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 Liquefied Natural Gas Chain

Liquefied Natural Gas (LNG) currently represents the most exciting aspect of the international gas landscape. Though the overall percentage of gas transported as LNG is less than 10% of global gas trade, it is growing rapidly, involving an increasing number of buyers and sellers. The past two decades have seen phenomenal growth in the LNG trade—growth that is expected to continue unabated this decade.

LNG is simply an alternative method to transport methane from the producer to the consumer. Methane (CH4) gas is cooled to minus 160°C (or more accurately, –161.5°C (–260°F), converting its gaseous phase into an easily transportable liquid whose volume is approximately 600 times less than the equivalent volume of methane gas. (The exact shrinkage is closer to 610 times, but 600 is commonly quoted.) Thus 600 ft3 of methane gas will shrink to a volume of around 1 ft3 of clear and odorless LNG. It is usually stored and moved at cold temperatures and at low pressure.

Gas converted to LNG can be transported by ship over long distances where pipelines are neither economic nor feasible. At the receiving location, liquid methane is offloaded from the ship and heated, allowing its physical phase to return from liquid to gas. This gas is then transported to gas consumers by pipeline in the same manner as natural gas produced from a local gas field.

The LNG process is more complex than pipeline transportation. The “LNG chain,” shown below, consists of discrete sections: upstream, midstream liquefaction plant, shipping, regasification, and finally, gas distribution.

LNG technology is not new. The first commercial LNG facility was built in the United States in 1941 in Cleveland as a peak load shaving facility. Gas (delivered via pipeline to the plant) was liquefied during hours or seasons of low demand and heated back to gaseous phase to be pumped into the pipeline grid during periods of high demand. Unfortunately, this plant was closed in 1944 due to a gas leak and subsequent explosion.

The decision to commercialize a gas field by either LNG or direct pipeline is related to the distance to market from the gas reservoir. A rule of thumb commonly followed states that LNG could be a viable option versus pipeline transport when the following characteristics are present:

The gas market is more than 2,000 km from the field.
The gas field contains at least 3 tcf to 5 tcf of recoverable gas.
Gas production costs are, ideally, less than $5/MMBtu, delivered to the liquefaction plant.
The gas contains minimal other impurities, such as CO2 or sulphur.
A marine port where a liquefaction plant could be built is relatively close to the field.
The political situation in the country supports large-scale, long-term investments.
The market price in the importing country is sufficiently high to support the entire chain and provide a competitive return to the gas exporting company and host country.
A pipeline alternative would require crossing uninvolved third-party countries and the buyer is concerned about security of supply.

Units used in the LNG trade can be confusing. Produced gas is measured in volume (cubic meters or cubic feet), but once it is converted into LNG, it is measured in mass units, usually tons or million tons. (This is abbreviated as MMT or, more commonly, MT. Million tons should technically be abbreviated MMT; however, the LNG industry uses MT to represent million tons.) LNG ship sizes are specified in cargo volume (typically, thousands of cubic meters), and once the LNG has been reconverted to gas, it is sold by energy units (in millions of British thermal units, MMBtu).

One ton of LNG contains the energy equivalent of 48,700 ft3 (1,380 m3) of natural gas. An LNG facility producing  1 million tons per year (million tons per annum, or MTA) of LNG requires 48.7 bcf (1.38 bcm) of natural gas per year, equivalent to 133 MMcfd. This facility would require recoverable reserves of approximately  1 tcf over a 20-year life. Similarly, a 4-MTA LNG train would consume an equivalent of 534 MMcfd (requiring reserves of 4 tcf over 20 years).

LNG chain: Upstream and Midstream

The upstream and midstream sections of the LNG chain are identical to traditional gas systems, with identical gas wells, wellheads, and field processing facilities. Because LNG requires gas to be cooled to very low temperatures, care must be taken to remove all impurities, especially water, from the methane stream prior to processing by the liquefaction plant.

LNG chain: Liquefaction Plants

The first large-scale LNG plant was built in Arzew, Algeria, in 1964 and went online in 1965. In 1969, Phillips constructed the Kenai LNG plant in Alaska. As of early 2006, there were at least 17 plants producing LNG in Africa, Middle East, Asia, Australia, the Caribbean, and Alaska. Though each plant is unique in design and size, they share many common features. The diagram below shows the layout of a typical LNG liquefaction and loading facility.

 Gas received into the LNG facility must be free from impurities and as close to pure methane as possible. Any other components, such as CO2 and sulphur, may damage the refrigeration units or decrease the quality of the produced LNG, or both.

The global LNG fraternity has adopted two main liquefaction processes for large (greater than 3 MTA) trains: the pure refrigerant cascade process (also known as the Phillips process), and the pre-cooled propane mixed refrigerant MCR process (promoted by Air Products, Shell, and others, and used by the majority of LNG plants). The first LNG plants in Algeria and Alaska were based on the Phillips cascade process using propane, ethylene, and methane as refrigerants. Since then, however, the majority of large base load projects have been based on Air Products’ propane Multi-Component Refrigerant (MCR) cryogenic heat exchangers. Various studies have shown that the efficiency of the main processors of both processes is similar. The choice of process may depend on individual company choice, license fees, and perceived advantages.  For smaller trains (less than 3 MTA), there are numerous processes available, including those from Black & Veatch, Hamworthy, and others.

Liquefaction plants are typically the most expensive element in an LNG project. Because 8%–10% of gas delivered to the plant is used to fuel the refrigeration process, overall operating costs are high even though other costs, such as labour and maintenance, are low.

Until the recent increase in capital costs over the past 8-10 years, economies of scale in LNG projects wassignificant.  Newer LNG plants were being built with larger, more efficient trains, and, in the case of adjoining plants (such as in Qatar) have shared facilities, thereby minimizing unit costs. Rising demand for steel and nickel, and high demand for engineering resources, are blamed for the reversal in the long-term declining cost trend. Recently completed plants, such as Woodside’s Pluto project, and nearly all the currently under construction Australian projects have announced costs that are upto 10 times greater per unit of LNG produced than those that began production before the rise in costs. This alarming trend will force project promoters to make increasingly aggressive LNG price forecasts and will undoubtedly result in squeezing of margins, and possibly, uneconomic projects if future prices do not live up to expectations.

Rising LNG prices are also encouraging development of gas resources previously considered uneconomic. Smaller and more remote fields could be developed using converted or specially constructed ships that will combine LNG production and storage systems, similar to FPSO production for oil fields. There are numerous technical challenges, most importantly the effect of ‘sloshing’ on partial filled tanks – while LNG is being produced – and the offloading of LNG from one floating vessel to another floating vessel. There are a number of companies that are promoting their FLNG (Floating LNG) concepts, with first production likely post 2015 in Malaysia followed by Colombia and then Australia with the giant Prelude FLNG project. FLNG has the potential to be a ‘game-changer’ opening up vast numbers of stranded gas fields – if costs can be maintained and technology keeps abreast with expectations.

 LNG chain: Transportation

LNG is usually transported to the gas consumer by specially designed refrigerated ships. The ships operate at low atmospheric pressure (unlike LPG carriers, which operate at much higher pressures), transporting the LNG in individual insulated tanks. Insulation around the tanks maintains the temperature of the liquid cargo, keeping the boil-off (conversion back to gas) to a minimum. Because most older ships do not have active refrigeration systems onboard, ships use the produced boil-off gas as engine fuel. On a typical voyage, an estimated 0.1%–0.25% of the cargo converts to gaseous phase daily.

Most LNG plants have their own dedicated fleet of LNG ships, operating a “virtual” pipeline. As a ship is being loaded, a sister ship may be discharging its cargo, and the remaining members of the fleet are either en route to the buyer’s regas facility or on the way back to the LNG plant to pick up new cargo. However, as the LNG short-term and spot trade increases, ships are loading LNG from different plants and discharging their cargoes wherever the prices are best at the time.

LNG chain: Regasification Terminals

LNG receiving terminals, also called regasification facilities or regas facilities, receive LNG ships, store the LNG until required, and send out gaseous methane into the local pipeline grid. The main components of a regas facility are the offloading berths and port facilities, LNG storage tanks, vaporizers to convert the LNG into gaseous phase, and pipeline link to the local gas grid. LNG tankers may also be offloaded offshore, away from congested and shallow ports. This is accomplished using a floating mooring system (similar to that used for oil imports) via undersea insulated LNG pipelines to a land-based regas facility.

The largest component of receiving terminal capital cost is the vaporizer process equipment. Vaporizers warm LNG from –161.5°C to more than 5°C, converting methane from liquid phase into gas. Conceptually, vaporizers are relatively simple units in which LNG is pumped through tubular or paneled heat exchangers, allowing the temperature to rise. Contact with seawater in warmer climates or heated water in colder climates keeps the heat exchangers warm. Large volumes of seawater are kept flowing through the system to avoid ice buildup on the panels.

In conventional onshore-based regas facilities, offloaded LNG is stored in large tanks, either above ground or semi-buried, until gas is required by consumers. Semi-buried tanks, which can be spaced closely together, are most common in Japan, where land is scarce. LNG is also being offloaded offshore, usually by modified LNG tankers that also have regasification units on board. These ships have the ability to discharge gaseous methane directly into a pipeline grid or discharge LNG by offshore moorings into cryogenic pipelines for gasification onshore, as well as conventional LNG offloading to a shore facility by fixed arms. Ship-to-ship LNG transfer is still in its early stages and all the technical hurdles have yet to be fully ironed out. Once this process will become conventional, we could see large ships discharging to smaller ships offshore, and these smaller ships will be able to come directly to port, convert the LNG to methane which will be directly piped to the local grid.


BBC video on LNG tankers


LNG Process - From Plant to Plant – the LNG process by Woodside Energy