot be the same in Africa (Niger). A positive net present value found in this study means that the discounted cash inflow for 25 years (lifetime of the project) is much greater than the initial investment of the project. The ROI of 13% represents the return on investment expressed as a percentage of the initial investment. A greater ROI signifies a better return on investment in comparison to the initial investment. The present ROI indicates that the project is likely to generate 13% of the initial investment each year. The obtained result on the payback period indicates that it may take 9.4 years to generate cash inflow that recoup the initial investment.

Table 9. Total Result of Economic Analysis.

Variable(s)	Value(s)
CAPEX	337342320€
ACAPEX	31372835.76€
OPEX	4925198.63€
LC(CH4)	4952.52€/ton
NPV	45205609.76€
ROI	13%
PP	9.4 years

Table 9. Total Result of Economic Analysis.

Variable(s)	Value(s)
CAPEX	337342320€
ACAPEX	31372835.76€
OPEX	4925198.63€
LC(CH4)	4952.52€/ton
NPV	45205609.76€
ROI	13%
PP	9.4 years

4.2. Carbon Capture Simulation

After settling all the parameters in the adsorption software, different specifications were made for the different steps in the cycle organizer in order to control the cycle. The simulation was run after putting all the inputs and making all the specifications to make a maximum of three cycles. Later on, two analyses were made together with a sensitivity analysis. Analysis of the adsorption bed performances and analysis of the composition of outlet stream.

Analysing the breakthrough curve, it is possible to conclude that, the adsorption bed is capable of performing a continuous adsorption procedure for CO₂ capture. This means that as the CO₂-containing gas stream passes over the bed material, the CO₂ molecules are preferentially captured and retained. The bed can continuously adsorb CO₂ over an extended period of time without requiring frequent regeneration or replacement of the adsorbent material. This continuous adsorption process enables the efficient and continuous removal of CO₂ from the gas stream, making the adsorption bed a viable solution for carbon capture and storage applications or other CO₂ removal operations.

Figure 4. Breakthrough curve.

Figure 4. Breakthrough curve.

In Figure 5, is shown the outlet stream composition of the first step (adsorption) of the cycle. Due to the effective adsorption process occurring within the bed, the mole fraction of CO₂ in the outlet stream gas is unusually low. The adsorption bed material selectively absorbs and holds CO₂ molecules as the gas stream passes through it, effectively eliminating them from the gas phase. Because of this excellent adsorption mechanism, only a tiny quantity of CO₂ molecules remains in the outflow stream. The bed maximizes separation efficiency through the continuous adsorption process by selectively adsorbing CO₂ while allowing other gases to pass through relatively unimpeded. This selectivity reduces the concentration of CO₂ in the outflow stream significantly, resulting in a very small mole fraction.

Unlike the relatively small mole fraction of CO₂ in the outflow stream, the mole fraction of the remaining gas components increases continuously. This phenomenon results from selective CO₂ adsorption within the bed, resulting in a relative enrichment of non-CO₂ gases in the exit stream. As the CO₂ molecules are selectively captured and retained by the adsorption bed, the gas stream that exits the bed contains a higher proportion of non-CO₂ components. While the CO₂ is successfully removed by the bed, the remaining gases flow through relatively un-adsorbed. This causes a progressive accumulation of non-CO₂ gases, resulting in a rising mole fraction in the exit stream.

A sensitivity analysis was also made to see the effect of varying some parameters such as flue gas temperature, adsorption bed height and the flue gas flow rate. The initial temperature, flow rate of flue gas and bed height were respectively as follows: 298K, 8e-7kmol/s and 0.6m.

Figure 6 shows the CO₂ adsorption from the flue gas at three different temperatures. It may be observed that, increasing flue gas temperature results in an increase in CO₂ adsorption at a short time as the molar fraction of CO₂ decreases in the flue gas. Adsorption of CO₂ contained in a flue gas at high temperatures has the advantage of reducing time to reach the maximum of adsorption. With a temperature of 450K and 350K, the maximum adsorption is reached at about 9500 seconds while with a temperature of 298K, the maximum adsorption is reached at around 12400 seconds. Higher temperatures increase the kinetic energy of molecules, which can speed up adsorption. When a rapid adsorption process is needed, this can be advantageous. It is crucial to remember, however, that extremely high temperatures might cause desorption or thermal breakdown of the adsorbate, which can reduce overall adsorption effectiveness.

The flow rate of flue gas is also another parameter to consider. Figure 7 demonstrates the adsorption of CO₂ at three different flue gas flow rates. In the considered figure, the two graphs corresponding to the adsorption of CO₂ from the flue gas at 4e-7kmol/s and 1e-6kmol/s are decreasing. This means that, there is more CO₂ adsorption at a flow rate of 4e-7 kmol/s and 1e-6 kmol/s compared to the remaining considered flow rate. In conclusion, at a temperature of 298K and an adsorption bed height of 0.6m (remember in this case, temperature and bed height were kept constant), the flow rates of 4e-7kmol/s and 1e-6kmol/s are more suitable for an effective rapid CO₂ in adsorption.

Figure 8 represents the CO₂ adsorption phenomenon at three different heights of the adsorption bed. It can be understood from the figure that, the height of the adsorption bed does not impact in general, the adsorption process for a short time process. However, when the flue gas takes more time in the adsorption column, it may be seen on the figure that, at a bed height of 0.9 meter and 1.2 meter, a sudden high rate of CO₂ adsorption takes place from time to time.

[17] has found that decreasing the flow rate of input increases the time taken to achieve the maximum adsorption, increasing temperature decreases the time taken to reach the maximum value of adsorption and increasing the bed height increases also the time taken to achieve the maximum adsorption. As well, in this work, it was found that, increasing temperature reduces the time taken for maximum adsorption. However, an increase in flow rate does not have any relation with adsorption time, and the bed height variation also does not have effect on adsorption time. The similarity observed here is due to the fact that the temperature is more related to the reaction not generally to the input, adsorbent and adsorption column characteristics. It is common that, increasing temperature augments the reaction rate. The differences noticed may be due to the difference in adsorbate and adsorbent used in both cases.

5. Conclusion

This study aimed to investigate the economic feasibility for implementing a carbon capture and methanation project. The results indicate that, the project is economically feasible with a return on investment of 13%, a payback period of 9.4 years and a synthetic natural gas cost of 0.32 €/MWh.

In addition, the study had also the goal of conducting a carbon capture simulation with Aspen Adsorption software for reducing the environmental impacts coming out of the project’s system, and for reducing as well the cost of initial investment, and the cost of some of the inputs. The adsorption process simulation findings show that, it is successful at producing continuous CO₂ adsorption while keeping a very low mole fraction of CO₂ in the outflow stream. Because of the bed's selective adsorption characteristics, CO₂ molecules can be efficiently removed from the gas phase, resulting in a highly pure exit stream. The flue gas temperature has the effect of reducing the adsorption time taken to reach the maximum value when it is increased.