University of Groningen The developing role of gas in decarbonizing China's energy system Zhang, Jinrui

The developing role of gas in decarbonizing China's energy system

Zhang, Jinrui

DOI:

10.33612/diss.162017806

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Publication date: 2021

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Zhang, J. (2021). The developing role of gas in decarbonizing China's energy system: system analysis of technical, economic and environmental improvements of LNG and low carbon gas supply chains and infrastructure. University of Groningen. https://doi.org/10.33612/diss.162017806

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As highlighted by IEA World Energy Outlook [1], global natural gas demand is expected to grow across a broad range of sectors over the next two decades. Half of this growth is concentrated in developing Asia. As presented in Figure 1, China is becoming a key natural gas market with a projected demand increase of 14.8 EJ during 2018 – 2040 [1], which is more than the growth in the rest of developing Asia combined. As the domestic natural gas production cannot meet consumption, China relies heavily on natural gas import since 2007 [2]. The LNG imports in China have surged in recent years, surpassing pipeline gas imports in 2017 [3].

Figure 1 Change in natural gas supply in the Stated Policies Scenario during 2018 –2040. Source: IEA World Energy Outlook [1]

Since natural gas consumption in China is expected to increase, new infrastructure is being planned or under construction to deliver natural gas from domestic and international gas fields to end-users [4]. The NG infrastructure can play an important role in the energy transition to a low emission future as well-established gas grids can deliver twice as much energy as electricity grids today, are a major source of flexibility, and have the potential to distribute low-carbon gas produced from renewable sources [1].

The gas system in China is essential for an energy transition towards a low-carbon future. The optimization of gas supply chains and gas infrastructure deployment is

-2 0 2 4 6 8 10 12 14 16 Cha ng e in g as suppl y and de m and dur ing 2 01 8-2040 ( EJ ) LNG Pipeline Domestic Other Industry Power Demand Supply

China India Southeast

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crucial for energy-saving, cost-saving, and GHG emissions mitigation. In the short term, natural gas can act as a transition fuel by replacing oil and coal in especially power and transport sectors. In the long term, gradually replacing natural gas with low-carbon gas can secure the role of the gas infrastructure in a low carbon energy system. In particular, the following knowledge gaps should be addressed in this thesis:

1. A quantitative performance overview of LNG technology is missing in the literature and the small-scale LNG processes are not well optimized compared to large-scale processes on energy efficiency and costs.

2. Few studies focus on life cycle GHG emissions, costs, and potential improvement options of LNG supply chain for various end-users.

3. The future deployment of the NG infrastructure in China is still uncertain and the potential role of the NG infrastructure to supply low-carbon gases has not been well investigated.

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As China is undergoing an energy transition from a coal dominated energy system to a low-carbon energy system, the main objective of this thesis is to investigate how gaseous energy carriers and the NG infrastructure can be used in the most efficient way for a low-carbon energy system in China towards 2050. In this thesis, the potential role of LNG in the short term and low-carbon gases in the long term for a low-carbon energy system with infrastructure deployment pathway in China are investigated by assessing the energy efficiency, GHG emissions, and costs of the supply chains.

Three research questions are formulated to meet the objective of the thesis:

1. What are energy-efficient and cost-effective configurations for natural gas liquefaction and low-carbon gas production when incorporating state-of-the-art improvement options?

2. How to supply and use gaseous energy carriers in a cost-effective way to reduce GHG emissions by assessing different markets and mitigation options on a life-cycle basis?

3. What are optimal deployment pathways of the gas system towards a low carbon future of China and what is the role of the NG infrastructure in these pathways considering low GHG emissions scenarios, availability/potential of low-carbon gas, and balance of regional supply and demand during 2020 – 2050?

The topic of each chapter in this thesis and the related research questions are summarized in Table 1.

Table 1 The topics of thesis chapters and corresponding research questions

Chapter Topic Research question_{1 2 3}

2 Quantitative harmonization of the technical and economic _{performance of natural gas liquefaction processes} X 3 Technical and economic optimization of expander-based small-_{scale natural gas liquefaction processes} X X 4 Techno-economic and life cycle GHG emissions assessment of _{LNG supply chain} X X 5 Potential role of natural gas infrastructure in China to supply low-_{carbon gases during 2020 – 2050} X X X

3. s

Chapter 2 provided a quantitative technical and economic overview of the status

of natural gas liquefaction processes. To compare improvements made for each LNG process, the processes reviewed are classified into three categories: onshore large-scale, onshore small-scale, and offshore. The technical and economic data of these processes are based on industrial practices in technical reports and optimization results in academic literature. The collected data are harmonized to primary energy input and production cost as indicators for techno-economic performance.

The findings show that improvements differ between LNG processes. The integration of the LNG process with NGL process, N₂ removal process, or power plant applies only to large-scale processes (CPOC, MFC, C3MR, and DMR). The configuration adjustment, including utilization of two-phase expander, improvements on operating control system, pressurized LNG concept, and the open loop concept, appears only in small-scale processes (SMR and EXP).

Objective functions are the core of the optimization of LNG processes. The optimization objective in most studies is the minimization of power consumption. However, using minimization of power consumption as the only objective was found to possibly lead to non-optimal results from the techno-economic perspective according

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to several studies [5][6][7][8]. The selection of optimization objectives should be according to the specific situation of each LNG plant. Besides minimization of power consumption, maximization of exergy efficiency and minimization of production cost could be promising optimization strategies for large-scale plants, while minimization of capital costs and simplicity related objectives are important for small-scale plants, and safety-related objective and space-related objective are key for offshore plants.

The harmonized technical performance of LNG processes shows that large-scale processes (CPOC, MFC, C3MR, and DMR) have lower primary energy input than small-scale processes (SMR, SE, and OE). However, literature data show that the primary energy input for an identical process with similar capacity has a wide range and does not necessarily decrease with increasing capacity. Potential reasons could be that the key simulation parameters are different and show low correlation with scale. In addition, it highlights the need for future researches focusing on the relationship between efficiency and scale for major equipment of the LNG plant.

The harmonized economic performance of LNG processes shows a large variation of specific capital costs for large-scale plants based on limited available data. This variation could be explained by the complexity of the facility and local circumstances: a repetition train or a complete plant, need for gas pretreatment, need for infrastructure, and the difference in environmental regulation, safety standard, and labor costs. The capital costs and feed natural-gas costs are found as two major contributors that affect the total production cost. It is also indicated that only a few studies are focusing on economic analysis for the LNG process.

Chapter 3 focuses on improving the technical and economic performance of

expander-based natural gas liquefaction processes for small-scale applications. Three improvement strategies were investigated: 1) use of mixed refrigerant; 2) use of two-phase expander; and 3) adding a precooling cycle. Applying these strategies resulted in four expander-based processes, namely conventional single nitrogen expansion process without (SN) and with ammonia absorption precooling (SNA), and single methane expansion process without (SM) and with ammonia absorption precooling (SMA). The processes were simulated and optimized in Aspen Plus. The optimization of the proposed expander-based processes was done by two objective functions: minimizing specific energy consumption and minimizing production cost.

The results show that the ammonia absorption precooling cycle reduces not only the specific energy consumption by 26 – 35%, but also the production cost by 13 – 17%. It highlights that adding an ammonia absorption precooling cycle is a promising improvement for the small-scale expander-based process. The precooling results in a smaller difference in temperature between the cold and hot composite curves with lower energy consumption. In addition, the waste heat from the gas turbine exhaust can provide all the required heat for the ammonia precooling cycle.

The comparison between optimization of minization of energy consumption and production costs indicates the trade-off between specific energy consumption and capital costs. Although minimization of production cost (OJB2) results in specific energy consumption being 0.7 – 3.1% higher compared to that of minimization of specific energy consumption (OJB1), it decreases the capital cost by 3.0 – 5.7%. This is mainly caused by cost reduction in the compressor. The increase of the intermediate compressor outlet pressure in OBJ2 compared to that of OBJ1 reduces the volumetric flowrate in the successive compressor, thereby reducing its cost. The results indicate that the commonly used energy-related objective function may not lead to the best economic performance.

The overall results show that the methane expansion processes (SM and SMA) have a better techno-economic performance for small-scale LNG plants compared to that of nitrogen expansion processes (SN and SNA). The methane expansion processes have 17 – 28% lower specific energy consumption and 21 – 32% lower production cost compared to those of the nitrogen expansion processes under two optimization objectives. This is mainly caused by the utilization of a two-phase expander. The two-phase expander can recover the pressure exergy within the feed natural gas in the SM and SMA, which is wasted at a valve in SN and SNA.

Chapter 4 assessed the techno-economic performance and life cycle greenhouse

gas (GHG) emissions for various LNG supply chains in China in order to find the most efficient way to supply and use LNG. It improves current insights by adding supply chain optimization options (cold energy recovery and hydrogen production) and by analyzing the entire supply chain of four different LNG end-users (power generation, industrial heating, residential heating, and truck usage). This resulted in 33 LNG pathways for which the energy efficiency, life cycle GHG emissions, and life cycle costs were determined by

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process-based material and energy flow analysis, life cycle assessment, and production cost calculation, respectively. Finally, the LNG and hydrogen supply chains were compared with a reference chain (coal or diesel) to determine avoided GHG emissions and GHG avoidance costs.

The results showed the GHG mitigation potential of the cold energy recovery options for carbon capture. Applying full cryogenic carbon capture (FCCC) in power generation or industrial heaing reduces GHG emissions by 56% with, but increased production costs by 17%. Converting LNG to H₂ with FCCC reduces GHG emission by 39 – 49% with a 194 – 425% increase in production costs compared to the NG pathway in power generation and industrial heating. This demonstrates that the NG with the FCCC pathway has better GHG emission and cost performances than H₂ with FCCC in the current situation. However, using the cold energy of LNG to produce electricity or provide cooling does not significantly affect GHG emissions and costs from a life cycle perspective. The cold energy recovery options used for power generation and direct cold usage slightly reduce GHG emissions by 0.9 – 1.2% and production costs by 0.2 – 0.8% compared to the NG pathway for all four end-users.

The findings also highlighted that the NG with FCCC for power generation is the best pathway among the four end-users. The H₂ pathways have the highest avoided GHG emission in residential heating and truck usage but also the highest GHG avoidance costs. The supply chain for the LNG truck is more environmentally-friendly and economic than that of the CNG truck. LNG trucks have lower GHG emissions by 7.2 – 8.4% and lower production costs by 17 – 19% compared to CNG trucks.

Chapter 5 analyzed the potential role of NG infrastructure to supply low-carbon

gases in China during 2020-2050 at a provincial resolution for different scenarios. In total, four low-carbon gases were considered: biomethane, bio-synthetic methane (bio-SNG), hydrogen, and low-carbon synthetic methane (low-carbon SNG). The research approach begins by harmonizing the data from scenario studies for NG demand and supply, biomass potential, and solar and wind capacity at the provincial level. Then, low-carbon gas supply chains were established based on a process-based model, allowing comparison of the GHG emissions and cost of utilizing the NG infrastructure to supply low-carbon gases using scenario analysis. Six scenarios are proposed to replace pipeline NG import (scenario 1, 3, and 5) or LNG import (scenario 2, 4, and 6): in scenario 1 and

2, all the hydrogen produced from solar and wind is converted to low-carbon SNG; in scenario 3 and 4, hydrogen is blended into the NG infrastructure up to 5%, while the rest of the hydrogen is converted to low-carbon SNG; in scenario 5 and 6, the hydrogen produced from solar and wind is supplied by a dedicated newly built hydrogen pipeline.

Results indicate that the biomethane supply chain has the highest GHG emissions and lowest production cost; the hydrogen and low-carbon SNG supply chains have the lowest GHG emissions and highest production cost. It is estimated that the total potential of low-carbon gas production increases from 1.21 EJ in 2020 to 5.25 EJ in 2050 with hydrogen and/or Low-carbon SNG being the fastest-growing type of low-carbon gases. Domestic low-carbon gas production can replace 20 – 67% of the gas imports required for China, thereby increasing the gas supply independence of China.

Results also highlight the spatial contribution to low-carbon gas production. In 2020, Ningxia is the only province with a relatively high proportion of low-carbon SNG and hydrogen, which is around 12%. Yunnan is the only province that exceeds 100 PJ of low-carbon gas production. In 2030, the low-carbon gas production of Inner Mongolia and Yunnan province exceeds 200 PJ and 300 PJ, respectively. In 2040, the gas demand of three south-west provinces (Yunnan, Guangxi, and Guizhou) can be met by low-carbon gases. In 2050, low-carbon gases consumption dominates in 10 provinces, because of the increase of low-carbon gases production and the decrease of gas demand. Yunnan is the only province where the gas demand can be met by domestic produced low-carbon gases in 2020-2050 and the gas demand can be met by pure hydrogen in 2040 and 2050. The results of the infrastructure with spatial distribution show that the existing NG infrastructure in 2020 is sufficient to meet the gas demand in 2020 for all scenarios. However, the expansion of the NG infrastructure is needed between 2030 to 2050. The expanded capacity of NG infrastructure of the base case and scenario 1 to scenario 6 are 31%, 19%, 41%, 20%, 48%, 18%, and 41% compared to 2020 level, respectively. High attention should be paid to the deployment of NG infrastructure during 2030-2050 because the expansion needed can be very different from scenario to scenario.

Scenario analysis indicates that scenario 5 (replacing pipeline NG import by H₂) has the highest cumulative avoided GHG emissions of 8,338 Mt and scenario 6 (replacing LNG import by H₂) has the lowest cumulative GHG emissions avoidance cost of 1,090 B$.

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In addition to the benefit of high avoided GHG emissions, scenario 5 also reduced the NG infrastructure expansion by 56% compared to scenario 6.

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Question 1: What are energy-efficient and cost-effective configurations for natural gas liquefaction and low-carbon gas production when incorporating state-of-the-art improvement options?

Question 1 aims to identify potential improvements in the gas energy system from an engineering perspective, where the capacity related energy consumption, capital costs, and production costs of the natural gas liquefaction and low-carbon gas production processes are the main focus. The comparison of the techno-economic performance and improvements of these processes are shown in Table 2.

Table 2 Technical and economic performance of natural gas liquefaction and low-carbon gas production processes with potential improvement options

Gas

type Process Energy consumption (efficiency) Production costs Improvement

Natural gas

Large-scale

liquefaction 0.031 – 0.102 GJ/GJ 2.20 – 8.11 $/GJ* Process integration Small-scale

liquefaction 0.049 – 0.362 GJ/GJ 2.20 – 8.11 $/GJ* Configuration adjustment Improved

small-scale liquefaction 0.059 – 0.060 GJ/GJ 3.35 – 5.91 $/GJ*

Use of mixed refrigerant, use of two-phase expander, and adding a

precooling cycle

Low-carbon

gas

Biomethane (29%) 13.2 $/GJ management and Advanced waste upgrading technology Bio-synthetic

methane (53%) 23.1 – 26.0 $/GJ Scaling-up of gasification Low-carbon

hydrogen (74%) 29.8 $/GJ Advanced electrolysis

Low-carbon

synthetic methane (59%) 44.2 – 59.3 $/GJ

Integration with biomass process and advanced air

capture

*Note: the production costs of NG liquefaction include NG feedstock costs and liquefaction costs; NG feedstock costs are in range of 1.51 – 4.01 $/GJ [9].

Natural gas liquefaction process is based on vapor compression cycle and gas expansion cycle. The harmonized techno-economic performance of liquefaction processes does not show a clear winner for natural gas liquefaction configuration, because of the large uncertainty ranges (Table 2). This wide range of the primary energy inputs, specific capital costs, and production costs appears on identical liquefaction

processes with approximately the same capacity, especially for small-scale liquefaction processes. The potential improvement options identified for large-scale are: integrating the LNG process with the NGL process, the N₂ removal process, or the power plant. For small-scale, the options are: utilization of two-phase expander, improvements on operating control system, pressurized LNG concept, and the open loop concept.

From the comparison of different improvements made for each LNG process, three promising improvement options were identified for small-scale liquefaction processes, namely use of mixed refrigerant, use of two-phase expander, and adding a precooling cycle. These improvement options were subsequently applied in four processes: conventional nitrogen expander process with and without ammonia absorption precooling (SN and SNA) and open-loop expander process (uses natural gas as the refrigerant and replaces the gas expander with a two-phase expander) with and without ammonia absorption precooling (SM and SMA). The results show that the SMA process is the best configuration among the four proposed configurations with energy consumption of 0.059 – 0.060 GJ/GJ and production costs of 1.84 – 1.90 $/GJ. The optimization also shows the trade-off between specific energy consumption and capital cost: minimization of costs increases the energy consumption by 0.7 – 3.1% but decreases the production costs by 1.7 – 2.3% compared to that of minimization of energy consumption. The optimized small-scale SMA process is expected to be suitable for the exploitation of satellite stranded gas fields, associated gas from oil fields, and coalbed methane from coal mines, which are currently vented or flared resulting in great loss of energy and damage to the environment.

Low-carbon gas production processes are investigated for biomethane, bio-synthetic methane (bio-SNG), low-carbon hydrogen, and low-carbon synthetic methane (low-carbon SNG). The state-of-the-art technology is derived from literaure studies to identify the best configurations for the four low-carbon gases production: large-scale biogas plant (daily biogas yield ≥500 Nm3_{) with six upgrading technologies;} large-scale biomass gasification plant (20-200 MW_bio-SNG) with dual fluidized bed allothermal gasifier; alkaline electrolysis and fixed-bed catalytic methanation for electrolysis and methanation. The energy conversion efficiency and production costs of these four low-carbon gases are shown in Table 2. At present, the production costs of low-carbon gas are much higher than the production costs for LNG. However, the production costs of low-carbon gas have potential cost reductions from up-scaling and

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applying advanced technology, including PEM and solid oxide electrolysis [10]. By 2050, the production costs of low-carbon SNG could be reduced to 7.27 $/GJ in large-scale plants (≥ 50 MW) [11], which could be competitive compared to the production costs for LNG. The benefits of the low-carbon gas production extend beyond energy production. Biomass utilization helps with waste treatment and the digestate can be used as an organic fertilizer. Power-to-Gas helps to solve the issues of surplus wind and solar electricity and increases the independence of the energy supply.

Question 2: How to supply and use gaseous energy carriers in a cost-effective way to reduce GHG emissions by assessing different markets and mitigation options on a life-cycle basis?

Question 2 focuses on the GHG mitigation potential of the gas energy system from a supply chain perspective, where the improved supply chain of gaseous energy carriers is compared to the reference chain to determine GHG mitigation potentials and costs. The comparison of the GHG mitigation potential and costs of these supply chains are shown in Table 3.

Table 3 GHG mitigation potential and costs of LNG supply chains and low-carbon gas supply chains compared to current LNG supply chain

Supply chain End-user mitigation GHG

potential Change in costs LNG supply chain: cold energy recovery cryogenic carbon

capture Power generation and industrial heating 56% 11 – 17% cold applications Residential heating_{Truck usage} 1%_{7% -17%}-1% LNG supply chain: hydrogen

production

Power generation and

industrial heating 39 – 49% 194 – 425% Residential heating 38% 148% Truck usage 61% 98% Low-carbon gas supply chain* Biomethane - 63% -12% Bio-synthetic methane - 67% 51 – 68% Low-carbon hydrogen - 98% 110% Low-carbon synthetic methane - 98% 184 – 279%

*Note: the low-carbon gas supply chain does not include changes in end-users.

For power generation and industrial heating, the LNG supply chains with cryogenic carbon capture are the most cost-effective supply chains to reduce GHG emissions compared to the LNG supply chain for hydrogen production. This is because hydrogen supply chains need one more conversion step from NG to hydrogen. In addition, hydrogen supply chains have the same or slightly higher power generation and

industrial heating efficiency compared to LNG supply chains with cryogenic carbon capture. Notably, as hydrogen supply chains are relatively novel, the cost is significantly high in the short term. Given its cost-effectiveness, the LNG supply chain with cryogenic carbon capture can play an important transitional role in GHG emissions mitigation for power generation and industrial heating.

For residential heating and truck usage, the LNG supply chains for hydrogen production are the most cost-effective supply chain to reduce GHG emissions compared to LNG supply chain with cold applications. The LNG supply chain with cold applications in residential heating and truck usage slightly reduces GHG emissions and production costs compared to the current supply chain, indicating that recovering the cold energy of LNG for energy-saving purposes does not significantly affect GHG emissions and costs in a life cycle perspective. It highlights that fossil-based hydrogen could help to reduce GHG emissions in a cost effectively way in the hard-to-abate sector, where carbon capture is not applicable.

The four low-carbon gas supply chains, which include gas production, upgrading/ methanation, and transportation (combustion in end-user is carbon neutral), are assessed for energy efficiency, GHG emissions and costs. As the feedstock for the biomethane supply chain is animal manure and for the bio-SNG supply chain is crop residue, forest residue, and energy crops, these two supply chains do not compete for the same feedstock. Compared to the current LNG supply chain, the biomethane supply chain reduces GHG emissions by 63% and reduces costs by 12%, and the bio-SNG supply chain reduces GHG emissions by 67%, but increase costs by 51 – 68%. It highlights that the utilization of biomass to produce low-carbon gas can reduce significantly the amount of GHG emissions with low to negative costs. Compared to the current LNG supply chain, the hydrogen supply chain reduces GHG emissions by 98% with a 110% cost increase, while the low-carbon SNG supply chain reduces GHG emissions by 98% with a 184 – 279% costs increase. As the existing NG pipelines have a low blending limit for hydrogen, the hydrogen needs to be transported in dedicated pipeline. As a result the Even though the transportation cost of hydrogen is four times higher than that of low-carbon SNG. Still, the costs of the hydrogen supply chain are only 55 – 74% of the costs of the low-carbon SNG supply chain. This indicates that hydrogen is a more cost-effective way to reduce GHG emissions compared to low-carbon SNG when utilizing the excess electricity from wind and solar generation. To deliver deep emissions reduction, the gas system needs to

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be gradually repurposed or retooled overtime to produce and supply low-carbon gases.

Question 3: What are optimal deployment pathways of the gas system towards a low carbon future of China and what is the role of the NG infrastructure in these pathways considering low GHG emissions scenarios, availability/potential of low-carbon gas, and balance of regional supply and demand during 2020 – 2050?

Question 3 aims at finding optimal deployment pathways from an energy system perspective considering the gas demand and supply, renewables potential, low-carbon gas supply chains, and utilization of the gas infrastructure at the provincial level in China.

According to CERO below 2 scenario [12] and “Oil and gas pipeline network development plan in mid-term and long-term” [13], the gas demand in China will peak around 2035 and the natural gas pipeline network will develop in high increase speed (9.8% annually) to a comparatively perfect network in 2030. There is an urgent need for optimal deployment pathways of the gas system towards a low carbon future of China. In the short term, it is essential to build new infrastructures in an economically and environmentally-friendly way to supply the increasing LNG imports in China. In the long term, the potential role of NG infrastructure to supply low-carbon gases during 2020-2050 for China on a provincial resolution was analyzed with scenario analysis.

The results of Chapter 5 show that the existing NG infrastructure in 2020 is sufficient to meet the gas demand in 2020 for all scenarios. Expansion of the NG infrastructure is needed from 2030 to 2050. There are trade-offs between scenarios on avoided GHG emissions, GHG avoidance cost, and NG infrastructure expansion. As China’s gas demand is mostly concentrated in the eastern coastal provinces, scenarios replacing pipeline import gas (mostly from the west) with domestically produced low-carbon gases will shorten the gas transmission distance and consequently reduce the necessary NG infrastructure. Conversely, scenarios replacing imported LNG with low-carbon gases will increase the need for infrastructure. Therefore, replacing pipeline imported gas will result in relatively high avoided GHG emissions (due to relatively high GHG emissions of pipeline imported NG compared to imported LNG) and high avoidance costs (due to relatively high cost of pipeline imported NG compared to imported LNG), while replacing imported LNG will result in comparably low avoided GHG emissions with low avoidance costs. The scenario, which converts excess renewable electricity to hydrogen

and replace pipeline gas imports, is identified as the best scenario because it results in the highest avoided GHG emissions and lowest NG infrastructure expansion with relatively low avoidance costs among the anlayzed scenarios. The detailed results of this scenario are discussed next.

The LNG imported to China is projected to increase from 3.6 EJ (2020) to 5.0 EJ (2030) and 6.2 EJ (2040), and eventually dropping to 2.2 EJ (2050). As discussed in Question 2, LNG with cryogenic carbon capture for power generation is the best supply chain for LNG. The GHG emissions reduction potential of this improved LNG supply chain in China during 2020 – 2050 is shown in Figure 2. By applying this supply chain, the GHG emissions reduction potentials are 143 Mt CO₂-e (2020), 198 Mt CO₂-e (2030), 248 Mt CO₂-e (2040), and 88 Mt CO₂-e (2050). The GHG avoidance costs are in a wide range of 47 – 150 $/t CO₂-e, which are affected by LNG import price, upstream GHG emissions, scale of power plant, and technology development.

For the low-carbon gas supply, it is estimated that the total potential of low-carbon gas production increases from 1.21 EJ in 2020 to 5.25 EJ in 2050. In 2020, low-carbon gas production is composed of biomethane (30%), bio-SNG (68%) and low-carbon SNG or hydrogen (2%). These ratios could change to 17%, 39%, and 44%, respectively, by 2050. The domestic low-carbon gas production cannot replace all the gas imports needed for China. Still, it narrows the gap by 20 – 67% between domestic supply and demand, and increases the gas supply independence of China. At the provincial level, Yunnan and Inner Mongolia contributed approximately 17% of China’s total low-carbon gas production during 2020 – 2050. The provinces of Yunnan, Guangxi, Guizhou, Hunan, Inner Mongolia, and Jilin have the potential to self-sufficient on gas demand with the low-carbon gas supply.

Supplying low-carbon gases in the natural gas infrastructure in China significantly reduce the GHG emissions and NG import not only in short term but also in long term. The GHG mitigation potentials are 78 Mt CO₂-e (2020), 230 Mt CO₂-e (2030), 344 Mt CO₂-e (2040), and 393 Mt CO₂-e (2050) (Figure 2). The GHG avoidance costs are in a wide range of 105 – 196 $/t CO₂-e, which are affected by natural gas import price, upstream GHG emissions of natural gas, the scale of low-carbon gas production, and development of low-carbon technology. To cost effectively reduce GHG emissions in gas energy system, a fast upscaling implementation and technology development of low-carbon gas

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production is essential in the long term.

Figure 2 GHG emissions reduction potential of gas energy system compared to total GHG emissions in China from 2020 to 2050 (Reference GHG emissions from CERO below 2 scenario [12])

The reference scenario (CERO below 2 scenario [12]) used in this study is consistent with China’s carbon neutrality goal before 2060, as the national GHG emissions are within the range provided by Synthesis Report 2020 on China's Carbon Neutrality [14]. Our effort on improving the LNG supply chain and supplying low-carbon gas has the potential to reduce GHG emissions in gas energy system by 21% (2020), 27% (2030), 36% (2040), and 35% (2050). To achieve the carbon neutrality goal, the transition in the gas energy system analyzed in this study can provide an efficient and cost-effective pathway to reduce GHG emission, provide flexibility, and improve energy security in the long term.

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• Besides minimization of energy efficiency, it is recommended that future studies should also address the following important aspects for further improvement in LNG process optimization: the minimization of production costs, waste

energy recovery, novel configurations, and process integration. For the natural gas liquefaction process, focusing on only energy saving will not always lead to the lowest production cost because the increase in capital and maintenance costs could exceed the energy costs saving. Adding an ammonia absorption precooling cycle and a two-phase expander are promising improvements for small-scale expander-based process both for energy saving and cost saving. For the LNG regasification process, recovery of the cold energy to capture CO₂ with integration with the power plant could reduce 56% of GHG emissions with an 11 – 17% cost increase. Therefore, we should stay open-minded to apply these aspects in process optimization to achieve further improvement.

• There is a need for investigation on cost development with respect to scaling effects and technological learning for future major processes in the low-carbon gas supply chain, such as biomass gasification, electrolysis, hydrogen fuel cell, and direct air capture. Many of these processes are still in their early stages of development. Currently, the high cost and uncertainty of efficiency are major hampering factors of the development of a low-carbon gas supply chain. Hence, research is needed to determine cost reductions, efficiency improvement opportunities as well as understand the rate and speed of these improvements over time. A better understanding of this technological learning can provide a good basis for targeted policy support and implementation.

• Integrating low-carbon gas system into detailed energy models is needed to identify the role of low-carbon gas in the entire energy system. Detailed energy models should cover the final energy demand of all energy carrier, including low-carbon gas, electricity, liquid fuel, coal, and others, to better estimate the low-carbon gas potential. They also need to cover as many as flexibility options, including optimal wind and solar complementary patterns, demand-side management, short and long term storage, and PtX, to avoid overestimating the role of low-carbon gas.

• Uncertainty in renewable potential projection in China should be further addressed to accurately evaluate the future low-carbon gas potential. Chinese biomass potential estimates vary between 13 – 33 EJ/year. The biomass potential, especially the uncertainty in energy crops potential, should be

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investigated in future studies by collecting reliable yield data for different marginal lands. The Power-to-Gas potential should be further investigated as there are large variations (from 11 to 43 EJ/year) in the projection of solar and wind capacity in 2050 by different low-carbon energy scenarios. In addition, detailed solar and wind capacity estimated at province level or even city level is necessary for local governments to build an adequate Power-to-Gas supply chain and thus warrant further study.

• A finer spatial resolution of gas infrastructure and renewable source availability would help to identify potential sites with low-carbon gas injection and the retrofitting opportunity of pipelines. It develops a better understanding of the demand and supply of low-carbon gas and the need for infrastructure at both transmission and distribution levels. Costs of retrofitting of the existing gas infrastructure to transport hydrogen would be much lower than building new dedicated hydrogen pipelines. The retrofitting opportunity of existing gas infrastructure for adopting hydrogen at high concentrations should be investigated further for different blend levels and time periods. To enable successful retrofitting of the gas infrastructure, more tests are needed to get a better understanding of the influence of hydrogen at high concentrations on transmission pipelines, distribution pipelines, compressors, valves, gas storage facilities, and end-users.

• Future work should consider the possibility of importing low-carbon gas. By international collaboration, the geographical and resource advantages of neighboring countries could be used to reduce the cost of low-carbon gas production. It does not necessarily compromise the energy security of China, since the imported amounts would probably remain small compared to the oil and gas import for China today and exporters would be more diverse. Such global trading would be beneficial for the commercial scale-up of low-carbon gas production and optimal resource allocation, therefore ensure an efficient low-carbon gas market and achieve cost reductions.

• Large-scale demonstration projects are needed for techno-economic evaluation of the whole low-carbon gas supply chain. It is helpful to identify the cost reduction opportunities for scaling effects and technological learning.

Further insights into operational challenges and uncertainties of the low-carbon gas technology can be obtained for the development of low-carbon gas supply chains. Due to the vast investment needed and large uncertainty existed, policies are needed for supporting low-carbon gas market development, including direct subsidy, taxing natural gas, and setting a minimum low-carbon gas share in the gas system.

• Central coordination and planning by the government are essential to realizing the cost-effective deployment of gas infrastructure to supply low-carbon gas at the local and national levels over time. As the gas demand in China will probably peak in around 2035, the central plan for the gas infrastructure deployment during 2020 – 2035 should consider the risks of under-utilization in the long-term. The different strategies for replacing imported natural gas with low-carbon gases will influence the expansion of gas infrastructure, avoided GHG emissions, and GHG avoidance costs. For example, replacing pipeline import gas will result in relatively high avoided GHG emissions with high avoidance cost (due to relatively high GHG emissions and low costs of pipeline imported gas compared to imported LNG). Due to the dynamic and uncertainty in low-carbon gas market development, vast investment in gas infrastructure could be wasted without optimal central coordination and planning. The results in Chapter 5 can be employed by the government to identify drivers and barriers for low-carbon gas supply chain development. Hence, the detailed strategies for natural gas replacement and natural gas infrastructure deployment should be investigated thoroughly to provide policy supports for low-carbon gas market development.

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