Overview study of LNG release prevention and control systems

More than 50 new Liquefied Natural Gas (LNG) importterminals are currently proposed for North America. Each of these developments will face the challenges of risk management and public risk perception. They are all dependent on support from local elected leadership and on a plan and ability to manage public communication. Failure to address these issues may cause rejected developments, lost opportunities and significant non-return costs. The questions of facility safety and security are raised as stakeholders and interest groups ask ‘what if’ questions regarding possible accident scenarios, such as ‘What is the maximum hazard area if a storage tank collapses, a LNG carrier is penetrated, or an offloading accident occurs?’ The questions are often characterized by misconceptions, but are nevertheless of vital importance. In order to answer thesequestions, safety and security aspects of LNG transport, storage and re-gasification must be communicated appropriately. How can the facility be perceived as ‘safe’ given the severity of the worst possible consequences from major accidents? Safety can be assured and enforced through compliance with a pre-defined set of risk acceptance criteria. These criteria can be absolute and tangible, or they may be more abstract. Different practices are accepted in different regions, countries, and states, as well as in different industry segments. Ideally, risk acceptance criteria should be regulated by authorities. This provides non-biased definition of safety and can remove safety as the alibi to oppose industrial developments. The debate can then focus on the real drivers for opposition such as deteriorated property values, deterioration of aesthetics and restrictions of pleasure craft activities in waterways also used by LNG carriers. Developers may use compliance with internationally recognized risk acceptance criteria if not enforced by regulators. It can be helpful in communication with stakeholders and gives credibility to safety documentation. Documentation of compliance with risk acceptance criteria provides answers to ‘How can I be safe without zero risk?’ Introduction North America is facing an increasing demand for natural gas; however, the domestic natural gas supply is decreasing. It is predicted that the United States will face a natural gas supply gap of about 5 trillion cubic feet by 2020 [1]. Therefore, the need for imports of LNG will continue to increase. In addition, the profitability and relatively low potential environmental impact from LNG will spur many projects over the next several years. Safety and security issues are brought to the fore when these projects are proposed. How should the risk associated with existing and proposed projects be presented to and perceived by the public? Stakeholders, including facility owners, public, and regulatory agencies, often have different points of view concerning LNG risk. The decision-making process concerning the projects becomes challenging when conflicts exist between the different parties. What risks are acceptable for the public? This paper will address the issue of risk acceptance criteria associated with LNG facilities.

Recent research in the liquefied natural gas (LNG) industry has concentrated on reducing specific power consumption (SPC) during production, which helps to lower operating costs and decrease the carbon footprint. Although reducing the SPC offers benefits, it can complicate the system and increase investment costs. This review investigates the thermodynamic parameters of various natural gas (NG) liquefaction technologies. It examines the cryogenic NG processes, including integrating NG liquid recovery plants, nitrogen rejection cycles, helium recovery units, and LNG facilities. It explores various approaches to improve hybrid NG liquefaction performance, including the application of optimization algorithms, mixed refrigerant units, absorption refrigeration cycles, diffusion–absorption refrigeration systems, auto-cascade absorption refrigeration processes, thermoelectric generator plants, liquid air cold recovery units, ejector refrigeration cycles, and the integration of renewable energy sources and waste heat. The review evaluates the economic aspects of hybrid LNG systems, focusing on specific capital costs, LNG pricing, and capacity. LNG capital cost estimates from academic sources (173.2–1184 USD/TPA) are lower than those in technical reports (486.7–3839 USD/TPA). LNG prices in research studies (0.2–0.45 USD/kg, 2024) are lower than in technical reports (0.3–0.7 USD/kg), based on 2024 data. Also, this review investigates LNG accidents in detail and provides valuable insights into safety protocols, risk management strategies, and the overall resilience of LNG operations in the face of potential hazards. A detailed evaluation of LNG plants built in recent years is provided, focusing on technological advancements, operational efficiency, and safety measures. Moreover, this study investigates LNG ports in the United States, examining their infrastructures, regulatory compliance, and strategic role in the global LNG supply chain. In addition, it outlines LNG’s current status and future outlook, focusing on key industry trends. Finally, it presents a market share analysis that examines LNG distribution by export, import, re-loading, and receiving markets.

Presented on Wednesday 22 May: Session 13 The liquefied natural gas (LNG) industry stands at the cusp of a transformation driven by the climate imperative. Focussing on the Middle Arm Industrial Precinct, this paper shows how carbon dioxide (CO2) emissions are being reduced in a proposed world-class LNG project by assessing, screening and selecting known technologies using a Marginal Abatement philosophy linked to key emissions drivers. (1) We propose a new breed of electrified LNG facilities that could deliver an up to 90% reduction in CO2 intensity. (2) We show that through developing strategic partnerships in upstream renewable power, hydrogen supply, and enabled downstream carbon capture and storage (CCS), the significant low carbon energy requirements of an LNG facility can be delivered. (3) We discuss a Marginal Abatement assessment strategy which ensures a pathway to viable lowest cost opportunities selected in an ‘Avoid & Mitigate’ first approach. This proposed strategy ensures that CO2 emission reduction opportunities are assessed and selected consistently to determine both a lifecycle cost ($) and volume (tons CO2e) of emission reduction. These innovative strategies collectively articulate a roadmap for a low carbon future for LNG and other heavy industrial industries, underlining Australia’s potential to become a leading provider of low-carbon natural resources. To access the Oral Presentation click the link on the right. To read the full paper click here

Transformers are used in Power systems to transform (step-down) voltages while maintaining the same frequency. Electrical Engineers designing power systems for Liquefied Natural Gas (LNG) or Petrochemical facilities typically use two-winding transformers to feed multiple process units in redundant distribution schemes throughout the facility. This method is repeated further to derive different voltage levels to feed process loads. As the industry moves towards larger production facilities which increase the power demand, multiple large two-winding transformers are utilized. This approach leads to increase in substation footprints, switchgear equipment, power feeders, site works, etc. This paper focuses on an alternative design using three-winding transformers for LNG or Petrochemical facilities. The input and output of a three-winding transformer generally consists of one primary (H) input, and two outputs defined as secondary (X) and tertiary (Y). Three-winding transformers are connected in a redundant configuration to feed multiple process units. In this paper, different types of three winding configurations and construction (radial or axial) methods are reviewed. In addition, this paper addresses the application of tap changers, overall system performance, defining impedance parameters, installation method, applications and specification requirements.

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) 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.

Validation of FLACS against experimental data sets from the model evaluation database for LNG vapor dispersion

Indonesia is an archipelago country with a scattered demand gas-fired power plant. Natural gas has potential to transform the role of energy in the domestic landscape, especially Liquefied Natural Gas (LNG). It could be the regulatory driver to apply the cleanest fossil-fuel energy. As a complement of renewable energy, LNG is still promising in the near future. It still provides sustainable and reliable energy. This opportunity triggers policy in technology to develop Small-Scale LNG (SSLNG) Facilities due to the particular condition of Indonesia. Besides technical issues, cost competitiveness has become the greatest challenge due to less the advantage of the economies of scale compared to conventional LNG. The collaborative works among governments, research bodies, the state-owned company, and the private sector are key points to realize the grand design of LNG infrastructure in Indonesia. The policies shall accommodate several sectors to stimulate the development of technology, feasible business schemes, and capacity building. Since the SSLNG supply chain is more complicated than conventional LNG projects and also involves more stakeholders, government leadership becomes more important. Identified considerations are also proposed as a result of opportunity and challenge mapping.

Application of computational fluid dynamics for LNG vapor dispersion modeling: A study of key parameters

Gorgon project One of the world’s largest natural-gas projects, involving one of the largest, most advanced carbon-dioxide-sequestration initiatives, is moving ahead in Coastal Western Australia. The Chevron-operated Gorgon project will develop offshore reservoirs for liquefied-natural-gas (LNG) export and domestic gas-market supply, centered around LNG and gas-plant facilities to be built on Barrow Island. Sanctioned in 2009, Gorgon is in its construction phase and is slated to begin operations in 2014. Not far behind is another huge Chevron-led natural-gas/LNG project, Wheatstone, in which company and third-party fields off Western Australia will be developed and tied into a planned coastal LNG-export and domestic-gas processing hub. Front-end engineering and design are under way, with a final investment decision expected in 2011. LNG exports to Asia Pacific customers are at the heart of both projects, which together point to a surging importance of Australian LNG in the world market. Australia is the world’s sixth largest exporter of LNG, and some market observers believe that anticipated projects could elevate Australia to No. 1 in world LNG exports within about a decade. ‘An Energy Sweet Spot’ “In every sense, the biggest game in town is the development of megaprojects for the export of LNG,” Western Australia Premier Colin Barnett said earlier this year. In a recent talk to the Australian Petroleum Production & Exploration Association, Roy Krzywosinski, managing director, Chevron Australia, said, “Our industry finds itself in an energy sweet spot, surrounded by natural-gas resources on the doorstep of the world’s biggest and fastest-growing market, the Asia Pacific region.” Gorgon’s reserves lie within the Greater-Gorgon-Area gas fields in the Carnarvon basin off the northwest coast of Western Australia. The initial phase of development includes 18 subsea wells to be drilled in two separate fields: Gorgon, approximately 80 miles offshore in 660 ft of water; and Jansz-Io, approximately 125 miles offshore in 4,300 ft of water. It is anticipated that up to 30 wells will be drilled in the Gorgon-area fields over approximately 30 years. From the wellheads, gas will flow to one of several cluster manifolds to be installed nearby on the seafloor, at which production from multiple wells will be combined and routed in a single flow path from each manifold to pipeline-termination structures. A system of flowlines will connect these termination points with each other. Produced gas will flow through lines leading from the termination structures and eventually traveling up a steep, 5/8-mile-high underwater escarpment en route to the Barrow Island processing facilities. All subsea equipment will be monitored and controlled from the onshore LNG plant by means of an electrohydraulic multiplexed system with primary fiber-optic communications, which will incorporate a system of subsea control umbilicals to tie in the seafloor infrastructure with the plant.

A hierarchical approach to optimize LNG fractionation units

This document provides a description of the model evaluation protocol (MEP) database for fires involving liquefied natural gas (LNG) and processing fuels at LNG facilities. The purpose of the MEP is to provide procedures regarding the assessment of a model?s suitability to predict thermal exclusion zones resulting from a fire. The database includes measurements from pool fire, jet fire, and fireball experiments which are provided in a spreadsheet. Users are to enter model results into the spreadsheet which automatically generates statistical performance measures and graphical comparisons with the experimental data. The intent of this document is to provide a description of the experiments and of the procedure required to carry out the validation portion of the MEP. In addition, the statistical performance measures, measurements for comparisons, and parameter variation are provided.

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.

Developing a CFD heat transfer model for applying high expansion foam in an LNG spill

This paper studies the possible impacts of liquefied natural gas (LNG) projects on natural gas prices on both sides of the U. S.-Mexico border in California. In that state gas prices are high and demand is expected to grow. Several projects for LNG facilities have been proposed and have to cope with public opinions against them. In Baja California, four LNG projects are under development given the rising demand forecasted for the next years. After a detailed study of the opportunity for LNG projects, we conclude with an analysis of the fundamentals of the current and future price formation in both sides of the U. S.Mexico border.