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Difference between revisions of "Liquified natural gas (LNG)"
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== Online multimedia ==
== Online multimedia ==
Morgan, John. 2012. LNG – Changing Quickly.
Morgan, John. 2012. LNG – Changing Quickly.://.spe.//
== External links ==
== External links ==
Latest revision as of 09:42, 15 January 2018
Liquified natural gas (LNG) is the liquid form of natural gas at cryogenic temperature of −265°F (−160°C). When natural gas is turned into LNG, its volume shrinks by a factor of approximately 600. This reduction in volume enables the gas to be transported economically over long distances.
Over the past 30 years, a considerable world trade in LNG has developed. Today, LNG represents a significant component of the energy consumption of many countries and has been profitable to both the exporting host countries and their energy company partners. The total LNG production capacity as of year 2001 is approximately 106 million tonnes per annum. LNG accounts for only 4% of the total gas consumption but 25% of internationally traded gas. Asia remains a dominant player in the world LNG market, both as an importer and an exporter. Japan is the world’s larger importer of LNG, with 53% of the total production capacity. Indonesia is the largest exporting nation, with 27% of all exports.
In 1914, Godfrey Cabot patented a river barge for handling and transporting liquefied gas. As early as 1917, liquefaction was used in the United States for the extraction of helium. However, it was not until 1959–60 that the Methane Pioneer, a converted cargo vessel, first demonstrated the technique of bulk LNG transport by successfully and safely carrying seven LNG cargoes from Lake Charles, Louisiana, in the United States, to Canvey Island in the U.K. The first commercial LNG plant in Algeria became operational in 1964 and exported LNG to western Europe. Currently, 12 countries have liquefaction facilities with 64 LNG trains, and 38 receiving terminals are operating in 10 countries.
The key components of the LNG chain include a gas field, liquefaction plant, LNG carriers, receiving and regasification terminal, and storage.
Fig. 1 shows the main components of a typical LNG liquefaction plant. LNG liquefaction plants are generally classified as baseload or peak shaving, depending on their purpose and size. This discussion is directed toward baseload LNG plants. The process for the liquefaction of natural gas is essentially the same as that used in modern domestic refrigerators, but on a massive scale. A refrigerant gas is compressed, cooled, condensed, and let down in pressure through a valve that reduces its temperature by the Joule-Thomson effect. The refrigerant gas is then used to cool the feed gas. The temperature of the feed gas is eventually reduced to −161°C, the temperature at which methane, the main constituent of natural gas, liquefies. At this temperature, all the other hydrocarbons in the natural gas will also be in liquid form. In the LNG process, constituents of the natural gas (propane, ethane, and methane) are typically used as refrigerants either individually or as a mixture. Feed pretreatment and refrigerant component recovery are normally included in the LNG liquefaction facility. LPG and condensate may be recovered as byproducts.
There are three main types of liquefaction cycles: cascade, mixed refrigerant, and expansion cycles. Most commercially available liquefaction processes are based on these cycles or a combination of these cycles. These processes include the pure-component cascade cycle, propane-precooled mixed-refrigerant cycle, dual mixed-refrigerant cycle, single mixed-refrigerant cycle, mixed-fluid cascade process, compact LNG technology, and integral incorporated cascade (CII™) process. 
Table 1 summarizes the market share (based on tonnage of LNG produced) as of year 2001 of the different liquefaction processes. Economies of scale are driving single-train sizes up from approximately 1 million tonnes per annum in 1960 to 5 million tonnes per annum in 2001.
LNG is shipped commercially in a fully refrigerated liquid state. The fundamental difference between LNG carriers and other tankers is the cargo containment and handling system. The combination of the metallic-tank containment and insulation needed to store LNG is called a “containment system.” There are two main types of containment systems: self-supporting tank and membrane tanks. Current LNG vessels have 135 thousand m3 carrying capacity (approximately 60 thousand metric tons) and cost approximately U.S. $160 million. These carriers either consume boiloff gas or reliquefy the gas and use diesel as fuel.
Receiving, regasification terminal and storage
The function of an LNG import terminal is to receive LNG cargos, store LNG, and revaporize the LNG for sale as gas. Odorant injection may be required if gas is to be exported through a transmission grid. There are two main systems used for LNG vaporization: submerged combustion vaporizers and open-rack vaporizers (ORVs). In submerged combustion vaporizers, the LNG passes through tubes immersed in a water bath, which is heated by submerged burners. In ORVs, water runs down the outside of the vaporizer tubes (usually vertical) as a film. River water or seawater is normally used.
The costs of delivering large quantities of gas by pipeline rise rapidly with distance. At some point, it becomes more economical to transport the gas as LNG. Several comparisons of pipeline and LNG have been published that point to the fact that LNG is competitive with pipelines for distances greater than 2500 km. Compared with pipelines, LNG has the benefits of modular buildup and few border/right-of-way issues. The LNG plant size can be determined by the gas-field size. Approximately, 1 Tcf of feed gas is required to produce 0.8 million tons per annum (mtpa) of LNG for 20 years. Hence, 5 million tons per annum of LNG production will require a gas-field size of approximately 6 Tcf. The typical gas consumption for the production of LNG from feed gas in the liquefaction plant can be calculated on the basis of 10% of the feed gas used for internal fuel consumption. The total energy required for the plant comes from the feed gas itself. Table 2 summarizes the loss of feed gas as fuel in the LNG chain (excluding the gas production facility, which may include extraction of liquids and nonhydrocarbon gases):
The LNG carriers are typically designed for speeds of 17 to 20 knots. The number of ships required for 1 mtpa can be quickly estimated by
where n = the number of ships and L = the one-way distance in nautical miles.
The following are some considerations in evaluating options for transportation of gas as LNG.
Long term contracts
LNG is a mature industry and has established a niche for itself by matching remote gas supplies to markets that lack indigenous gas reserves. Currently, the majority of the LNG is not traded like a commodity. LNG trading requires coordination of principals in the production, export, shipping, and import segments of the trade. As a result, long-term contracts for LNG dominate the industry. The requirement for long-term (20 to 25 years) contracts is seen by some as a possible hurdle in the growth potential for LNG.
Economics of the LNG chain
The costs to produce and supply LNG can be divided among the major elements that make up the supply chain.
- Gas production facilities. In view of the high cost of liquefaction and shipping of LNG, it is essential to have low-cost feed gas to produce LNG competitively. Gas production cost typically varies from U.S. $0.25/million Btu to more than U.S. $1.0/million Btu. A production cost of less than U.S. $1.0/million Btu is desirable to make the LNG option economically viable.
- Baseload liquefaction plant with storage and export facilities. LNG projects are inherently capital intensive. The liquefaction plant is the largest cost component, accounting for approximately 50% of the total cost of the LNG chain.  Fig. 2 shows the typical capital cost breakdown of a grassroots LNG liquefaction facility. The capital cost of the liquefaction facilities is dependent on several factors such as plant location, size of plant, site conditions, and quality of feed gas. The contribution of the liquefaction plant cost to the cost of delivery of LNG ranges from U.S. $1.5 to $2.0/million Btu. The cost of a liquefaction plant is a significant component of the cost of the LNG chain; hence, cost reduction of the liquefaction facility is an important issue. The thermodynamics of the liquefaction processes are well developed. Thus, further advances and cost reductions in this industry come from refinement of equipment to better service (make more efficient) the liquefaction process and/or support infrastructure (utilities). Several publications discuss cost reductions in liquefaction plants.   
- LNG tanker ships (transportation). The fleet of tankers for an LNG project is a significant portion of the total cost of the LNG chain. The number of ships and, hence, the cost of shipping is dependent on the distance between the liquefaction facility and the market. A typical contribution of the shipping cost to the cost of delivered LNG is approximately U.S. $0.5 to $1.2/million Btu.
- Import terminal with storage and regasification facilities. The receiving terminals with tanks, vaporization equipment, and utilities contribute approximately U.S. $0.3 to $0.4/million Btu to the delivered price of LNG. These costs are highly dependent on design practices (especially the design of the storage tanks) and specific site conditions.
For LNG to become the energy source of choice, the cost of the LNG chain has to be competitive with alternative fuel sources. The trend is toward large liquefaction-train sizes and fit-for-purpose plants to reduce the capital cost of the liquefaction facilities. On the terminal side, there is a high level of interest in moving facilities offshore because of environmental and permitting issues. Several companies have proposed concepts for offshore storage and regasification terminals. Other areas of interest are integration of receiving terminals with facilities such as power plants or air separation units.
- World LNG Source Book 2001. 2001. Des Plaines, Illinois: Gas Technology Inst.
- A Guide to the LNG World. 2001. Oil & Gas J. (16 July): 17.
- Finn, A.J., Johnson, G.L., and Tomilinson, T.R. 1999. Developments in Natural Gas Liquefaction. Hydrocarbon Processing (April).
- Vink, K.J. and Nagelvoort, R.K. 1998. Comparison of Baseload Liquefaction Processes. Paper presented at the 1998 Intl. Conference on Liquefied Natural Gas, Perth, Australia, 4–7 May.
- Process Evaluation—Research Planning, Liquefied Natural Gas. PERP report by Chemsystems Inc, 96/97S2, November. Cite error: Invalid
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- Kotzot, H.J. 2001. LNG Plant Size Versus LNG Transportation Distance. 2001 AICHE Spring Natl. Meeting, Houston, Texas, 22–26 April.
- Robertson, G.A. and Nagelvoort, R.K. 1998. Minimizing Costs to Compete with Alternative Energy Sources. Fundamentals of the Global LNG Industry. London, England: The Petroleum Economist.
- Coyle, D.A., Durr, C.A., and Hill, D.K. 1998. Cost Optimization, the Contractor’s Approach. Paper presented at the 1998 Intl. Conference on Liquefied Natural Gas, Perth, Australia, 4–7 May.
- Durr, C.A. et al. 1998. Improved Plant Design and Cost Reduction Through Engineering Development. Paper presented at the 1998 Intl. Conference on Liquefied Natural Gas, Perth, Australia, 4–7 May.
- Durr, C.A. et al. 1998. The Commercial and Technical Interface. Paper presented at the 1998 Intl. Conference on Liquefied Natural Gas, Perth, Australia, 4–7 May.
- DiNapoli, R.N. and Yost, C.C. 1998. LNG Plant Costs: Present and Future Trends. Paper presented at the 1998 Intl. Conference on Liquefied Natural Gas, Perth, Australia, 4–7 May.
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Morgan, John. 2012. LNG – Changing Quickly. https://webevents.spe.org/products/lng-changing-quickly
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