Listing description
Liquefied natural
gas takes up about 1/600th the volume of natural gas in the gaseous state. It
is odorless, colorless, non-toxic and non-corrosive. Hazards include flammability,
freezing and asphyxia
A typical LNG
process. The gas is first extracted and transported to a processing plant where
it is purified by removing any condensates such as water, oil, mud, as well as
other gases like CO2 and H2S and some times solids as
mercury. The gas is then cooled down in stages until it is liquefied. LNG is
finally stored in storage tanks and can be loaded and shipped.
The liquefication
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 (maximum transport pressure set at around 25 kPa/3.6 psi) by
cooling it to approximately −162 °C (−260 °F
Detailed description
The reduction in
volume makes it much more cost efficient to transport over long distances where
pipelines do not exist. Where moving natural gas by pipelines is not possible
or economical, it can be transported by specially designed cryogenic sea vessels (LNG carriers) or cryogenic road tankers.
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Basic facts
LNG is
principally used for transporting natural gas to markets, where it is
regasified and distributed as pipeline natural gas. LNG offers an energy density comparable to Gasoline and diesel fuels and produces less pollution, but its
relatively high cost of production and the need to store it in expensive
cryogenic tanks have prevented its widespread use in commercial applications.
It can be used in natural
gas vehicles,
although it is more common to design vehicles to use compressed
natural gas.
The density of
LNG is roughly 0.41 kg/L to 0.5 kg/L, depending on temperature,
pressure and composition, compared to water at 1.0 kg/L. The heat value
depends on the source of gas that is used and the process that is used to
liquefy the gas. The higher
heating value
of LNG is estimated to be 24 MJ/L at −164 degrees Celsius. This value
corresponds to a lower
heating value
of 21 MJ/L.
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% methane. It also contains small amounts of ethane, propane, butane and some heavier alkanes. The purification process can be designed to
give almost 100% methane. One of the very rare risks of LNG is
rapid
phase transition
(RPT), which occurs when cold LNG comes into contact with water[2].
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 now in operation is in Qatar. Until
recently it was the Train 4 of Atlantic LNG in Trinidad
and Tobago
with a production capacity of 5.2 million metric ton per annum (mmtpa),[3] followed by the SEGAS LNG plant in Egypt with a capacity of
5 mmtpa. The Qatargas II plant has a production capacity of
7.8 mmtpa for each of its two trains. LNG is loaded onto ships and
delivered to a regasification terminal, where the LNG is reheated and turned
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).
In 1964, the UK
and France made the first LNG trade, buying gas from Algeria, witnessing a new era of energy. As
most LNG plants are located in "stranded" areas not served by
pipelines and the costs of LNG treatment and transportation are huge,
development was slow during the second half of the last century. The
construction of an LNG plant costs at least USD 1.5 billion per
1 mmtpa capacity, a receiving terminal costs USD 1 billion per 1 bcf/day
throughput capacity, and LNG vessels cost USD 0.2–0.3 billion. Compared
with the crude oil market, the natural gas market is about 60% 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).
Commercial aspects
LNG is shipped
around the world in specially constructed seagoing vessels. The trade of LNG is completed by
signing a sale and purchase agreement (SPA) between a supplier and receiving
terminal, and by signing a gas sale agreement (GSA) 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, contract with the
term of FOB increased. Under such term, 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 15 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, the OPEC equivalent of
natural gas.
Russia and Qatar, countries with the largest and the third
largest natural gas reserves in the world, have finally supported such move.[citation needed]
Until 2003, LNG
prices have closely followed oil prices. Since then, LNG prices in Europe and
Japan have been lower than oil prices, although the link between LNG and oil is
still strong. In contrast, prices in the US and the UK have recently
skyrocketed, then fallen as a result of changes in supply and storage.[citation needed]
In 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.[citation needed]
Receiving
terminals exist in about 18 countries, including India, Japan, Korea, Taiwan,
China, Belgium, Spain, Italy, France, the UK, the US, Chile, and the Dominican
Republic, among others. Plans exist for Argentina, Brazil, Uruguay, Canada,
Greece, and others to also construct new receiving or gasification terminals.
Trade
In
2004, LNG accounted for 7% of the world’s natural gas demand.[5]
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 during the coming years.[6]
The projected growth in LNG in the base case is expected to increase at 6.7
percent per year from 2005 to 2020.[6]Until the mid-1990s, LNG demand was heavily concentrated in Northeast Asia — Japan, Korea and Taiwan. At the same time, Pacific Basin supplies dominated world LNG trade.[6] The world-wide 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.[6]
By the end of 2007 there were 15 LNG exporting countries and 17 LNG importing countries. The three biggest LNG exporters in 2007 were Qatar (28 MT), Malaysia (22 MT) and Indonesia (20 MT) and the three biggest LNG importers in 2007 were Japan (65 MT), South Korea (34 MT) and Spain (24 MT). LNG trade volumes increased from 140 MT in 2005 to 158 MT in 2006, 165 MT in 2007, 172[7] MT in 2008 and it is forecasted to be increased to about 200 MT in 2009 and about 300 MT in 2012. During next several years there would be significant increase in volume of LNG Trade and only within next three years; about 82 MTPA of new LNG supply will come to the market. For example just in 2009, about 59 MTPA of new LNG supply from 6 new plants comes to the market, 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
Cargo diversion
Based
on the LNGSPAs, 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 diversion of the cargoes is possible but subject to sharing the profits
coming from such diversion. In some jurisdictions such as the European Union it
is not allowed to apply the profit-sharing clause in the LNGSPAs for any
diverted cargoes inside the EU territories.$4.90/68286KG OR $4.90/150,230IB
For more information:
mobile: +2348039721941
contact person: emeaba uche
e-mail: emeabau@yahoo.com
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