Natural Gas Facts

What is LNG?

LNG is simply natural gas – primarily methane with small quantities of ethane and propane – that has condensed into a liquid state when cooled to minus-162.2º Celsius. At this temperature it becomes a clear, colorless, odorless liquid similar to water (although LNG weighs about half as much as water). In a well-insulated container, LNG does not require compression and yet occupies about 1/600th the volume that would be occupied by the same natural gas at atmospheric pressure and 15º C. Despite relatively high costs and energy use, LNG offers a useful way to store and transport natural gas where other, less costly means are not available.

Since the 1960s, LNG has become an increasingly important way to transport natural gas from natural-gas-producing areas such as Indonesia, Australia, the Middle East, Africa and the Caribbean to consuming areas such as Japan, Korea, Taiwan, Western Europe and the United States. In addition, some natural gas companies liquefy natural gas and store it on site for use during peak demand periods.
In Canada, two terminals are currently under construction to receive, store and regasify LNG in New Brunswick and Nova Scotia, with imports scheduled to begin in 2008. Five other terminals have been proposed for locations in Nova Scotia, Quebec and British Columbia. There are also three LNG storage facilities – in British Columbia, Ontario and Quebec – that liquefy natural gas for on-site storage and regasification.

How is LNG produced, shipped and delivered?

The natural gas for LNG projects is produced in the conventional manner from onshore or offshore wells and pipelined to the liquefaction plant. To date, all liquefaction facilities have been located on land, but designs have been developed for floating liquefaction plants that may be built to serve offshore gas fields such as those off the coasts of Africa or Australia. Floating liquefaction plants could possibly be used eventually in other locations such as the crude oil and natural gas fields off Newfoundland and Labrador. (There is one floating terminal to receive LNG shipments, 50 kilometres offshore in the Gulf of Mexico.)

A liquefaction plant consists of one or more production lines, known as trains. The first stage removes hydrogen sulphide, other sulphur compounds, carbon dioxide, water, and heavier hydrocarbons such as butane and pentanes. It is particularly important to remove anything that might freeze and cause blockages in the cooling process. After treatment, the gas is mainly methane with small amounts of propane, ethane and nitrogen. Some propane and ethane is removed from the gas stream for use as refrigerant fluid for the cooling process.

Liquefaction plants are based on the same principles used in refrigerators, freezers, hockey rinks and heat pumps. The compression and expansion of refrigerant fluid removes heat from the natural gas. This typically requires several stages of cooling to reach the temperature where the methane becomes a liquid. The liquid is then stored at atmospheric pressure in insulated, double-walled stainless steel tanks. Because some heat enters even the best-insulated tanks, a small amount of LNG is continually boiling off; this evaporation serves to keep the rest of the contents chilled. The boiled-off natural gas is captured and fed back into the production train at liquefaction plants.

Where is LNG produced?

Twelve countries currently produce and ship LNG: Algeria, Australia, Brunei, Indonesia, Libya, Malaysia, Nigeria, Oman, Qatar, Trinidad and Tobago, United Arab Emirates, and the United States (Alaska). The five largest exporters of LNG are: Algeria, Australia, Indonesia, Malaysia, and Qatar. For more than 30 years, small quantities of LNG have been produced in Kenai, Alaska, for export to Japan. Russia began exporting LNG in 2005, while Norway is scheduled to begin exporting LNG by 2006.

How is LNG shipped?

LNG tankers are loaded and unloaded through insulated pipes. The double-hulled ships are typically more than 300 metres long and carry five or more insulated, double-walled stainless steel LNG tanks. The natural gas that boils off in transit from the LNG tanks is captured and mixed with fuel in the ship’s power boilers.

How is LNG stored and regasified?

Import terminals store the LNG in insulated, double-walled stainless steel tanks. When demand arises, the LNG is warmed enough to return it to a gaseous state before it is pumped into the pipeline system for delivery to consumers. A similar procedure is followed at so-called “peak-shaving” liquefaction plants, where the LNG is stored on site for use during peak demand periods.

In Japan, much of the LNG is used directly in adjacent electric generating stations, where the chilled gas increases the efficiency of combustion. Japanese power plants have been the biggest single market for LNG since the 1970s. Otherwise, the natural gas from LNG regasification is pipelined to residential, commercial and industrial customers and is indistinguishable from other natural gas.

Fourteen countries currently import LNG: Belgium, Dominican Republic, France, Greece, India, Italy, Japan, Korea, Portugal, Puerto Rico, Spain, Taiwan, Turkey, and the United States. The five largest importers of LNG are: Japan, Korea, Spain, Taiwan, and the United States. Japan has only small domestic natural gas production and imports 97 per cent of its natural gas requirements, all as LNG. China and the United Kingdom are expected to begin importing LNG in 2006.

LNG, in addition to being imported from abroad in large ocean tankers, can be produced domestically. Domestic LNG serves as a “peak-shaving” fuel to meet peak demand in North America. The three such LNG liquefaction and storage facilities in Canada are located near Vancouver, British Columbia; Montreal, Quebec, and Sudbury, Ontario.

LNG facilities are expensive to build because all equipment must meet high safety standards and because many costly components, including large amounts of stainless steel, are needed to resist the embrittling effects of extreme cold. The liquefaction plant is the most expensive part, costing $1-2 billion or more depending on the size and location. The cost of receiving terminals varies widely, from about $500 million to $2 billion, depending on factors such as the number of storage tanks. LNG tankers cost $150 million or more. In addition, there are high energy and maintenance costs for the liquefaction plants, plus significant operating costs for the ships and terminals.

How has the LNG industry evolved?

The process of compressor refrigeration was developed in the 19th century based on the scientific work of Michael Faraday. The first plant to use refrigeration to liquefy natural gas was built in West Virginia in 1912. In 1914 Godfrey Cabot submitted a U.S. patent for shipping LNG by barge. Until the 1950s, however, LNG was seen mainly as a way to store natural gas for use during peak demand periods. Natural gas was also sometimes liquefied in order to extract helium. (Helium is a valuable by-product of liquefaction when it is present in the raw natural gas. Qatar and Australia both extract helium at their LNG facilities.)

The practicality of transporting LNG in tankers was demonstrated in 1959 when a converted freighter delivered a shipment of LNG from Louisiana to Britain. Five years later, regular tanker deliveries began between a liquefaction plant in Algeria and a British terminal. The second trade route for LNG opened in 1969 from Alaska to Japan. Japan has remained the world’s largest importer of LNG ever since, drawing on supplies from Indonesia and Australia as well as Alaska.

High natural gas prices and perceived shortages during the 1970s spurred construction of U.S. LNG terminals in Massachusetts, Maryland and Georgia, drawing mainly on supplies from Algeria. (Britain no longer required Algerian gas as North Sea natural gas production came on stream in the 1970s.) U.S. imports peaked in 1979 but dropped rapidly thereafter due to lower prices, more abundant North American supplies and a pricing dispute with Algeria. A fourth U.S. terminal, in Louisiana, opened in 1981 and shut down a year later. Another approved terminal in California was never built. In 1986, U.S. LNG imports dropped to zero. Imports resumed two years later, and the Louisiana terminal reopened, but LNG remained a very small factor in meeting U.S. natural gas demand. During the 1990s, the shortfall in U.S. supplies was met almost entirely from Canada, which saw its share of the U.S. market rise to nearly 15 per cent.

Japan, subsequently joined by Korea and Taiwan, remained the major market for LNG through the 1980s and 1990s. Along with a steady increase in European LNG demand – and new exporters in the Middle East, Africa and the Caribbean – the LNG industry was able to keep growing and improving its technology and economics. The cost of building an LNG tanker, for example, dropped nearly 40 per cent from the mid-1980s to 2003. Low natural gas prices gave operators a powerful incentive to reduce costs and improve efficiency. New technologies also enabled the industry to reduce substantially its energy consumption and emissions.

LNG was therefore well positioned to grow as the 21st century brought higher natural gas prices and renewed concerns about future supplies in North America and other consuming areas. Meanwhile, many of the world’s largest remaining natural gas reserves were located in areas not currently connected by pipeline to consumers.

No wonder there have been more than 50 proposals for new terminals in the United States, Mexico and Canada.
It may seem surprising that LNG-importing projects are being built and proposed in Canada, an exporter of natural gas. However, there are a number of reasons for this. Current natural gas producing areas in Western Canada have not been able to increase output despite record drilling activity. Nova Scotia offshore production has been declining, and only one new field has been found there. Meanwhile, demand continues to grow in the United States and Canada, especially for natural gas to extract and process oilsands bitumen in Alberta. Even when pipelines are built to bring natural gas from the Arctic, much of it will be needed in Alberta and the continental heartland. Since there are pipeline systems already in place on both the east and west coasts, LNG project sponsors believe it makes sense to bring in supplementary supplies from places such as West Africa that have natural gas reserves but no pipelines to markets.

What new LNG projects have been proposed?

Two LNG terminals have received regulatory approval and are under construction on the East Coast, one at Saint John, New Brunswick, and one at Bear Head near Point Tupper, Nova Scotia. Both plan to be in operation by 2008, and each will be capable of delivering about 1 billion cubic feet per day (bcf/d) of natural gas. (This compares with Canada’s 2004 natural gas production of 17.4 bcf/d, of which 9.7 bcf/d was exported to the United States. One billion cubic feet is equivalent to 28.32 million cubic metres or 1.091 petajoules of energy.)

The additional gas will serve nearby markets and feed into the pipeline system that currently carries Nova Scotia offshore natural gas through New Brunswick to the New England states.

Up-to-date maps of existing, approved and proposed LNG projects in North America are posted on the U.S. Federal Energy Regulatory Commission website.

Sponsors have identified five other potential LNG terminal sites in Canada – near Quebec City (0.5 bcf/d); Rivere-du-Loup, Quebec (0.5 bcf/d); Kitimat, British Columbia (0.6 bcf/d); Prince Rupert, British Columbia (0.3 bcf/d), and Goldboro, Nova Scotia (1.0 bcf/d). Natural gas from the proposed Quebec terminals would supplant Western Canadian gas in Quebec, with any surplus exported to the northeast United States. The B.C. projects would supplement the province’s own natural gas production and free up more gas for U.S. exports.

Further information regarding approved and proposed LNG import projects in Canada can be found at Natural Resources Canada.

As of October 2005, more than 30 LNG terminals are proposed in the United States and eight in Mexico; 13 of these have received regulatory approval – 10 in the United States and three in Mexico.

What are the economic issues in using LNG?

The cost of liquefying, shipping, storing and regasifying LNG can amount to US$3 per thousand cubic feet of natural gas or more. During the 1980s and 1990s, North American natural gas prices were often below these levels, so there was no profit available for the project operators or the gas producers. In 2004, however, the average price for natural gas in North American was about US$6, and the trend seems headed upward. As a result, there appear to be ample rewards available for both project developers and natural gas producers. For producing countries, the economic development from building and operating liquefaction facilities is an important incentive. If the natural gas would otherwise be shut in, flared or reinjected, any revenue may seem a bonus.

What are the safety and environmental issues?

If LNG is released into the environment, it initially flows like water but rapidly regasifies on exposure to ambient temperatures. The gaseous form is lighter than air and rapidly rises into the atmosphere. At a concentration of 5 to 15 per cent natural gas in air, the mixture is flammable. In 2004, an explosion and fire at a liquefaction plant in Algeria killed 27 people. In 1979, an explosion at a Maryland LNG terminal killed one worker. In 40 years of LNG tanker operation, and more than 30,000 voyages, there have been no incidents involving onboard explosions or major releases from the ships.

The worst LNG accident took place in 1944 at a peak-shaving plant in Cleveland, Ohio. In this incident 138 people were killed after LNG leaked into a sewer and exploded. A review of the causes showed that, due to wartime shortages, low-nickel-content steel had been used in the storage tank that leaked. Since then, regulators and companies have insisted on high standards for siting, materials and procedures for all LNG facilities.

A sudden release of LNG would pose two kinds of safety concerns – the risk of fire or explosion, and the risk from contact with the extremely cold liquid or gas before it disperses. Extreme cold can cause burns, so workers wear protective clothing and are trained to avoid contact with cold surfaces or LNG.

Controlled experiments and computer models have been used to determine how far the ignition or freezing hazards might extend after an LNG release, and the sites for facilities are chosen on the basis of this research. For example, the research indicates that the cold might cause water to freeze in an enclosed water body after an LNG release but that this would probably not occur in open water.

U.S. regulations establish formal “exclusion zones” around LNG facilities to ensure public safety. The zones, typically about 300 to 400 metres, are based on meteorological data and known dispersion patterns for LNG and natural gas.

The Canadian regulatory review process for LNG development includes two main elements. First, all LNG facilities are subject to comprehensive federal-provincial environmental assessment, including public consultation, prior to approval. Second, proponents of LNG projects are also required to obtain a permit to construct and operate the facility. (Further information about Canadian LNG regulatory requirements is posted on the Natural Resources Canada and National Energy Board websites.)

The Canadian Standards Association (CSA) has established standards for the siting, construction, materials and procedures used in LNG facilities. CSA standard Z-276, LNG – Production, Storage and Handling, dates back to 1972 and was originally developed for the 3 Canadian LNG peak-shaving storage plants that were built in the 1960s and 1970s. The CSA LNG standards are currently being revised to reflect the development of LNG import terminals in Canada.

Challenges and opportunities