Prospects for Long-Distance Cascaded Liquid—Gaseous Hydrogen Delivery: An Economic and Environmental Assessment

Abstract

As an important energy source to achieve carbon neutrality, green hydrogen has always faced the problems of high use cost and unsatisfactory environmental benefits due to its remote production areas. Therefore, a liquid-gaseous cascade green hydrogen delivery scheme is proposed in this article. In this scheme, green hydrogen is liquefied into high-density and low-pressure liquid hydrogen to enable the transport of large quantities of green hydrogen over long distances. After long-distance transport, the liquid hydrogen is stored and then gasified at transfer stations and converted into high-pressure hydrogen for distribution to the nearby hydrogen facilities in cities. In addition, this study conducted a detailed model evaluation of the scheme around the actual case of hydrogen energy demand in Chengdu City in China and compared it with conventional hydrogen delivery methods. The results show that the unit hydrogen cost of the liquid-gaseous cascade green hydrogen delivery scheme is only 51.58 CNY/kgH₂, and the dynamic payback periods of long- and short-distance transportation stages are 13.61 years and 7.02 years, respectively. In terms of carbon emissions, this scheme only generates indirect carbon emissions of 2.98 kgCO₂/kgH₂ without using utility electricity. In sum, both the economic and carbon emission analyses demonstrate the advantages of the liquid-gaseous cascade green hydrogen delivery scheme. With further reductions in electricity prices and liquefication costs, this scheme has the potential to provide an economically/environmentally superior solution for future large-scale green hydrogen applications.

1. Introduction

In order to achieve carbon peak and carbon neutrality, China has proposed in the Medium- and Long-Term Plan for the Development of Hydrogen Energy Industry (2021–2035) that by 2025, great progress will be made in hydrogen production from clean energy and hydrogen storage and transportation technology, hydrogen production from renewable energy will reach 100,000–200,000 tons per year, and a number of hydrogen filling stations will be deployed and built. Hydrogen produced from renewable energy has lower carbon emissions, but most of the hydrogen produced in China currently comes from fossil fuels, and green hydrogen accounts for less than 1% [1]. The proposal of the dual carbon target means that China will accelerate the transformation from gray hydrogen to green hydrogen [2,3].

The western region of China is currently witnessing the construction of numerous renewable energy power generation facilities, which possess abundant green hydrogen resources capable of fulfilling China’s self-sufficiency in carbon-free hydrogen energy [4]. Most regions abundant in renewable energy lack sufficient local energy consumption capacity and are located at a certain distance from the energy load center [5,6], resulting in a regional mismatch between hydrogen production capacity and downstream application upon the widespread realization of green hydrogen [7]. Therefore, to achieve the large-scale application of green hydrogen, it is crucial to consider the storage and transportation of hydrogen, as the cost associated with these processes will significantly impact the final utilization cost of green hydrogen [8,9].

At present, the three mainstream transportation modes of hydrogen are gaseous hydrogen (GH₂) pipelines, GH₂ transport vehicles, and liquid hydrogen (LH₂) transport vehicles [10,11]. The rigidity of GH₂ pipelines and their higher initial investment make them suitable only for point-to-point transmission of large volumes of hydrogen [12]. GH₂ vehicle transport offers greater flexibility, but a typical 20 MPa GH₂ transport vehicle can only accommodate 350 kg of hydrogen, greatly limiting its transport efficiency [13,14]. Compared with GH₂ transport vehicles, the LH₂ transporter exhibits a significantly higher hydrogen storage density, with a single vehicle capable of transporting 4000 kg of hydrogen, surpassing the GH₂ transport vehicle by more than tenfold. This provides evident advantages in scenarios requiring large-scale hydrogen transportation [15,16]. However, the LH₂ transport vehicle also faced some problems. Most of the existing hydrogen refueling stations are GH₂ refueling stations with a size of 500 kg/day to 1000 kg/day [17,18]. The hydrogen refueling station served by the LH₂ transport vehicle must add an LH₂ gasification unit, which will increase the investment cost. In addition, the spacing between multiple hydrogen refueling stations will also lead to an increase in vehicle transportation distance and time. This increases evaporation losses and fuel consumption generated during transportation [19,20], raising operating costs. The above three modes of hydrogen storage and transportation have been fully verified in actual projects. At present, various standards have been established to support the use of GH₂ and LH₂, and the relevant equipment has high safety standards to realize the safe use of hydrogen [21]. In addition, organic liquid hydrogen storage and solid hydrogen storage are also the current research hotspots of hydrogen storage and transportation technology; methanol, liquid ammonia, and porous silicon SI+ are more typical examples [22]. The common point of organic liquid hydrogen storage and solid hydrogen storage is that both can avoid harsh conditions such as high pressure or low temperature required for physical transportation of hydrogen to a certain extent and have better safety and economy [23,24]. However, due to the complexity of the process, the other two methods of hydrogen storage and transportation have not been commercialized.

The problems faced by LH₂ transport vehicles in practical application can be alleviated by establishing a liquid-gas cascade transportation scheme. The LH₂ transport vehicle only undertakes the long-distance transport task. After vaporizing at the hydrogen transfer station [25], the transported LH₂ is connected with the nearby hydrogen energy facilities through the GH₂ transport vehicle. Compared with the existing point-to-point hydrogen energy transportation scheme, the liquid-gas cascade transportation scheme can use the advantages of high storage density of liquid hydrogen, transport a large amount of hydrogen efficiently, and greatly reduce transportation costs and energy consumption. The problem of the mismatch between liquid hydrogen transportation and existing hydrogen energy facilities and the need to purchase new equipment has also been solved through the hydrogen transfer station. In summary, the liquid-gas cascade transportation scheme significantly reduces transportation costs and energy consumption while avoiding additional initial investment. However, to the best of our knowledge, no studies have been carried out to provide a comprehensive economic evaluation and system-level analysis of liquid-gas cascade transport options for hydrogen. Meanwhile, previous literature has not fully considered the energy consumption and carbon emissions of hydrogen throughout its life cycle, from production to use, nor has it introduced cost analyses to assess the payback period from an engineering economics perspective. Therefore, this study designs a complete liquid-gas cascade green hydrogen supply scheme around the actual hydrogen use case in Chengdu city and provides a detailed feasibility analysis of the scheme.

Different from those existing studies on single hydrogen storage and transport methods, this article explores a new type of green hydrogen supply scheme applicable to the current situation of hydrogen energy development in China. The novelties and contributions can be summarized as follows:

(1)

Taking the future hydrogen demand of Chengdu City as an example, a liquid-gas cascade green hydrogen supply scheme from Qinghai to Chengdu is proposed. The scheme makes full use of the surplus renewable energy in Qinghai province for the electrolysis of water to produce hydrogen and uses a cascade storage and transport scheme to maximize the advantages of LH₂ transport and GH₂ transport, and the transport vehicle also uses hydrogen-powered vehicles. While lowering the cost of hydrogen, it also significantly reduces the amount of indirect carbon emissions generated during the process, with no direct CO₂ emissions throughout the entire transport process.

(2)

Based on the actual costs and performance of the equipment, an economic model and a carbon emission model of the liquid-gas cascade green hydrogen supply scheme are established. The model systematically analyzes the economic and environmental benefits, taking into account the costs of operation and maintenance and the consumption of various energy sources. Finally, a static/dynamic payback period analysis and a carbon emission analysis are performed to evaluate the economics and emission reduction capability of the scheme, providing a universal evaluation method for the practical development and use of liquid-gas cascade transport schemes.

2. Overall Framework and Principle

Chengdu’s hydrogen energy industry development plan proposes to build 40 hydrogen refueling stations in 2023–2025; in the long-term goal of 2025–2030, it is proposed to build about 100 hydrogen refueling stations, and the proportion of green hydrogen is more than 75%; By 2030, it will fully transform to green hydrogen operation mode [26]. Referring to the hydrogen energy demand proposed in the plan, this paper designs the liquid-gas cascade green hydrogen supply scheme (Route 1) from Qinghai to Chengdu. The scheme adopts the mixed transportation mode of long-distance liquid hydrogen transportation and short-distance gas-hydrogen transportation, which can simultaneously meet the daily hydrogen energy demand of twenty 1000 kg hydrogen refueling stations and twenty 500 kg hydrogen refueling stations, and the daily hydrogen transportation volume is 28 tons.

Route 1 gives priority to the use of excess wind and solar energy in Qinghai Province for the electrolysis of water to produce H₂. The H₂ produced is liquefied and deposited in the LH₂ storage tanks in the hydrogen plant, then transported to the H₂ transfer station around Chengdu City by LH₂ transporters, and finally the transported LH₂ is centrally stored in the H₂ transit station. The above is the long-distance transport component, which includes three stages: H₂ production, LH₂ transport, and H₂ transit station. The LH₂ transporter operates from the hydrogen plant to the H₂ transit station, a distance of 1050 km, and transports 28,000 kg of LH₂ daily. The short-distance transport component consists of two stages: GH₂ transport and H₂ refueling stations. The H₂ transit stations gasify and pressurize a quantitative amount of LH₂ according to the specific hydrogen requirements before transporting it to the individual H₂ refueling stations by GH₂ transporters. The GH₂ transporter operates from the H₂ transit station to each H₂ refueling station over a distance of 0–70 km, and the amount of H₂ transported in a single day depends on the H₂ demand of each H₂ refueling station, which is typically 500 kg. The energy distribution, transformation, and transmission in Route 1 are shown in Figure 1.

As a comparison, the LH₂ transport scheme (Route 2) and the GH₂ transport scheme (Route 3) of the same scale are additionally designed in this paper. Unlike Route 1, there are no H₂ transit stations in Route 2 and Route 3, and the transporters operate from the hydrogen plants to the various H₂ refueling stations. In Route 2, the H₂ produced by electrolysis is liquefied and then transported directly to H₂ refueling stations by LH₂ transporters, each of which is required to meet the hydrogen demand of several H₂ refueling stations. Route 3 does not involve LH₂ throughout the process, and the H₂ produced by electrolysis is pressurized and transported to H₂ refueling stations by GH₂ transporters. The three routes differ in the equipment required at each stage due to the different modes of transport, as shown in Figure 2.

3. System Modeling

3.1. H₂ Production Stage

The main equipment involved in the H₂ production stage is the H₂ production equipment and the H₂ storage tank [27]. All three routes used electrolysis of water to obtain H₂ [28], and the mass of H₂ produced (liquefier input) was 29,863 kg per day. The Alkaline Water Electrolysis (AWE) technology selected in this paper is the most economically optimal way to produce H₂ from electrolytic water [29], with a market share of 97% in 2022. Compared with AWE, Proton Exchange Membrane (PEM) and Solid Oxide Water Electrolysis (SOEC) water electrolysis technology have higher efficiency [30]. The SOEC water electrolysis technology requires additional energy to ensure the high-temperature environment required for its operation, so the technology is more suitable for scenarios with suitable heat sources. As of now, the technology is still in the early stages of commercialization [31]. PEM technology has been applied in many new projects and gradually promoted, but the problems of short life and high cost of PEM electrolyzers still exist. At present, the average hydrogen production cost of the AWE electrolyzer is 33.37 CNY/kgH₂, while the average hydrogen production cost of the PEM electrolyzer is 50.97 CNY/kgH₂. Among them, the equipment investment of the PEM electrolyzer is 3–5 times that of the AWE electrolyzer [32,33].

In addition to the high purity H₂ obtained when producing H₂ from electrolytic water, a high-value by-product of high-purity green oxygen (up to 99.995% concentration after dewatering and dehydrogenation) can also be brought about [34]. The specific parameters of the selected AWE electrolyzer are shown in

Table 1. Parameters of the AWE electrolyzer.

Technical Data	Value	Unit
Price	14,100,000	RMB
Capacity	89.3	kgH2/h
Operating temperature	343	K
Operating pressure	15	atm
Power consumption of electrolysis	50.392	kWh/kgH2
Other consumption	4.7	kWh/kgH2
Delivered H2 pressure	2	MPa
Fresh water consumption	10.99	kg/kgH2
Recycling water consumption	405.15	kg/kgH2
Day running time	18	h

[35,36].

Electricity for electrolysis consists of excess wind power and solar power not connected to the grid in Qinghai Province, and electricity is uniformly delivered by the grid. Qinghai Province launched the PV parity project and large industrial grid-connected electricity price time-sharing policy. The design of the electrolysis tank operation time for the day was 23:00 to 17:00 the next day, avoiding most of the peak power hours and reducing the grid load while saving the cost of H₂ production [37,38].

The hydrogen plant storage equipment for Route 1 and Route 2 is LH₂ storage tanks, while Route 3 stores GH₂ [39].

3.2. LH₂ Transport

Route 1 and Route 2 both use LH₂ transporters for long-distance transport. Route 1 has a H₂ refueling station, and the truck only needs to deliver LH₂ from the hydrogen plant to the H₂ transit station 1050 km away; in Route 2, a single LH₂ truck needs to deliver LH₂ to multiple H₂ refueling stations in Chengdu, and the distance between each H₂ refueling station increases the distance of Route 2 compared to Route 1, and unloading multiple times also prolongs the truck’s running time and increases H₂ losses [40]. The distance from the hydrogen plant to Chengdu is about 1100 km, and the total operating distance of Route 2 is 1500 km after the 50 km between H₂ refueling stations is taken into account.

The equipment involved in LH₂ transport is the LH₂ transporter and the liquefier, and the specific parameters of the hydrogen energy LH₂ transporter are shown in

Table 2. Hydrogen fuel LH₂ transport truck parameters.

Parameter	Value	Unit
Price	1,200,000	$
Fuel type	H2	-
Transport type	LH2	-
Load capacity	4000	kg
Fuel economy	0.08	kg/km
Average speed	70	km/h
Truck use per day	15	h

[41,42].

The selected H₂ liquefier has a maximum liquefaction capacity of 15,000 kg/d [43]. Since LH₂ has H₂ losses when it is produced, transported, and stored, it needs to be liquefied by producing more H₂ than the actual hydrogen demand. Liquefier input m_liq (kg) is calculated by [44]:

$$m_{liq}=m_d/{\phi }_{liq}/{\phi }_{del}/{\phi }_{sto},$$

(1)

where m_d is the daily H₂ demand in Chengdu, kg; φ_liq, φ_del, and φ_sto are the mass efficiencies of liquefaction, transport, and storage, with typical values of 99.5%, 94.5%, and 99.7%.

The energy requirement E_liq (kWh/kgH₂) for each unit of H₂ liquefied is calculated by:

$$E_{liq}=13.382\times {(m_{liq}/N/1000)}^{-0.1},$$

(2)

where N is the number of liquefiers; in the example, 2 liquefiers are required.

3.3. GH₂ Transport

Currently, GH₂ transport technology is mature, and most of the existing H₂ refueling, storage, and transport facilities are constructed with GH₂ as the energy carrier [45,46]. The use of GH₂ transport can be well adapted to the existing H₂ refueling and use facilities in Chengdu and is more suitable for the complex traffic situation within the city. Route 1 and Route 3 both involve GH₂ transport, and the GH₂ transporter in Route 1 is only tasked with short-distance, small-scale transport between H₂ transit stations and individual H₂ refueling stations within 70 km. In Route 3, the H₂ is transported by GH₂ transporters from the hydrogen plant to the H₂ refueling stations. The H₂ produced by electrolysis is compressed and transported to Chengdu by the GH₂ transporter.

The equipment involved in GH₂ transport is the GH₂ transporter and compressor, and the specific parameters of the hydrogen energy GH₂ transporter are shown in

Table 3. Hydrogen fuel GH₂ transport truck parameters.

Parameter	Value	Unit
Price	376,470	$
Fuel type	H2	-
Transport type	GH2	-
Tube trailer pressure	20	MPa
Load capacity	350	kg
Fuel economy	0.08	kg/km
Average speed	70	km/h
Truck use per day	15	h

[41,42]. The selected H₂ compressor power P_com (kW) is calculated by [44]:

$$P_{com}=ZmRT\times \left({\displaystyle \frac{k}{\eta (k-1)}}\right)\times [{\left({\displaystyle \frac{P_{outlet}}{P_{inlet}}}\right)}^{{\displaystyle \frac{k-1}{k}}}-1],$$

(3)

where Z is the average compressibility factor; m is the mass flow rate, kg/s; R is the universal gas constant, 8.3144 KJ/kg-mole-°K; T is the inlet gas temperature, °K; η is the efficiency, 75%; k is 1.4; and P_outlet and P_inlet are the outlet and inlet pressures.

The daily H₂ compressor energy consumption E_com (kWh/d) is calculated by:

$$E_{com}=P_{com}\times t_{dispening}/{\eta }_{ele},$$

(4)

where η_ele is the compressor efficiency, typically 90%; t_dispening is the daily running time, h.

3.4. H₂ Transit Stage

The main equipments at the H₂ transit station mainly include the LH₂ storage tank and the gasifier [47]. Currently, the main function of the transit station is to store and redistribute H₂ according to the hydrogen consumption in Chengdu, but the development plan of Chengdu proposes to increase the scale of H₂ export for nearby cities, so there is an increased need for a large-scale H₂ transit station to carry out unified planning and scheduling for the city’s input and output of H₂. In addition, the LH₂ storage tank also provides an on-site cryogenic operating condition for integrating various advanced superconducting power devices in future cryogenic energy networks [48,49].

3.5. H₂ Refueling Stations Stage

H₂ refueling stations are mainly composed of H₂ storage tanks, compressors, high-pressure tanks, pre-cooling units, and dispensers, but the equipment for H₂ refueling stations varies slightly depending on the mode of transport [50]. In this paper, we take the common 500 kg refueling station in China as an example. It has a peak flow rate of 26 kgH₂/h and operates 24 h daily.

The H₂ delivery method in Route 1 and Route 3 is GH₂ delivery, so the H₂ storage device at the H₂ refueling stations is the GH₂ tank. As the GH₂ transport pressure does not reach the distribution pressure, it needs to be further pressurized by the compressor and cooled to meet the distributor’s operating requirements. In Route 2, the station H₂ storage tanks are LH₂ tanks, which also need to be equipped with additional gasifiers [51]. The function of the high-pressure tank is to supply H₂ to meet peak demand during periods of high H₂ requirements. In general, 35 MPa H₂ refueling stations should be equipped with 45 MPa high-pressure tanks. The formula for calculating the capacity of the high-pressure tank, C_H (kg), is calculated by [52]:

$$C_H=m_{peak}\times SF,$$

(5)

where m_peak is the total mass to be delivered at peak time, kg; SF is the safety factor, generally 1.2.

The H₂ needs to be cooled before distribution, and the pre-cooling unit energy consumption E_pcu (kWh/kgH₂) is calculated by [53]:

$$E_{pcu}={\displaystyle \frac{0.3}{1.6\times e^{-0.018\times T_{amb}}}}+\left[{\displaystyle \frac{25\times \ln \left(T_{amb}\right)-21}{DD{H}_2}}\right],$$

(6)

where DDH₂ is the daily demand of H₂, kg/d, and T_amb is the ambient temperature, 27 °C.

4. Economic Analysis

4.1. Methods of Economic Calculation

The cost of hydrogen use C in all phases consists of both capital and operating costs. C is calculated by [54]:

$$C=ACC+OPC,$$

(7)

where the annual cost of capital (ACC) can be calculated by multiplying the total initial cost of capital (TCC) and the Capital Recovery Factor (CRF). The TCC is composed of the total price of the unit (TPU) plus any additional expenditures. Additional costs include conventional facility costs, engineering permits, and start-up costs, contingency handling costs, and miscellaneous land costs, which can be calculated by multiplying the TPU by an experience factor (EF) [55]. The CRF can be calculated from the discount rate and the lifetime of the equipment. ACC, TCC, and CRF are calculated by [56]:

$$ACC=TCC\times CRF,$$

(8)

$$TCC=TPU+TPU\times EF,$$

(9)

$$CRF={\displaystyle \frac{{i(1+i)}^t}{{(1+i)}^t-1}}.$$

(10)

Operating costs (OPC) include the cost of raw materials for production, fuel (gas, diesel, coal, etc.), labor costs, non-fuel OandM costs, fixed costs, and the cost of by-products sold at market price, as calculated by [57]:

$$OPC=C_{feed}+C_{uti}+C_{lab}+C_{O\&M}+C_{byp}.$$

(11)

The total cost of H₂ use (RMB/kgH₂) can be calculated by adding up the costs of all stages. The total H₂ cost (C_H) is calculated by:

$$C_H=C_{pro}+C_{tra1}+C_{transit}+C_{tra2}+C_{dis},$$

(12)

where C_pro, C_tra1, C_transit, C_tra2, and C_dis are the unit H₂ costs for the five stages of H₂ production, long-distance transport, transit, short-distance transport, and distribution, respectively. The raw material prices and by-product selling prices used in this paper are shown in

Table 4. Prices of raw materials, fuels, and by-products.

Item	Price	Unit
Electricity in flat and low periods (Qinghai Province)	0.28	RMB/kWh
Electricity (Qinghai Province)	0.35	RMB/kWh
Electricity (Sichuan Province)	0.55	RMB/kWh
Fresh water	1.5	RMB/ton
Recycling water	0.3	RMB/ton
Fuel H2	40,000	RMB/ton
O2	0.25	RMB/Nm3

[58], the economic assumptions used are shown in

Table 5. Economic assumptions.

Item	Value	Unit
HRS capacity	500	kgH2/d
Discounted rate	8%	-
Exchange rate of RMB	7	RMB:$
Lifetime for H2 production	20	years
Lifetime for H2 transportation	20	years
Lifetime for H2 refueling station	15	years
General facilities	10%	of TPU
Engineering permitting and startup	5%	of TPU
Contingencies	5%	of TPU
Land Miscellaneous	3%	of TPU
Variable non-fuel O and M	0.5%	of TCC
Labor	3%	of TCC
Fixed operating cost	5%	of TCC

, and the prices of the main equipment used are shown in

Table 6. Main equipment prices.

Equipment	Capital Costs	Refs
Liquefier cost	75,185,000 $ each unit	[43]
Compressor	51,901 × (3600 m)0.65 $	[50]
Gasifier	650,000 $ each unit	[50]
Low-pressure buffer tank	1001 $/kgH2	[50]
High-pressure buffer tank	1495 $/kgH2	[50]
Liquid H2 tank	27 $/kgH2	[59]
Dispenser with precooling unit	170,000 $ each unit	[53]

.

4.2. Results of Economic Calculations

After modeling, the total H₂ cost of Route 1 was calculated to be 51.5825 CNY/kgH₂; Route 2 was calculated to be 53.1102 CNY/kgH₂, and Route 3 was calculated to be 59.0321 CNY/kgH₂. The specific cost components of the three routes are shown in Figure 3 and Figure 4.

In Route 1, the three parts of H₂ production, LH₂ transport, and H₂ transit station have a carrier scale of 28,000 kgH₂/day, and the cost of H₂ is 17.372, 15.952, and 0.765 CNY/kgH₂, respectively, for a total of 34.089 CNY/kgH₂, and the initial investment is RMB 336.46 million, RMB 1111.39 million, and RMB 73.67 million, respectively, for a total of RMB 1521.52 million. The scale of carriage for the GH₂ transport and H₂ refueling stations component is 500 kgH₂/day. The costs were 4.822 and 12.671 CNY/kgH₂, totaling 17.493 CNY/kgH₂, and the initial investments were RMB 9.28 million and RMB 17.34 million, totaling RMB 26.62 million.

In Route 1, the stages where the cost will fluctuate with the change in electricity price are hydrogen production, long-distance transportation, and hydrogen refueling stations. Their variation curves are shown in Figure 5. In addition, with the progress of the electrolysis process and the liquefication process, the initial investment of the related equipment will be further reduced, and the hydrogen cost will also fall.

4.3. Capital Recovery, Profitability, and Government Subsidies

The General Office of the Chengdu Municipal People’s Government issued a policy on hydrogen subsidies in 2020 [60], proposing investment and operational subsidies for companies engaged in the storage and transport of H₂ and the construction of H₂ refueling stations. If the investment is made in the long-distance transport component of Route 1, then both the H₂ production and transit station phases involve the storage of H₂, with a total of RMB 10 million in one-off subsidies available. The LH₂ transport stage is eligible for an annual transport subsidy of RMB 1.5 million, which translates to 0.147 CNY/kg per unit of subsidized H₂. If investing in the short-distance transport component, each H₂ refueling station will receive a one-time subsidy of RMB 5 million upon completion; the GH₂ transport stage receives a subsidy of 1.5 CNY/kg per unit of H₂. If H₂ refueling stations sell H₂ at prices not higher than 40 CNY/kg, they are also eligible for an annual sales subsidy of RMB 20 per unit of H₂. Therefore, after enjoying the policy subsidy, Route 1 provides 1 kg of H₂ sold at 40 CNY/kg, with an actual income of RMB 61.647. Dividing the actual income in a 6/4 ratio, we get RMB 37 from selling 1 kg of H₂ in the long-distance transport section and RMB 24.647 from selling 1 kg of H₂ in the short-distance transport section.

The payback period is an important indicator for measuring the effectiveness of project investment and its ability to resist risk. The dynamic payback period (DPP) is the time required to recover the total investment in terms of the net return of the project under the condition that the time value of money is fully taken into account, whereas the static payback period (SPP) is the time required for recovering the total investment without taking into account the time value of money [61]. Net Present Value (NPV) is the sum of the present values of the net cash flows over the project’s calculated period by specifying the discount rate and is an absolute indicator of the project’s profitability. DPP, SPP, and NPV are calculated by [59,62]:

$$\sum _{t=1}^{DPP}{\left(CI-CO\right)}_t{(1+i)}^{-t}=0,$$

(13)

$$\sum _{t=1}^{SPP}{\left(CI-CO\right)}_t=0,$$

(14)

$$NPV=\sum _{t=1}^n{\left(CI-CO\right)}_t{(1+i)}^{-t},$$

(15)

where CI is the annual revenue (income per unit of H₂ × annual volume of H₂ transported), CNY; CO is the annual operating cost (operating cost per unit of H₂ × annual volume of H₂ transported), CNY; and (CI-CO)_t is the net cash flow at the end of year t, CNY. After considering the one-time subsidy, the cumulative life cycle NPV of RMB 1829.41 million is obtained for investing in the long-distance transport component, with DPP and SPP of 13.61 and 8.11 years, respectively. When the scale of short-distance transport exceeds 2000 kg/d, GH₂ transporters and related equipment can achieve a high utilization rate to further improve economic benefits. After considering the lump-sum subsidy, the DPP and SPP of the short-distance transport component with a scale of 2000 kg/d are 7.02 years and 5.21 years, respectively, and the cumulative NPV of the life cycle is RMB 104.84 million. The cumulative NPV and dynamic and static payback periods over the life cycle of the long and short-distance transport components are shown in Figure 6 and Figure 7.

5. CO₂ Emissions

The three routes in this paper all use a green hydrogen supply system that combines H₂ production from electrolytic water with hydrogen trucking, and the main energy sources consumed are electricity, hydrogen, and water, with no direct CO₂ emissions. Thus, only the indirect CO₂ emissions from the process need to be calculated. The indirect CO₂ emissions are calculated by [63]:

$$E_{{CO}_2}=\sum _{j=1}^n{m}_j\times {EF}_{j,{CO}_2},$$

(16)

where $E_{{CO}_2}$ is the indirect emission of CO₂ and ${EF}_{{j,CO}_2}$ is the CO₂ emission factor of the energy source. The CO₂ emission factors of the main energy sources in this paper refer to the “China Product Full Life Cycle Greenhouse Gas Emission Coefficient Library” [64,65]. The CO₂ emission factors of major energy sources are shown in

Table 7. CO₂ emission coefficient.

Item	Value	Unit
Wind photovoltaic	0.01	kgCO2/kWh
Electricity (Qinghai Province)	0.096	kgCO2/kWh
Electricity (Sichuan Province)	0.123	kgCO2/kWh
Fresh water	5.75	kgCO2/ton
Recycling water	0.82	kgCO2/ton
Fuel H2	10,063	kgCO2/ton
Diesel	3797	kgCO2/ton

.

When renewable energy cannot meet the electricity demand for hydrogen production, the surplus electricity will be supplemented through the Qinghai provincial power grid [66]. The more grid-connected electricity is consumed, the more indirect carbon emissions per unit of green hydrogen are generated, with an overall linear upward trend. As shown in Figure 8, Routes 1 and 2 require additional electricity for hydrogen liquefaction in addition to water electrolysis, and indirect CO₂ emissions from liquefaction exceed those from H₂ production without the use of grid-connected electricity. Indirect CO₂ emissions from the hydrogen fuel required to obtain the transporter are small, but in Route 3, this share increases considerably. Thus, comparing the two modes of transport, LH₂ and GH₂, the indirect CO₂ emissions from LH₂ transport come mainly from the electricity used in the liquefiers, while the CO₂ emissions from GH₂ transport come from the acquisition of hydrogen fuel. Indirect CO₂ emissions from the H₂ production stage rise sharply when access to the transmission grid is required for power supplementation, reaching up to 75% of the total CO₂ emissions, with the detailed share shown in

Table 8. Indirect CO₂ emissions and their proportion in each stage when the utilization rate of grid-connected electricity is 100%.

The Main Energy-Consuming Phase	Line 1		Line 2		Line 3
	The Amount and Proportion of CO2 Emissions	Proportion of Energy	The Amount and Proportion of CO2 Emissions	Proportion of Energy	The Amount and Proportion of CO2 Emissions	Proportion of Energy
H2 production	5.684 (78.6%)	Electric 73.1%	5.684 (70.5%)	Electric 65.6%	5.684 (61.3%)	Electric 57%
		Water 5.5%		Water 4.9%		Water 4.3%
H2 transportation	1.36 (18.8%)	Electric 13.6%	1.703 (21.1%)	Electric 17.4%	3.406 (36.7%)	Electric 7%
		H2 5.2%		H2 3.7%		H2 29.7%
H2 refueling station	0.188 (2.6%)	Electric 2.6%	0.675 (8.4%)	Electric 8.4%	0.188 (2%)	Electric 2%
Total CO2 emissions	7.232		8.062		9.278

.

The electrolytic water hydrogen production technology, which is common to the three routes, emits 0.946 kgCO₂/kgH₂ and 5.684 kgCO₂/kgH₂ of CO₂ per unit of H₂ obtained in the two scenarios of no grid-connected electricity used and all grid-connected electricity used, which is a reduction in carbon emissions per unit of H₂ produced from conventional natural gas hydrogen production of 10.063 kgCO₂/kgH₂, respectively, by 90.6% and 43.5%.

The hydrogen trucks chosen for the three routes will also have reduced CO₂ emissions compared to conventional diesel trucks. Taking Route 1, which is the most environmentally friendly, as an example, the amount of CO₂ emitted per unit of H₂ delivered is 2.98 kgCO₂/kgH₂ and 7.72 kgCO₂/kgH₂ for the two scenarios of no grid-connected electricity used and all grid-connected electricity used, respectively. However, if the hydrogen trucks in Route 1 are replaced with diesel trucks, the amount of CO₂ emitted per unit of H₂ delivered is raised to 3.09 kgCO₂/kgH₂ and 7.82 kgCO₂/kgH₂ in both scenarios, resulting in 1022 metric tons of additional CO₂ emissions each year.

6. Conclusions

To realize the large-scale production and application of green hydrogen, this paper proposes a low-cost and low-emission liquid-gas cascade hydrogen energy transportation scheme to solve the long-distance transportation problem faced by green hydrogen. This paper selects the hydrogen energy demand of Chengdu, Sichuan Province, as the realistic background and designs a complete green hydrogen supply scheme from hydrogen production to application. The technological process and main equipment involved in the scheme are introduced in detail, and the economic analysis and environmental benefit analysis are carried out. The results demonstrate the advantages (lower cost and greenhouse gas emissions) of the liquid-gas cascade green hydrogen transport scheme over the traditional transport scheme.

A detailed economic analysis of the scheme is carried out and compared with the traditional transport scheme. The results show that the liquid-gas cascade hydrogen energy transport scheme has obvious advantages in the cost of hydrogen supply, which is only 51.5825 CNY/kgH₂. In addition, because long- and short-distance transportation is divided, each enterprise can flexibly choose the investment part according to its field of involvement. Enterprises investing in the long-distance transportation stage need large initial capital and a high total return, and the investment cost can be fully recovered in 13.61 years. The start-up capital and expected revenue of investing in the short-distance transportation stage depend on the number of lines invested, with an average payback period of 7.02 years.

In terms of environmental analysis, this scheme does not produce direct carbon dioxide emissions in the whole process, so indirect carbon emissions are calculated and the relationship between grid-connected electricity consumption and emissions is studied. The results show that the scheme only generates 2.98 kg of indirect carbon emissions per unit of hydrogen delivered without grid-connected electricity and only 7.72 kgCO₂/kgH₂ when grid electricity is fully used, which is better than the traditional transportation scheme. In summary, the newly proposed liquid-gas cascade hydrogen energy delivery scheme has economic and emission reduction advantages and is expected to become the main mode of green hydrogen delivery in China in the future.