СОЗДАНИЕ ИНФРАСТРУКТУРЫ ИСПОЛЬЗОВАНИЯ СЖИЖЕННОГО ПРИРОДНОГО ГАЗА

In the last years, the increased demand of the energy market has led to the increasing penetration of renewable energies in order to achieve the primary energy supply. However, simultaneously natural gas still plays a key role in the energy market, mainly as gaseous fuel for stationary energy generation, but also as liquefied fuel, as an alternative to the diesel fuel, in vehicular applications. Liquefied Natural Gas (LNG) is currently produced in large plants directly located at the extraction sites. In this study, the idea of realizing plug & play solutions to produce LNG directly at vehicle’s filling stations has been investigated. A novel process of LNG production for filling stations has been analyzed, consisting in a single stage Joule-Thompson isenthalpic expansion process, with intercooled compression. Furthermore, the presented layout has been developed with the purpose of optimizing the energy consumption of the plant, obtaining moderately pressurized LNG. With the aim of investigating the feasibility of this novel LNG generation process, a thermodynamic analysis has been carried out and presented in this study. Moreover, the minimization of energy consumption has been investigated with a parametric analysis, in order to optimize the LNG production and to maximize the efficiency of the process. Furthermore, novel performance indicators have been defined, in order to account the efficiency of the LNG production process. Results of the optimization analysis show that, with the proposed layout, an energy consumption equal to about 1.9 MJ/kg of produced LNG can be achieved.

In the last years, the increased demand of the energy market has led to the increasing penetration of renewable energies, in order to achieve the primary energy supply. Simultaneously, natural gas is predicted to play a vital and strategic role in the energy market, on account of its lower environmental impact than other fossil fuels, both as gaseous fuel for stationary energy generation and as liquefied fuel. In particular, the Liquefied Natural Gas (LNG) is becoming interesting in transports as an alternative to diesel fuel, allowing a decrease in pollutant emissions and a reduction in fuel’s costs for the users. As a consequence, in this context, the LNG production process can be seen as an electrical storage system by the integration with renewables, becoming an interesting solution to avoid the issues related to intermittency and unpredictability of renewables. The aim of the paper is the development of a calculation code and the evaluation of the off-design operation of a LNG production plant coupled with wind renewable energy sources. With this purpose, on the basis of mathematical models from literature, a dedicated calculation code has been developed, able to thermodynamically analyze both design and off-design operation of the integrated process. In addition, in this study the proposed model is employed to investigate the correct integration between renewables and LNG generation, in order to define the optimal choice of the wind size for a given LNG production plant. With this purpose, the LNG plant size of a real prototype has been considered and an economic analysis has been carried out, accounting for the revenue of the LNG sale, the costs for NG purchase, for operation and maintenance and for the initial investment costs, but also with the aim to minimize the electricity introduction into the grid, considered in this study as a penalty.

Governments and Operators are researching the potential for the development of floating liquefied natural gas (LNG) production facilities as a means to monetize gas reserves and to eliminate flaring of natural gas associated with oil extraction. Floating Production Storage and Offtake (FPSO) vessel hulls may be constructed in either steel or concrete. Concrete hull structures offer a number of advantages for the support of cryogenic facilities and the storage of produced liquids. Additionally, concrete substructures may be constructed in country using a significant proportion of locally procured materials and labor. A concrete FPSO solution has been developed to support a two LNG train facility. The concrete hull may be configured to be much larger than traditional steel FPSO alternatives and need not limit the liquid storage volume or deck area. The proposed solution has sufficient deck area to allow the topside facilities to be configured with some modularization and preassembly using vendor supplied skids. Cryogenic liquid containment requirements have been reviewed for the offshore storage. It is concluded that "double" liquid containment should be adopted rather than the "partial double" containment typical of LNG carrier ships. The adoption of the double containment design criteria has implications for the alternate storage systems, membrane or prismatic self-supporting tanks. It is accepted that the membrane system can be shown to be double containment and is well suited to a concrete FPSO application. The prismatic self-supporting tankage system requires further development, but could also be used. Concrete hull vessels can be shown to be durable and stable. The proposed CFPSO arrangement has a wide beam that ensures superior stability and low motions in extreme environmental conditions. The proposed CFPSO construction could be carried out in country and has been shown to be feasible for several locations. Indicative costs are provided, which are competitive with other alternatives, especially on a life cycle evaluation. The 9MMTPA LNG production CFPSO may be completed within 43 months of EPIC contract signing. Introduction Governments and offshore oil and gas field operators are researching means by which natural gas from associated and stranded gas fields may be monetized. In addition, governments are legislating to limit or prohibit the flaring of gas associated with oil production. The result is an increasing interest in the development of offshore gas liquefaction installations, in particular the development of floating liquefied natural gas (LNG) production facilities. The primary focus of floating LNG proposals has beendirected toward steel hulled floating, production storage and offtake (FPSO) vessels. Steel hulled FPSOs may be procured from established shipyards and fitted out at an offshore fabrication and assembly facility. Established fabrication and assembly facilities are located in East Asia, Northern Europe and North America. Construction of the hull and topside facilities in a shipyard offers a number of benefits including contractor competition at bid stage. However, shipyards generally do not have the dock facilities to construct large concrete substructures. An alternative procurement strategy that incorporates local construction in purpose built graving docks is better suited to both the concrete substructure option and a procurement strategy that seeks to assemble the production facility locally..

1. Introduction: Qatar currently produces 77 mtpa of Liquefied Natural Gas (LNG), which dwarfs the 24 mtpa production of 2nd placed Indonesia. Production started as recently as 1997, compared to the several decades that other LNG producers have been in operation. This paper will review the key policy factors that have been responsible for Qatar's success story including leadership vision, efficient utilization of International Oil Companies’ (IOCs) expertise and technology, and a conducive hydrocarbons policy. 2. Qatar-Country Brief GDP trend, population 3. Qatar National Vision (QNV): Impact on the Energy Sector The QNV envisages that Qatar's hydrocarbon resources would be subject to cautious development in order to safeguard the interest of future generations, and there would be greater focus on non-hydrocarbon industries. 4. Hydrocarbon Legislation The Permanent Constitution of Qatar establishes the state's sovereignty over the ownership of its resources. 5. Qatar's Gas and LNG Sector Figures: * Qatar LNG Projects, 1997-2011 * Global LNG production by country * Qatar LNG production trend 6. Analysis of Development & Fiscal Agreements (DFAs) and Production Sharing Agreements (EPSAs/DPSAs) The DFA is joint venture between Qatar Petroleum and an IOC. Most LNG (and gas) agreements are structured as such, due to the strategic nature of Qatar's gas sector and the gigantic North Field, as well as the sophisticated liquefaction technology involved in LNG projects. The two main LNG joint ventures are RasGas and Qatargas. Most of the country's oil contracts have been awarded on the EPSA and DPSA basis, which do not have any state equity participation unlike the gas DFAs. These allow for exclusive grant of rights to explore and produce petroleum. 8. Conclusion:Qatar has kept a stable and prospective hydrocarbon regime that has attracted investors. The state wisely diversified its partnerships to include capable oil majors to spread the risks and to create a better bargaining position when negotiating fiscal terms, and preferred long-term Sale & Purchase Agreements with customers to safeguard future revenues. Through careful collaboration with IOCs and balanced bilateral contracts, the focus was on a win-win scenario for the investor and the government.

The article examines the current situation in the world production and consumption of the liquefied natural gas (LNG). The main global trends as well as the reasons for significant growth in LNG consumption in most countries are analyzed. The authors also study the structure of global import of LNG and the opportunities for increasing supplies by the Russian energy companies. Russian companies are primarily supplying LNG to European countries. However, the results of the analysis show high export potential of the Asian market. Realizing the potential is the most important strategic task for domestic energy companies. The article also examines the history and the current process of developing LNG production on the Russian territory. The authors reveal various aspects of the current implementation of such projects as “Yamal LNG” and “Arctic LNG 2” within the Arctic area of the Russian Federation. Particularly, the authors describe development of transportation-logistics system as part of these projects. Moreover, the article contains the analysis of the problem of ensuring technological independence in the process of implementation of LNG projects. Russian energy companies should increase their technological independence and localization of production by consistent implementation of the import substitution strategy. One of the solutions in ensuring technological independence is innovation technology of natural gas liquefaction “Arctic Cascade”. The article presents the detailed technical and economical aspect of implementing this technology. Using this technology ensures 30 % reduction of the LNG production cost price. Besides, this innovation technology can ensure 100 % localization of production.

A variable capacity, small-scale liquefied natural gas (LNG) refueling system has been designed, built, and tested at the Cryofuel Systems’ Laboratory, University of Victoria, Canada. The system, designed to continuously liquefy between 5 and 15 litres of NG, utilizes liquid nitrogen (LN2) as its cold source and contains most of the components found in a typical commercial refueling system; ie. purification system, liquefier, LNG storage, automatic control and monitoring system. This paper describes the design of the system as well as the results of a set of LNG production trials. The performance of the system exceeded expected LNG production rates, but at levels of efficiency somewhat less than predicted. Cryofuel Systems expects to use this system to implement an LNG vehicle demonstration program and to gain experience in the integration of LNG refueling systems which exploit advanced liquefaction technology such as magnetic refrigeration.

Produced natural gas must be treated to ensure high efficiency removal of sulfurous contaminants before it can be processed into liquefied natural gas (LNG).The selection of processes for removal of H2S may be a straightforward decision with extensive supporting data available. However, when the produced natural gas feedstock contains significant mercaptan, COS or other sour components, the process selection and design may become extremely complex. Several issues including process selectivity, energy requirements, total sulfur recovery, hydrocarbon coabsorption, and impact on downstream facilities will be weighed in this poster. When technologies are being evaluated for use in pretreatment of gas for LNG production for the first time, the extremely high reliability and strict specifications of the LNG process must be taken into consideration. Often the processes under consideration are provided by licensors, and evaluation of data from historical applications should be undertaken cooperatively by the licensor and the operator to ensure that all facets of the operation are well understood. This is particularly challenging since it is rare to encounter exactly the same compositions and conditions more than once in the midstream. LNG facilities operating in Qatar have installed multiple processes to maximize sulfur recovery at minimum cost. Based on the operating data from these units, ExxonMobil in cooperation with RasGas Company Limited (RasGas) has developed dynamic models and modified processes to optimize the operation of the existing facilities and the design of future ones. This work is aimed at high reliability, high efficiency, environmentally sound process units that support maximum LNG production at the lowest supply cost. Background RasGas has extensive experience in operating gas sweetening and sulfur recovery units. In addition to moderate concentrations of H2S and CO2 that must be removed from the produced gas, a variety of mercaptans and other sulfur containing species compose up to 400 ppm of the gas. In RasGas Trains 1 and 2, Sulfinol-D was chosen as the gas sweetening process, and the acid gas stream was directed to an Acid Gas Enrichment unit before entering the Sulfur Recovery Unit. This system has worked effectively to achieve the very low levels of total sulfur (< 14 ppm) required for the liquefied product.

This paper describes the important regulatory changes underway in the United States (US) that will dramatically affect the design, construction, and operation of offshore terminals for importing liquefied natural gas (LNG). Numerous US oil and gas companies are developing projects to build offshore terminals for importing LNG into the US. As the offshore LNG terminal concept applies new technology, regulatory and technical design rules that will apply to these facilities are rapidly evolving. With the passage of the Maritime Transportation Security Act of 2002, the Deepwater Port Act of 1974 (DWPA) (33 USC 1501-1524) has been amended to include natural gas, fundamentally altering the regulatory process for offshore LNG terminals. Whereas the Federal Energy Regulatory Commission (FERC) and the US Coast Guard (USCG) previously played important roles in permitting and regulating onshore LNG facilities, the USCG and the US Maritime Administration (MARAD) now share the primary responsibility of regulating these facilities offshore, with subsidiary roles played by other federal agencies and the involved states. This paper examines the USCG's new role in offshore LNG terminal development, as well as the major requirements the DWPA imposes on applicants. The USCG will soon publish implementing regulations. DWPA requirements that previously applied to oil, now provide clues regarding the likely environmental review process. Although the USCG will be moving to the Department of Homeland Security, siting and operational oversight for deepwater ports is expected to remain with the Secretary of the Department of Transportation (SECDOT). This paper examines the Deepwater Port regulatory process and describes how these complex licensing requirements could affect the proposed siting, commercial viability, and environmental regulatory review of offshore LNG terminals. This paper also examines current efforts by various classification societies to develop technical guidance regarding the design, construction, and ongoing maintenance of offshore LNG terminals. The ABS Guidance Notes on Building and Classing Offshore LNG Terminals will be presented as an example of classification society efforts to fill the US regulatory void that currently exists for the technical requirements of offshore LNG terminals. In conclusion, this paper proposes a process to combine current regulations with classification society guidance as an effective means of developing appropriate design, construction, and operational requirements for offshore LNG terminals. Such a process may be helpful to US regulators in expediting the regulatory approval process for offshore LNG terminals currently being developed. Finally, this paper assists developers of offshore LNG terminals in understanding the complex US regulatory process and developing effective strategies to expedite critical regulatory approvals. The US Regulatory Scheme for LNG Terminals Prior to the passage of the Maritime Transportation Security Act of 2002 by Congress, and its signing by President Bush on November 25, 2002, FERC had jurisdiction over the siting of LNG import terminals under Section 3 of the Natural Gas Act. FERC asserted that this authority applied to both onshore and offshore LNG terminals.

Liquefied natural gas (LNG) and offshore activities have much in common. - The ultimate goal of each is to produce and deliver hydrocarbons to the market. - The main oil operators are active in LNG as well as other offshore activities (e.g., ExxonMobil, Shell, BP, Total, and ChevronTexaco). - Production is transported over long distances by carriers (even if LNG carriers are far more sophisticated than oil tankers!). But, until now, LNG production plants have always been built onshore, even when gas is produced offshore (e.g., Qatar, Trinidad, and Sakhalin). The first concepts of LNG floating production, storage, and offloading (FPSO) vessels were presented by the industry in the mid-1970s. These concepts were targeting stand-alone gasfield developments or associated gas fields. Even if an LNG FPSO appears economically very attractive when compared with a “grass roots” onshore LNG plant, the operators seem not to have found the proper location or the correct “scheme” to select an LNG FPSO for developing an offshore gas field. At the other end of the LNG chain, huge investments also are foreseen to build facilities for the reception and regasification of LNG to cope with a fast-growing demand for gas. Many terminals are under construction or planned in many countries. This increased demand is not without obstacles. In some areas of North America or Europe (Italy for example), environmental constraints prevent the installation of newly built, land-based LNG terminals. As a result, the projects are moving offshore, taking the shape of fixed, gravity-based structures or floating storage and regasification units. In this offshore move of the LNG industry—“tomorrow” for the receiving terminals and the “day after tomorrow” for LNG FPSOs—those who combine LNG and offshore expertise will be key players in this new arena. Additional Offshore Facilities Construction and Design Technical Papers Available at the SPE eLibrary: www.spe.org SPE 89998 - Subsea HIPPS: A Way To Develop High-Pressure Subsea Fields Available at the OTC Library: www.otcnet.org OTC 16106 - Monitoring of Sand Deposition in Subsea Separators OTC 16185 - High-Strength Aluminum Alloys for Deepwater Riser Applications

This study presents a comparative review of the environmental implications of Liquefied Natural Gas (LNG) usage in the United States (USA) and Africa, examining the policies that govern LNG-related environmental concerns in these regions. Recognizing the global significance of LNG as a pivotal energy source, the analysis explores the distinct policy landscapes shaping its utilization in two diverse contexts. In the USA, where LNG has emerged as a key component of the energy mix, the study scrutinizes federal and state-level environmental policies. This includes regulations governing the extraction, production, and transportation of LNG, with a focus on mitigating emissions, preserving air and water quality, and ensuring ecological sustainability. The review also encompasses the regulatory frameworks promoting the integration of LNG into the broader strategy for reducing carbon footprints in the country. In contrast, the study delves into the nuanced environmental policies across multiple African nations where LNG is increasingly gaining prominence. Africa, with its unique environmental challenges and diverse regulatory approaches, presents a dynamic landscape for LNG utilization. The analysis explores how environmental policies address the specific needs and challenges of African nations, emphasizing sustainable practices, biodiversity conservation, and community welfare. By undertaking this comparative review, the study aims to highlight commonalities and disparities in the environmental policies governing LNG usage in the USA and Africa. Understanding these variations can contribute to the development of informed and context-specific approaches to LNG-related environmental challenges. Additionally, the study seeks to identify areas for potential collaboration and knowledge exchange, fostering a global dialogue on sustainable LNG practices. Ultimately, the findings aim to inform policymakers, industry stakeholders, and environmental advocates, promoting responsible LNG usage that aligns with both regional and global environmental goals.

Last year, 244 million tonnes per annum (MTPA) of liquefied natural gas (LNG) was transported around the globe. The recent shale gas revolution, coupled with low domestic natural gas prices, has led many operators in the US to consider export of their gas to more lucrative markets in Asia and Europe. More than 25 LNG projects have been proposed in the US, totaling a capacity of more than 200 MTPA. The Federal Energy Regulatory Commission (FERC) has approved five LNG terminals in the US. Most experts believe US LNG export capabilities will be about 10% of domestic production in the coming years, which puts LNG export estimates between 6 and 8 Bscf/D. The question remains, where will all of this gas come from? The vast amount of increased gas production in the onshore US will come from growth in the shale gas plays. These plays, including the Barnett, Fayetteville, Woodford, Marcellus, Haynesville, Eagle Ford, and others, will be further exploited to supply domestic needs and the new LNG export demand. A typical proposed US LNG train is estimated to output 4.5 MTPA, which requires an input of around 636 MMscf/D. It will take a significant quantity of shale gas wells to deliver enough gas to keep a train at full capacity. This paper addresses the impact that LNGdriven natural gas demand will have on the future development of shale gas plays in the US. Increased demand on domestic US natural gas supplies will be met with increased development drilling. In order to quantify the impact of LNG exports on the market, this paper considers the number of horizontal shale gas wells needed to supply one LNG train continuously. Shale gas basins around the US were studied to estimate both the number of wells needed to supply a train initially and the number and frequency of future wells that will need to be drilled to maintain the train at full capacity. Current activities, including infrastructure and rig counts, decline trends, economics, and drilling times are included in the analysis. This paper discusses the impact future increased LNG gas demand will have on the field development plans of shale gas plays and identifies probable future activity levels in shale gas basins due to exploitation activity focused on LNG supply. The feasibility of LNG export from the US is a topic of debate, and this paper will provide context and rationale for the discussions. LNG Global Historical Perspective LNG has been around for over 100 years. LNG was discovered during a focus on cryogenics in the late 1800s when scientists took on the challenge to liquefy all known gases. In 1886, natural gas was first liquefied by lowering its temperature to –260°F. LNG didn’t have much commercial application until the discovery that liquefying natural gas was a way to produce helium. LNG was the first discovered means to capture helium in large quantities. Helium was believed to be a rare element and it was the last gas to be liquefied in 1908. Once the process to liquefy natural gas had been developed, the next challenge was its transportation. The idea of transporting LNG was advanced during World War I, as governments sought to utilize the extremely valuable and rare helium in dirigibles (The Oil Drum 2012; Hrastar 2014). The first US patent for LNG shipping URTeC 2015 Page 2328

ABSTRACT: The rapid economic progress of Bangladesh is associated with a swiftly rising demand and energy consumption. Future economic growth will undoubtedly require a proportionate increase in energy availability within affordable prices. Bangladesh is inherently energy-scarce and heavily dependent on imported energy, primarily fossil fuels. Several approaches and strategies were attempted over time to mitigate the energy shortage. Some of them were reasonably successful, while others failed. In this study, we first examine the historical developments of the energy sector in Bangladesh since its independence and then use three approaches – triple exponential smoothing, vector autoregression, and the Cochrane-Orcutt AR(1) process to forecast the energy demand. Data for this study were taken from various sources, including British Petroleum, International Gas Union, International Energy Agency, Bangladesh Bureau of Statistics, World Bank, Petrobangla, and Energy Information Agency of the United States. As expected, each model predicts an exponential growth of energy demand in Bangladesh. We then explored the possibilities of mitigating such projected energy demand. Various studies show that Bangladesh has some potential for producing energy from renewable sources, i.e., solar, hydro, wind, wave, and others. However, such possibilities are limited, and many are still in their infancy. Although an increase in renewable energy is desirable from an environmental perspective, it alone will not meet Bangladesh's growing energy demand. At least in the short term, Bangladesh must rely on imported fossil energy. Among the fossil energy sources, LNG is by far the cleanest. With the development of technology, liquefaction, transportation, and regasification, LNG production, transportation, and use are becoming less expensive. Progressively more natural gas-producing countries are joining LNG production and export, contributing to the market's competitiveness. Though historically tied to the oil market, LNG markets are becoming more and more independent because of the increasing number of participants from both the demand and supply sides. Given that both its global price and negative impact on the environment are relatively lower than other fossil fuels, imported LNG should be the fuel of choice for Bangladesh. Government policies should focus on both importing LNG and expanding renewable energy resources.

_ Liquefied natural gas (LNG) has been in global energy supply discussions for decades. Geopolitical tensions, however, recently elevated it from a bullet point to the entire conversation. Rarely does a day pass without mention of signed long-term LNG purchase agreements or LNG terminal construction projects advancing, one day making it possible to transport the curiously cold molecules across oceans to eventually power industries or heat homes. So strong are the fundamentals of the LNG industry, for example, that they were cited as a primary driver in the conversion of one of the largest pure-play US-listed shipping companies—Capital Product Partners led by Greek shipowner Evangelos Marinakis—to a pure-play LNG shipping company. In addition to changing its name to Capital New Energy Carriers, the partnership is selling off its modern fleet of 15 Neo-Panamax and Panamax container vessels. It will spend $3.13 billion to purchase 11 newbuild LNG carriers (LNGC). According to an announcement on 13 November, the first of the new vessels arrived in October 2023. The company already had seven LNG carriers in its fleet, with the remaining 10 newbuild vessels scheduled for delivery through March 2027. Jerry Kalogiratos, chief executive of Capital Product Partners, said the acquisition was transformative, noting that the partnership “expects our contracted revenues to increase by 87% percent to $3.1 billion, our revenue weighted charter duration to 7.2 years as of the closing date, and the average age of our LNG fleet to decrease to 3.2 years by the time all LNGCs have been delivered in 2027.” LNG Market Overview Events like the Russian invasion of Ukraine in February 2022 and the sudden loss of Russian pipeline gas supplies upended global energy markets. European buyers turned to LNG imports to meet demand. According to Wood Mackenzie, the current conflict in Israel/Gaza, possible pipeline sabotage in the Baltics, and the threat of fresh strike action at Australian LNG facilities all pushed spot prices up 35% through October. In a November blog post, Wood Mackenzie noted that a record 200 mtpa of new supply is under construction as “players bet big on Asia’s push to reduce its dependence on coal and Europe’s need to replace Russian gas.” While the proliferation of LNG projects is prompting concerns that there may be too much LNG on the market once these projects are completed, this is not the case, according to Wood Mackenzie. “Increased supply availability will bring prices down and boost demand growth,” said Gavin Thompson, vice chair of Europe, Middle East, and Africa, and Massimo Di Odoardo, vice president, gas and LNG research for Wood Mackenzie, noting that the market will need another 60 mtpa of new LNG by 2033. “Much will hinge on sustained economic growth, driving increased demand across emerging markets in Asia. China’s LNG demand will increase by 12% in 2023, and with 50 mtpa of LNG contracted over the past 2 years, imports will double by 2030. LNG demand in South and Southeast Asia will also grow twofold by this time,” they said.

abstractEnergy markets are an important contemporary site of economic globalization. In this article we use a global production network (GPN) approach to examine the evolutionary dynamics of the liquefied natural gas (LNG) sector and its role in an emerging global market for natural gas. We extend recent work in the relational economic geography literature on the organizational practices by which production networks are assembled and sustained over time and space; and we address a significantly underdeveloped aspect of GPN research by demonstrating the implications of these practices for the territoriality of GPNs. The article introduces LNG as a techno-material reconfiguration of natural gas that enables it to be moved and sold beyond the continental limits of pipelines. We briefly outline the evolving scale and geographic scope of LNG trade, and introduce the network of firms, extraeconomic actors, and intermediaries through which LNG production, distribution, and marketing are coordinated. Our analysis shows how LNG is evolving from a relatively simple floating pipeline model of point-to-point, binational flows orchestrated by producing and consuming companies and governed by long-term contracts, to a more geographic and organizationally complex production network that is constitutive of an emergent global gas market. Empirically the article provides the first systematic analysis within economic geography of the globalization of the LNG sector and its influence on global gas markets, demonstrating the potential of GPN (and related frameworks) to contribute meaningful analysis of the contemporary political economy of energy. Conceptually the article pushes research on GPN to realize more fully its potential as an analysis of network territoriality by examining how the spatial configuration of GPNs emerges from the organizational structures and coordinating strategies of firms, extraeconomic actors and intermediaries; and by recognizing how network territoriality is constitutive of markets rather than merely responsive to them.

Addressing methane emissions across the liquefied natural gas (LNG) supply chain is key to reducing climate impacts of LNG. Actions to address methane emissions have emphasized the importance of the use of measurement-informed emissions inventories given the systematic underestimation in official greenhouse gas (GHG) emission inventories. Despite significant progress in field measurements of GHG emissions across the natural gas supply chain, no detailed measurements at US liquefaction terminals are publicly available. In this work, we conduct multiscale, periodic measurements of methane and carbon dioxide emissions at two US LNG terminals over a 16-month campaign. We find that methane emission intensity varied from 0.007% to 0.045%, normalized to methane in LNG production. Carbon dioxide emissions accounted for over 95% of total GHG emissions using 100-year global warming potential (GWP) for methane. Thus, contrary to observations across other natural gas supply chain segments, we find that reported GHG emissions intensity closely matches measurement informed GHG emissions intensity of 0.24-0.27 kg CO2e/kg CH4. In the context of developing LNG supply chain emissions intensity, we conclude that the use of the Greenhouse Gas Reporting Program emissions intensity provides reasonably accurate estimates of total GHG emissions at LNG terminals.