Liquefied natural gas (LNG) is natural gas (predominantly methane, CH4, with some mixture of ethane, C2H6) that has been cooled down to liquid form for ease and safety of non-pressurized storage or transport. It takes up about 1/600th the volume of natural gas in the gaseous state at standard conditions for temperature and pressure.
LNG is odorless, colorless, non-toxic and non-corrosive. Hazards include flammability after vaporization into a gaseous state, freezing and asphyxia. The liquefaction process involves removal of certain components, such as dust, acid gases, helium, water, and heavy hydrocarbons, which could cause difficulty downstream. The natural gas is then condensed into a liquid at close to atmospheric pressure by cooling it to approximately −162 °C (−260 °F); maximum transport pressure is set at around 25 kPa (4 psi) (gauge pressure), which is about 1.25 times atmospheric pressure at sea level.
The gas extracted from underground hydrocarbon deposits contains a varying mix of hydrocarbon components, which usually includes mostly methane (CH4), along with ethane (C2H6), propane (C3H8) and butane (C4H10). Other gases also occur in natural gas, notably CO2. These gases have wide-ranging boiling points and also different heating values, allowing different routes to commercialization and also different uses. The "acidic" elements such as hydrogen sulphide (H2S) and carbon dioxide (CO2), together with oil, mud, water, and mercury, are removed from the gas to deliver a clean sweetened stream of gas. Failure to remove much or all of such acidic molecules, mercury, and other impurities could result in damage to the equipment. Corrosion of steel pipes and amalgamization of mercury to aluminum within cryogenic heat exchangers could cause expensive damage.
La corriente de gas normalmente se separa en fracciones licuadas de petróleo (butano y propano), que pueden almacenarse en forma líquida a una presión relativamente baja, y fracciones más ligeras de etano y metano. Estas fracciones más ligeras de metano y etano luego se licuan para formar la mayor parte del GNL que se envía.
Durante el siglo XX, se consideró que el gas natural no tenía importancia económica allí donde los yacimientos de petróleo o gas productores de gas estaban distantes de los gasoductos o estaban ubicados en ubicaciones costa afuera donde los gasoductos no eran viables. En el pasado, esto generalmente significaba que el gas natural producido se quemaba , especialmente porque, a diferencia del petróleo, no existía ningún método viable para el almacenamiento o transporte de gas natural aparte de los gasoductos comprimidos hasta los usuarios finales del mismo gas. Esto significó que los mercados de gas natural eran históricamente enteramente locales y cualquier producción tenía que consumirse dentro de la red local o regional.
Los avances en los procesos de producción, el almacenamiento criogénico y el transporte crearon efectivamente las herramientas necesarias para comercializar el gas natural en un mercado global que ahora compite con otros combustibles. Además, el desarrollo del almacenamiento de GNL también introdujo una confiabilidad en las redes que antes se pensaba imposible. Dado que el almacenamiento de otros combustibles es relativamente fácil mediante tanques simples, se podría mantener almacenado un suministro para varios meses. Con la llegada del almacenamiento criogénico a gran escala, fue posible crear reservas de almacenamiento de gas a largo plazo. Estas reservas de gas licuado podrían desplegarse en cualquier momento a través de procesos de regasificación , y hoy son el principal medio para que las redes manejen los requisitos locales de reducción de picos . [1]
El poder calorífico depende de la fuente de gas que se utiliza y del proceso que se utiliza para licuar el gas. El rango de poder calorífico puede abarcar ±10 a 15 por ciento. Un valor típico del poder calorífico superior del GNL es aproximadamente 50 MJ/kg o 21.500 BTU/lb. [2] Un valor típico del poder calorífico inferior del GNL es 45 MJ/kg o 19.350 BTU/lb.
A efectos de comparación de diferentes combustibles, el poder calorífico puede expresarse en términos de energía por volumen, lo que se conoce como densidad de energía expresada en MJ/litro. La densidad del GNL es aproximadamente de 0,41 kg/litro a 0,5 kg/litro, dependiendo de la temperatura, la presión y la composición, [3] en comparación con el agua a 1,0 kg/litro. Utilizando el valor medio de 0,45 kg/litro, los valores típicos de densidad de energía son 22,5 MJ/litro (basado en un poder calorífico más alto) o 20,3 MJ/litro (basado en un poder calorífico más bajo).
The volumetric energy density of LNG is approximately 2.4 times that of compressed natural gas (CNG), which makes it economical to transport natural gas by ship in the form of LNG. The energy density of LNG is comparable to propane and ethanol but is only 60 percent that of diesel and 70 percent that of gasoline.[4]
Experiments on the properties of gases started early in the 17th century. By the middle of the seventeenth century Robert Boyle had derived the inverse relationship between the pressure and the volume of gases. About the same time, Guillaume Amontons started looking into temperature effects on gas. Various gas experiments continued for the next 200 years. During that time there were efforts to liquefy gases. Many new facts about the nature of gases were discovered. For example, early in the nineteenth century Cagniard de la Tour showed there was a temperature above which a gas could not be liquefied. There was a major push in the mid to late nineteenth century to liquefy all gases. A number of scientists including Michael Faraday, James Joule, and William Thomson (Lord Kelvin) did experiments in this area. In 1886 Karol Olszewski liquefied methane, the primary constituent of natural gas. By 1900 all gases had been liquefied except helium, which was liquefied in 1908.
The first large-scale liquefaction of natural gas in the U.S. was in 1918 when the U.S. government liquefied natural gas as a way to extract helium, which is a small component of some natural gas. This helium was intended for use in British dirigibles for World War I. The liquid natural gas (LNG) was not stored, but regasified and immediately put into the gas mains.[5]
The key patents having to do with natural gas liquefaction date from 1915 and the mid-1930s. In 1915 Godfrey Cabot patented a method for storing liquid gases at very low temperatures. It consisted of a Thermos bottle-type design which included a cold inner tank within an outer tank; the tanks being separated by insulation. In 1937 Lee Twomey received patents for a process for large-scale liquefaction of natural gas. The intention was to store natural gas as a liquid so it could be used for shaving peak energy loads during cold snaps. Because of large volumes it is not practical to store natural gas, as a gas, near atmospheric pressure. However, when liquefied, it can be stored in a volume 1/600th as large. This is a practical way to store it but the gas must be kept at −260 °F (−162 °C).
There are two processes for liquefying natural gas in large quantities. The first is the cascade process, in which the natural gas is cooled by another gas which in turn has been cooled by still another gas, hence named the "cascade" process. There are usually two cascade cycles before the liquid natural gas cycle. The other method is the Linde process, with a variation of the Linde process, called the Claude process, being sometimes used. In this process, the gas is cooled regeneratively by continually passing and expanding it through an orifice until it is cooled to temperatures at which it liquefies. This process was developed by James Joule and William Thomson and is known as the Joule–Thomson effect. Lee Twomey used the cascade process for his patents.
The East Ohio Gas Company built a full-scale commercial LNG plant in Cleveland, Ohio, in 1940 just after a successful pilot plant built by its sister company, Hope Natural Gas Company of West Virginia. This was the first such plant in the world. Originally it had three spheres, approximately 63 feet in diameter containing LNG at −260 °F. Each sphere held the equivalent of about 50 million cubic feet of natural gas. A fourth tank, a cylinder, was added in 1942. It had an equivalent capacity of 100 million cubic feet of gas. The plant operated successfully for three years. The stored gas was regasified and put into the mains when cold snaps hit and extra capacity was needed. This precluded the denial of gas to some customers during a cold snap.
The Cleveland plant failed on October 20, 1944, when the cylindrical tank ruptured, spilling thousands of gallons of LNG over the plant and nearby neighborhood. The gas evaporated and caught fire, which caused 130 fatalities.[6] The fire delayed further implementation of LNG facilities for several years. However, over the next 15 years new research on low-temperature alloys, and better insulation materials, set the stage for a revival of the industry. It restarted in 1959 when a U.S. World War II Liberty ship, the Methane Pioneer, converted to carry LNG, made a delivery of LNG from the U.S. Gulf Coast to energy-starved Great Britain. In June 1964, the world's first purpose-built LNG carrier, the Methane Princess, entered service.[7] Soon after that a large natural gas field was discovered in Algeria. International trade in LNG quickly followed as LNG was shipped to France and Great Britain from the Algerian fields. One more important attribute of LNG had now been exploited. Once natural gas was liquefied it could not only be stored more easily, but it could be transported. Thus energy could now be shipped over the oceans via LNG the same way it was shipped in the form of oil.
The LNG industry in the U.S. restarted in 1965 with the building of a number of new plants, which continued through the 1970s. These plants were not only used for peak-shaving, as in Cleveland, but also for base-load supplies for places that never had natural gas before this. A number of import facilities were built on the East Coast in anticipation of the need to import energy via LNG. However, a recent boom in U.S. natural gas production (2010–2014), enabled by hydraulic fracturing ("fracking"), has many of these import facilities being considered as export facilities. The first U.S. LNG export was completed in early 2016.[8]
By 2023, the U.S. had become the biggest exporter in the world, and projects already under construction or permitted would double its export capacities by 2027.[9] The largest exporters were Cheniere Energy Inc., Freeport LNG, and Venture Global LNG Inc.[10] The U.S. Energy Information Administration reported that the U.S. had exported 4.3 trillion cubic feet in 2023.[11]
The process begins with the pre-treatment of a feedstock of natural gas entering the system to remove impurities such as H2S, CO2, H2O, mercury and higher-chained hydrocarbons. Feedstock gas then enters the liquefaction unit where it is cooled to between -145 °C and -163 °C.[12] Although the type or number of heating cycles and/or refrigerants used may vary based on the technology, the basic process involves circulating the gas through aluminum tube coils and exposure to a compressed refrigerant.[12] As the refrigerant is vaporized, the heat transfer causes the gas in the coils to cool.[12] The LNG is then stored in a specialized double-walled insulated tank at atmospheric pressure ready to be transported to its final destination.[12]
Most domestic LNG is transported by land via truck/trailer designed for cryogenic temperatures.[12] Intercontinental LNG transport travels by special tanker ships. LNG transport tanks comprise an internal steel or aluminum compartment and an external carbon or steel compartment with a vacuum system in between to reduce the amount of heat transfer.[12] Once on site, the LNG must be stored in vacuum insulated or flat bottom storage tanks.[12] When ready for distribution, the LNG enters a regasification facility where it is pumped into a vaporizer and heated back into gaseous form.[12] The gas then enters the gas pipeline distribution system and is delivered to the end-user.[12]
The natural gas fed into the LNG plant will be treated to remove water, hydrogen sulfide, carbon dioxide, benzene and other components that will freeze under the low temperatures needed for storage or be destructive to the liquefaction facility. LNG typically contains more than 90% methane. It also contains small amounts of ethane, propane, butane, some heavier alkanes, and nitrogen. The purification process can be designed to give almost 100% methane. One of the risks of LNG is a rapid phase transition explosion (RPT), which occurs when cold LNG comes into contact with water.[13]
The most important infrastructure needed for LNG production and transportation is an LNG plant consisting of one or more LNG trains, each of which is an independent unit for gas liquefaction and purification. A typical train consists of a compression area, propane condenser area, and methane and ethane areas.
The largest LNG train in operation is in Qatar, with a total production capacity of 7.8 million tonnes per annum (MTPA). LNG is loaded onto ships and delivered to a regasification terminal, where the LNG is allowed to expand and reconvert into gas. Regasification terminals are usually connected to a storage and pipeline distribution network to distribute natural gas to local distribution companies (LDCs) or independent power plants (IPPs).
Information for the following table is derived in part from publication by the U.S. Energy Information Administration.[14]
See also List of LNG terminals
The LNG industry developed slowly during the second half of the last century because most LNG plants are located in remote areas not served by pipelines, and because of the high costs of treating and transporting LNG. Constructing an LNG plant costs at least $1.5 billion per 1 MTPA capacity, a receiving terminal costs $1 billion per 1 bcf/day throughput capacity and LNG vessels cost $200 million–$300 million.
In the early 2000s, prices for constructing LNG plants, receiving terminals and vessels fell as new technologies emerged and more players invested in liquefaction and regasification. This tended to make LNG more competitive as a means of energy distribution, but increasing material costs and demand for construction contractors have put upward pressure on prices in the last few years. The standard price for a 125,000 cubic meter LNG vessel built in European and Japanese shipyards used to be US$250 million. When Korean and Chinese shipyards entered the race, increased competition reduced profit margins and improved efficiency—reducing costs by 60 percent. Costs in US dollars also declined due to the devaluation of the currencies of the world's largest shipbuilders: the Japanese yen and Korean won.
Since 2004, the large number of orders increased demand for shipyard slots, raising their price and increasing ship costs. The per-ton construction cost of an LNG liquefaction plant fell steadily from the 1970s through the 1990s. The cost reduced by approximately 35 percent. However, recently the cost of building liquefaction and regasification terminals doubled due to increased cost of materials and a shortage of skilled labor, professional engineers, designers, managers and other white-collar professionals.
Due to natural gas shortage concerns in the northeastern U.S. and surplus natural gas in the rest of the country, many new LNG import and export terminals are being contemplated in the United States. Concerns about the safety of such facilities create controversy in some regions where they are proposed. One such location is in the Long Island Sound between Connecticut and Long Island. Broadwater Energy, an effort of TransCanada Corp. and Shell, wishes to build an LNG import terminal in the sound on the New York side. Local politicians including the Suffolk County Executive raised questions about the terminal. In 2005, New York Senators Chuck Schumer and Hillary Clinton also announced their opposition to the project.[25] Several import terminal proposals along the coast of Maine were also met with high levels of resistance and questions. On September 13, 2013, the U.S. Department of Energy approved Dominion Cove Point's application to export up to 770 million cubic feet per day of LNG to countries that do not have a free trade agreement with the U.S.[26] In May 2014, the FERC concluded its environmental assessment of the Cove Point LNG project, which found that the proposed natural gas export project could be built and operated safely.[27] Another LNG terminal is currently proposed for Elba Island, Georgia, US.[28] Plans for three LNG export terminals in the U.S. Gulf Coast region have also received conditional Federal approval.[26][29] In Canada, an LNG export terminal is under construction near Guysborough, Nova Scotia.[30]
In the commercial development of an LNG value chain, LNG suppliers first confirm sales to the downstream buyers and then sign long-term contracts (typically 20–25 years) with strict terms and structures for gas pricing. Only when the customers are confirmed and the development of a greenfield project deemed economically feasible, could the sponsors of an LNG project invest in their development and operation. Thus, the LNG liquefaction business has been limited to players with strong financial and political resources. Major international oil companies (IOCs) such as ExxonMobil, Royal Dutch Shell, BP, Chevron, TotalEnergies and national oil companies (NOCs) such as Pertamina and Petronas are active players.
LNG is shipped around the world in specially constructed seagoing vessels. The trade of LNG is completed by signing an SPA (sale and purchase agreement) between a supplier and receiving terminal, and by signing a GSA (gas sale agreement) between a receiving terminal and end-users.[31] Most of the contract terms used to be DES or ex ship, holding the seller responsible for the transport of the gas. With low shipbuilding costs, and the buyers preferring to ensure reliable and stable supply, however, contracts with FOB terms increased. Under such terms the buyer, who often owns a vessel or signs a long-term charter agreement with independent carriers, is responsible for the transport.
LNG purchasing agreements used to be for a long term with relatively little flexibility both in price and volume. If the annual contract quantity is confirmed, the buyer is obliged to take and pay for the product, or pay for it even if not taken, in what is referred to as the obligation of take-or-pay contract (TOP).
In the mid-1990s, LNG was a buyer's market. At the request of buyers, the SPAs began to adopt some flexibilities on volume and price. The buyers had more upward and downward flexibilities in TOP, and short-term SPAs less than 16 years came into effect. At the same time, alternative destinations for cargo and arbitrage were also allowed. By the turn of the 21st century, the market was again in favor of sellers. However, sellers have become more sophisticated and are now proposing sharing of arbitrage opportunities and moving away from S-curve pricing. There has been much discussion regarding the creation of an "OGEC" as a natural gas equivalent of OPEC. Russia and Qatar, countries with the largest and the third largest natural gas reserves in the world, have finally supported such move.[citation needed]
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Until 2003, LNG prices have closely followed oil prices. Since then, LNG prices in Europe and Japan have been lower than oil prices, although the link between LNG and oil is still strong. In contrast, prices in the US and the UK have recently skyrocketed, then fallen as a result of changes in supply and storage.[citation needed] In the late 1990s and early 2000s, the market shifted for buyers, but since 2003 and 2004, it has been a strong seller's market, with net-back as the best estimation for prices.[citation needed].
Research from Global Energy Monitor in 2019 warned that up to US$1.3 trillion in new LNG export and import infrastructure currently under development is at significant risk of becoming stranded, as global gas risks becoming oversupplied, particularly if the United States and Canada play a larger role.[32]
The current surge in unconventional oil and gas in the U.S. has resulted in lower gas prices in the U.S. This has led to discussions in Asia' oil linked gas markets to import gas based on Henry Hub index.[33] Recent high level conference in Vancouver, the Pacific Energy Summit 2013 Pacific Energy Summit 2013 convened policy makers and experts from Asia and the U.S. to discuss LNG trade relations between these regions.
Receiving terminals exist in about 40[34] countries, including Belgium, Chile, China, the Dominican Republic, France, Greece, India, Italy, Japan, Korea, Poland, Spain, Taiwan, the UK, the US, among others. Plans exist for Bahrain, Germany, Ghana, Morocco, Philippines, Vietnam[35] and others to also construct new receiving (regasification) terminals.
Base load (large-scale, >1 MTPA) LNG projects require natural gas reserves,[36] buyers[37] and financing. Using proven technology and a proven contractor is extremely important for both investors and buyers.[38] Gas reserves required: 1 tcf of gas required per Mtpa of LNG over 20 years.[36]
LNG is most cost efficiently produced in relatively large facilities due to economies of scale, at sites with marine access allowing regular large bulk shipments direct to market. This requires a secure gas supply of sufficient capacity. Ideally, facilities are located close to the gas source, to minimize the cost of intermediate transport infrastructure and gas shrinkage (fuel loss in transport). The high cost of building large LNG facilities makes the progressive development of gas sources to maximize facility utilization essential, and the life extension of existing, financially depreciated LNG facilities cost effective. Particularly when combined with lower sale prices due to large installed capacity and rising construction costs, this makes the economic screening/ justification to develop new, and especially greenfield, LNG facilities challenging, even if these could be more environmentally friendly than existing facilities with all stakeholder concerns satisfied. Due to high financial risk, it is usual to contractually secure gas supply/ concessions and gas sales for extended periods before proceeding to an investment decision.
The primary use of LNG is to simplify transport of natural gas from the source to a destination. On the large scale, this is done when the source and the destination are across an ocean from each other. It can also be used when adequate pipeline capacity is not available. For large-scale transport uses, the LNG is typically regassified at the receiving end and pushed into the local natural gas pipeline infrastructure.
LNG can also be used to meet peak demand when the normal pipeline infrastructure can meet most demand needs, but not the peak demand needs. These plants are typically called LNG Peak Shaving Plants as the purpose is to shave off part of the peak demand from what is required out of the supply pipeline.
LNG can be used to fuel internal combustion engines. LNG is in the early stages of becoming a mainstream fuel for transportation needs. It is being evaluated and tested for over-the-road trucking,[39] off-road,[40] marine, and train applications.[41] There are known problems with the fuel tanks and delivery of gas to the engine,[42] but despite these concerns the move to LNG as a transportation fuel has begun. LNG competes directly with compressed natural gas as a fuel for natural gas vehicles since the engine is identical. There may be applications where LNG trucks, buses, trains and boats could be cost-effective in order to regularly distribute LNG energy together with general freight and/or passengers to smaller, isolated communities without a local gas source or access to pipelines.
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China has been a leader in the use of LNG vehicles[43] with over 100,000 LNG-powered vehicles on the road as of Sept 2014.[44]
In the United States the beginnings of a public LNG fueling capability are being put in place. An alternative fuelling centre tracking site shows 84 public truck LNG fuel centres as of Dec 2016.[45] It is possible for large trucks to make cross country trips such as Los Angeles to Boston and refuel at public refuelling stations every 500 miles. The 2013 National Trucker's Directory lists approximately 7,000 truckstops,[46] thus approximately 1% of US truckstops have LNG available.
While as of December 2014 LNG fuel and NGV's were not taken to very quickly within Europe and it was questionable whether LNG will ever become the fuel of choice among fleet operators,[47] recent trends from 2018 onwards show different prospect.[48]During the year 2015, the Netherlands introduced LNG-powered trucks in transport sector.[49] Additionally, the Australian government is planning to develop an LNG highway to utilise the locally produced LNG and replace the imported diesel fuel used by interstate haulage vehicles.[50]
In the year 2015, India also began transporting LNG using LNG-powered road tankers in Kerala state.[51] In 2017, Petronet LNG began setting up 20 LNG stations on highways along the Indian west coast that connect Delhi with Thiruvananthapuram covering a total distance of 4,500 km via Mumbai and Bengaluru.[52] In 2020, India planned to install 24 LNG fuelling stations along the 6,000 km Golden Quadrilateral highways connecting the four metros due to LNG prices decreasing.[53]
Japan, the world's largest importer of LNG, is set to begin use of LNG as a road transport fuel.[54]
Engine displacement is an important factor in the power of an internal combustion engine. Thus a 2.0 L engine would typically be more powerful than an 1.8 L engine, but that assumes a similar air–fuel mixture is used.
However, if a smaller engine uses an air–fuel mixture with higher energy density (such as via a turbocharger), then it can produce more power than a larger one burning a less energy-dense air–fuel mixture. For high-power, high-torque engines, a fuel that creates a more energy-dense air–fuel mixture is preferred, because a smaller and simpler engine can produce the same power.
With conventional gasoline and diesel engines the energy density of the air–fuel mixture is limited because the liquid fuels do not mix well in the cylinder. Further, gasoline and diesel fuel have autoignition temperatures and pressures relevant to engine design. An important part of engine design is the interactions of cylinders, compression ratios, and fuel injectors such that pre-ignition is prevented but at the same time as much fuel as possible can be injected, become well mixed, and still have time to complete the combustion process during the power stroke.
Natural gas does not auto-ignite at pressures and temperatures relevant to conventional gasoline and diesel engine design, so it allows more flexibility in design. Methane, the main component of natural gas, has an autoignition temperature of 580 °C (1,076 °F),[55] whereas gasoline and diesel autoignite at approximately 250 °C (482 °F) and 210 °C (410 °F) respectively.
With a compressed natural gas (CNG) engine, the mixing of the fuel and the air is more effective since gases typically mix well in a short period of time, but at typical CNG pressures the fuel itself is less energy-dense than gasoline or diesel, so the result is a less energy-dense air–fuel mixture. For an engine of a given cylinder displacement, a normally-aspirated CNG-powered engine is typically less powerful than a gasoline or diesel engine of similar displacement. For that reason turbochargers are popular in European CNG cars.[56] Despite that limitation, the 12-litre Cummins Westport ISX12G engine[57] is an example of a CNG-capable engine designed to pull tractor–trailer loads up to 80,000 pounds (36,000 kg) showing CNG can be used in many on-road truck applications. The original ISX G engine incorporated a turbocharger to enhance the air–fuel energy density.[58]
LNG offers a unique advantage over CNG for more demanding high-power applications by eliminating the need for a turbocharger. Because LNG boils at approximately −160 °C (−256 °F), by using a simple heat exchanger a small amount of LNG can be converted to its gaseous form at extremely high pressure with the use of little or no mechanical energy. A properly designed high-power engine can leverage this extremely-high-pressure, energy-dense gaseous fuel source to create a higher-energy-density air–fuel mixture than can be efficiently created with a CNG-powered engine. The result when compared to CNG engines is more overall efficiency in high-power engine applications when high-pressure direct-injection technology is used. The Westport HDMI2[59] fuel system is an example of a high-pressure direct-injection system that does not require a turbocharger if paired with an appropriate LNG heat exchanger. The Volvo Trucks 13-litre LNG engine[60] is another example of an LNG engine leveraging advanced high-pressure technology.
Westport recommends CNG for engines 7 litres or smaller and LNG with direct-injection for engines between 20 and 150 litres. For engines between 7 and 20 litres either option is recommended. See slide 13 from their NGV Bruxelles – Industry Innovation Session presentation.[61]
High-power engines in the oil drilling, mining, locomotive, and marine fields have been or are being developed.[62] Paul Blomerus has written a paper[63] concluding as much as 40 million tonnes per annum of LNG (approximately 26.1 billion gallons/year or 71 million gallons/day) could be required just to meet the global needs of such high-power engines by 2025 to 2030.
As of the end of first quarter of 2015, Prometheus Energy Group Inc claimed to have delivered over 100 million gallons of LNG to the industrial market within the previous four years[64] and is continuing to add new customers.
LNG bunkering has been established in some ports via truck-to-ship fueling. This type of LNG fueling is straightforward to implement, assuming a supply of LNG is available.
Feeder and short-sea shipping company Unifeeder has been operating the world's first LNG powered container vessel, the Wes Amelie, since late 2017, transiting between the port of Rotterdam and the Baltics on a weekly schedule.[65]Container shipping company Maersk Group has decided to introduce LNG-powered container ships.[66] The DEME Group has contracted Wärtsilä to power its new generation 'Antigoon' class dredger with dual fuel (DF) engines.[67] Crowley Maritime of Jacksonville, Florida, launched two LNG-powered ConRo ships, the Coquí and Taino, in 2018 and 2019, respectively.[68]
In 2014, Shell ordered a dedicated LNG bunker vessel.[69] It is planned to go into service in Rotterdam in the summer of 2017[70]
The International Convention for the Prevention of Pollution from Ships (MARPOL), adopted by the IMO, has mandated that marine vessels shall not consume fuel (bunker fuel, diesel, etc.) with a sulphur content greater than 0.5% from the year 2020 within international waters and the coastal areas of countries adopting the same regulation. Replacement of high sulphur bunker fuel with sulphur-free LNG is required on a major scale in the marine transport sector, as low sulphur liquid fuels are costlier than LNG.[71] Japan's is planning to use LNG as bunker fuel by 2020.[72][73]
BHP, one of the largest mining companies in the world, is aiming to commission minerals transport ships powered with LNG by late 2021.[74]
In January 2021, 175 sea-going LNG-powered ships were in service, with another 200 ships ordered.[75]
Florida East Coast Railway has 24 GE ES44C4 locomotives adapted to run on LNG fuel.[76]
The global trade in LNG is growing rapidly from negligible in 1970 to what is expected to be a globally substantial amount by 2020.[77] As a reference, the 2014 global production of crude oil was 14.6 million cubic metres (92 million barrels) per day[78] or 54,600 terawatt-hours (186.4 quadrillion British thermal units) per year.
In 1970, global LNG trade was of 3 billion cubic metres (bcm) (0.11 quads).[79] In 2011, it was 331 bcm (11.92 quads).[79] The U.S. started exporting LNG in February 2016. The Black & Veatch Oct 2014 forecast is that by 2020, the U.S. alone will export between 10 and 14 billion cu ft/d (280 and 400 million m3/d) or by heating value 3.75 to 5.25 quad (1,100 to 1,540 TWh).[80] E&Y projects global LNG demand could hit 400 mtpa (19.7 quads) by 2020.[81] If that occurs, the LNG market will be roughly 10% the size of the global crude oil market, and that does not count the vast majority of natural gas which is delivered via pipeline directly from the well to the consumer.
In 2004, LNG accounted for 7 percent of the world's natural gas demand.[82] The global trade in LNG, which has increased at a rate of 7.4 percent per year over the decade from 1995 to 2005, is expected to continue to grow substantially.[83] LNG trade is expected to increase at 6.7 percent per year from 2005 to 2020.[83]
Until the mid-1990s, LNG demand was heavily concentrated in Northeast Asia: Japan, South Korea and Taiwan. At the same time, Pacific Basin supplies dominated world LNG trade.[83] The worldwide interest in using natural gas-fired combined cycle generating units for electric power generation, coupled with the inability of North American and North Sea natural gas supplies to meet the growing demand, substantially broadened the regional markets for LNG. It also brought new Atlantic Basin and Middle East suppliers into the trade.[83]
By the end of 2017, there were 19 LNG exporting countries and 40 LNG importing countries. The three biggest LNG exporters in 2017 were Qatar (77.5 MT), Australia (55.6 MT) and Malaysia (26.9 MT). The three biggest LNG importers in 2017 were Japan (83.5 MT), China (39 MT) and South Korea (37.8 MT).[84] LNG trade volumes increased from 142 MT in 2005 to 159 MT in 2006, 165 MT in 2007, 171 MT in 2008, 220 MT in 2010, 237 MT in 2013, 264 MT in 2016 and 290 MT in 2017.[84] Global LNG production was 246 MT in 2014,[85] most of which was used in trade between countries.[86] During the next several years there would be significant increase in volume of LNG Trade.[81] For example, about 59 MTPA of new LNG supply from six new plants came to market just in 2009, including:
En 2006, Qatar se convirtió en el mayor exportador de GNL del mundo. [79] A partir de 2012, Qatar es la fuente del 25 por ciento de las exportaciones mundiales de GNL. [79] En 2017, se estimaba que Qatar suministraba el 26,7% del GNL del mundo. [84]
Las inversiones en instalaciones de exportación de EE. UU. aumentaron en 2013; estas inversiones fueron impulsadas por la creciente producción de gas de esquisto en los Estados Unidos y un gran diferencial de precios entre los precios del gas natural en los EE. UU. y los de Europa y Asia. Cheniere Energy se convirtió en la primera empresa de Estados Unidos en recibir permiso y exportar GNL en 2016. [8] Después de un acuerdo entre Estados Unidos y la UE en 2018, las exportaciones de Estados Unidos a la UE aumentaron. [87] En noviembre de 2021, el productor estadounidense Venture Global LNG firmó un contrato de veinte años con la empresa estatal china Sinopec para suministrar gas natural licuado. [88] Las importaciones chinas de gas natural estadounidense se duplicarán con creces. [89] Las exportaciones estadounidenses de gas natural licuado a China y otros países asiáticos aumentaron en 2021 , y los compradores asiáticos estaban dispuestos a pagar precios más altos que los importadores europeos. [90] Esto se revirtió en 2022, cuando la mayor parte del GNL estadounidense se destinó a Europa. Los contratos de exportación de GNL de EE. UU. se celebran principalmente por 15 a 20 años. [91] Es probable que las exportaciones de EE. UU. alcancen los 13,3 Bcf/d en 2024 debido a la puesta en marcha de proyectos en el Golfo de México. [92]
En 1964, el Reino Unido y Francia realizaron el primer comercio de GNL, comprando gas a Argelia , siendo testigos de una nueva era energética.
En 2014, 19 países exportaron GNL. [79]
En comparación con el mercado del petróleo crudo, en 2013 el mercado del gas natural representaba alrededor del 72 por ciento del mercado del petróleo crudo (medido en términos de equivalente de calor), [93] del cual el GNL forma una parte pequeña pero en rápido crecimiento. Gran parte de este crecimiento está impulsado por la necesidad de combustible limpio y cierto efecto de sustitución debido al alto precio del petróleo (principalmente en los sectores de calefacción y generación de electricidad).
Japan, South Korea, Spain, France, Italy and Taiwan import large volumes of LNG due to their shortage of energy. In 2005, Japan imported 58.6 million tons of LNG, representing some 30 percent of the LNG trade around the world that year. Also in 2005, South Korea imported 22.1 million tons, and in 2004 Taiwan imported 6.8 million tons. These three major buyers purchase approximately two-thirds of the world's LNG demand. In addition, Spain imported some 8.2 MTPA in 2006, making it the third largest importer. France also imported similar quantities as Spain.[citation needed] Following the Fukushima Daiichi nuclear disaster in March 2011 Japan became a major importer accounting for one third of the total.[94]European LNG imports fell by 30 percent in 2012, and fell further by 24 percent in 2013, as South American and Asian importers paid more.[95] European LNG imports increased to new heights in 2019, remained high in 2020 and 2021, and increased even more in 2022.[91] Main contributors were Qatar, USA, and Russia.[96]
In 2017, global LNG imports reached 289.8[97] million tonnes of LNG. In 2017, 72.9% of global LNG demand was located in Asia.[98]
Based on the LNG SPAs, LNG is destined for pre-agreed destinations, and diversion of that LNG is not allowed. However, if Seller and Buyer make a mutual agreement, then the diversion of the cargo is permitted — subject to sharing the additional profit created by such a diversion, by paying a penalty fee.[91] In the European Union and some other jurisdictions, it is not permitted to apply the profit-sharing clause in LNG SPAs.
For an extended period of time, design improvements in liquefaction plants and tankers had the effect of reducing costs.
In the 1980s, the cost of building an LNG liquefaction plant cost $350/tpa (tonne per annum). In the 2000s, it was $200/tpa. In 2012, the costs can go as high as $1,000/tpa, partly due to the increase in the price of steel.[79]
As recently as 2003, it was common to assume that this was a "learning curve" effect and would continue into the future. But this perception of steadily falling costs for LNG has been dashed in the last several years.[83]
The construction cost of greenfield LNG projects started to skyrocket from 2004 afterward and has increased from about $400 per ton per year of capacity to $1,000 per ton per year of capacity in 2008.
The main reasons for skyrocketed costs in LNG industry can be described as follows:
Excluding high cost projects the increase of 120% over the period 2002-2012 is more in line with escalation in the upstream oil & gas industry as reported by the UCCI index [99]
The 2007–2008 global financial crisis (GFC) caused a general decline in raw material and equipment prices, which somewhat lessened the construction cost of LNG plants.[100][101] However, by 2012 this was more than offset by increasing demand for materials and labor for the LNG market.
Small-scale liquefaction plants are suitable for peakshaving on natural gas pipelines, transportation fuel, or for deliveries of natural gas to remote areas not connected to pipelines.[102] They typically have a compact size, are fed from a natural gas pipeline, and are located close to the location where the LNG will be used. This proximity decreases transportation and LNG product costs for consumers.[103][104] It also avoids the additional greenhouse gas emissions generated during long transportation.
The small-scale LNG plant also allows localized peakshaving to occur—balancing the availability of natural gas during high and low periods of demand. It also makes it possible for communities without access to natural gas pipelines to install local distribution systems and have them supplied with stored LNG.[105]
There are three major pricing systems in the current LNG contracts:
The formula for an indexed price is as follows:
CP = BP + β X
The formula has been widely used in Asian LNG SPAs, where base price represents various non-oil factors, but usually a constant determined by negotiation at a level which can prevent LNG prices from falling below a certain level. It thus varies regardless of oil price fluctuation.
Some LNG buyers have already signed contracts for future US-based cargos at prices linked to Henry Hub prices.[107] Cheniere Energy's LNG export contract pricing consists of a fixed fee (liquefaction tolling fee) plus 115% of Henry Hub per million British thermal units of LNG.[108] Tolling fees in the Cheniere contracts vary: US$2.25 per million British thermal units ($7.7/MWh) with BG Group signed in 2011; $2.49 per million British thermal units ($8.5/MWh) with Spain's GNF signed in 2012; and $3.00 per million British thermal units ($10.2/MWh) with South Korea's Kogas and Centrica signed in 2013.[109]
Oil parity is the LNG price that would be equal to that of crude oil on a barrel of oil equivalent (BOE) basis. If the LNG price exceeds the price of crude oil in BOE terms, then the situation is called broken oil parity. A coefficient of 0.1724 results in full oil parity. In most cases the price of LNG is less than the price of crude oil in BOE terms. In 2009, in several spot cargo deals especially in East Asia, oil parity approached the full oil parity or even exceeded oil parity.[110] In January 2016, the spot LNG price of $5.461 per million British thermal units ($18.63/MWh) has broken oil parity when the Brent crude price (≤32 US$/bbl) has fallen steeply.[111] By the end of June 2016, LNG price has fallen by nearly 50% below its oil parity price, making it more economical than more-polluting diesel/gas oil in the transport sector.[112]
Most of the LNG trade is governed by long-term contracts. Many formulae include an S-curve, where the price formula is different above and below a certain oil price, to dampen the impact of high oil prices on the buyer, and low oil prices on the seller. When the spot LNG price is cheaper than long term oil price indexed contracts, the most profitable LNG end use is to power mobile engines for replacing costly gasoline and diesel consumption.
In most of the East Asian LNG contracts, price formula is indexed to a basket of crude imported to Japan called the Japan Crude Cocktail (JCC). In Indonesian LNG contracts, price formula is linked to Indonesian Crude Price (ICP).
In continental Europe, the price formula indexation does not follow the same format, and it varies from contract to contract. Brent crude price (B), heavy fuel oil price (HFO), light fuel oil price (LFO), gas oil price (GO), coal price, electricity price and in some cases, consumer and producer price indexes are the indexation elements of price formulas.
Usually there exists a clause allowing parties to trigger the price revision or price reopening in LNG SPAs. In some contracts there are two options for triggering a price revision. regular and special. Regular ones are the dates that will be agreed and defined in the LNG SPAs for the purpose of price review.
LNG quality is one of the most important issues in the LNG business. Any gas which does not conform to the agreed specifications in the sale and purchase agreement is regarded as "off-specification" (off-spec) or "off-quality" gas or LNG. Quality regulations serve three purposes:[159]
In the case of off-spec gas or LNG the buyer can refuse to accept the gas or LNG and the seller has to pay liquidated damages for the respective off-spec gas volumes.
The quality of gas or LNG is measured at delivery point by using an instrument such as a gas chromatograph.
The most important gas quality concerns involve the sulphur and mercury content and the calorific value. Due to the sensitivity of liquefaction facilities to sulfur and mercury elements, the gas being sent to the liquefaction process shall be accurately refined and tested in order to assure the minimum possible concentration of these two elements before entering the liquefaction plant, hence there is not much concern about them.
Sin embargo, la principal preocupación es el poder calorífico del gas. Normalmente los mercados del gas natural se pueden dividir en tres mercados en términos de valor calorífico: [159]
Existen algunos métodos para modificar el poder calorífico del GNL producido al nivel deseado. Para aumentar el poder calorífico, inyectar propano y butano es una solución. Con el fin de disminuir el poder calorífico, la inyección de nitrógeno y la extracción de butano y propano son soluciones probadas. Mezclarlo con gas o GNL puede ser una solución; sin embargo, todas estas soluciones, aunque teóricamente viables, pueden resultar costosas y logísticamente difíciles de gestionar a gran escala. El precio del GNL pobre en términos de valor energético es más bajo que el precio del GNL rico. [160]
Hay varios procesos de licuefacción disponibles para grandes plantas de GNL de carga básica (en orden de prevalencia): [161]
En enero de 2016, la capacidad nominal mundial de licuefacción de GNL era de 301,5 MTPA (millones de toneladas por año), con otras 142 MTPA en construcción. [162]
La mayoría de estos trenes utilizan tecnología APCI AP-C3MR o Cascade para el proceso de licuefacción. Los otros procesos, utilizados en una pequeña minoría de algunas plantas de licuefacción, incluyen la tecnología DMR (refrigerante de doble mezcla) de Shell y la tecnología Linde.
APCI technology is the most-used liquefaction process in LNG plants: out of 100 liquefaction trains onstream or under-construction, 86 trains with a total capacity of 243 MTPA have been designed based on the APCI process. Phillips' Cascade process is the second most-used, used in 10 trains with a total capacity of 36.16 MTPA. The Shell DMR process has been used in three trains with total capacity of 13.9 MTPA; and, finally, the Linde/Statoil process is used in the Snohvit 4.2 MTPA single train.
Floating liquefied natural gas (FLNG) facilities float above an offshore gas field, and produce, liquefy, store and transfer LNG (and potentially LPG and condensate) at sea before carriers ship it directly to markets. The first FLNG facility is now in development by Shell,[163] due for completion in 2018.[164]
Modern LNG storage tanks are typically of the full containment type, which has a prestressed concrete outer wall and a high-nickel steel inner tank, with extremely efficient insulation between the walls. Large tanks are low aspect ratio (height to width) and cylindrical in design with a domed steel or concrete roof. Storage pressure in these tanks is very low, less than 10 kilopascals (1.5 psi). Sometimes more expensive underground tanks are used for storage. Smaller quantities (say 700 cubic metres (180,000 US gal) and less) may be stored in horizontal or vertical, vacuum-jacketed, pressure vessels. These tanks may be at pressures anywhere from less than 50 to over 1,700 kPa (7.3–246.6 psi).
LNG must be kept cold to remain a liquid, independent of pressure. Despite efficient insulation, there will inevitably be some heat leakage into the LNG, resulting in vaporisation of the LNG. This boil-off gas acts to keep the LNG cold (see "Refrigeration" below). The boil-off gas is typically compressed and exported as natural gas, or it is reliquefied and returned to storage.
LNG is transported in specially designed ships with double hulls protecting the cargo systems from damage or leaks. There are several special leak test methods available to test the integrity of an LNG vessel's membrane cargo tanks.[165]
The tankers cost around US$200 million each.[79]
Transportation and supply is an important aspect of the gas business, since natural gas reserves are normally quite distant from consumer markets. Natural gas has far more volume than oil to transport, and most gas is transported by pipelines. There is a natural gas pipeline network in the former Soviet Union, Europe and North America. Natural gas is less dense, even at higher pressures. Natural gas will travel much faster than oil through a high-pressure pipeline, but can transmit only about a fifth of the amount of energy per day due to the lower density. Natural gas is usually liquefied to LNG at the end of the pipeline, before shipping.
Short LNG pipelines for use in moving product from LNG vessels to onshore storage are available. Longer pipelines, which allow vessels to offload LNG at a greater distance from port facilities, are under development. This requires pipe-in-pipe technology due to requirements for keeping the LNG cold.[166]
LNG is transported using tanker trucks,[167] railway tanker cars,[168] and purpose built ships known as LNG carriers. LNG is sometimes taken to cryogenic temperatures to increase the tanker capacity. The first commercial ship-to-ship transfer (STS) transfers were undertaken in February 2007 at the Flotta facility in Scapa Flow[169] with 132,000 m3 of LNG being passed between the vessels Excalibur and Excelsior. Transfers have also been carried out by Exmar Shipmanagement, the Belgian gas tanker owner in the Gulf of Mexico, which involved the transfer of LNG from a conventional LNG carrier to an LNG regasification vessel (LNGRV). Before this commercial exercise, LNG had only ever been transferred between ships on a handful of occasions as a necessity following an incident.[citation needed] The Society of International Gas Tanker and Terminal Operators (SIGTTO) is the responsible body for LNG operators around the world and seeks to disseminate knowledge regarding the safe transport of LNG at sea.[170]
Besides LNG vessels, LNG is also used in some aircraft.
Liquefied natural gas is used to transport natural gas over long distances, often by sea. In most cases, LNG terminals are purpose-built ports used exclusively to export or import LNG.
The United Kingdom has LNG import facilities for up to 50 billion cubic meters per year.[171]
El aislamiento, por muy eficiente que sea, no mantendrá el GNL lo suficientemente frío por sí solo. Inevitablemente, la fuga de calor calentará y vaporizará el GNL. La práctica de la industria es almacenar el GNL como criógeno en ebullición . Es decir, el líquido se almacena en su punto de ebullición para la presión a la que se almacena (presión atmosférica). A medida que el vapor se evapora, el calor generado por el cambio de fase enfría el líquido restante. Debido a que el aislamiento es muy eficiente, sólo se necesita una cantidad relativamente pequeña de ebullición para mantener la temperatura. Este fenómeno también se llama autorefrigeración .
El gas de ebullición de los tanques de almacenamiento de GNL en tierra generalmente se comprime y se alimenta a las redes de gasoductos . Algunos buques de GNL utilizan gas de ebullición como combustible.
El gas natural podría considerarse el combustible fósil menos dañino para el medio ambiente porque tiene las menores emisiones de CO 2 por unidad de energía y es adecuado para su uso en centrales eléctricas de ciclo combinado de alta eficiencia. Para una cantidad equivalente de calor, la quema de gas natural produce alrededor de un 30 por ciento menos de dióxido de carbono que la quema de petróleo y alrededor de un 45 por ciento menos que la quema de carbón . [172] El biometano se considera aproximadamente neutro en cuanto a CO 2 y evita la mayor parte del problema de las emisiones de CO 2 . Si se licua (como LBM), cumple las mismas funciones que el GNL. [173]
Por kilómetro transportado, las emisiones del GNL son menores que las del gas natural canalizado, lo cual es un problema particular en Europa, donde se transportan cantidades significativas de gas a varios miles de kilómetros desde Rusia. Sin embargo, las emisiones del gas natural transportado como GNL pueden ser mayores que las del gas natural producido regionalmente y canalizado hasta el punto de combustión, ya que las emisiones asociadas con el transporte son menores para este último. [174]
However, on the West Coast of the United States, where up to three new LNG importation terminals were proposed before the U.S. fracking boom, environmental groups, such as Pacific Environment, Ratepayers for Affordable Clean Energy (RACE), and Rising Tide had moved to oppose them.[175] They claimed that, while natural gas power plants emit approximately half the carbon dioxide of an equivalent coal power plant, the natural gas combustion required to produce and transport LNG to the plants adds 20 to 40 percent more carbon dioxide than burning natural gas alone.[176] A 2015 peer-reviewed study evaluated the full end-to-end life cycle of LNG produced in the U.S. and consumed in Europe or Asia.[177] It concluded that global CO2 production would be reduced due to the resulting reduction in other fossil fuels burned.
Some scientists and local residents have raised concerns about the potential effect of Poland's underground LNG storage infrastructure on marine life in the Baltic Sea.[178] Similar concerns were raised in Croatia.[179]
Natural gas is a fuel and a combustible substance. To ensure safe and reliable operation, particular measures are taken in the design, construction and operation of LNG facilities. In maritime transport, the regulations for the use of LNG as a marine fuel are set out in the IGF Code.[180]
In its liquid state, LNG is not explosive and can not ignite. For LNG to burn, it must first vaporize, then mix with air in the proper proportions (the flammable range is 5 percent to 15 percent), and then be ignited. In the case of a leak, LNG vaporizes rapidly, turning into a gas (methane plus trace gases), and mixing with air. If this mixture is within the flammable range, there is risk of ignition, which would create fire and thermal radiation hazards.
Gas venting from vehicles powered by LNG may create a flammability hazard if parked indoors for longer than a week. Additionally, due to its low temperature, refueling an LNG-powered vehicle requires training to avoid the risk of frostbite.[181][182]
LNG tankers have sailed over 100 million miles without a shipboard death or even a major accident.[183]
Several on-site accidents involving or related to LNG are listed below:
On 8 May 2018, the United States withdrew from the Joint Comprehensive Plan of Action with Iran, reinstating Iran sanctions against their nuclear program.[190] In response, Iran threatened to close off the Strait of Hormuz to international shipping.[191] The Strait of Hormuz is a strategic route through which a third of the world's LNG passes from Middle East producers.[192]
In January 2024, Qatar halted tankers of liquefied natural gas through the strait of Bab-el-Mandeb after US-led airstrikes on Houthi targets in Yemen increased risks in the strait.[193] The LNG tankers were forced to sail around Africa via the Cape of Good Hope to avoid the war zone.[194]
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