Economic and Technical Analysis of Power to Gas Factory Taking Karamay as an Example

Abstract

Power to gas (PTG) refers to the technology of converting power into energy-storage gas, which can absorb excess power when there is excess power and release energy-storage gas when needed. Based on the carbon dioxide (CO₂) emission of Karamay City in Northwest China, this study designed a process flow of the CO₂ absorption process, and the hydrogen and CO₂ methanation process, in PTG technology. The results show that the efficiency of the CO₂ absorption process was 91.5%, and the methanation efficiency was 77.5%. The heat recovery module was set during the process, and the total heat recovered was 17.85 MW. The cost of producing synthetic natural gas (SNG) in the PTG factory was 1782 USD/ton. In terms of cost, the cost of hydrogen production from electrolyzed water accounted for the largest proportion. In terms of product profit, the sale of pure oxygen was the largest part of the profit. At present, the carbon emission reduction index profit brought by SNG production accounted for a small proportion. In the future, with technological progress, industrial upgrading and the improvement in the carbon trading market, PTG technology is expected to become one of the ways to achieve carbon-emission-reduction targets.

1. Introduction

With the further intensification of global warming, the climate has become an increasingly serious issue. With the rapid growth in the global population and economy, more and more greenhouse gases are emitted into the atmosphere [1]. Among them, CO₂ emissions account for more than 60% of the total greenhouse gas emissions, which are the main cause of global warming and climate change [2]. Therefore, countries have introduced policies to reduce CO₂ emissions. The European Union is committed to reducing greenhouse gas emissions by 80–95% by 2050, compared with 1990 [3]. The Biden government of the United States promises to achieve 100% carbon-free emission in the power industry by 2035 [4]. India is committed to reducing its CO₂ emissions by 33–35% by 2030, compared with 2005 [5]. China is the world’s largest industrial country. Due to the rapid development of its industry in the past two decades, China has emitted nearly 30% of the CO₂ in the world in 2020 alone [6]. Therefore, in the face of this situation, China has also set ambitious emission-reduction targets: By 2030, CO₂ emissions will reach a peak, at 50–60% lower than that in 2005. In addition, carbon neutrality will be achieved by 2060 [7].

Carbon capture utilization and storage (CCUS) technology is expected to achieve climate commitments and solve climate problems. At present, CCUS technology has two main research directions. One is to physically store the captured CO₂ and store it in oil fields or coalfields, so as to improve oil and gas recovery and reduce CO₂ stock [8]. The second is to chemically convert the captured CO₂ into methane and other fuels. In this direction, electricity generated from renewable energy is used to electrolyze water to produce hydrogen, which is converted into methane together with captured CO₂. This technology is called PTG. At present, relevant PTG projects have been established in many parts of the world to carry out miniaturization experiments and commercialization attempts [9]. The first PTG project in the world is Ameland in the Netherlands. The project uses a proton exchange membrane electrolyzer (PEM) to produce hydrogen, which is mixed into the natural-gas pipe network and supplied to 14 families in apartments. The operation of the project has no safety problems currently [10]. Project Hybridge is one of the largest PTG projects in Europe. It is planned that it will design 100-MW electrolytic cells to produce hydrogen before 2030. The hydrogen will be used for transportation, mixing into the natural-gas pipeline network and conversion to methane [11]. At present, the largest PTG project in operation is located in the Audi e-gas plant in Werlte, Germany. The total capacity of its three electrolytic cells is 6.3 MW. Wind energy is used to provide power, and the generated hydrogen is converted into methane and injected into the gas network [12]. In general, based on literature research, there are nearly 130 PTG projects in the world, involving 26 countries or regions [9]. However, it should be pointed out that current projects often choose to provide surplus power in areas rich in renewable resources, rely on existing thermal power plants, or choose to obtain convenient raw materials in heavy industrial areas. Therefore, the choice of location is particularly important. Different resources exist in different regions; there are different bank discount rates, labor, land-use costs and product prices, leading to different project operation costs in different regions. These reasons also led to the emergence of this work.

Another important factor is based on energy-storage considerations. In recent years, renewable energy has received strong support from many countries, developed rapidly and steadily increased its market share [13]. However, the research shows that, with the increase in renewable installed capacity, the demand for power-system flexibility is also increasing [14]. Energy storage is one of the important options to improve the flexibility of power systems [15]. At present, the most widely used energy-storage technology is pumped storage, but its disadvantage is also very obvious: that is, specific locations such as steep slopes and nearby lakes are needed to meet the needs of system operation [16]. However, it is worth noting that PTG technology is expected to become a solution for large-scale energy-storage technology, which converts electric energy into hydrogen or methane [17]. At the same time, due to the construction of the “West-to-East gas transmission” project, the region has more natural-gas infrastructure, including pipelines and storage tanks. These can significantly improve energy-storage capacity and utilization capacity.

The focus of this study is to simulate the establishment of a PTG plant based on the distribution of renewable resources in Northwest China, CO₂ emissions of industrial enterprises in this region, local prices and labor costs, and explore the utilization of renewable resources and the CO₂ conversion path in this region. The schematic diagram of the plant is shown in Figure 1. The plant is composed of renewable-energy power generation, electrolytic-cell hydrogen production, the CO₂ absorption process and the CO₂ methanation process. The ratio of the CO₂ absorption solution was 10 wt% MDEA + 30 wt% PZ, to save the energy in the absorption process to the greatest extent. The heat of the absorption process and methanation process was coupled to recover 17.85 MW of heat. Through the CO₂ flow, the H₂ flow was determined, and then the electrolytic cell capacity and renewable power generation capacity were determined. The economy of the PTG plant was evaluated. Combined with the corresponding carbon tax policy, the results show that the SNG cost generated by PTG at this stage was 1782 USD/ton. The cost sensitivity analysis shows that the cost of an electrolytic cell accounted for the largest proportion. In the future, with the progress of technology and the improvement in electrolytic efficiency, this technology is expected to run on a large scale, which is one of the technical paths towards decarbonization in the future.

2. Materials and Methods

This part focuses on the methods and technologies used in carbon-dioxide capture, carbon-dioxide methanation and hydrogen production from electrolytic water

2.1. Carbon Capture

Carbon capture generally requires specific sources of CO₂, such as tail gas from large coal power plants, steel, cement and other large industries. Carbon capture can be implemented in three stages: post-combustion, pre-combustion and oxy-fuel [18]. Post combination is widely used in large-scale industrialization. Dust and sulfide need to be removed from the treated flue gas first. These amine-based solutions, such as monoethanolamine (MEA), amino methyl propanol, amino ethyl amino ethanol, piperazine (PZ), and methyldiethanolamine (MDEA), are then used to absorb CO₂. However, the disadvantage of amine-based technology is that the energy consumption is very high, which led many researchers to study efficient processes and solvents [19]. Previous work showed that optimizing the process can significantly reduce energy consumption, by 20% [20]. Studies also showed that the configuration of new solvents can save 18% of current energy consumption [21].

The establishment of the CO₂ absorption model in this study is based on Aspen HYSYS™ V.12 software (China University of Petroleum, Beijing authorized use. Beijing, China). By visiting and investigating relevant petroleum and petrochemical enterprises in Karamay, the composition of tail gas to be absorbed was obtained, as shown in

Table 1. Composition of gas to be treated (molar flow 1100 kg·mole/h, 12 MPa, 40 °C).

Main Gas Composition	Mole Fraction (%)
N2	62.1
CO2	23.1
O2	8.6
H2O	6.2

.

The design of the CO₂ absorption process is shown in Figure 2. The mixture of MDEA and PZ is considered as the absorbent. The absorption liquid from the absorption tower enters the flash module (FLASH) through the heat exchanger (LNG-101) and is divided into two parts: gas flow and liquid flow. Here, the rich solvent is flashed to produce a gas stream (composed of H₂O and CO₂), which is then compressed and sent back to the bottom of the flash module. The liquid flow is at the top of the flash module. This design can reduce the steam demand of the distillation column (REGEN) and heat the rich solvent entering the heat exchanger (LNG-102). This design refers to the practice of Le Moullec et al. [22]. Based on the heat-pump effect, the heat quality of the supply system is improved.

2.2. CO₂ Methanation

The methanation of CO₂ refers to the process of producing methane and water with CO₂ (and a small part of CO) under high pressure and a certain temperature. At present, the catalysts used in large-scale commercial use are nickel or nickel-based catalysts [23]. The methanation process is shown in Equations (1)–(4). Here, (1) and (2) represent the hydrogenation of CO₂ and CO, (3) represents the reverse reaction of water gas, and (4) represents the Boudouard reaction. The whole reaction process is strongly exothermic, but some studies have shown that a temperature exceeding 500 °C will lead to carbon deposition and deactivation of the catalyst. High temperatures will inhibit the conversion of CO₂; therefore, it is necessary to control the reaction temperature to ensure the progress of the reaction. Processes (1)–(3) will produce water, which can be supplied to the electrolytic cell.

$${\mathrm{CO}}_2+4{\mathrm{H}}_2\rightleftharpoons {\mathrm{CH}}_4+2{\mathrm{H}}_2\mathrm{O} (\Delta {\mathrm{H}}^0=-165.1\; KJ/Mol)$$

(1)

$$\mathrm{CO}+3{\mathrm{H}}_2\rightleftharpoons {\mathrm{CH}}_4+2{\mathrm{H}}_2\mathrm{O} (\Delta {\mathrm{H}}^0=-206.3\; KJ/Mol)$$

(2)

$${\mathrm{CO}}_2+{\mathrm{H}}_2\rightleftharpoons \mathrm{CO}+{\mathrm{H}}_2\mathrm{O} (\Delta {\mathrm{H}}^0=+41.2\; KJ/Mol)$$

(3)

$$2\mathrm{CO}\rightleftharpoons \mathrm{C}\left(\mathrm{S}\right)+\mathrm{C}{\mathrm{O}}_2 (\Delta {\mathrm{H}}^0=-172.5\; KJ/Mol)$$

(4)

The establishment of the CO₂ methanation model in this study is based on Aspen Plus™ V.12 software. The methanation reactors adopt fixed-bed adiabatic reactors, which can adapt to large-scale methanation production. The process flow is shown in Figure 3. Four fixed-bed adiabatic reactors (R-1; R-2; R-3; R-4) are set; each stage is equipped with a cooling system (S13; S16; S22; S25) to ensure that the reaction temperature is controlled at 350 °C, so as to avoid carbon deposition (coking) and ensure that the catalyst will not be inactivated. At the same time, the heat taken away by the cooling system will not be wasted and will be used in the CO₂-capture process or sold to the public sector for use (if any). The molar flow ratio of feed ports S1 (CO₂) and S3 (H₂) is 1:4. The reason for setting this ratio is available in a previous study [24]. The synthesized methane gas contains a lot of water, which must be removed in the use stage. Therefore, a condensation module (B19) is set to separate the water. Finally, further dehydrogenation (B24) and pressurization are required to produce SNG that meets the existing natural-gas pipeline standards.

2.3. Hydrogen Production from Electrolytic Water

Hydrogen production from electrolyzed water refers to the use of renewable energy, such as wind, solar and tidal energy, to generate electricity. Electricity is supplied to the electrolytic cell, and electrolyzed water produces hydrogen. The reaction equation of this process is shown in (5) [25]. Since renewable energy is used and the products are oxygen and hydrogen, this method has also become an environment-friendly technology option. At present, researchers have developed three typical electrolytic cells: alkaline water electrolytic (AWE), solid oxide electrolytic (SOE), and proton exchange membrane electrolytic (PEM). The technical specifications of the three electrolyzers are shown in

Table 2. Typical specifications of electrolyzers.

Specifications	Unit	AWE	PEM	SOE
Technology maturity		Large-scale commercialization	Certain commercialization	Laboratory research
System life	year	20–30	10–20	-
Hydrogen purity	%	>99.8	99.999	-
Cold start-up time	min	15	<15	>60
Investment cost	$/kW	890–1700	1550–2300	>2200

[26,27].

However, due to low conversion rate and high energy consumption, the biggest problem of electrolytic hydrogen production is low economic competitiveness. However, with the goal of energy decarbonization and the approaching pressure of carbon neutralization, coupling this technology with existing old power plants, photovoltaic power plants and wind power plants; using excess power to produce hydrogen; and storing it as energy-storage gas seems to be a scheme that can improve economic competitiveness and be implemented commercially.

H₂O + Electricity (237.2 KJ/Mol) + Heat (48.6 KJ/Mol) → H₂ + 1/2O₂

(5)

AWE was first proposed by Troostwijk and Diemann in 1789 [28]. The electrolysis process is shown in Figure 4. The alkaline solution (KOH/NaOH) near the cathode is reduced to one hydrogen molecule (H₂) and two hydroxyl ions (OH⁻) are generated. Hydrogen molecules escape from the cathode surface. Under the influence of current, hydroxyl groups are transferred to the anode through the middle diaphragm, where they are converted into 1/2 oxygen molecules (O₂) and one water molecule (H₂O). Finally, oxygen molecules escape from the anode surface. The working temperature of the electrolytic is 40–90 ℃ and the service life can reach 30 years. Moreover, with the progress of technology, the response time of electrolytic has also gradually shortened. A study in 2014 showed that the restart time after shutdown was shortened to 15 min, which can adapt to fluctuating renewable power [29]. However, some studies have shown that the scheduling model is very important for the flexible operation of an electrolytic [30]. Generally speaking, an alkaline electrolyzer is the most mature, stable and cheap commercial cell because of its early development. Therefore, AWE was selected for hydrogen-production facilities.

3. Results

This section mainly analyzes the CO₂ capture process, methanation process, hydrogen production from AWE, and energy consumption designed above. For the CO₂ capture process, the energy consumption of different absorbents was analyzed and the CO₂ absorption efficiency was calculated. For the methanation process, the flow data of each reaction stage are given as Supplementary Materials, and the final methanation efficiency was calculated. Through the hydrogen flow rate at the feed inlet of the methanation process, an AWE group was constructed to stably produce hydrogen.

3.1. Carbon-Capture Process

Select the CO₂ adsorbent to be used: MDEA, PZ, and the mixture of MDEA and PZ. Referring to previous studies [31,32], the 40 wt% concentration of a PZ solution was used as a CO₂ capture solvent. Then the concentration of the absorbent solution was set to 40 wt%. For PZ + MDEA mixed solution, the total solution mass fraction remained unchanged, and only the proportion of the two solutions changed. In order to ensure that the solvent ratio was the only variable, the pressure of the absorption tower and distillation tower should be consistent, in which the pressure of the absorption tower was 12 MPa and the pressure of the distillation tower was 52 MPa. By changing the composition of the absorbent, the total energy required in the absorption process was investigated. The energy required for different solvent processes is shown in Figure 5. It can be seen that, when the absorption solution is composed of 10 wt% MDEA + 30 wt% PZ, the energy required for the whole process is the least. Therefore, that solvent was selected as the CO₂ absorbent.

Through the whole carbon-capture process, the captured gas was obtained, and the components are shown in

Table 3. Gas composition after capture (molar flow 208.9 kmol/h, 50 MPa, 40 °C).

Main Gas Composition	Mole Fraction (%)
N2	0.2%
CO2	98.43%
H2O	1.55%

.

In order to investigate the carbon-capture efficiency, the CO₂-absorption efficiency is defined, η_CO2, as shown in Equation (6).

η_CO2 = f_produced/f_in

(6)

where, f_produced is the molar flow rate of CO₂ in the product, and f_in is the molar flow rate of CO₂ at the feed end. Through calculation, the capture efficiency was 91.5%. At the same time,

Table 4. Performance specifications of CO₂ capture.

Parameters	Values
Waste gas
N2	712.499 kmol/h
CO2	18.9572 kmol/h
O2	94.7028 kmol/h
H2O	56.0436 kmol/h
CO	0.0146 kmlo/h
SO2	0.0006 kmol/h
NO	0.0052 kmol/h
Energy demand
Compressor	1.039 MW
Pumps	0.085 MW
Coolers	6.728 MW
Total	319 MW
Material requirement
PZ	1.3931 kmol/h
MDEA	0.3357 kmol/h

gives some performance specifications of the CO₂-capture device.

3.2. CO₂ Methanation

This section discusses the output results of the CO₂ methanation process.

Table 5. Molar gas flow of each module.

Gas Composition	S1	S3	R-1	R-2	R-3	R-4	S38
Total molar flow (kmol/h)	211	827.12	3258.72	842.974	793.894	625.741	202.02
CH4 (%)	/	/	3.09	11.57	15.38	32.95	99.90
CO2 (%)	98	/	18.06	12.96	10.66	0.09	0.01
H2 (%)	/	99.9	72.14	51.72	42.56	0.25	0.07
H2O (%)	1.98	0.1	6.7	23.74	31.39	66.7	0.02
O2 (%)	/	/	/	/	/	/	/
N2 (%)	0.12	/	/	/	/	/	/

shows the changes in gas components in each part of the methanation process.

In order to investigate the methanation efficiency of the process, methanation efficiency η_h-c is shown in (7). Where, η_H-C is methanation efficiency, λ_c-out is the molar flow of (S38) CH₄ at the outlet of the reaction process (kmol/s), λ_h-out is the molar flow of (S36) H₂ at the outlet of the reaction process (kmol/s), λ_h-in is the molar flow rate of (S3) H₂ at the reaction inlet (kmol/s). M_c and M_h are the molar mass (kg/mol) of CH₄ and H₂, respectively, and L_c and L_h are the low calorific values (MJ/kg) of CH₄ and H₂, respectively. Finally, the methanation efficiency of this process was 77.5%.

η_h-c = (λ_c-out·M_c·L_c + λ_h-out·M_h ·L_h)/λ_h-in·M_h·L_h

(7)

Similarly,

Table 6. Performance specifications of CO₂ methanation.

Parameters	Values
Energy demand
Compressor	0.967 MW
Coolers	−7.9026 MW
Reactor
Operating pressure	100 MPa
Pressure loss	2%
Operating temperature	350 °C
Catalyzer	Ni/MgAl2O4

shows the operating specifications of other equipment in the methanation process. The specific dimensions of the four adiabatic reactors and the mass of the catalyst are given in

Table 7. Adiabatic reactor specification.

Parameters	R-1	R-2	R-3	R-4
Length	4.97 m	5.56 m	6.83 m	6.62 m
Diameter	2 m	1.4 m	1.2 m	1.2 m
Catalyst weight	22 ton	5.87 ton	5.44 ton	7.47 ton

.

3.3. Electrolytic Scale

This part discusses the capacity of the electrolytic cell to ensure the stable supply of hydrogen required in the methanation stage. It can be seen from Table 4 that the hydrogen molar flow rate at the feed inlet (S3) of the methanation process was 826.29 kmol/h. In order to adapt to this flow, through sufficient market research and literature research, China Huaneng Group Clean Energy Technology Research Institute Co., Ltd. was selected to develop an alkaline electrolytic [33]. The specific specifications are shown in

Table 8. Technical specifications of alkaline electrolyzer.

Parameters	Values
Rated hydrogen production	1300 Nm/h
Maximum hydrogen production	1500 Nm/h
Maximum current density	6000 A/m
Energy consumption	<4.2 kWh/NmH

.

Then, the required electrolytic capacity was obtained. It was specified that the electrolytic works with customized hydrogen power. Through calculation, the electrolytic capacity is 158 MW, that is, 29 alkaline electrolytics. Considering the start-up, shutdown, maintenance, and other operations of the electrolytic, the capacity of the electrolytic was expanded by 10% to ensure stable output. Then, 174 MW capacity was required, that is, 32 sets of the equipment are required.

In conclusion, based on the industrial tail gas emission of Karamay City, the scale of the carbon capture process, methanation process and hydrogen production from electrolytic water were designed.

Table 9. PTG-plant energy consumption and material consumption.

	Specification	Values
Carbon capture	Tail gas	34.109 ton/h
CO2 methanation inputs	CO2	9.177 ton/h
	H2	1.681 ton/h
	Cooling water	14.8 ton/h
Hydrogen production	Number of electrolytic cells	30
PtG outputs	SNG	3.236 ton/h

is a summary of these works. The table shows the materials, output, and other information required by the PTG plant.

4. Discussion

This section mainly analyzes the economy and technology of the PTG plant. The energy consumption of the plant was analyzed, and the heat circulation module was added to make better use of heat. Based on the current market levels, current policies, and bank discount rates, the prices of land, equipment, labor, raw materials, and products were fully considered, and the economic feasibility of establishing PTG factory was explored at this stage.

4.1. Energy Consumption Analysis

As the methanation process is highly exothermic, it can collect heat for carbon capture, or send it to a steam turbine for power generation to provide power for plant operation. Figure 6 shows the composite curve of the cooling and heating load of the PTG plant. The total heat recovered was 17.85mw and the temperature range was 40–350 °C. At 150 °C, this part of heat can be sent to the distillation tower of the CO₂ process. This part of the heat was 5.16 MW, which can effectively compensate for the heat demand of the process.

At the same time, it should be pointed out that the adiabatic reactor in the methanation stage is equipped with a cooling module. This high-temperature steam can be sent to the steam turbine to generate electricity, to be used for the consumption of compressors and pumps. The turbine heat rate [34] was 8063.6 kJ/kWh. The total molar enthalpy of cooling modules (S14, S17, S21, S27) per unit time was 196075.147 MJ, so the power generated by the steam turbine can fully meet the power required by the carbon-capture and methanation equipment, with reference to Table 4 and Table 6.

4.2. Economic Analysis

In this section, the investment cost and operation cost of the PTG plant is simulated and evaluated according to the simulation results, and the plant income is calculated according to the products. The cost coefficient method was used to calculate the fixed investment cost, as shown in (8).

$${\mathrm{P}}_1={\mathrm{P}}_2\text{·}(1+{{\displaystyle \sum }}_{\mathrm{i}=1}^{\mathrm{n}}{\mathrm{R}}_{\mathrm{i}})\text{·}\mathrm{N}$$

(8)

Among them, P₁ is the total investment in fixed assets; P₂ is the investment in equipment, taken to be 1.2; R_i is the cost coefficient of each part; and N is the comprehensive coefficient.

Table 10. Cost coefficient of each part.

Part	Expense Type i	$\mathbf{Cost}\mathbf{Coefficient}{\mathbf{R}}_{\mathbf{i}}$
Direct cost	Existing equipment and plant	1
	Purchased equipment	0.47
	Instrumentation and control equipment	0.36
	The conduit	0.68
	Electrical system	0.11
	Building service facilities	0.18
	Plant-improvement facilities	0.10
	Living-service facilities	0.60
Indirect cost	Engineering supervision	0.28
	Construction cost	0.31
	Legal service fee	0.04
	Contractor’s costs	0.18
	Contingency expenditure	0.35

shows the cost coefficients of each part. The operating period is assumed to be 20 years and the residual value is assumed to be 0. The total project cost C is defined as Equation (9) [35], where C_i is the cost of each part; see

Table 11. Operating costs of various parts of the project.

Project (i)	Specific Matters	Cost
1	Raw material	Amine solvent: 3.5 USD/kg, catalyzer: 240 USD/kg, industrial water: 0.24 USD/ton, electrolytic water: 1.57 USD/kg, hydrogen: produced by electrolysis; selling price of methane: 0.32 USD/Nm3, price of industrial oxygen: 157 USD/ton
2	Public utility	Cooling water: 0.03 USD/ton, electric energy required for electrolysis [37], 0.047 USD/kWh;
3	Plant operation and maintenance costs	Labor cost	40 people/shift, 3 shifts/day, 9432 USD/person·year
		Maintenance and repair	6% of capital investment
		Consumption of operating supplies	15% of working capital
4	Depreciation	20-year operation cycle, with a maturity discount of 0 USD
5	General expenses	15% of the total product cost

for details. Methane and pure oxygen can be sold, and carbon-emission reductions can be sold through the carbon trading market. The price is based on the national carbon trading price on 4 June 2021 [36], and the labor cost refers to the per capita disposable income of the city.

$$\mathrm{C}={\mathrm{P}}_1+{{\displaystyle \sum }}_{\mathrm{i}=1}^{\mathrm{n}}{\mathrm{C}}_{\mathrm{i}}$$

(9)

Regarding the cost of the alkaline electrolyzer, with the maturity of large-scale commercial technology and sufficient market competition, the equipment investment price will continue to decline. The investment cost of the alkaline electrolyzer selected in this study is 314 USD/kW [38]. Then, the calculation method of hydrogen production costs from electrolytic water is shown in (10).

S = (S₁ + S₂ + S₃)/(C·Y) + S_E·B

(10)

where S is hydrogen production cost, S₁ is the investment cost for the electrolytic, S₂ and S₃ are the renewal and maintenance costs of electrolytic; these costs are 40% and 5%. C is the annual output of hydrogen, and Y is the operation cycle of the unit, which is 20 years. S_E is the power cost of the electrolytic, and B is the power required to produce 1kg of hydrogen. After calculation, the hydrogen cost of electrolytic water was 4.66 USD/kg.

According to Formulas (8) and (9), Table 8 and Table 9, the cost required for each ton of natural gas produced by the PTG plant can be calculated, as shown in Figure 7.

The cost of producing SNG in the PTG plant is 1782 USD/ton, which is also shown in Guilera. et al. [39], and Chauvy et al. [3], within the cost range assessed. Compared with the traditional LNG price [40] of 607.7 USD/ton, the SNG produced by the PTG plant is three times the traditional price. However, it is worth noting that, from Figure 7, it can be seen that the high cost of hydrogen production increases the cost of SNG. Product pure oxygen and methanation product SNG can be sold to improve system revenue. It is worth noting that China launched the carbon trading market in 2017, so the CO₂ used in the methanation stage can be sold as a carbon reduction quota, but the profit proportion is not high at this stage.

In order to further investigate the economy of the PTG plant, the sensitivity analysis of a large part of the cost was carried out. This included electrolytic electricity price, oxygen price, carbon trading price, etc., as shown in Figure 8.

Through sensitivity analysis, it can be seen that the change in electrolytic cell power consumption in the hydrogen production stage has the greatest impact on SNG cost. In the future, through technological progress, the improvement of electrolytic cell efficiency and the decrease in power consumption, the production cost of SNG can be reduced. Changes in oxygen sales profits and carbon trading prices can also have a certain impact on SNG costs.

5. Conclusions

The current work evaluates the technical route of setting up a PTG plant to produce SNG with CO₂. Based on Karamay industrial tail gas emissions, the carbon capture process and methanation process were designed using Aspen Hysys™ V.12 software and Aspen Plus™ V.12 software. The heat flow in the process was recycled to ensure the balance of quality and energy. The alkaline electrolyzer module was designed to supply hydrogen stably. The results show that the PTG plant can produce 3.326 tons of natural gas per hour and consume 8.899 tons of CO₂ at the same time. The final carbon capture efficiency was 91.5%, and the methanation efficiency was 77.5%. The price of one ton of SNG produced by the PTG plant was USD 1782, which is three times the price of traditional natural gas. At present, it is not economically competitive. According to the cost analysis, the cost of hydrogen accounted for the largest proportion, which is due to the high-power consumption of electrolytic hydrogen production. However, it is worth noting that the implementation of large-scale commercial electrolysis cases in the future will gradually reduce the electrolysis cost, and then reduce SNG production costs. With the continuous improvement of the national carbon trading market, the carbon price is expected to rise in the future, which can also bring objective benefits to the PTG plant.

It should be pointed out that, although this study gives a economic and technological construction scheme of a PTG plant in Karamay, it is based on the flue gas produced by industrial enterprises. In future research, more flexible schemes can be designed. For example, matching the thermal power plant, using the surplus power of the thermal power plant to produce hydrogen by electrolysis, and then converting it into methane as energy-storage gas, which is expected to greatly reduce the cost. In a previous study, Momeni and others chose a 500 MW gas-fired power plant, which can produce 579.8 ktons of methane per year by recovering tail gas and excess power, reducing the carbon emission of the power plant by 66%. In addition, it can also be combined with power-grid energy storage and peak shaving. Electricity is provided through renewable energy, hydrogen is produced by electrolysis, and then converted into methane with the captured CO₂, which is used as energy-storage gas to regulate the grid load. However, with technological progress, PTG technology is expected to be implemented on a large scale, and is one of the technologies to achieve carbon neutrality in the future.