University of Groningen

Techno-economic and life cycle greenhouse gas emissions assessment of liquefied naturalgas supply chain in ChinaZhang, Jinrui; Meerman, Hans; Benders, René; Faaij, André

Published in:Energy

DOI:10.1016/j.energy.2021.120049

IMPORTANT NOTE: You are advised to consult the publisher's version (publisher's PDF) if you wish to cite fromit. Please check the document version below.

Document VersionPublisher's PDF, also known as Version of record

Publication date:2021

Link to publication in University of Groningen/UMCG research database

Citation for published version (APA):Zhang, J., Meerman, H., Benders, R., & Faaij, A. (2021). Techno-economic and life cycle greenhouse gasemissions assessment of liquefied natural gas supply chain in China. Energy, 224, [120049].https://doi.org/10.1016/j.energy.2021.120049

CopyrightOther than for strictly personal use, it is not permitted to download or to forward/distribute the text or part of it without the consent of theauthor(s) and/or copyright holder(s), unless the work is under an open content license (like Creative Commons).

The publication may also be distributed here under the terms of Article 25fa of the Dutch Copyright Act, indicated by the “Taverne” license.More information can be found on the University of Groningen website: https://www.rug.nl/library/open-access/self-archiving-pure/taverne-amendment.

Take-down policyIf you believe that this document breaches copyright please contact us providing details, and we will remove access to the work immediatelyand investigate your claim.

Downloaded from the University of Groningen/UMCG research database (Pure): http://www.rug.nl/research/portal. For technical reasons thenumber of authors shown on this cover page is limited to 10 maximum.

lable at ScienceDirect

Energy 224 (2021) 120049

Contents lists avai

Energy

journal homepage: www.elsevier .com/locate/energy

Techno-economic and life cycle greenhouse gas emissions assessmentof liquefied natural gas supply chain in China

Jinrui Zhang*, Hans Meerman, Ren�e Benders, Andr�e FaaijIntegrated Research on Energy, Environment and Society, Energy and Sustainable Research Institute Groningen, University of Groningen, Nijenborgh 6, 9747,AG, Groningen, the Netherlands

a r t i c l e i n f o

Article history:Received 11 July 2020Received in revised form8 January 2021Accepted 1 February 2021Available online 9 February 2021

Keywords:Liquefied natural gasTechno-economic assessmentLife cycle greenhouse gas emissionCold recoveryBlue hydrogen

* Corresponding author.E-mail address: jinrui.zhang@rug.nl (J. Zhang).

https://doi.org/10.1016/j.energy.2021.1200490360-5442/© 2021 The Author(s). Published by Elsev

a b s t r a c t

This study assessed the techno-economic performance and life cycle greenhouse gas (GHG) emissions forvarious liquefied natural gas (LNG) supply chains in China in order to find the most efficient way tosupply and use LNG. This study improves current literature by adding supply chain optimization options(cold energy recovery and hydrogen production) and by analyzing the entire supply chain of fourdifferent LNG end-users (power generation, industrial heating, residential heating, and truck usage). Thisresulted in 33 LNG pathways for which the energy efficiency, life cycle GHG emissions, and life cycle costswere determined by process-based material and energy flow analysis, life cycle assessment, and pro-duction cost calculation, respectively. The LNG and hydrogen supply chains were compared with areference chain (coal or diesel) to determine avoided GHG emissions and GHG avoidance costs. Resultsshow that NG with full cryogenic carbon dioxide capture (FCCC) is most beneficial pathway for bothavoided GHG emissions and GHG avoidance costs (70.5e112.4 g CO2-e/MJLNG and 66.0e95.9 $/t CO2-e).The best case was obtained when NG with FCCC replaces coal-fired power plants. Results also indicatethat hydrogen pathways requires maturation of new technology options and significant capital costreductions to become attractive.© 2021 The Author(s). Published by Elsevier Ltd. This is an open access article under the CC BY license

(http://creativecommons.org/licenses/by/4.0/).

1. Introduction

China consumes 22.3% of the total world primary energy con-sumption [1] resulting in 9.3 billion tonnes CO2 emitted in 2017[2,3]. NG is seen as the cleanest fossil fuel with 29%e44% less CO2,79%e80% less NOx, 99.9%e99.996% less SO2, and 92%e99.7% fewerparticulates per unit of energy compared to oil and coal, respec-tively [4]. NG consumption in China reached 280.3 billion m3 in2018, while domestic NG production was only 157.5 billion m3 [5].As the domestic NG production cannot meet its consumption,China imports NG by two options: pipeline gas and liquefied nat-ural gas (LNG). Chinese LNG imports have surged in recent years,surpassing pipeline gas imports in 2017 [6]. In 2018, LNG imports inChina reached 73.0 billion m3 [5], which is 26% of China’s NGconsumption and 2.8 times that in 2015 [7]. Moreover, the importinfrastructure for LNG in China could double in 5 years from 2018[8]. In 2018, 39.42 billion cubic meters of LNG (54%) were regasifieddirectly and transported by pipeline to the end-users. The rest

ier Ltd. This is an open access artic

(33.58 billion m3) of the LNG (46%) were transported in liquid formby truck, railway, or ship [9]. The imported LNG usage by sector inChina by percentage was 18%, 45%, 22%, and 12% for power, in-dustry, building, and transportation in 2016, respectively [10].

As the demand for LNG imports in China increases rapidly, it isessential to build new infrastructures in an economically andenvironmentally-friendly way. Life cycle assessment (LCA) is arobust methodology to evaluate technology, processes, projects,and supply chains for environmental impacts [11]. Previous studiesfocusing on life cycle GHG emissions of LNG can be divided intothree general types. The first type of life cycle GHG emissionsstudies focus on parts of the LNG supply chain (mainly on the up-stream). Barnett [12] assessed GHG emissions of liquefaction,shipping and regasification including 10 LNG plants in Australia and5 shipping routes to Asia. He concluded that Australian LNG resultsin 38% less GHG emissions than other global suppliers. Safaei et al.[13] assessed well to tank GHG emissions of Nigerian LNG and theyconclude that methane emissions could increase the life cycle (LC)GHG emissions by 59%. The second type of life cycle GHG emissionsstudies focus on comparing LNG with other energy sources, such aspipeline NG, synthetic natural gas (SNG), domestic NG, coal, diesel,

le under the CC BY license (http://creativecommons.org/licenses/by/4.0/).

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

renewables etc. Jaramillo et al. [14] compared LC emissions of im-ported LNG, domestic NG, coal and SNG from coal gasification inUnited States for electricity generation. They found that importedLNG increased GHG emissions by 32% compared to domestic NG.Song et al. [15] compared LC emissions of diesel and LNG for heavy-duty vehicle for China using real time consumption data and actualvehicle population data. They found that replacing heavy dutydiesel vehicles by LNG heavy vehicles could reduce emissions by6.5e9.1 Mt CO2 in 2020. The third type of life cycle GHG emissionsstudies focus on different usage options, such as power generation,hydrogen production, and vehicle fuel. Raj et al. [16] assessed well-to-wire GHG emissions of four Canadian shale gas reserves forpower generation in China and found that the GHG emissionsreduced by 38e43% compared to China’s current coal-fired elec-tricity. Zhang et al. [11] compared LC emission from regasificationto various end-use for LNG including hydrogen production, elec-tricity generation, and vehicle fuel. They found that the GHGemissions of using LNG to produce hydrogen was 45% and 53% ofusing LNG for electricity generation and vehicle fuel, respectively.

The abovementioned studies focus on a specific life cycle stageor a single usage option. However, few studies analyze the life cycleGHG emissions of various usage options, including hydrogen pro-duction, on the whole life cycle of LNG. There is also a lack ofresearch focusing on the economic performance of the LNG supplychain, which could be as crucial as the life cycle GHG emissionsperformance of the supply chain. In addition, the opportunities forcold utilization of LNG in regasification processes are not includedin previous studies, except for one study from Tamura et al. [17].They assessed the reduction of GHG emissions by using LNG coldenergy. Results shown 3% reduction in GHG emissions when sup-pling cold energy to air separation units and cold storage ware-houses. Several studies assessed the technical performance of coldenergy recovery of LNG regasification. Khor et al. [18] assessed theexergy efficiency and GHG emissions of LNG cold energy recoveryfor cryogenic applications, including air separation, dry ice pro-duction, deep freezing, and space cooling. They found that an LNGcold energy assisted power cycle reduced GHG emissions by 18.3%,while using LNG cold energy for space cooling could reduce GHGemissions by 38%. Gomez et al. [19] proposed an innovative LNGpower plant, which capture CO2 from flue gases using the coldenergy of the LNG. Results indicated that the power plant couldreach an efficiency of 65% with almost no GHG emissions. However,the life cycle GHG emissions and economic impact of these coldutilization systems for the entire LNG supply chain are not wellinvestigated yet.

In anticipation of increased natural gas use in China in the nearfuture, it is important to assess the GHG emissions and economicperformance of different LNG supply chains to various end-usersand to identify potential improvement in these supply chainsresulting in improved environmental and economic performance.Therefore, this paper has the following objectives:

� To quantify the current LC energy efficiency, GHG emissions andcosts of Australian LNG consumed in China for four end-users:power generation, industrial heating, residential heating, andtruck usage;

� To estimate the impact on LC energy efficiency, GHG emissionsand costs by applying cold energy recovery technologies andhydrogen production and usage in the current Australia-ChinaLNG supply chain;

� To optimize Australia-China LNG supply chains to achieve thelowest GHG emission and costs.

The approach of this study is based on process-based materialand energy flow analysis, LCA methodology, and production cost

2

calculation to determine the energy efficiency, LC GHG emissions,and LC costs. This paper comprehensively assesses and comparesthe LC GHG emissions and LC costs of Australia-China LNG supplychains. The results aim to identify the potential improvement on LCGHG emissions and LC cost for various LNG end-users to accom-plish energy-saving, cost-saving, and GHG emissions reduction forChina.

2. Methodology

A process-based material and energy flow analysis method isused to calculate the energy consumption [20]. GHG emissions aredetermined based on LCA methodology following ISO 14040/44[21,22]. The production cost of each LC stage is calculated based onannualized costs and yields [23]. The technical, economic, andenvironmental data for each stage can be found in Section 3 andSupporting Information. Three different functional units areselected in this study for LNG power generation, heat generation,and truck usage: 1 MJ electricity (MJe), 1 MJ heat (MJh), and 1 MJwork (MJw), respectively. The emissions and costs are normalized toa g CO2-e/MJ and $/MJ metric. This study excludes GHG emissionsfrom the manufacturing and decommissioning of facilities. Theeconomic analysis excludes land acquisition costs. The generalparameters used in this study are shown in Table 1.

The energy efficiency h (%) per life cycle stage is calculated basedEquation (1) [32]. Energy output Eout (MJ) is the delivered LNG foreach life cycle stage. The energy input Ein (MJ) of each life cyclestage in the LNG supply chain is calculated as process fuel con-sumption PFi (MJ) plus the delivered LNG or hydrogen (Equation(2)). Variable i is the type of process fuel used in this study, whichincludes LNG (NG) and electricity [33,34].

h¼ EinEout

� 100% (1)

Ein ¼X

PFi þ Eout (2)

The life cycle GHG emissions of CO2, CH4, and N2O from theoperation of facilities are assessed for each supply chain. The GHGemissions (g CO2-e/MJe,h,w) are aggregated as CO2-e emissions usingIPCC AR5 GWP100 [26]. It includes upstream and combustionemissions of process fuel consumption, venting emissions, fugitive(methane leakage) emissions, and avoided CO2 emissions, as shownin Equation (3). The upstream emission factor EFu (g CO2-e/MJ) re-fers to upstream GHG emissions related to the imported processfuel. The combustion emission factor EFc (g CO2-e/MJ) refers to GHGemissions due to the combustion of a certain type of fuel. Ventingemission GHGv (g CO2-e/MJ) refers to the controlled release andburning of gases. Fugitive emission GHGf (g CO2-e/MJe,h,w) refers toleakage and unintended releases of gases. The cut-down CO2

emission GHGc (g CO2-e/MJe,h,w) is due to the application of coldenergy recovery of LNG to generate electricity, provide cooling dutyand capture CO2. The avoided GHG emissions GHGa (g CO2-e/MJLNG)are expressed in Equation (4), where GHGrc (g CO2-e/MJe,h,w) rep-resents the life cycle GHG emissions of the reference chain. Thisstudy uses a process-based LCA approach to estimate the GHGemissions [35].

GHG¼X

PFi � ðEFu þ EFcÞi þ GHGv þ GHGf � GHGc (3)

GHGa ¼ðGHG�GHGrcÞ � h (4)

The production cost Cp ($/MJ) is estimated for each LC stage. Theupstream LNG life cycle cost is represented by the LNG importingprice at the LNG terminal in China [36]. The downstream

Table 1General technical, economic, and environmental parameters.

Parameters Unit Value Reference

Australia LNG composition % N2:0.01, CH4:87.82, C2H6:8.30, C3H8:2.98, i-C4H10:0.40, n-C4H10:0.48 [24]LNG lower heating value MJLHV/kg 49.1 [24]H2 lower heating value MJLHV/kg 127.7 [25]CO2 GWP100 e 1 [26]CH4 GWP100 e 28 [26]N2O GWP100 e 265 [26]Emission factor for electricity in China g CO2-e/MJ 206.8 [27]Discount rate % 10 [28]Total capital requirementa %-equipment and installation cost 143 [28]LNG import priceb $/MJHHV 0.0075 [29]Electricity price for industry $/MJe 0.0364 [30]

a Total capital requirement (TCR) includes the costs of equipment, installation, engineering fees, contingencies, owner cost, and interest during construction. The values hereare within the ranges for industrial chemical process construction [23].

b The LNG import price is the Chinese LNG import price from Australia in 2018 [31].

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

production cost per LC stage is calculated based on Equation (5)[23,37]. The annualized capital cost Cac ($/year) is calculated byconsidering the discount rate r and plant life n in Equation (6). Thetotal capital requirement CTCR ($) includes cost for equipment,installation, engineering fees, contingencies, owner cost and in-terest during construction [28]. CTCR is calculated by multiplyingequipment and installation costs with the typical percentage ofother cost components. CPF and CO&M ($/year) are the annual costsof process fuel and operation and maintenance (O&M), respec-tively. PLNG ($/MJ) is the average LNG import price in China. Y (MJ/year) is the annual yield of the supply chain. The GHG avoidancecosts Ca ($/t CO2-e) are calculated in Equation (7) to show theeconomic performance of each supply chain. Cp;rc ($/MJ) is theproduction for the reference chain. All the cost data are indexed to$2018 using the Chemical Engineering Plant Cost Index (CEPCI).

Cp ¼Cac þ CPF þ CO&M

Yþ PLNG (5)

Cac ¼CTCR * ðr*ð1þ rÞnð1þ rÞn � 1

Þ (6)

Ca ¼ Cp � Cp;rcGHG� GHGrc

� 1;000;000 (7)

3. System boundary and description

3.1. Reference chain

The reference chains represent typical energy sources for powergeneration, industrial heating, residential heating, and truck usagein China, as shown in Fig. 1. LNG is considered as a potential sub-stitute for typical energy sources to reduce GHG emissions. All dataused in the calculation of the reference chain are shown in Sup-porting Information table S2.

The reference for power generation is a coal power plant. In2020, 64% of power generation is from coal and only 3% is fromnatural gas; these values predicted to be 55% and 5% by 2025 ac-cording to the policies expressed in the 13th Five-Year Plan and19th Party Congress [38]. The unit capacity of coal-fired power isfrom 50 MW to 1000 MW [39]. Therefore, a coal-fired power plantis chosen as reference chain for power generation with averageGHG emissions of 263.9 g CO2-e/MJe [40,41] and costs of 10.8 $/GJe[41,42].

The reference for industrial heating is a coal-fired industrialboiler. Coal and oil represent 80% and 15% of total energy input for

3

industrial boilers, respectively [43]. The national and local gov-ernments of China plan to eliminate coal-fired boilers with smallcapacity (steam less than 20 t/h) and retrofit large coal-fired boilersto increase their efficiency and decrease pollution [44]. Therefore, acoal-fired industrial boiler is chosen as the reference chain for in-dustrial heating with average GHG emissions of 124.3 g CO2-e/MJh[45] and costs of 5.4 $/GJh [42,43,46].

The reference for residential heating is the central coal boilerheating system. The central heating supply policy is an importantpolicy that affects people’s life in China [47]. It covers approxi-mately 70% and 5% of urban building areas in northern andsouthern China, respectively [48]. This central heating supply burnscoal by up to 85% [49]. The heating of the rest of China is mainlyprovided by air conditioners using electricity [48]. The potential ofreplacing coal-fired electricity with NG will be shown in the powergeneration section. Therefore, a central coal boiler heating system ischosen as the reference chain for residential heating with averageGHG emissions of 124.3 g CO2-e/MJh [45] and costs of 9.0 $/GJh[42,48,50,51].

The reference for truck usage is diesel trucks. Diesel represented98% of truck fuel in China in 2018 [52]. Truck road freight accountsfor approximately 80% of cargo transportation in China and willremain as such for a long time [53]. Diesel trucks are less than 10%of China’s vehicle population but they are the primary contributorof nitrogen oxide emissions (70%) and particulate matter emissions(90%) of all on-road emissions [54]. The State Council issued the AirPollution Prevention and Control Plan to control on-road emissionsand promote cleaner fuel trucks, including CNG, LNG, or electrictrucks [55]. Therefore, diesel trucks are chosen as the referencechain for truck usage with average GHG emissions of 1567 g CO2-e/km [27,56e58] and costs of 0.07 million $ for a 23 tonnage truck[56,59,60].

3.2. LNG supply chain 1: current chain

The Australia-China LNG supply chain in Fig. 2 is the current LNGsupply chain. LNG is imported from Western Australia and isreceived in the Shanghai LNG terminal. The imported LNG isdistributed in the Near Harbor area (200 km) and Far from Harborarea (1000 km). The upstream GHG emissions of the LNG supplychain, including NG production and processing (and possiblepipeline transport), liquefaction, and shipping, are 24.4 g CO2-e/MJLNG based on average value of 7 previous studies [12,17,61e65].Upstream production cost is 7.5 $/GJLNG based on the LNG importprice from Australia to China in 2018 [29].

Downstream life cycle stages include LNG regasification, trans-portation, and final use, as shown in Fig. 3. The energy consump-tion, GHG emissions, and cost of each LC stage are discussed in the

Fig. 1. Reference chains in China.

Fig. 2. Transport route of LNG or NG from Shanghai LNG terminal in China [5,66].

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

following paragraphs. All data used in calculation of downstreamare shown in Supporting Information table S3, S5, S6, S7, S9, andS11. The locations of four end-users are assumed as follows:

� Near Harbor: The power plant and industrial heating users arelocated in the harbor and the residential heating users and truckusers are located 200 km away from the harbor.

� Far from Harbor: All four end-users are located 1000 km awayfrom the harbor.

Regasification process turns the LNG into NG for pipelinetransportation, which includes LNG storage tanks and regasifica-tion systems [24,67]. Among several vaporizer types, three of themare used in China: open rack vaporizers (ORV) and submergedcombustion vaporizers (SCV) are both applied in large-scale ter-minals for normal and secondary peak shaving operations [68];Ambient air vaporizers (AAV) are used in small-scale terminals [69].Seawater and air is used in ORV and AAV as the heat source,

4

respectively. The heat source for SCV comes from the combustion ofnatural gas. The Shanghai Yangshan LNG terminal, which has 3million tonne LNG per annual (MTPA) regasification capacity [70], ischosen to represent the large-scale regasification with electricityconsumption of 0.89 MJ/GJLNG [64,67,69,71,72] and capital costs of1472.5 million $ [73]. The small-scale regasification capacity isassumed to be 0.45 MTPA with electricity consumption of 0.97 MJ/GJLNG [64,67,69,71,72] and capital costs of 258.7 million $ [73], ac-cording to the IGU small-scale LNG report [68,74].

Natural gas pipeline mainly includes transmission pipelines andcompression stations. The capacity of the natural gas pipeline isassumed according to a pipeline project of the Shanghai GasLimited Company [75] that is 1.75 billion m3 NG. The lengths ofnatural gas pipelines considered in this study are 1000 km and200 km. The energy consumption of natural gas compression sta-tion is assumed as the average natural gas consumption of an entireyear (MJ/MJNG) [76]. The natural gas consumption is 0.19 kJ/(GJNG$km) [76] and the capital costs are 27.1 k$/km [75,77,78].

Fig. 3. LNG Supply Chain 1: Current chain.

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

LNG trucks are an alternative transport method to deliver LNG inliquid form. Some remote areas with dispersed populations, iso-lated factories, and complex terrain are not economically viable forpipelines constructions [79]. For these potential end-users, LNGroad transport could have an advantage over pipelines. In China,the LNG road transport network, which is referred to as a “virtualpipeline”, covers approximately 1000 km from the Eastern Coast toWestern China [80]. The LNG truck capacity, which is 23 tonnes, iscollected from Chart LNG transport trailers [81]. However, trans-porting LNG through trucks is expensive and limited to low volume[82]. The natural gas consumption is 0.20 kJ/(GJNG$km) [27] andaverage costs per truck are 0.25 million $ [73].

The specific refueling systems for LNG and CNG are investigatedseparately in this study. The capacities of LNG and CNG refuelingstations are assumed to be the same based on several studies[73,83], in terms of total stored 520 tonnes per annual (TPA)product. LNG refueling stations are technologically mature andsettled with more than 3200 stations in China in 2016 [83,84]. AnLNG refueling station is mainly comprised of storage tanks, cryo-genic pumps, heaters, and dispensers [84]. The energy consumedby the LNG refueling stations is mainly electricity to run pumps andheaters, which is 2.10 MJ/GJLNG [83]. The capital costs for 520 TPALNG refueling station are 0.16 million $ [77,83,85]. CNG refuelingstations are connected to the local NG grid and mainly consist of

5

inlet gas treatment, a compressor, storage tanks, and dispensers.China has the largest natural gas vehicle population around theworld with more than 8400 CNG refueling stations in 2018 [86].Vehicles are filled with CNG at 200 bar [87]. The energy con-sumption of CNG refueling station is mainly electricity for com-pressors and is approximately ten times higher than the respectivevalue for LNG refueling stations, which is 19.40 MJ/GJLNG [88,89].The capital costs of 520 TPA CNG refueling station are approxi-mately 1.5 times higher than that of LNG refueling station, whichare 0.25 million $ [77,83,85].

The life cycle stage of end-users is the last life cycle stageconsidered in this study. For LNG or NG, five end-users areincluded: power plants, industrial steam systems, residential cen-tral heating systems, CNG trucks, and LNG trucks.

A natural gas combined cycle (NGCC) power plant is consideredfor power generation in this study. NGCC power plants have highefficiency ranging from 55% to 60% [90] because the waste heat isrecovered to run steam turbines [16]. The natural gas consumptionis 1.74 MJ/MJe [16,45,62,90,91]. The capacity of NGCC power plants,which represent large-scale power plants, are assumed as 300 MWelectricity (MWe) [92]. The capital costs are 229.26 million $[46,50,91].

An industrial steam system with a natural gas boiler is consid-ered for industrial heating in this study. The efficiency of the

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

industrial NG boiler is assumed as 90% to produce saturated steamat 1 MPa [45,46,93]. The capacity of the industrial steam system is29.98 MW heat (MWh) according to several studies [43,94]. Thenatural gas consumption is 1.11 MJ/MJh [43,45,49,93] and the cap-ital costs are 3.91 million $ [43,46,50]. The residential centralheating system is considered for residential heating is based on anatural gas boiler. The efficiency of the NG boiler for the centralheating system is assumed as 90%, according to previous studies[45,49]. The capacity of the central heating system is 7.59 MWh,according to the area size of 0.5 million m2 [48]. The capital costs ofresidential central heating system is much higher than industrialsteam system due to additional costs of heating stations, externalnetworks, and indoor radiators [48]. The natural gas consumptionis 1.11 MJ/MJh [43,45,49,93] and the capital costs are 0.89 million $[46,48,50].

Two types of heavy-duty trucks are considered in this study:CNG and LNG heavy-duty trucks. CNG and LNG trucks have similarenergy efficiency and costs due to their similar engine systems [27].The average natural gas consumption for CNG and LNG truck (23tonnages) are 17.07 MJ/km and 16.81 MJ/km [27,86,88,95],respectively. The primary difference between them is the fuelstorage tank; CNG trucks need high pressure tanks and LNG trucksneed insulated cryogenic tanks. The storage tanks of LNG trucks arecheaper than those of CNG trucks, which makes the price of LNGtrucks 10% lower than that of CNG trucks [96]. The average costs forCNG and LNG truck (23 tonnages) are 0.11 million $ and 0.10million$ [59,60,97], respectively.

3.3. LNG supply chain 2: cold energy utilization chain

To improve the current LNG supply chain (Supply Chain 1), LNGcold energy utilization technology is applied in the cold energyutilization chain (Supply Chain 2 in Fig. 4). LNG releases a largeamount of cold energy in the regasification process, which could berecovered by cold recovery application to improve its efficiency.Cold recovery application is considered an add-on modification inexisting regasification plants in this study. After modification, theenergy consumption in the original regasification process is saved,and part of cold energy in LNG is recovered, however, the cost of theregasification plant also increases. It is assumed that venting andfugitive emissions after adding cold recovery remain the same as inthe original regasification plant. Four types of cold recovery optionsare used in this study: cold power generation (CP), direct cold usage(DC), partial cryogenic carbon dioxide capture (PCCC), and fullcryogenic carbon dioxide capture (FCCC). All data used in calcula-tion of cold energy recvoery are shown in Supporting Informationtable S8.

CP is the most studied application of LNG cold energy recoveryand is based on a direct expansion cycle, Rankine cycle, Braytoncycle, or a combination of these [98]. The power generated from CPapplication is assumed as the mean value of 13 studies and 2operation data [98] and is assumed to replace electricity from thegrid. The electricity replaced from CP is 2.62 MJ/GJLNG [98] and thecapital cost is 54.5 million $ [99]. The DC considered in this studyincludes four applications: air separation units, dry ice production,freezing, and district cooling [18]. The cold energy recovered fromDC is assumed to replace electricity from the grid, which is used togenerate cold. The cold energy recovered from DC is also assumedas the mean value of the four applications [18]. The electricityreplaced from DC is 2.62 MJ/GJLNG [18] and the capital cost is 42.1million $ [99]. The CP and DC applications are only applied in large-scale regasification, where the potential industrial users are nearby.

PCCC and FCCC are established according to four studies[19,99e101]. PCCC recovers LNG cold energy to partially captureand liquefy CO2 from flue gas from the power plant or industrial

6

end-users, and FCCC needs additional electricity input to fullycapture and liquefy CO2. The electricity input for FCCC in powerplants is from its generation, and the electricity input for FCCC inindustrial end-users is from the national electricity grid. The elec-tricity consumption for FCCC is 20.43 MJ/GJLNG [19,99e101]. Thecapital costs of PCCC for large-scale and small-scale liquefaction are69.0 and 9.2 million $ [99], respectively. The capital costs of FCCCfor large-scale and small-scale liquefaction are 83.5 and 12.5million $ [99], respectively. After the CO2 is captured from flue gas,it is transported to its storage site or industrial CO2 utilization fa-cilities [102]. As CO2 transport, storage, and utilization fall outsidethe system boundary, their impacts on energy efficiency, GHGemissions, and costs are not considered in this study.

3.4. LNG supply chain 3: hydrogen chain

As an alternative to the current LNG supply chain, this studyincludes H2 production and transport after LNG arrived in theharbor as shown in Fig. 5 (Supply Chain 3). Hydrogen is seen as aninteresting energy carrier as it can be used to decarbonize the hard-to-abate sectors [1]. The energy consumption, GHG emissions, andcosts of each LC stage of hydrogen supply chain are based onexisting pioneer projects and are discussed in following. For the NHarea, the imported LNG is directly sent to a hydrogen productionfactory, which is located near the harbor. Then, the hydrogen isdistributed by pipeline to nearby users. For the FH area, the LNG istransported by truck to a hydrogen production factory. Then, thehydrogen is distributed to end-users. All data used in calculation ofhydrogen chain are shown in Supporting Information table S4 andS10.

Hydrogen production is based on the steam methane reforming(SMR) method to produce hydrogen using natural gas as feedstock.SMR is the most common production method for hydrogen, andtherefore, it is selected in this study to produce hydrogen [103]. Itinvolves a catalytic conversion of methane and steam to hydrogen[25]. The capacity of hydrogen production is assumed to be0.15 MTPA, which is based on the capacity of small-scale regasifi-cation. This hydrogen production capacity belongs to large-scaleplants, which are more energy-efficient (85%) than the small-scale plants [103]. The natural gas and electricity consumptionare 1.17 MJNG/MJH2 and 4.67 � 10^-3 MJ/MJH2 [25,103]. The capitalcosts for a 0.15MTPA hydrogen plant are 231.9 million $ [25,77,104].

The capacity of the hydrogen pipeline is assumed according to aDOE report [78], which is 1.01 billion cubic meters H2 annually.Hydrogen needs a dedicated pipeline because it can only beblended in the natural gas pipeline up to 15% due to leakage issues[77]. The length and design pressure are 200 km and 60 bar,respectively. It is assumed that the energy consumption forhydrogen compression stations is equivalent to natural gascompression stations with a difference in electricity use. Theventing and fugitive emissions for hydrogen pipelines are zero. Theelectricity consumption is 0.31 kJ/(GJH2$km) [76] and the capitalcosts are 18.4 k$/km [75,77,78].

The capacity of hydrogen refueling stations is assumed as 240TPA based on previous research [103]. Hydrogen refueling stationsmainly consist of storage tanks, a compressor, and dispensers [103].China is planning to increase its number of hydrogen refuelingstations to more than 100 in 2020 [105]. The hydrogen of the fuelcell vehicles is at 600e700 bar [77,103]. The energy consumption ofhydrogen refueling stations, which is mainly electricity for com-pressors, is highest among the three types of refueling stations inthis study. It is four times higher than CNG refueling stations withequivalent amounts of fuel filled [88,103]. For a 240 TPA hydrogenrefueling station, the electricity consumption is 76.10 MJ/GJH2 [103]and the capital costs are 0.49 million $ [77,83,85].

Fig. 4. LNG Supply Chain 2: cold energy utilization chain.

Fig. 5. LNG Supply Chain 3: Hydrogen chain.

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

The life cycle stage of four end-users, which include powergeneration, industrial heating, residential heating, and truck usage,is the last life cycle stage for hydrogen.

There are two types of large-scale hydrogen power plantsconsidered in this study: a hydrogen-fueled combined cycle (HCC)plant and phosphoric acid fuel cell (PAFC) hydrogen power plant.

7

The first hydrogen power plant in the world is the Fusina (Venice)hydrogen power plant, which is an HCC power plant built in 2010with a 16-MW capacity [106]. The cost and capacity of the Fusinahydrogen power plant are used in this study to represent HCCpower plants. The efficiency of HCC power plants is assumed to bethe same as that of NGCC power plant based on the work of

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

Pambudi et al. (2017) [107]. The hydrogen consumption is 1.74 MJ/MJe [107] and the capital costs are 64.85 million $ [106]. Large-scalePAFC hydrogen power plants are considered in this study. TheDaesan hydrogen fuel cell power plant in Korea is the world’s firstlarge-scale hydrogen fuel cell power plant with a 50-MW capacity.The cost, capacity, and efficiency of the Daesan hydrogen powerplant are used in this study to represent PAFC hydrogen powerplants. The hydrogen consumption is 1.82 MJ/MJe [108e110] andthe capital costs are 216.01 million $ [111,112].

The industrial and residential heating system for hydrogen inthis study is the hydrogen boil system. Hydrogen has a similarWobbe Index as natural gas, which enables the existing natural gasboilers to run on hydrogen mixtures up to 28% [113]. It also impliesthat the hydrogen boiler has comparable efficiency to a natural gasboiler. Based on the Frazer-Nash Consultancy report [114], newlybuilt hydrogen boiler systems are as efficient as natural gas boilersystems. As NG boilers can run on high concentration of hydrogenwith the small modification of replacing the burner tips [115], it isassumed that hydrogen boiler systems cost 5% more than thenatural gas boiler systems [114]. The hydrogen consumption forhydrogen heating system is 1.11 MJ/MJe [114]. The capital costs forthe hydrogen industrial and residential heating system are 4.11million $ and 0.93 million $ [43,46,114], respectively.

Hydrogen fuel cell (HFC) heavy-duty trucks are considered inthis study as vehicular end-users for hydrogen. The energy effi-ciency of HFC trucks is two times higher than CNG/LNG trucks[86,88] but the cost for HFC trucks is also much higher than CNG/LNG trucks. The cost estimation of HFC heavy-duty trucks is mainlybased on a report of Fuel Cell and Hydrogen Joint Undertaking [59],which focuses on the technical and economic performances ofthese trucks. The hydrogen consumption for Hydrogen fuel celltruck is 8.24 MJ/km [27,86,88,95] and the costs are 0.35 million $[59,60,97].

4. Results

The results in Fig. 6, Fig. 7, Fig. 8, and Fig. 9 show that CP and DCslightly reduce GHG emissions by 0.9e1.2% and production costs by0.2e0.8% compared to the NG pathway in all four end-users. ThePCCC reduced GHG emissions by 9.5e10.4% and production costs by0.2e0.7% compared to the NG pathway in power generation andindustrial heating. FCCC and hydrogen production pathways havesignificantly changed the GHG emissions and production costs ofthe LNG supply chain. The detailed results are shown in section4.1e4.4.

4.1. Power generation

The life cycle GHG emissions, production cost, and energy effi-ciency of each pathway for power generation are shown in Fig. 6.The avoided GHG emissions and GHG avoidance cost compared to acoal-fired power plant are shown in Table 2. In the NH area, theGHG emissions of NG with FCCC are approximately 15% lower thanthose of H2 HCC with FCCC and H2 PAFC with FCCC. The productioncosts are 76.4% and 70.8% lower than those of H2 HCC with FCCCand H2 PAFC with FCCC, respectively. NG with FCCC has the largestavoided GHG emissions of 112.4 g CO2-e/MJLNG and NG with PCCChas the lowest GHG avoidance cost of 57.4 $/t CO2-e in the NH area.In the FH area, NG, NG with CP, and NG with DC have similar per-formances. NG with CP has the largest avoided GHG emissions of73.1 g CO2-e/MJLNG and the lowest GHG avoidance cost of 70.1 $/tCO2-e in the FH area.

8

4.2. Industrial heating

Fig. 7 presents the results of the life cycle GHG emissions, pro-duction cost, and energy efficiency of each pathway for industrialheating. Table 3 shows the avoided GHG emissions and GHGavoidance cost compared to a coal-fired industrial boiler. In the NHarea, the GHG emissions and production costs of NG with FCCC are27.8% and 66.7% lower than that of H2 with FCCC, respectively. Inthe FH area, the GHG emissions and production cost of NG (road)with FCCC are 29.3% and 66.8% lower than that of H2 (road) withFCCC, respectively. For industrial heating NG with FCCC in the NHarea and NG (road) with FCCC in the FH area have the largestavoided GHG emissions of 70.5 and 66.3 g CO2-e/MJLNG and lowestGHG avoidance costs of 95.9 and 124.1 $/t CO2-e, respectively.

4.3. Residential heating

As shown in Fig. 8, the life cycle GHG emissions, production cost,and energy efficiency of residential heating are compared betweenpathways. The avoided GHG emissions and GHG avoidance costscompared to a central coal boiler heating system are shown inTable 4. Due to the same NG boiler efficiency in industrial andresidential heating systems, the GHG emissions performance ofeach pathway for residential heating is similar to that of industrialheating. Due to the additional costs of heating stations, externalnetworks, and indoor radiators compared to industrial heating, theproduction costs of residential heating is higher than industrialheating. It is clear for residential heating that H₂ with FCCC has thelargest avoided GHG emissions of 51.8 and 49.5 g CO2-e/MJLNG inthe NH and FH areas, respectively. NG, NG with CP, and NG with CDhave similar GHG avoidance costs in the NH and FH areas for res-idential heating.

4.4. Truck usage

Fig. 9 shows the life cycle GHG emissions, production costs, andenergy efficiency of each pathway for truck usage. Table 5 presentsthe avoided GHG emissions and GHG avoidance costs compared todiesel trucks. In both the NH and FH areas, the GHG emissions andproduction costs of LNG (road) are 7.2e8.4% and 16.9e18.5% lowerthan that of CNG (CNG (road)) pathways, respectively. H2 with FCCChas the highest GHG emissions but also the highest productioncosts in the NH and FH areas. It is also clear that H2 with FCCC hasthe largest avoided GHG emissions of 104.9 and 102.2 g CO2-e/MJLNG, and the LNG (road) has the lowest GHG avoidance costs of79.4 and 114.3 $/t CO2-e in the NH and FH area, respectively.

4.5. Overall results of four end-users for avoided GHG emissions andGHG avoidance costs

The comparison of pathways on avoided GHG emissions andGHG avoidance costs is shown in Fig. 10. CP and DC slightly reducedGHG emissions and production costs compared to NG pathway inall four end-users. The reason for a minor reduction in GHG emis-sions is that energy-saving and energy generated (electricity andcold) in the regasification process is only a small portion (around1%) of the LNG supply chain. The reason is that the cost-savingcaused by energy-saving exceeds the increase in capital costs.PCCC pathways have higher avoided GHG emissions and lower GHGavoidance costs than CP and DC pathways in power generation andindustrial heating, indicating that using LNG cold energy to captureCO2 has better performance on reducing GHG emissions comparedto cold power generation and direct cold usage.

NG with FCCC pathways have the highest avoided GHG emis-sions with relatively low GHG avoidance costs in power generation

Fig. 6. GHG emissions, production cost and energy efficiency for power generation.

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

and industrial heating in NH compared to H2 pathways. This isbecause H2 pathways have the same or slightly higher powergeneration and industrial heating efficiency compared to NG withFCCC pathways. Moreover, H2 pathways need one more conversionstep from NG to H2. Notably, H2 pathways are relatively novel, thecost is significantly high in all four end-users on short term.Therefore, H2 pathways have lower energy efficiency and higherGHG emissions compared to NG with FCCC pathways, indicatingthat the H2 pathways do not have advantages compared to NGwithFCCC in both GHG emissions and production costs for power gen-eration and industrial heating in short term.

For residential heating, H2 pathways have the highest avoidedGHG emission but also the highest GHG avoidance costs. CP and DCpathways are only slightly better than NG pathways. Therefore, thecurrent NG pathways for residential heating are the most attractivepathways for residential heating in the short term. In the long term,H2 pathways could be applicable when cost is reduced due totechnological development and economies of scale. For truck usage,NG pathways include CNG pathways and LNG pathways. LNGpathways have higher avoided GHG emission andmuch lower GHGavoidance costs than CNG pathways. This is because LNG pathwaysdo not need regasification process and LNG pathways have lowerenergy consumption, GHG emissions, and costs on LNG refuelingstation compared to CNG refueling stations. The high energy con-sumption, GHG emissions, and costs of CNG refueling stations arecaused by the need for NG to be compressed to CNG. This indicatesthat LNG trucks are more environmentally-friendly and economicalcompared to CNG trucks. H2 fuel cell truck have much higheravoided GHG emissions with similar GHG avoidance costs thanCNG pathways. The low GHG emissions are mainly due to the high

9

energy efficiency of H2 fuel cell truck, which is two times higherthan CNG and LNG trucks. Therefore, LNG pathways and H2 path-ways are the best pathways for truck usage in terms of GHGavoidance costs and avoided GHG emissions, respectively.

The comparison of four end-users shows that NG with FCCCpathways for power generation are the best pathways with highavoided GHG emissions and low GHG avoidance costs. Besidespower generation, FCCC for industrial heating is also attractivecompared to other pathways for industrial heating due to high GHGemissions and low GHG avoidance costs. In conclusion, applyingFCCC to the LNG supply chain for power generation is the bestpathway among all four end-users that can avoid a large amount ofGHG emissions at relatively low costs. FCCC, CP and DC, and LNGpathways are the most attractive pathways in industrial heating,residential heating, and truck usage, respectively.

5. Discussion

5.1. Sensitivity analysis

As the energy consumption and costs of NG pipeline, H2 pipe-line, and LNG truck transport per unit distance and unit energy arerelatively insignificant compared to other life cycle stages, the GHGemissions and production costs are not sensitive to transport op-tions [27]. The major factors affecting GHG emissions and pro-duction costs include LNG import price and upstream GHGemissions, energy efficiency for hydrogen production, energy effi-ciency for cold recovery, and energy efficiency and costs for end-users.

China’s average LNG import prices varied from 0.0036 $/MJ to

Fig. 7. GHG emissions, production cost and energy efficiency for industrial heating.

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

0.0133 $/MJ from 2008 to 2018 [29]. The upstream GHG emissionsfor LNG from Australia to China varied from 14.45 g CO2-e/MJLNG to43.64 g CO2-e/MJLNG (according to section 4.1). The impact of LNGimport price and the upstream GHG emissions is illustrated by thepathway of NG with FCCC for power generation in the NH area. Ifthe LNG import price is assumed to be 0.0036 $/MJ, the GHGavoidance costs will be 45.7 $/t CO2-e, which is reduced by 48%. Ifthe LNG import price is assumed to be 0.0133 $/MJ, the GHGavoidance costs will be 149.3 $/t CO2-e, which is increased by 70%. Ifthe upstream GHG emissions are assumed to be 14.45 g CO2-e/MJLNG, the avoided GHG emission and the GHG avoidance costs willbe 103.3 g CO2-e/MJLNG and 79.1 $/t CO2-e, respectively. The avoi-ded GHG emissions increase by 11% and the GHG avoidance costsare reduced by 10%. If the upstream GHG emissions are assumed tobe 43.64 g CO2-e/MJLNG, the avoided GHG emission and the GHGavoidance costs will be 74.1 g CO2-e/MJLNG and 110.3 $/t CO2-e,respectively. The avoided GHG emissions decrease by 21% and GHGavoidance costs increase by 26%. The LNG import price and up-stream GHG emission significantly affect the GHG emissions andproduction costs for NG with FCCC; a similar impact can be foundfor other pathways.

The energy efficiency for H2 production using SMR varies from74% to 85% [25]. The energy efficiency of 85% is used in this study forthe newly built H2 production plant. The impact of the energy ef-ficiency of H2 production is illustrated by the pathway of H2 PAFCwith FCCC in the NH area. If the energy efficiency is 74%, theavoided GHG emissions and the GHG avoidance costs will be 88.7 gCO2-e/MJLNG and 441.1 $/t CO2-e, respectively. The avoided GHGemissions decrease by 5% and GHG avoidance costs increase by 17%.

10

As SMR is the most common method for H2 production and itstechnology is mature [25], the energy efficiency cannot be signifi-cantly improved in the short term. Therefore, the energy efficiencyused in this study can indicate SMRH2 production in the short term.

Cryogenic power generation from LNG regasification varies from0.00108 MJ/MJLNG to 0.00595 MJ/MJLNG [98,116]. The impact ofelectricity generated from CP is illustrated by the pathway of NGwith CP for power generation in the NH area. If the 0.00108 MJ/MJLNG electricity is generated from CP, the GHG emissions andeconomic benefits would almost vanish compared to NG pathways.If the 0.00595 MJ/MJLNG is generated from CP, the avoided GHGemissions and GHG avoidance costs will be 58.2 g CO2-e/MJLNG and94.6 $/t CO2-e, respectively. The avoided GHG emissions increase by2% and GHG avoidance costs reduce by 3%. The GHG emissions andeconomic benefits could make CP options applicable in the shortterm.

The power generation efficiency for H2 PAFC with FCCC isassumed as 55% [108,109] in this study. If an alkaline fuel cell is usedin the H2 power plant, the electric efficiency can reach 70%[108,117]. Then the avoided GHG emissions in the NH area will be116.2 g CO2-e/MJLNG and 320.4 $/t CO2-e, respectively. The avoidedGHG emissions increase by 40% and the GHG avoidance costs re-duces by 23%. The high efficiency of alkaline fuel cell makes theavoided GHG emissions of H2 fuel cell power plant exceed those ofNG with FCCC by 3% in the NH area. The costs for the H2 fuel celltruck is assumed as 0.35 million $ in this study. According to a FuelCell and Hydrogen Joint Undertaking report [59], the costs for theH2 fuel cell truck will be 0.12million $ in 2030. If the costs for the H2fuel cell truck is assumed as 0.12 million $ for the H2 with FCCC in

Fig. 8. GHG emissions, production costs, and energy efficiency for residential heating.

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

the NH area, the GHG avoidance costs will be 192.5 $/t CO2-e, whichis a 60% reduction. This indicates that the hydrogen pathway couldonly have better GHG emission and cost performances by techno-logical development and cost reduction.

5.2. Study limitations and future work

The results of this study have some limitations. One limitation ofthis study is data quality of capital cost for each life cycle stage,especially for the cost estimation of cold recovery at the regasifi-cation process and hydrogen pathways, due to limited informationfor capital cost and the difficulty of capital cost estimation. Muchliterature lack cost estimation and optimization.

Combined heat and power generation for the hydrogen fuel cellis a promising end-use and its overall efficiency can reach 85%[108,110]. It is not included in this study to avoid high complexity inallocation of GHG emissions and comparison between four end-users. Further efforts should be made in investigating the perfor-mance of combined heat and power generation and cover variousend-users.

The GHG emissions are not the only environmental benefit ofLNG use considered in this study. Other environmental benefitsachieved by substituting coal and diesel by LNG, can lead toreduction of about 80% NOx, over 99% SO2, and between 92% and99% particulates per unit of energy compared to oil and coal [4]. Toget a comprehensive environmental performance of LNG, the lifecycle air pollutant emissions should be further addressed in futurestudies. The benefits of air pollutant reduction makes the transitionfrom coal and diesel to LNG more attractive.

11

6. Conclusion

This study aims to find the best way to supply and use LNG inChina from a GHG mitigation and economic perspective. To quan-tify and optimize GHG emission and economic performance forLNG supplied for the four end-users, we proposed three LNG supplychains and defined the life cycle stages involved in each one. Theenergy efficiency, life cycle GHG emissions, and production costs foreach LNG supply chain were determined in this study. Lastly,pathways for each end-user are compared with a reference chain inChina to show the avoided GHG emissions and GHG avoidancecosts. From the results, the following can be concluded:

� The CP and DC options slightly reduce GHG emissions by0.9e1.2% and production costs by 0.2e0.8% compared to the NGpathway in all four end-users, indicating that using the coldenergy of LNG to produce electricity or provide cooling does notsignificantly affect GHG emissions and costs in a life cycleperspective. The PCCC option reduced GHG emissions by9.5e10.4% and production costs by 0.2e0.7% compared to theNG pathway in all four end-users, indicating that using the coldenergy of LNG to capture CO2 has more benefits on GHG emis-sions compared to CP and DC.

� NG with FCCC reduces GHG emissions by 55.5% with an11.1e17.3% production costs increase in power generation andindustrial heating compared to NG pathway. H2 with FCCC re-duces GHG emission by 38.5e48.6% with a 194.1e425.3% pro-duction costs increase compared to NG pathway in powergeneration and industrial heating. This demonstrates that the

Fig. 9. GHG emissions, production costs, and energy efficiency for truck usage.

Table 2Avoided GHG emissions and GHG avoidance costs for power generation.

location Supply chain GHGa (g CO2-e/MJLNG) Ca ($/t CO2-e)

Near Harbor NG 75.6 64.3NG with CP 76.7 62.6NG with DC 76.6 63.1NG with PCCC 83.8 57.4NG with FCCC 112.4 66.0H₂ HCC with FCCC 89.8 438.6H₂ PAFC with FCCC 83.0 417.9

Far from harbor NG 72.7 72.0NG with CP 73.7 70.1NG with DC 73.7 70.7

Table 3Avoided GHG emissions and GHG avoidance costs for industrial heating.

location Supply chain GHGa (g CO2-e/MJLNG) Ca ($/t CO2-e)

Near Harbor NG 35.9 138.9NG with CP 36.8 133.8NG with DC 36.9 134.5NG with PCCC 43.9 112.3NG with FCCC 70.5 95.9H₂ with FCCC 53.3 405.4

Far from harbor NG 33.7 158.8NG (road) 32.0 198.1NG with CP 34.6 152.9NG with DC 34.7 153.6NG (road) with PCCC 41.6 145.1NG (road) with FCCC 66.3 124.1H₂ (road) with FCCC 49.5 454.6

Table 4Avoided GHG emissions and GHG avoidance costs for residential heating.

location Supply chain GHGa (g CO2-e/MJLNG) Ca ($/t CO2-e)

Near Harbor NG 35.4 205.8NG with CP 36.3 199.1NG with DC 36.4 199.5H₂ with FCCC 51.8 460.8

Far from harbor NG 33.7 213.1NG (road) 32.0 265.6NG with CP 34.6 216.7NG with DC 34.7 217.0H₂ (road) with FCCC 49.5 494.5

Table 5Avoided GHG emissions and GHG avoidance costs for truck usage.

location Supply chain GHGa (g CO2-e/MJLNG) Ca ($/t CO2-e)

Near Harbor CNG 16.5 421.1LNG (road) 23.4 79.4CNG with CP 17.4 397.4CNG with DC 17.5 396.4H₂ with FCCC 104.9 547.2

Far from harbor CNG 15.1 479.3CNG (road) 14.0 527.4LNG (road) 22.1 114.3CNG with CP 15.9 450.6CNG with DC 16.0 448.9H₂ with FCCC 102.2 563.5

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

12

Fig. 10. Comparison of four end-users on avoided GHG emissions and GHG avoidance costs.

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

NG with the FCCC pathway has better GHG emission and costperformances than H2 with FCCC in the current situation.

� When the power generation efficiency of fuel cell hydrogenpower plant with FCCC is 70%, it has a better GHG emissionperformance compared to NG with FCCC. According to a FuelCell and Hydrogen Joint Undertaking report [59], the costs for anH2 fuel cell truck will be only one-third in 2030 compared to thecosts used in this study. This indicates that the hydrogenpathway could have better performance on GHG emissions andproduction costs with technological development and long-term cost reductions.

� LNG trucks have lower GHG emissions by 7.2e8.4% and lowerproduction costs by 16.9e18.5% compared to CNG trucks. Thisindicates that the LNG truck is more environmentally-friendlyand economical than the CNG truck.

� The comparison of the four end-users shows that the NG withFCCC for power generation is the best pathway, as it can avoid alarge amount of GHG emissions at relatively low GHG avoidancecosts.

In conclusion, the pathway of NG with FCCC is the most bene-ficial pathway for both avoided GHG emissions and GHG avoidancecosts. The LNG supply chain of hydrogen production is only appli-cable when new technology options are mature and costs aresignificantly reduced in the future. A comparison of four end-usersshows that it is better to first promote NG with FCCC to substitutecoal-fired power plants in the power generation section.

This study aims to find the most adequate way, in terms of lifecycle GHG emissions and costs, to supply and use LNG in China inthe short term. Other important environmental benefits besidesGHG emissions, which are not addressed in this study, includesignificant reductions in NOx, SO2, and particulates emissions [4] byapplying LNG to substitute coal and diesel. The benefits of airpollutant emissions could be another important driver of thetransition from coal and diesel to LNG. The infrastructures in thethree proposed supply chains could further reduce GHG emissionsin the long term. The potential of using LNG infrastructures tosupply and use biogas, bio-SNG (synthetic natural gas), and H2 fromrenewable energy should be investigated in the future to evaluatehow the current LNG infrastructures can be used as a bridge towardrenewable sources and achieve further GHG emission reductions inthe future.

13

Author contribution

Jinrui Zhang: Data curation; Formal analysis; Investigation;Methodology; Visualization; Writing e original draft; Hans Meer-man: contribute equally to this paper: Supervision; Writing e re-view & editing; Ren�e; Benders: contribute equally to this paper:Supervision; Writing e review & editing; Andr�e Faaij: contributeequally to this paper: Supervision; Writing e review & editing

Declaration of competing interest

The authors declare that they have no known competingfinancial interests or personal relationships that could haveappeared to influence the work reported in this paper.

Acknowledgment

This work is supported by the China Scholarship Council andUniversity of Groningen (awarded to Jinrui Zhang for four years ofstudy at the University of Groningen).

Appendix A. Supplementary data

Supplementary data to this article can be found online athttps://doi.org/10.1016/j.energy.2021.120049.

References

[1] International Energy Agency (IEA). World energy outlook 2019, vol. 23.OECD; 2019. https://doi.org/10.1787/caf32f3b-en.

[2] International Energy Agency. CO2 emissions from fuel combustion, vol. 2019.OECD; 2019. https://doi.org/10.1787/2a701673-en.

[3] Zhang J, Meerman H, Benders R, Faaij A. Comprehensive review of currentnatural gas liquefaction processes on technical and economic performance.Appl Therm Eng 2020;166:114736. https://doi.org/10.1016/j.applthermaleng.2019.114736.

[4] Liang F-Y, Ryvak M, Sayeed S, Zhao N. The role of natural gas as a primaryfuel in the near future, including comparisons of acquisition, transmissionand waste handling costs of as with competitive alternatives. Chem Cent J2012;6(Suppl 1):S4. https://doi.org/10.1186/1752-153X-6-S1-S4.

[5] IEA (International Energy Agency). Gas market liberalisation reform key in-sights from international experiences and the implications. 2019.

[6] Eria. LNG market development in asia. In: ERIA research project reportFY2018 no.4. Jakarta: ERIA; 2019.

[7] Hongkun W, Yuanqi J, Xiaoqing W, Ruirui J, Huihui L. Analysis and prospecton LNG import industry in China. Int Pet Econ 2019;27.

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

[8] Royal Dutch shell plc, shell. Shell LNG outlook 2019. 2019.[9] Yanni J, Haiping S, Jing Q. Review and prospect of LNG liquid distribution

market in China in 2018. Int Pet Econ 2019;27. https://doi.org/10.3969/j.issn.1004-7298.2019.01.021.

[10] Cnpc Etri. China energy outlook 2050. 2018. https://doi.org/10.1787/g2659b7a2e-en.

[11] Zhang Y, Jiang H, Li J, Shao S, Hou H, Qi Y, et al. Life cycle assessment andoptimization analysis of different LNG usage scenarios. Int J Life Cycle Assess2018;23:1218e27. https://doi.org/10.1007/s11367-017-1347-2.

[12] Barnett PJ. Life Cycle Assessment (LCA) of Liquefied Natural Gas (LNG) and itsenvironmental impact as a low carbon energy source. University of SouthernQueensland; 2010.

[13] Safaei A, Freire F, Henggeler Antunes C. Life-cycle greenhouse gas assessmentof nigerian liquefied natural gas addressing uncertainty. Environ Sci Technol2015;49:3949e57. https://doi.org/10.1021/es505435j.

[14] Jaramillo P, Griffin WM, Matthews HS. Comparative life-cycle air emissionsof coal, domestic natural gas, LNG, and SNG for electricity generation. En-viron Sci Technol 2007;41:6290e6. https://doi.org/10.1021/es063031o.

[15] Song H, Ou X, Yuan J, Yu M, Wang C. Energy consumption and greenhousegas emissions of diesel/LNG heavy-duty vehicle fleets in China based on abottom-up model analysis. Energy 2017;140:966e78. https://doi.org/10.1016/j.energy.2017.09.011.

[16] Raj R, Ghandehariun S, Kumar A, Linwei M. A well-to-wire life cycleassessment of Canadian shale gas for electricity generation in China. Energy2016;111:642e52. https://doi.org/10.1016/j.energy.2016.05.079.

[17] Tamura I, Tanaka T, Kagajo T, Kuwabara S, Yoshioka T, Nagata T, et al. Lifecycle CO2 analysis of LNG and city gas. Appl Energy 2001;68:301e19.https://doi.org/10.1016/S0306-2619(00)00062-3.

[18] Khor JO, Dal Magro F, Gundersen T, Sze JY, Romagnoli A. Recovery of coldenergy from liquefied natural gas regasification: applications beyond powercycles. Energy Convers Manag 2018;174:336e55. https://doi.org/10.1016/j.enconman.2018.08.028.

[19] Romero G�omez M, Romero G�omez J, L�opez-Gonz�alez LM, L�opez-Ochoa LM.Thermodynamic analysis of a novel power plant with LNG (liquefied naturalgas) cold exergy exploitation and CO 2 capture. Energy 2016;105:32e44.https://doi.org/10.1016/j.energy.2015.09.011.

[20] Pierie F, Bekkering J, Benders RMJ, van Gemert Wjt, Moll HC. A new approachfor measuring the environmental sustainability of renewable energy pro-duction systems: focused on the modelling of green gas production path-ways. Appl Energy 2016;162:131e8. https://doi.org/10.1016/j.apenergy.2015.10.037.

[21] ISO. ISO 14040:2006 Environmental management d life cycle assessment dprinciples and framework. Geneva, Switzerland: 2006.

[22] ISO. ISO 14044:2006 Environmental management d life cycle assessment drequirements and guidelines. Geneva, Switzerland: 2206.

[23] Kuramochi T, Ramírez A, Turkenburg W, Faaij A. Comparative assessment ofCO2 capture technologies for carbon-intensive industrial processes. ProgEnergy Combust Sci 2012;38:87e112. https://doi.org/10.1016/j.pecs.2011.05.001.

[24] API. Consistent methodology for estimating greenhouse gas emissions. 2015.[25] Nikolaidis P, Poullikkas A. A comparative overview of hydrogen production

processes. Renew Sustain Energy Rev 2017;67:597e611. https://doi.org/10.1016/j.rser.2016.09.044.

[26] Groups I, II and III to the Fifth Assessment Report of the IntergovernmentalPanel on Climate Change. Core writing team RKP and LAM (eds. ). IPCC, 2014:climate change 2014. Geneva, Switzerland: Synthesis Report; 2015.

[27] Yuan Z, Ou X, Peng T, Yan X. Life cycle greenhouse gas emissions of multi-pathways natural gas vehicles in China considering methane leakage. ApplEnergy 2019;253:113472. https://doi.org/10.1016/j.apenergy.2019.113472.

[28] Berghout N, Meerman H, van den Broek M, Faaij A. Assessing deploymentpathways for greenhouse gas emissions reductions in an industrial plant e acase study for a complex oil refinery. Appl Energy 2019;236:354e78. https://doi.org/10.1016/j.apenergy.2018.11.074.

[29] O’Sullivan S. China’s long march to gas price freedom, NG138; 2018. https://doi.org/10.26889/9781784671235.

[30] China Electricity Price. CEIC. 2019. https://www.ceicdata.com/en/china/electricity-price. [Accessed 18 February 2020].

[31] Bp. BP statistical review of world energy. 2018.[32] Hekkert MP, Hendriks FHJF, Faaij APC, Neelis ML. Natural gas as an alter-

native to crude oil in automotive fuel chains well-to-wheel analysis andtransition strategy development. Energy Pol 2005;33:579e94. https://doi.org/10.1016/j.enpol.2003.08.018.

[33] Aub�e F. Guide for computing carbon dioxide emissions related to energy use.Nat Gas 2001;37:2e4.

[34] Ou X, Zhang X, Zhang X, Zhang Q. Life cycle GHG of NG-based fuel andelectric vehicle in China. Energies 2013;6:2644e62. https://doi.org/10.3390/en6052644.

[35] Hauschild MZ, Rosenbaum RK, Olsen SI. Life cycle assessment: theory andpractice. 2017. https://doi.org/10.1007/978-3-319-56475-3.

[36] Hunkeler D, Lichtenvort K, Rebitzer G. Environmental life cycle costing. En-viron. Life Cycle Costing 2008:1e4. https://doi.org/10.1201/9781420054736.

[37] Zhang J, Meerman H, Benders R, Faaij A. Technical and economic optimiza-tion of expander-based small-scale natural gas liquefaction processes withabsorption precooling cycle. Energy 2020;191:116592. https://doi.org/10.1016/j.energy.2019.116592.

14

[38] CNREC. China renewable energy outlook 2018. 2018.[39] List of power stations in China n.d. https://en.wikipedia.org/wiki/List_of_

power_stations_in_China (accessed April 4, 2020).[40] Shen W, Han W, Wallington TJ, Winkler SL. China electricity generation

greenhouse gas emission intensity in 2030: implications for electric vehicles.Environ Sci Technol 2019;53:6063e72. https://doi.org/10.1021/acs.est.8b05264.

[41] Han S, Zhang B, Sun X, Han S, H€o€ok M. China’s energy transition in the powerand transport sectors from a substitution perspective. Energies 2017;10.https://doi.org/10.3390/en10050600.

[42] Hansen K. Decision-making based on energy costs: comparing levelized costof energy and energy system costs. Energy Strateg Rev 2019;24:68e82.https://doi.org/10.1016/j.esr.2019.02.003.

[43] Shen B, Han Y, Price L, Lu H, Liu M. Techno-economic evaluation of strategiesfor addressing energy and environmental challenges of industrial boilers inChina. Energy 2017;118:526e33. https://doi.org/10.1016/j.energy.2016.10.083.

[44] Guo Y, Tian J, Chen L. Managing energy infrastructure to decarbonize in-dustrial parks in China. Nat Commun 2020;11:981. https://doi.org/10.1038/s41467-020-14805-z.

[45] Abrahams LS, Samaras C, Griffin WM, Matthews HS. Life cycle greenhousegas emissions from U.S. liquefied natural gas exports: implications for enduses. Environ Sci Technol 2015;49:3237e45. https://doi.org/10.1021/es505617p.

[46] IEA Etsap. Industrial combustion boilers. CRC Press; 2010. https://doi.org/10.1201/EBK1420085280.

[47] Jiang Y, Guo S, Hu S. China building energy use 2018. 2018.[48] Chen X, Wang L, Tong L, Sun S, Yue X, Yin S, et al. Mode selection of China’s

urban heating and its potential for reducing energy consumption and CO 2emission. Energy Pol 2014;67:756e64. https://doi.org/10.1016/j.enpol.2013.11.057.

[49] Du M, Wang X, Peng C, Shan Y, Chen H, Wang M, et al. Quantification andscenario analysis of CO2 emissions from the central heating supply system inChina from 2006 to 2025. Appl Energy 2018;225:869e75. https://doi.org/10.1016/j.apenergy.2018.05.064.

[50] Gudmundsson O, Thorsen JE, Zhang L. Cost analysis of district heatingcompared to its competing technologies. WIT Trans Ecol Environ 2013;176:3e13. https://doi.org/10.2495/ESUS130091.

[51] Nian V, Sun Q, Ma Z, Li H. A comparative cost assessment of energy pro-duction from central heating plant or combined heat and power plant. En-ergy Procedia 2016;104:556e61. https://doi.org/10.1016/j.egypro.2016.12.094.

[52] [n.d] China heavy truck industry report. 2019-2025.[53] China Automotive Technology and Research Center. China green freight

assessment. 2018.[54] INTERNATIONAL COUNCIL ON CLEAN TRANSPORTATION. China ’ S clean

diesel action Plan : 2018 e 2020. 2020.[55] Hu M, Huang W, Cai J, Chen J. The evaluation on liquefied natural gas truck

promotion in Shenzhen freight. Adv Mech Eng 2017;9:1e10. https://doi.org/10.1177/1687814017705065.

[56] Shahraeeni M, Ahmed S, Malek K, Van Drimmelen B, Kjeang E. Life cycleemissions and cost of transportation systems: case study on diesel andnatural gas for light duty trucks in municipal fleet operations. J Nat Gas SciEng 2015;24:26e34. https://doi.org/10.1016/j.jngse.2015.03.009.

[57] Quiros DC, Smith J, Thiruvengadam A, Huai T, Hu S. Greenhouse gas emis-sions from heavy-duty natural gas, hybrid, and conventional diesel on-roadtrucks during freight transport. Atmos Environ 2017;168:36e45. https://doi.org/10.1016/j.atmosenv.2017.08.066.

[58] Tong F, Jaramillo P, Azevedo IML. Comparison of life cycle greenhouse gasesfrom natural gas pathways for light-duty vehicles. Energy Fuels 2015;29:6008e18. https://doi.org/10.1021/acs.energyfuels.5b01063.

[59] FCH, Berger Roland. Development of business cases for fuel cells andhydrogen applications for regions and cities - hydrogen injection into thenatural gas grid. 2017.

[60] CERG. Study on the cost-effectiveness of natural gas ( CNG or compressednatural gas ) used as fuel in cars. 2018.

[61] Okamura T, Furukawa M, Ishitani H. Future forecast for life-cycle greenhousegas emissions of LNG and city gas 13A. Appl Energy 2007;84:1136e49.https://doi.org/10.1016/j.apenergy.2007.05.005.

[62] Hardisty PE, Clark TS, Hynes RG. Life cycle greenhouse gas emissions fromelectricity generation: a comparative analysis of australian energy sources.Energies 2012;5:872e97. https://doi.org/10.3390/en5040872.

[63] Bista S, Jennings P, Anda M. Carbon footprint management of unconventionalnatural gas development in the export scenario. Renew Energy EnvironSustain 2019;4:3. https://doi.org/10.1051/rees/2018008.

[64] Roman-white S, Rai S, Littlefield J, Cooney G, Skone TJ. Life cycle greenhousegas perspective on exporting liquefied natural gas from the United States.2019.

[65] Biswas W, ENgelbrecht D, Rosano M. A life cycle assessment of WesternAustralian LNG production and export to the Chinese market. 2011.

[66] Ishwaran M, King W, Haigh M, Lee T, Nie S. China’s gas development stra-tegies. Cham: Springer International Publishing; 2017. https://doi.org/10.1007/978-3-319-59734-8.

[67] Pace Global. LNG and coal life cycle assessment of greenhouse gas emissions.2015.

J. Zhang, H. Meerman, R. Benders et al. Energy 224 (2021) 120049

[68] Agarwal R, Rainey TJ, Ashrafur Rahman SM, Steinberg T, Perrons RK,Brown RJ. LNG regasification terminals: the role of geography and meteo-rology on technology choices. Energies 2017;10. https://doi.org/10.3390/en10122152.

[69] International Gas Union. Small scale LNG. 2015. Paris.[70] Miyamoto A, Ishiguro C. The outlook for natural gas and LNG in China in the

war against air pollution. 2018.[71] Pospí�sil J, Charv�at P, Arsenyeva O, Klime�s L, �Spil�a�cek M, Kleme�s JJ. Energy

demand of liquefaction and regasification of natural gas and the potential ofLNG for operative thermal energy storage. Renew Sustain Energy Rev2019;99:1e15. https://doi.org/10.1016/j.rser.2018.09.027.

[72] Papadopoulo M, Kaddouh S, Pacitto P, Vernat AP. Life cycle assessment of theEuropean natural gas chain focused on three environmental impact in-dicators. Final report; 2011.

[73] Eria. Investment in LNG supply chain infrastructure estimation, vol. II; 2018.[74] IGU. World LNG report 2019. 2019. p. 126.[75] Ruan Y, Liu Q, Zhou W, Batty B, Gao W, Ren J, et al. A procedure to design the

mainline system in natural gas networks. Appl Math Model 2009;33:3040e51. https://doi.org/10.1016/j.apm.2008.10.008.

[76] Fan M wei, chu Ao C, Wang X rong. Comprehensive method of natural gaspipeline efficiency evaluation based on energy and big data analysis. Energy2019;188:116069. https://doi.org/10.1016/j.energy.2019.116069.

[77] ASSET. Sectoral integration- long-term per- spective in the EU Energy Sys-tem. 2018.

[78] Cheng T-P. The power of experience hydrogen delivery infrastructure op-tions analysis: final report. 2010.

[79] Chrz V, Emmer C. Lng directly to customer stations. Conf Pap 2007:1e16.[80] International Gas Union. LNG as fuel. 2015.[81] Chart. LNG transport trailer. Chart 2015;236:185. http://files.chartindustries.

com/14722928_TransportTrailers.pdf. [Accessed 4 February 2020].[82] Kr€ohling C. MAN whitepaper small-scale LNG. 2018.[83] Mariani F. Cost analysis of LNG refuelling stations. 2016.[84] Sharafian A, Talebian H, Blomerus P, Herrera O, M�erida W. A review of liq-

uefied natural gas refueling station designs, vol. 69; 2017. https://doi.org/10.1016/j.rser.2016.11.186.

[85] Smith M, Gonzales J. Costs associated with compressed natural gas vehiclefueling infrastructure. Nat Gas-Powered Cars Truck Options Issues 2015:31e51.

[86] Chala GT, Aziz ARA, Hagos FY. Natural gas engine technologies: challengesand energy sustainability issue. Energies 2018;11. https://doi.org/10.3390/en11112934.

[87] Hagos DA, Ahlgren E. A state-of-the art review on the development of CNG/LNG infrastructure and natural gas vehicles. NGVs); 2017.

[88] USDOE. Using natural gas for vehicles: comparing three technologies. US depenergy. Energy Effic Renew Energy 2015:1e4. https://www.nrel.gov/docs/fy16osti/64267.pdf. [Accessed 12 February 2020].

[89] Kagiri C, Zhang L, Xia X. A hierarchical optimisation of a compressed naturalgas station for energy and fuelling efficiency under a demand responseprogram. Energies 2019;12. https://doi.org/10.3390/en12112165.

[90] Bao J, Zhang L, Song C, Zhang N, Guo M, Zhang X. Reduction of efficiencypenalty for a natural gas combined cycle power plant with post-combustionCO2 capture: integration of liquid natural gas cold energy. Energy ConversManag 2019;198:111852. https://doi.org/10.1016/j.enconman.2019.111852.

[91] National Energy Technology Laboratory (NETL). Cost and performancebaseline for fossil energy and natural gas to electricity volume 1: bituminouscoal plants, vol. 1; 2013. DOE/NETL-2010/1397.

[92] World Power Plants Database d Opendatasoft n.d. https://data.-opendatasoft.com/explore/dataset/world-power-plants-list%40kapsarc/ta-ble/?disjunctive.plant_country&disjunctive.plant_state&disjunctive.plant_status&disjunctive.plant_type_of_ownership&disjunctive.plant_operating_company&disjunctive.type&sort¼-plant_design_capacity_mwe&refine.-plant_coun-try¼China&location¼6,34.66032,114.76318&basemap¼jawg.sunny(accessed March 3, 2020).

[93] USDoE. Energy Tips. STEAM improve your combustion efficiency. In: US depenergy - energy effic renew energy - adv manuf off, vol. 2; 2012. DOE/GO-102012-3405 � January 2012.

[94] Han Y, Shen B, Zhang T. A techno-economic assessment of fuel switchingoptions of addressing environmental challenges of coal-fired industrialboilers: an analytical work for China. Energy Procedia 2017;142:3083e7.

15

https://doi.org/10.1016/j.egypro.2017.12.448.[95] Stolten D, Samsun RC, Garland N. Fuel Cells : data, facts and figures. Wein-

heim, Germany: Wiley-VCH Verlag GmbH & Co. KGaA; 2016. https://doi.org/10.1002/9783527693924.

[96] CNG vs. LNG for Heavy Duty Trucks: Which One is Right for Your Fleet? d

FuelSpace n.d. http://www.fuelspace.org/blog/2014/10/20/cng-vs-lng-for-heavy-duty-trucks (accessed March 3, 2020).

[97] Sen B, Ercan T, Tatari O. Does a battery-electric truck make a difference? e

life cycle emissions, costs, and externality analysis of alternative fuel-powered Class 8 heavy-duty trucks in the United States. J Clean Prod2017;141:110e21. https://doi.org/10.1016/j.jclepro.2016.09.046.

[98] Badami M, Bruno JC, Coronas A, Fambri G. Analysis of different combinedcycles and working fluids for LNG exergy recovery during regasification.Energy 2018;159:373e84. https://doi.org/10.1016/j.energy.2018.06.100.

[99] Zhang N, Lior N, Liu M, HanW. COOLCEP (cool clean efficient power): a novelCO2-capturing oxy-fuel power system with LNG (liquefied natural gas)coldness energy utilization. Energy 2010;35:1200e10. https://doi.org/10.1016/j.energy.2009.04.002.

[100] Zhao L, Dong H, Tang J, Cai J. Cold energy utilization of liquefied natural gasfor capturing carbon dioxide in the flue gas from the magnesite processingindustry. Energy 2016;105:45e56. https://doi.org/10.1016/j.energy.2015.08.110.

[101] Al-Musleh EI, Mallapragada DS, Agrawal R. Efficient electrochemical refrig-eration power plant using natural gas with ~100% CO2 capture. J PowerSources 2015;274:130e41. https://doi.org/10.1016/j.jpowsour.2014.09.184.

[102] Leung DYC, Caramanna G, Maroto-Valer MM. An overview of current statusof carbon dioxide capture and storage technologies. Renew Sustain EnergyRev 2014;39:426e43. https://doi.org/10.1016/j.rser.2014.07.093.

[103] Wulf C, Kaltschmitt M. Life cycle assessment of hydrogen supply chain withspecial attention on hydrogen refuelling stations. Int J Hydrogen Energy2012;37:16711e21. https://doi.org/10.1016/j.ijhydene.2012.03.028.

[104] Kayfeci M, Keçebas A, Bayat M. Hydrogen production. In: Sol. Hydrog. Prod,vol. 119. Elsevier; 2019. p. 45e83. https://doi.org/10.1016/B978-0-12-814853-2.00003-5.

[105] Verheul B. Overview of hydrogen and fuel cell developments in China. 2019.[106] Enel Enel. At Fusina ( venice ), inauguration of first industrial-scale hydrogen

plant in the world, vol. 795; 2010. p. 1e2. https://www.enel.com/content/dam/enel-com/pressrelease/porting_pressrelease/1634798-2_PDF-1.pdf.[Accessed 1 March 2020].

[107] Pambudi NA, Itaoka K, Yamakawa N, Kurosawa A. Future Japan powergeneration sector by introducing hydrogen plant with 80% CO2 emissionreduction target: a preliminary analysis. In: Proceeding - 2016 int confsustain energy eng appl sustain energy a better life, ICSEEA 2016; 2017.https://doi.org/10.1109/ICSEEA.2016.7873569. 66e9.

[108] Salameh Z. Energy storage. In: Renew. Energy syst. Des. Elsevier; 2014.p. 201e98. https://doi.org/10.1016/B978-0-12-374991-8.00004-0.

[109] Sadeghi S, Baniasad Askari I. Performance and economic investigation of acombined phosphoric acid fuel cell/organic Rankine cycle/electrolyzer sys-tem for sulfuric acid production; Energy-based organic fluid selection. Int JEnergy Res 2020;44:2704e25. https://doi.org/10.1002/er.5073.

[110] Abderezzak B. Introduction to hydrogen technology. In: Introd. To transf.Phenom. PEM fuel cell, vol. 4. Elsevier; 2018. p. 1e51. https://doi.org/10.1016/B978-1-78548-291-5.50001-9.

[111] Doosan starts installation of hydrogen-fueled 50 MW fuel cell power plant inSouth Korea. Fuel Cell Bull 2018;2018:1. https://doi.org/10.1016/S1464-2859(18)30270-0.

[112] Fuel Sd. Doosan FC to supply power plants for two major Korean projects.Fuel Cells Bull 2017 2017:7. https://doi.org/10.1016/s1464-2859(17)30114-1.

[113] Melaina M, Antonia O, Penev M. Blending hydrogen into natural gas pipelinenetworks. A Review of Key Issues 2013;303. https://doi.org/10.2172/1068610.

[114] Frazer-Nash Consultancy. Appraisal of domestic hydrogen appliances. 2018.[115] Staffell I, Scamman D, Velazquez Abad A, Balcombe P, Dodds PE, Ekins P, et al.

The role of hydrogen and fuel cells in the global energy system. EnergyEnviron Sci 2019;12:463e91. https://doi.org/10.1039/c8ee01157e.

[116] Atienza-M�arquez A, Bruno JC, Coronas A. Cold recovery from LNG-regasification for polygeneration applications. Appl Therm Eng 2018;132:463e78. https://doi.org/10.1016/j.applthermaleng.2017.12.073.

[117] U.S. Department of Energy. Hydrogen fuel cells fact sheet. 2006.