Not to be confused with Natural gas processing or Liquefied petroleum gas.
Liquefied natural gas (LNG) is natural gas (predominantly methane, CH4, with some mixture of ethane C2H6) that has been converted 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). It 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).
Natural gas is mainly converted in to LNG to achieve the natural gas transport over the seas where laying pipelines is not feasible technically and economically. LNG achieves a higher reduction in volume than compressed natural gas (CNG) so that the (volumetric) energy density of LNG is 2.4 times greater than that of CNG (at 250 bar) or 60 percent that of diesel fuel. This makes LNG cost efficient in marine transport over long distances. However, CNG carrier can be used economically up to medium distances in marine transport. Specially designed cryogenic sea vessels (LNG carriers) or cryogenic road tankers are used for its transport. LNG is principally used for transporting natural gas to markets, where it is regasified and distributed as pipeline natural gas. It can be used in natural gas vehicles, although it is more common to design vehicles to use compressed natural gas. Its relatively high cost of production and the need to store it in expensive cryogenic tanks have hindered widespread commercial use. Despite these drawbacks, on energy basis LNG production is expected to hit 10% of the global crude production by 2020.(see LNG Trade)
Specific energy content and energy density
The heating value depends on the source of gas that is used and the process that is used to liquefy the gas. The range of heating value can span +/- 10 to 15 percent. A typical value of the higher heating value of LNG is approximately 50 MJ/kg or 21,500 BTU/lb. A typical value of the lower heating value of LNG is 45 MJ/kg or 19,350 BTU/lb.
For the purpose of comparison of different fuels the heating value may be expressed in terms of energy per volume which is known as the energy density expressed in MJ/liter. The density of LNG is roughly 0.41 kg/liter to 0.5 kg/liter, depending on temperature, pressure, and composition, compared to water at 1.0 kg/liter. Using the median value of 0.45 kg/liter, the typical energy density values are 22.5 MJ/liter (based on higher heating value) or 20.3 MJ/liter (based on lower heating value).
The (volume-based) energy density of LNG is approximately 2.4 times greater than that of 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.
Experiments on the properties of gases started early in the seventeenth 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 on the nature of gases had been discovered. For example, early in the nineteenth century Cagniard de la Tour had shown 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.
The key patents having to do with natural gas liquefaction were in 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, if it can be liquefied it can be stored in a volume 600 times smaller. This is a practical way to store it but the gas must be stored 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 prior to 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 it through an orifice until it is cooled to temperatures at which it liquefies. The cooling of gas by expanding it through an orifice 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.
Commercial operations in the United States
The East Ohio Gas Company built a full-scale commercial liquid natural gas (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. 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. 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 by oil.
The US LNG industry restarted in 1965 when a series of new plants were built in the U.S. The building 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 prior to 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.
The natural gas fed into the LNG plant will be treated to remove water, hydrogen sulfide, carbon dioxide and other components that will freeze (e.g., benzene) under the low temperatures needed for storage or be destructive to the liquefaction facility. LNG typically contains more than 90 percent 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 percent methane. One of the risks of LNG is a rapid phase transition explosion (RPT), which occurs when cold LNG comes into contact with water.
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. The largest LNG train in operation is in Qatar. These facilities recently reached a safety milestone, completing 12 years of operations on its offshore facilities without a Lost Time Incident. The Qatar operation overtook the Train 4 of Atlantic LNG in Trinidad and Tobago with a production capacity of 5.2 million metric ton per annum (mmtpa), followed by the SEGAS LNG plant in Egypt with a capacity of 5 mmtpa. In July 2014, Atlantic LNG celebrated its 3000th cargo of LNG at the company’s liquefaction facility in Trinidad. The Qatargas II plant has a production capacity of 7.8 mmtpa for each of its two trains. LNG sourced from Qatargas II will be supplied to Kuwait, following the signing of an agreement in May 2014 between Qatar Liquefied Gas Company and Kuwait Petroleum Corp. 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).
LNG plant production
Information for the following table is derived in part from publication by the U.S. Energy Information Administration.
See also List of LNG terminals
|Plant Name||Location||Country||Startup Date||Capacity (mmtpa)||Corporation|
|Gorgon||Barrow Island||Australia||2016||3 x 5 = 15||Chevron 47%|
|Ichthys||Browse Basin||Australia||2016||2 x 4.2 = 8.4||INPEX, Total S.A. 24%|
|Das Island I Trains 1–2||Abu Dhabi||UAE||1977||1.7 x 2 = 3.4||ADGAS (ADNOC, BP, Total, Mitsui)|
|Das Island II Train 3||Abu Dhabi||UAE||1994||2.6||ADGAS (ADNOC, BP, Total, Mitsui)|
|Arzew (CAMEL) GL4Z Trains 1–3||Algeria||1964||0.3 x 3 = 0.9||Sonatrach. Shutdown since April 2010.|
|Arzew GL1Z Trains 1–6||Algeria||1978||1.3 x 6 = 7.8||Sonatrach|
|Arzew GL2Z Trains 1–6||Algeria||1981||1.4 x 6 = 8.4||Sonatrach|
|Skikda GL1K Phase 1 & 2 Trains 1–6||Algeria||1972/1981||Total 6.0||Sonatrach|
|Skikda GL3Z Skikda Train 1||Algeria||2013||4.7||Sonatrach|
|Skikda GL3Z Skikda Train 2||Algeria||2013||4.5||Sonatrach|
|Badak NGL A-B||Bontang||Indonesia||1977||4||Pertamina|
|Badak NGL C-D||Bontang||Indonesia||1986||4.5||Pertamina|
|Badak NGL E||Bontang||Indonesia||1989||3.5||Pertamina|
|Badak NGL F||Bontang||Indonesia||1993||3.5||Pertamina|
|Badak NGL G||Bontang||Indonesia||1998||3.5||Pertamina|
|Badak NGL H||Bontang||Indonesia||1999||3.7||Pertamina|
|Darwin LNG||Darwin, NT||Australia||2006||3.7||ConocoPhillips|
|Donggi Senoro LNG||Luwuk||Indonesia||2015||2||Mitsubishi, Pertamina, Medco|
|Sengkang LNG||Sengkang||Indonesia||2014||5||Energy World Corp.|
|Atlantic LNG||Point Fortin||Trinidad and Tobago||1999||Atlantic LNG|
|Atlantic LNG||[Point Fortin]||Trinidad and Tobago||2003||9.9||Atlantic LNG|
|SEGAS LNG||Damietta||Egypt||2004||5.5||SEGAS LNG|
|Bintulu MLNG 1||Malaysia||1983||7.6|
|Bintulu MLNG 2||Malaysia||1994||7.8|
|Bintulu MLNG 3||Malaysia||2003||3.4|
|Northwest Shelf Venture||Karratha||Australia||1984||16.3|
|Tangguh LNG Project||Papua Barat||Indonesia||2009||7.6|
|Qatargas Train 1||Ras Laffan||Qatar||1996||3.3|
|Qatargas Train 2||Ras Laffan||Qatar||1997||3.3|
|Qatargas Train 3||Ras Laffan||Qatar||1998||3.3|
|Qatargas Train 4||Ras Laffan||Qatar||2009||7.8|
|Qatargas Train 5||Ras Laffan||Qatar||2009||7.8|
|Qatargas Train 6||Ras Laffan||Qatar||2010||7.8|
|Qatargas Train 7||Ras Laffan||Qatar||2011||7.8|
|Rasgas Train 1||Ras Laffan||Qatar||1999||3.3|
|Rasgas Train 2||Ras Laffan||Qatar||2000||3.3|
|Rasgas Train 3||Ras Laffan||Qatar||2004||4.7|
|Rasgas Train 4||Ras Laffan||Qatar||2005||4.7|
|Rasgas Train 5||Ras Laffan||Qatar||2006||4.7|
|Rasgas Train 6||Ras Laffan||Qatar||2009||7.8|
|Rasgas Train 7||Ras Laffan||Qatar||2010||7.8|
|Equatorial Guinea||2007||3.4||Marathon Oil|
|Risavika||Stavanger||Norway||2010||0.3||Risavika LNG Production|
|Dominion Cove Point LNG||Lusby, Maryland||United States||2018||5.2||Dominion Resources|
World total production
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 large costs to treat and transport LNG. Constructing an LNG plant costs at least $1.5 billion per 1 mmtpa 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 nature 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. Several import terminal proposals along the coast of Maine were also met with high levels of resistance and questions. On Sep. 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. 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. Another LNG terminal is currently proposed for Elba Island, Ga. Plans for three LNG export terminals in the U.S. Gulf Coast region have also received conditional Federal approval. In Canada, an LNG export terminal is under construction near Guysborough, Nova Scotia.
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, BG Group, Chevron, 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. 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.
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. In late 1990s and in 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..
Research from QNB Group in 2014 shows that robust global demand is likely to keep LNG prices high for at least the next few years.
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. 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 18 countries, including India, Japan, Korea, Taiwan, China, Greece, Belgium, Spain, Italy, France, the UK, the US, Chile, and the Dominican Republic, among others. Plans exist for Argentina, Brazil, Uruguay, Canada, Ukraine and others to also construct new receiving (gasification) terminals.
LNG Project Screening
Base load (large scale, >1 MTPA) LNG projects require natural gas reserves, buyers and financing. Using proven technology and a proven contractor is extremely important for both investors and buyers. Gas reserves required: 1 tcf of gas required per Mtpa of LNG over 20 years.
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, off-road, marine, and train applications. There are known problems with the fuel tanks and delivery of gas to the engine, 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.
Use of LNG to fuel large over-the-road trucks
China has been a leader in the use of LNG vehicles with over 100,000 LNG powered vehicles on the road as of Sept 2014.
In the United States the beginnings of a public LNG Fueling capability is being put in place. An alternative fuelling centre tracking site shows 84 public truck LNG fuel centres as of Dec 2016. 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, thus approximately 1% of US truckstops have LNG available.
As of December 2014 LNG fuel and NGV's have not been taken to very quickly within Europe and it is questionable whether LNG will ever become the fuel of choice among fleet operators. During the year 2015, Netherlands introduced LNG powered trucks in transport sector. 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.
In the year 2015, India also made small beginning by transporting LNG by LNG powered road tankers in Kerala state. In 2017, Petronet LNG is 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. Japan, the world’s largest importer of LNG, is set to use of LNG as road transport fuel.
Use of LNG to fuel high-horsepower/high-torque engines
In internal combustion engines the volume of the cylinders is a common measure of the power of an engine. Thus a 2000cc engine would typically be more powerful than a 1800cc engine, but that assumes a similar air-fuel mixture is used. Also If, via a turbocharger as an example, the 1800cc engine were using an air-fuel mixture that was significantly more energy dense, then it might be able to produce more power than a 2000cc engine burning a less energy dense air-fuel mixture. Unfortunately turbochargers are both complex and expensive. Thus it becomes clear for high-horsepower/high-torque engines a fuel that can inherently be used to create a more energy dense air-fuel mixture is preferred because a smaller and simpler engine can be used to produce the same power.
With traditional 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 auto-ignite at temperatures and pressures relevant to engine design. An important part of traditional engine design is designing the cylinders, compression ratios, and fuel injectors such that pre-ignition is avoided, 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 traditional gasoline and diesel engine design, thus providing more flexibility in the design of a natural gas engine. Methane, the main component of natural gas, has an autoignition temperature of 580 °C (1,076 °F), 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 compression pressures the fuel itself is less energy dense than gasoline or diesel thus the end result is a lower energy dense air-fuel mixture. Thus for the same cylinder displacement engine, a non turbocharged CNG powered engine is typically less powerful than a similarly sized gas or diesel engine. For that reason turbochargers are popular on European CNG cars. Despite that limitation, the 12 liter Cummins Westport ISX12G engine is an example of a CNG capable engine designed to pull tractor/trailer loads up to 80,000 lbs showing CNG can be used in most if not all on-road truck applications. The original ISX G engines incorporated a turbocharger to enhance the air-fuel energy density.
LNG offers a unique advantage over CNG for more demanding high-horsepower 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-horsepower 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 end result when compared to CNG engines is more overall efficiency in high-horsepower engine applications when high-pressure direct injection technology is used. The Westport HDMI2 fuel system is an example of a high-pressure direct injection technology that does not require a turbocharger if teamed with appropriate LNG heat exchanger technology. The Volvo Trucks 13-liter LNG engine is another example of a LNG engine leveraging advanced high pressure technology.
Westport recommends CNG for engines 7 liters or smaller and LNG with direct injection for engines between 20 and 150 liters. For engines between 7 and 20 liters either option is recommended. See slide 13 from there NGV Bruxelles – Industry Innovation Session presentation
High horsepower engines in the oil drilling, mining, locomotive, and marine fields have been or are being developed. Paul Blomerous has written a paper 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 the high-horsepower engines by 2025 to 2030.
As of the end of 1st quarter 2015 Prometheus Energy Group Inc claims to have delivered over 100 million gallons of LNG within the previous 4 years into the industrial market, and is continuing to add new customers.
Use of LNG in maritime applications
LNG bunkering has been established in some ports via truck to ship fueling. This type of LNG fueling is straightforward to establish assuming a supply of LNG is available. Unfortunately, it doesn't meet the needs of containerships and other vessels with large full capacity.
Container shipping company, Maersk Group has decided to introduce LNG fuel driven container ships. DEME Group has contracted Wärtsilä to power its new generation ‘Antigoon’ class dredger with dual fuel (DF) engines.
In 2014, Shell ordered a dedicated LNG bunker vessel. It is planned to go into service in Rotterdam in the summer of 2017
The International Convention for 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 0.1% from the year 2020. Replacement of high sulphur bunker fuel with sulphur free LNG is required on major scale in marine transport sector as low sulphur liquid fuels are costlier than LNG.
The global trade in LNG is growing rapidly from negligible in 1970 to what is expected to be a globally meaningful amount by 2020. As a reference, the 2014 global production of crude oil was 92 million barrels per day or 186.4 quads/yr (quadrillion BTUs/yr).
In 1970, global LNG trade was of 3 billion cubic metres (bcm) (0.11 quads). In 2011, it was 331 bcm (11.92 quads). 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 Bcf/d (3.75 quads/yr) and 14 Bcf/d (5.25 quads/yr). E&Y projects global LNG demand could hit 400 mtpa (19.7 quads) by 2020. 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. 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. LNG trade is expected to increase at 6.7 percent per year from 2005 to 2020.
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. 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.
By the end of 2011, there were 18 LNG exporting countries and 25 LNG importing countries. The three biggest LNG exporters in 2011 were Qatar (75.5 MT), Malaysia (25 MT) and Indonesia (21.4 MT). The three biggest LNG importers in 2011 were Japan (78.8 MT), South Korea (35 MT) and UK (18.6 MT). LNG trade volumes increased from 140 MT in 2005 to 158 MT in 2006, 165 MT in 2007, 172 MT in 2008. Global LNG production was 246 MT in 2014, most of which was used in trade between countries. During the next several years there would be significant increase in volume of LNG Trade. For example, about 59 MTPA of new LNG supply from six new plants came to market just in 2009, including:
- Northwest Shelf Train 5: 4.4 MTPA
- Sakhalin II: 9.6 MTPA
- Yemen LNG: 6.7 MTPA
- Tangguh: 7.6 MTPA
- Qatargas: 15.6 MTPA
- Rasgas Qatar: 15.6 MTPA
In 2006, Qatar became the world's biggest exporter of LNG. As of 2012, Qatar is the source of 25 percent of the world's LNG exports.
Investments in U.S. export facilities were increasing by 2013, these investments were spurred by increasing shale gas production in the United States and a large price differential between natural gas prices in the U.S. and those in Europe and Asia. Cheniere Energy became the first company in the United States to receive permission and export LNG in 2016.
In 1964, the UK and France made the first LNG trade, buying gas from Algeria, witnessing a new era of energy.
Today, only 19 countries export LNG.
Compared with the crude oil market, in 2013 the natural gas market was about 72 percent of the crude oil market (measured on a heat equivalent basis), of which LNG forms a small but rapidly growing part. Much of this growth is driven by the need for clean fuel and some substitution effect due to the high price of oil (primarily in the heating and electricity generation sectors).
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 mmtpa in 2006, making it the third largest importer. France also imported similar quantities as Spain. Following the Fukushima Daiichi nuclear disaster in March 2011 Japan became a major importer accounting for one third of the total. European LNG imports fell by 30 percent in 2012, and are expected to fall further by 24 percent in 2013, as South American and Asian importers pay more.
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. In the European Union and some other jurisdictions, it is not permitted to apply the profit-sharing clause in LNG SPAs.
Cost of LNG plants
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 per tpa (tonne per year). In 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.
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.
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:
- Low availability of EPC contractors as result of extraordinary high level of ongoing petroleum projects worldwide.
- High raw material prices as result of surge in demand for raw materials.
- Lack of skilled and experienced workforce in LNG industry.
- Devaluation of US dollar.
The 2007–2008 global financial crisis caused a general decline in raw material and equipment prices, which somewhat lessened the construction cost of LNG plants. However, by 2012 this was more than offset by increasing demand for materials and labor for the LNG market.
Small-scale liquefaction plants
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. 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. 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.
There are three major pricing systems in the current LNG contracts:
- Oil indexed contract used primarily in Japan, Korea, Taiwan and China;
- Oil, oil products and other energy carriers indexed contracts used primarily in Continental Europe; and
- Market indexed contracts used in the US and the UK.;
The formula for an indexed price is as follows:
CP = BP + β X
- BP: constant part or base price
- β: gradient
- X: indexation
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.
Henry Hub Plus
Some LNG buyers have already signed contracts for future US-based cargos at Henry Hub-linked prices. Cheniere Energy’s LNG export contract pricing consists of a fixed fee (liquefaction tolling fee) plus 115% of Henry Hub per MMBtu of LNG. Tolling fees in the Cheniere contracts vary: $2.25/MMBtu with BG Group signed in 2011; $2.49/MMBtu with Spain's GNF signed in 2012; and $3.00/MMBtu with South Korea's Kogas and Centrica signed in 2013.
Oil parity is the LNG price that would be equal to that of crude oil on a Barrel of oil equivalent basis. If the LNG price exceeds the price of crude oil in BOE terms, then the situation is called broken oil parity. A coefficient of 0.1724 results in full oil parity. In most cases the price of LNG is less than the price of crude oil in BOE terms. In 2009, in several spot cargo deals especially in East Asia, oil parity approached the full oil parity or even exceeds oil parity. In January 2016, the spot LNG price (5.461 US$/mmbtu) has broken oil parity when the Brent crude price (≤32 US$/bbl) has fallen steeply. 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 transport sector.
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. Most of the LNG trade is governed by long term contracts. When the spot LNG price are 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.
JCC and ICP
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).
Brent and other energy carriers
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.
Quality of LNG
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:
- 1 – to ensure that the gas distributed is non-corrosive and non-toxic, below the upper limits for H2S, total sulphur, CO2 and Hg content;
- 2 – to guard against the formation of liquids or hydrates in the networks, through maximum water and hydrocarbon dewpoints;
- 3 – to allow interchangeability of the gases distributed, via limits on the variation range for parameters affecting combustion: content of inert gases, calorific value, Wobbe index, Soot Index, Incomplete Combustion Factor, Yellow Tip Index, etc.
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.
However, the main concern is the heating value of gas. Usually natural gas markets can be divided in three markets in terms of heating value:
- Asia (Japan, Korea, Taiwan) where gas distributed is rich, with a gross calorific value (GCV) higher than 43 MJ/m3(n), i.e. 1,090 Btu/scf,
- the UK and the US, where distributed gas is lean, with a GCV usually lower than 42 MJ/m3(n), i.e. 1,065 Btu/scf,
- Continental Europe, where the acceptable GCV range is quite wide: approx. 39 to 46 MJ/m3(n), i.e. 990 to 1,160 Btu/scf.
There are some methods to modify the heating value of produced LNG to the desired level. For the purpose of increasing the heating value, injecting propane and butane is a solution. For the purpose of decreasing heating value, nitrogen injecting and extracting butane and propane are proved solutions. Blending with gas or LNG can be a solutions; however all of these solutions while theoretically viable can be costly and logistically difficult to manage in large scale. Lean LNG price in terms of mmbtu is lower to the rich LNG price.
There are several liquefaction processes available for large, baseload LNG plants (in order of prevalence):
- AP-C3MRTM – designed by Air Products & Chemicals, Inc. (APCI)
- Cascade – designed by ConocoPhillips
- AP-X® – designed by Air Products & Chemicals, Inc. (APCI)
- AP-SMRTM (Single Mixed Refrigerant) – designed by Air Products & Chemicals, Inc. (APCI)
- AP-NTM (Nitrogen Refrigerant) – designed by Air Products & Chemicals, Inc. (APCI)
- MFC® (mixed fluid cascade) – designed by Linde
- PRICO® (SMR) – designed by Black & Veatch
- AP-DMRTM (Dual Mixed Refrigerant) - designed by Air Products & Chemicals, Inc. (APCI)
- Liquefin – designed by Air Liquide
As of January 2016, global nominal LNG liquefaction capacity was 301.5 MTPA (million tonnes per annum), and liquefaction capacity under construction was 142 MTPA.
The majority of these trains use either APCI AP-C3MR or Cascade technology for the liquefaction process. The other processes, used in a small minority of some liquefaction plants, include Shell's DMR (double-mixed refrigerant) technology and the Linde technology.
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 MMTPA have been designed based on the APCI process. Philips Cascade process is the second most-used, used in 10 trains with a total capacity of 36.16 MMTPA. The Shell DMR process has been used in three trains with total capacity of 13.9 MMTPA; and, finally, the Linde/Statoil process is used in the Snohvit 4.2 MMTPA 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, due for completion in around 2017.
Modern LNG storage tanks are typically 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 kPa (1.45 psig). Sometimes more expensive underground tanks are used for storage. Smaller quantities (say 700 m3 (190,000 US gallons) and less), may be stored in horizontal or vertical, vacuum-jacketed, pressure vessels. These tanks may be at pressures anywhere from less than 50 kPa to over 1,700 kPa (7 psig to 250 psig).
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. The boil-off gas is typically compressed and exported as natural gas, or it is reliquefied and returned to storage.
Main article: LNG carrier
Main article: Aviation_fuel § LNG
Liquefied natural gas (LNG) is natural gas that has been converted liquefied for ease of storage or transport.
liquefied Natural Gas (LNG)
LNG (Liquefied Natural Gas) is natural gas that has been liquefied for transport and storage.
Methane has a very low density and is therefore costly to transport and store. High pressure gas pipelines can be used to transport gas on land or for short ocean crossings. Liquefying natural gas makes it feasible to transport gas economically across oceans or in a few applications by truck to small scattered consumers. LNG occupies 600 times less space than the gas, but must be kept at temperatures below 160 degrees celsius and be pressurised. At the receiving terminal, LNG is unloaded and stored before being regasified and transported by pipe to the end-usersShell (2011).What Is LNG?Retrieved from: http://www.shell.com/global/future-energy/natural-gas/liquefied-natural-gas/what-is-lng.html Shell (2011).What Is LNG?Retrieved from: http://www.shell.com/global/future-energy/natural-gas/liquefied-natural-gas/what-is-lng.html Shell (2011).What Is LNG?Retrieved from: http://www.shell.com/global/future-energy/natural-gas/liquefied-natural-gas/what-is-lng.html Shell (2011).What Is LNG?Retrieved from: http://www.shell.com/global/future-energy/natural-gas/liquefied-natural-gas/what-is-lng.html .
The four main elements of the LNG value chain areLiquefied Natural Gas: Understanding the basic facts (2005).Primary Energy Consumption by Source and Sector, 2011Retrieved from: http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/LNG-PrimerUpdate.pdf Liquefied Natural Gas: Understanding the basic facts (2005).Primary Energy Consumption by Source and Sector, 2011Retrieved from: http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/LNG-PrimerUpdate.pdf Liquefied Natural Gas: Understanding the basic facts (2005).Primary Energy Consumption by Source and Sector, 2011Retrieved from: http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/LNG-PrimerUpdate.pdf Liquefied Natural Gas: Understanding the basic facts (2005).Primary Energy Consumption by Source and Sector, 2011Retrieved from: http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/LNG-PrimerUpdate.pdf :
- Exploration and Production - LNG is a transportation method for natural gas and therefore natural gas must first be produced and transported to an LNG facility for processing
- Liquefaction - this process converts gas to liquid by lowering the temperature of the gas to approximately -260 degrees Fahrenheit (-160 degrees Celsius)
- Shipping - special tankers with insulation and autorefrigeration keep the natural gas in liquid form as it is transported over massive bodies of water.
- Storage and Regasification - once the LNG reaches its destination it is stored or regasified back to its gaseous state. The regasification process involves passing the LNG through a series of vaporizers that reheat the fuel.
The demand for LNG is rising in markets with limited domestic gas production or pipeline imports. This increase is primarily from growing Asian economies and is particularly driven by their desire for cleaner fuels; and due to the shutdown of nuclear power plants. The largest producer of LNG is Qatar, with a liquefaction capacity in 2013 of roughly one-quarter of the global LNG productionInternational Energy Agency (2014). FAQs: Natural gashttp://www.iea.org/aboutus/faqs/gas/ International Energy Agency (2014). FAQs: Natural gashttp://www.iea.org/aboutus/faqs/gas/ International Energy Agency (2014). FAQs: Natural gashttp://www.iea.org/aboutus/faqs/gas/ International Energy Agency (2014). FAQs: Natural gashttp://www.iea.org/aboutus/faqs/gas/ . Japan has always been the largest importer of LNG and in 2013 consumed over 37% of global LNG trade.
LNG projects require very large amounts of upfront capital and, because of this, suppliers usually enter into long-term agreements ( up to 15 to 20 years) with buyers before taking their investment decision.
The extraction process has environmental and social issues to consider. These concerns are normally due to the energy inputs and local environmental impacts of such large scale industrial development. Additionally, while natural gas is the cleanest burning fossil fuel, it does produce CO2 when it is combusted and is a potent greenhouse gas itself, leading to climate-related concerns.
There have been two accidents (Cleveland, 1944 and Skikda, 2004) connected to LNG, but, in general, liquefaction, LNG-Shipping, -Storage, and -Regasification have been proven to be extremely safe. Only the Cleveland incident resulted in any loss of life to the general public; moreover, that event was 70 years ago and was before the effect of cryogenic temperatures on steels was understood.
- a, bLiquefied Natural Gas: Understanding the basic facts (2005).Primary Energy Consumption by Source and Sector, 2011Retrieved from: http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/LNG-PrimerUpdate.pdf
- ^Shell (2011).What Is LNG?Retrieved from: http://www.shell.com/global/future-energy/natural-gas/liquefied-natural-gas/what-is-lng.html
- ^International Energy Agency (2014). FAQs: Natural gashttp://www.iea.org/aboutus/faqs/gas/