Petroleum Industrial Chemistry

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PETROLEUM INDUSTRIAL

CHEMISTRY

PROJECT

LIQUEFIED NATURAL GAS

PREPARED BY JAY JANI 08BT01088



ABSTRACT

The natural gas in its liquid form is known as LNG or liquefied natural gas. LNG

is an odourless, colourless, non-toxic and non-corrosive liquid, and is produced from

natural gas by cooling it at atmospheric pressure and temperature to -160ºC. Liquefied

natural gas takes up about 1/600th the volume of natural gas in the gaseous state. And

because of this reason it is widely used as an efficient and safe way to transport natural

gas across long distances and store it near consumers. Hence the natural gas in the

liquefied from occupies a smaller volume and does not need to be stored at high

pressures. The natural gas is then condensed into a liquid at close to atmospheric pressure

by cooling it to approximately í162 °C (í260 °F).LNG is a very clean fuel since absence

of an ignition source results in its quick evaporation and dispersion, leaving no

residue.When vaporized, it burns only in concentrations of 5% to 15% when mixed with

air. Neither LNG, nor its vapour, can explode in an unconfined environment. 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.The energy density of LNG is 60% of that of diesel

fuel.

Manufacturing process of liquefied natural gas involves mainly four steps that are

exploration and production, liquefaction process, LNG transportation and its storage. And

finally if it is required to convert it into natural gas, a re-gasification process is

used.Theliquefaction process involves removal of certain components, such as dust,

helium, acid gases, water, and heavy hydrocarbons, which could cause difficulty

downstream, and then condensed into a liquid at close to atmospheric pressure. LNG has

become a viable alternative to oil or piped gas (natural gas transported from its country of

origin through pipelines). Indeed, LNG is increasingly being seen as the best technology

for large-scale movement of natural gas over long distances. And LNG terminals provide

flexibility as the gas can come from anywhere in the world, especially countries too far

away to supply gas by pipeline. 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.

LNG which has been highly purified (i.e. about 95 to 99 mol % methane purity) is

suitable for use as vehicular fuel, since it is clean burning, costs significantly less than

petroleum or other clean fuels, provides almost the same travel range between fill-ups as

gasoline or diesel, and requires the same fill-up time. High methane purity LNG can also

be economically converted into compressed natural gas (CNG), another clean,

economical vehicle fuel.



History of LNG

Liquefied natural gas (LNG) was proven viable in 1917, when the first LNG plant

went into operation in West Virginia. The first commercial liquefaction plant was built in

Cleveland, Ohio in 1941. In January 1959, the world's first LNG tanker carried LNG

cargo from Lake Charles, Louisiana to Canvey Island, United Kingdom. This eventdemonstrated that large quantities of LNG could be transported safely across the ocean.

In 1961, Britain signed a 15-year contract to take less than 1 million tonnes per

annum (mtpa) from Algeria, commencing in 1965. The first liquefaction plant in the

world was commissioned at Arzew in Algeria to supply this contract with gas production

coming from huge gas reserves found in the Sahara. The following year the French signed

a similar deal to buy LNG from Algeria.

Alaska's Kenai plant (which currently has a capacity of 1.3 mtpa) began LNG

deliveries to Japan's Tokyo Gas and Tokyo Electric Power Company (Tepco) in 1969. In1972, Brunei became Asia's first producer, bringing on stream an LNG plant at Lumut

that now has a capacity of 6.5 mtpa and supplies Korea as well as Japan. Libya's plant at

Marsa el Brega began deliveries to Spain in 1970. Italy was also supplied by Libya,

marking the entry of a new producer and two new buyers into the ranks of LNG trade.

U.S. imports from Algeria were approved in 1972 with Boston's Distrigas

committing to buy 50 million standard cubic feet per day (mmscfd) from the Skikda plant

over a 20-year period.

1979 witnessed the first LNG contract expiration: the 15-year contract betweenAlgeria and the UK came to an end. Deliveries from Algeria continued into the 1980s but

were eventually terminated. During 1979, the market was shaken by disputes over pricing

between the U.S. buyers and Sonatrach which eventually resulted in the termination of

the contracts, retiring of six LNG carriers (three of which were subsequently scrapped)

and the mothballing of two of the U.S.'s four LNG terminals.

However, demand for LNG in Asia continued to rise and Malaysia entered the

LNG market in 1983 (contract volume originally 6 mtpa but subsequently increased to 7.5

mtpa), followed by Australia in 1989 (similarly with an initial contract volume of 6 mtpa

which has now been increased to 7.5 mtpa).

Qatar became the second Middle Eastern LNG producer with the delivery of its

first cargo of LNG from the Qatargas LNG plant in January 1997. More recently several

plants have come on line: Trinidad (3 mtpa) started up in April 1999; RasLaffan (6.6

mtpa) in May 1999; Nigeria (5.6 mtpa) in October 1999. In April 2000, Oman

commenced production with a plant of design capacity of 6.6 mtpa delivering its first

cargo to Korea.





facilities to assure the process gas is liquefiable.Once the LNG is produced, it will store in

LNG tank at atmospheric pressure prior pumped to LNG t anker for transportation.

LNG pumped into LNG tanker via LNG loading station will be send to customer.

Good insulation is one of the key factor in keep LNG in liquid form during thetransportation process. Any vaporized LNG will be compressed and used as fuel to

generate power and drive all equipment in LNG tanker.

Once the LNG tanker arrived at LNG terminal, it is unloaded from the LNG tanker

to the LNG storage tank. From the LNG storage, LNG is pumped and regassified using

seawater or closed loop heated water. Vaporized natural gas is then injected into natural

gas grid and deliver to customer.

One of the most common applications of LNG is ³peakshaving´. Peakshaving is a way

local electric power and gas companies utilises store gas for peak demand that cannot bemet via their typical pipeline source. Peakshaving can occur during the winter heating

season or when more natural gas is needed to generate electric power for air conditioning

in the summer months. The utility companies liquefy natural gas when it is abundant and

available at off-peak prices, or they purchase LNG from import terminals supplied from

overseas liquefaction facilities. When gas demand increases, the stored LNG is converted

from its liquefied state back to its gaseous state, to supplement the utilities¶ pipeline

supplies. LNG is also currently being used as an alternative transportation fuel in

public transit and in vehicle fleets such as those operated by many local natural gas

utilities companies for maintenance and emergencies.



LNG Exploration and Production

The first segment in the LNG value chain is exploration and production. E & P

activity ranges from the development of ideas about where the natural gas resourcesmight occur (prospect generation), to the mobilization of financial capital to support

drilling and field development, to ultimate production. The E&P segment incorporates

geologic risk²the chance that natural gas resources in a ³play´ (an area of interest) either

do not exist or exist in quantities or subsurface conditions that do not favour

commercially successful exploitation. Higher natural gas prices both spur drilling and

increase the amount of natural gas resource that can be recovered (higher prices facilitate

production from higher cost fields that might otherwise not be economic). LNG²helps to

provide a diverse portfolio of supply options that can offset tight domestic supplies and

soften impacts of higher prices. For the year 2005, worldwide proved reserves of natural

gas were 6,348 Tcf, an increase of 25 percent over the year 1995, and more reserves of natural gas continue to be discovered. Much of this natural gas is stranded a long way

from market, in countries that do not need large quantities of additional energy. Leading

countries producing natural gas and selling it to world markets in the form of LNG are

Indonesia, Malaysia, Qatar and Algeria. Trinidad & Tobago is an example of a small

country that has benefited hugely from its LNG export strategy. Several countries are

growing rapidly as natural gas producers and LNG exporters, such as Nigeria and

Australia. Countries like Angola and Venezuela are striving to reach their full potential in

the global LNG marketplace, and countries like Saudi Arabia and Iran, that have vast

reserves of natural gas, could also participate as LNG exporters.

Liquid productrecovery from a

h ydrocarbongas stream

Liquefaction of the natural gas is the primary process by which the produced

natural gas from the oil and gas wells is converted in its liquid form to give rise to

liquefied natural gas having a high methane purity. Natural gas that is recovered from petroleum reservoirs is normally comprised mostly of methane. Depending on the

formation from which the natural gas is recovered, the gas will usually also contain

varying amounts of hydrocarbons heavier than methane such as ethane, propane, butanes,

and pentanes as well as some aromatic hydrocarbons. Natural gas may also contain non-

hydrocarbons, such as water, nitrogen, carbon dioxide, sulfur compounds, hydrogen

sulfide, and the like.



It is desirable to liquify natural gas for a number of reasons: natural gas can be

stored more readily as a liquid than in the gaseous form, because it occupies a smaller

volume and does not need to be stored at high pressures; LNG can be transported in liquid

form by transport trailers or rail cars; and stored LNG can be revaporized and introduced

into a pipeline network for use during peak demand periods.

LNG which has been highly purified (i.e. about 95 to 99 mol % methane purity) is

suitable for use as vehicular fuel, since it is clean burning, costs significantly less than

petroleum or other clean fuels, provides almost the same travel range between fill-ups as

gasoline or diesel, and requires the same fill-up time. High methane purity LNG can also

be economically converted into compressed natural gas (CNG), another clean,

economical vehicle fuel. The need for economical, clean-burning fuels such as LNG is

particularly urgent because the Clean Air Act Amendment (CAAA) and the Energy

Policy Act of 1992 are forcing companies with large vehicle fleets operating in areas with

ozone problems, railroads, and some stationery unit operators to convert to cleaner

burning fuels.In an effort to design engineer, and manufacture the most cost effective, space and

weight efficient facility possible, many factors must be considered. The first thing that

must be determined is what detrimental contaminants exist in the entering gas stream.

These contaminants can include, but are not limited to, oxygen, nitrogen, water, carbon

dioxide (CO2), hydrogen sulfide (H2S), mer cury, arsenic and/or heavy hydrocarbons

(C3+). Each of these components can create significant problems for the operation of an

LNG plant. For example, the CO2 content in a gas stream entering an LNG Plant must be

reduced to less than 50 ppmv to avoid the formation of dry ice within the system which

can plug off equipment and shutdown the plant. Similarly, mercury in the gas stream can

attack the aluminum components often used in LNG Plant heat exchangers and other

equipment.

Depending on the amount of H2S contained in the inlet gas, an H2S scavenger

system may be used to remove the sulfur before entering any other part of the plant

system. A few general rules of thumb for deciding to use an H2S scavenger include:

y Total sulfur content in the gas stream of less than 400 pounds per day

y Gas volumes less than 50 MMSCFD

y H2S content of less than 500 ppmv

y Oxygen is contained in the inlet gas

If none of these general rules apply, it is typically best to remove the

H2S later on in the treatment process. Oxygen is typically not found in the gas stream

feeding an LNG Plant, but this must be verified before proceeding further. If oxygen is



present, it must be removed before entering the downstream amine unit where it would

degrade the amine and form heat stable salts and other undesirable byproducts.

Newpoint¶s X-O2, catalytic reactor system,removes any contained oxygen by reacting the

oxygen with a portion of the inlethydrocarbon to form CO2 and water (H2O). The X-O2

plant can be designed to handleup to 3% oxygen with no special requirements or design

features and will typicallydeliver a product stream containing less than 100 ppmv oxygen.

Depending on the amount of CO2 contained in the inlet gas stream and the volume of gas

entering the plant, it may be beneficial to remove the bulk amount of CO2 using a

membrane treating system in order to minimize the size of the downstream amine plant

and reduce the overall energy consumption of the plant. For example, a plant having an

inlet of 100 MMSCFD of gas containing 10% CO2 would require a 1300 gpm amine

plant if this were the only means available, whereas a two-stage membrane unit could be

used to reduce the CO2 to 2% and then be followed by a 225 gpm amine plant, resulting

in an energy consumption equal to only 20% of that of the amine plant alone. (Of course,

if a Waste Heat Recovery Unit (WHRU) is available, the system heat input requirement

is essentially ³free´ and use of the membrane system may not be economical or an

efficient use of space.) Additionally, since membranes deal only with the gas phase and

no liquid hydraulics are involved, the membranes systems can be configured in any way

necessary to fit within existing plot space limitations and constraints and are not

concerned with plant dynamics that may occur on offshore applications.

An amine plant is used to remove essentially all of the CO2 and H2S from the

inlet gasstream. In order for the LNG Plant to operate properly and reliably, the CO2

should be removed to a level of less than 50 ppmv. For the product to be considered

³sweet´, theH2S needs to be less than 4 ppmv. Amine systems are capable of meeting

both of thesecriteria. The concentration of these two contaminants and the operating

conditions of theplant (pressure, temperature, remaining gas composition, etc.) will

determine what amineshould be used and what the required circulation rate will be. The

amine plant process isessentially identical in all cases, though the configuration can

usually be manipulated tofit within a specified plot area. However, as amine systems are

liquid systems, care mustbe used in ensuring that the liquid hydraulics are acceptable and

that any dynamicmovement that may be incurred in offshore applications are incorporated

into the detaileddesign of the overall system.

Upon leaving the amine plant, the oxygen, CO2 and H2S have all been removed to

acceptable levels to enter the LNG Plant. The next step is to dry the gas to the point that

it will contain less than 1 ppmv of H2O. A Molecular Sieve (mol sieve) dry desiccant is

the industry standard for performing this func tion. The number of beds is generally

determined by the volume of gas being dehydrated and the water content in the inlet gas

stream. One or more of the dehydration beds operate in the adsorption phase, where

water vapour is adsorbed onto the desiccant, while one bed is heat regenerated to strip



water from the mol sieve. Regeneration gas can be either a slip-stream of dehydrated

inlet gas that will be recycled back to the front end of the plant for re -processing, or a

stream of residue or off-gas that can be routed to the sales gas line or into the fuel system

after regenerating the mol sieve. Mol sieves can also be designed to remove trace

amounts of CO2, H2S and mercaptans, if it is known before hand that these contaminants

are present and need to be removed. Additionally, if residue gas is used to regenerate themol sieve, a regenerative mercury removal sieve, such as UOP¶s HgSieve, can be used to

remove mercury from the inlet gas stream. Properly designed mol sieve systems will

remove water to less than 1 ppmv and PLC programming will automatically control

switching beds between adsorption and regeneration and switching between heating and

cooling in the regeneration step.

If mercury is present, but the regenerative HgSieve is not used for mercury

removal, a separate vessel, filled with activated carbon, is typically used to remove

mercury gas stream. These beds are typically located downstream of the mol sieve system

to keep water from deactivating the bed. Mercury removal systems are generally designedto reduce the mercury content in a gas stream to less than 10 nano-grams per cubic meter.

Arsenic removal systems are a virtual duplicate of mercury removal systems in

appearance, but utilize a different bed material to remove arsenic and the various arsines

that may be present in the gas stream.

Finally, depending on the quality of the inlet gas and how ³clean´ of an LNG

product is desired, the gas may be ³conditioned´ to remove the heavy-end hydrocarbons

from the gas stream before it enters the actual LNG liquefaction plant. The recovery of

these heavy-end hydrocarbons can be accomplished using something as simple as a propane refrigeration plant to a full-scale cryogenic gas plant, complete with turbo-

expander. Depending on the extent that the ethane and heavier components (C2+) are

removed, the feed to the LNG liquefaction plant may consist of only methane and

nitrogen. The nitrogen will be separated from the methane in the LNG liquefaction plant.

Method for liquifying a natural gas stream starts with the cooling and condensing

the natural gas stream in a heat exchanger to produce a condensed natural gas stream.

natural gas stream is in gaseous form and comprises compressed residue gas from a

cryogenic plant. cryogenic plant utilizes a separation means to separate methane gas from

liquified heavier hydrocarbons; and wherein cooling is provided in said heat exchanger bya slipstream of said separated methane gas taken as overhead from said separation means.

This method also comprises of expanding said condensed natural gas stream to produce a

liquid natural gas product. This involves at least one isenthalpic "flash" expansion of said

condensed natural gas stream through a Joule-Thomson valve. compressed residue gas

from said cryogenic plant has a pressure of about 100 to 1200 psig and a temperature of

about 0 to 400 degrees F.; wherein said condensed natural gas stream has a pressure of



about 100 to 700 psig and a temperature of about -203 to -100 degrees F.; and wherein

said liquid natural gas product has a pressure of about 0 to 100 psig and a temperature of

about -259 to -200 degrees F. The isenthalpic flash expansion involves three steps: i)

performing a first isenthalpic "flash" expansion of said condensed natural gas stream

through a first Joule-Thomson valve to produce a first liquid fraction and first vapor

fraction; ii) performing a second isenthalpic "flash" expansion of said first liquid fractionthrough a second Joule-Thomson valve to produce a second liquid fraction and a second

vapor fraction; and iii) performing a third isenthalpic "flash" expansion of said second

liquid fraction through a third Joule-Thomson valve to produce a liquid natural

gasproduct and a third vapor fraction. a portion of at le ast one of said first vapor fraction,

said second vapor fraction, and said third vapor fraction is routed to said heat exchanger

for use as an auxilliary cooling medium for providing cooling to said natural gas stream.

A process for producing liquid natura l gas comprising the steps of:

a) cooling a natural gas feedstock with a cooling means to obtain a cooled liquid/gas

mixture;

b) separating said cooled liquid/gas mixture in a separation means to obtain a gas fraction

comprising primarily methane and a liquid fraction comprising primarily ethane and

heavier hydrocarbons;

c) compressing said gas fraction to obtain a compressed gas fraction; and

d) condensing at least a part of said compressed gas fraction via heat exchange with at

least a portion of the gas fraction taken from said separation means, to obtain a liquified

natural gas fraction; natural gas feedstock consists primarily of natural gas in gaseous

form.

The main purpose of liquid fractionation means is to remove the methane which

may have condensed with the liquids formed during the expansion. Liquid fractionation

means separates overhead gas (also called residue gas) comprising primarily methane,

from heavier hydrocarbons such as ethane, butane, propane, etc. which exit fractionation

means as liquids. In a general sense, expansion inlet separator , expansion means,

expansion outlet separator and liquid fractionation means together serve as a

fractionation means, and some other arrangement of similar components could be used to

perform the same fractionation function (e.g. separation of premarily methane gas from

heavier hydrocarbon liquids).

Overhead stream (overhead gas and/or said second gas fraction from expansion

outlet separator ) is used as a coolant in the inventive process. Overhead stream is used as

a coolant because it provides the lowest temperature available in the cryogenic plant and

permits liquefaction of the residue gas stream at moderate pressure. The invention is

preferably used in cryogenic plants in which overhead stream has a temperature of about

-200 to -100 degrees F. and a pressure of 100 to 600 psig. A slipstream of overhead



stream serves as a coolant in residue gas condenser . Overhead stream is preferably also

used as a cooling medium in inlet cooling train. Overhead stream is compressed in

compression train. In the case that expansion means is a turboexpander, compression

train preferably comprises the booster compressor of said turboexpander plus one or

more additional compressors (various types of compressors may be used, for example

centrifugal compressors, reciprocating compressors, screw compressors, or other compressors) to provide further compression. In the case that expansion means is

something other than a turboexpander, compression train comprises one or more

compressors of the types listed above, or similar, but no turboexpander-driven booster

compressor.

A slipstream of the compressed overhead stream (residue gas) is used as feed gas

to residue gas condenser, where it is condensed to form condensed stream, which

comprises liquid natural gas which has been cooled to its bubble point, or to a lower

temperature. Slipstream typically has a temperature between about 0 and about 400

degrees F. and a pressure between about 100 and about 1200 psig. It is preferable thatslipstream has a temperature between about 20 and about 200 degrees F. and a pressure

between about 300 and 900 about psig. Slipstream is also referred to as condenser

feedstock.

Residue gas condenser is cooled by slipstream and optionally other cold gas

streams taken from other stages in the cryogenic or LNG plant, or by an auxilliary

refrigerant stream. Condenser feedstock is condensed in residue gas condenser to its

bubble point temeprature, or below. Condensed stream is typically at a pressure of about

100 to 700 psig, with associated bubble point temperatures of -203 to -100 degrees F., and

preferably at a pressure of about 300 to 700 psig, with associated bubble point

temperatures of -159 to -100 degrees F. Condensed stream is expanded in expansion

means 90 to further reduce the temperature and pressure of the LNG. During the

expansion a minor portion of the liquid is vaporized.

Expansion means preferably comprises one or more flash drums into which the

natural gas stream is isenthalpically expanded ("flashed") using the Joule-Thomson (JT)

effect. Alternatively, said expansion means could also comprise an expander. The

expansion step carried out in expansion means 90 reduces the pressure of said liquid

natural gas to a level at which it can be conveniently stored and transported. The LNG

product will typically have a pressure of about 0.0 to 100 psig and temperature of about -

259 to -200 degrees F., and preferably have a pressure of about 0.5 to 10 psig andtemperature of about -258 to -247 degrees F. LNG product may be taken from outlet for

storage or transportation or any other desired use.





when evaporated at a constant pressure furnish distinct temperature levels of heat

exchange. In this respect, the system operates as an autocascade cycle.

The compression system of the foregoing plant is simple s ince only one refrigerant

is used. However, the heat exchange system and its controls are extensive and costly. The

nature of the equipment requires series flow of all refrigerant gas over the cascade type of

exchangers. This can be accomplished by vertically stacking the exchangers to a height of

over 200 feet. Unless good soil bearing is available, the support of such a unit is difficult

and the erection of such unit on the deck of a floating vessel presents serious problems of

stability. To segmentize the heat exchangers would require very large vapor lines in the

range of 5 and 6 feet in diameter. Therefore, this type of cycle would be impractical in a

liquefaction plant near off-shore wells, where the soil bearing is poor or where the wells

are in a nonindustrialized part of the world. A large Multicomponent Refrigerant cycle

also requires a complete hydrocarbon fractionating unit to prepare the pure components

required to maintain the carefully controlled refrigerant analysis.

The "Expander Cycle" is similar to that used on most of the large air separation

plants today and it does have the advantage of simplicity over a "Cascade Cycle." In this

cycle, gas is compressed to a selected pressure, cooled, then allowed to expand through

an expansion turbine, thereby performing work and reducing the temperature of the gas. It

is quite possible to liquify a portion of the gas in such an expansion. The low temperature

gas is then heat exchanged to effect liquefaction of the feed. The power obtained from the

expansion is usually used to supply part of the main compression power utilized in the

refrigeration cycle. If the expander cycle is a closed cycle, any suitable refrigerant gas can

be used. If it is an open cycle liquid natural gas plant, the refrigerant would have to be

methane or a methane-nitrogen mixture as this would be flashed from the gas-liquid

separator in the process.

An expander cycle plant is compact, has minimum items of equipment, simple

control and utilizes all standard machinery and heat exchangers. This type of plant has an

important added advantage of mechanical simplicity that is particularly significant when

considering operations in remote areas of the world.

An efficient "Expander Cycle" method for liquefaction of low boiling gases such

as oxygen and nitrogen is presently known. The heat exchange cycle of this process is

operated under 400 to 1,000 psia head pressure and cooling is made more efficient by

causing components of the warming stream to undergo a plurality of work expansion

steps with intervening reheating. In this process, two or more heat exchangers are

employed in series with an intermittent refrigeration of the incoming gas. A portion of the

feed stream which had been previously cooled by a warm-leg heat exchanger and a



refrigeration unit is work expanded and thereafter used to adsorb heat from the remaining

portion of the feed stream in a countercurrent heat exchanger. The warmed effluent gas

from the heat exchanger is work-expanded a second time and this cooled and expanded

gas is combined with the flash gas to be used to adsorb heat from the incoming feed

stream in the second heat exchanger. The cold effluent from the second heat exchanger is

isenthalpically expanded and passed to a gas-liquid separator to remove the liquid for storage and the flash gas is combined with the work-expanded gas as discussed above.

The combined warmed effluent gas from the heat exchangers is recycled to the feed

stream to be recompressed and undergoes the foregoing liquefaction.

This type of process suffers the drawback of expensive refrigerants and separate

compression and expansion systems driven by an outside source of power to maintain its

operation. Furthermore, such a process is not practicable in the liquefaction of natural gas

since there is no provision for handling the heavy gases which freeze at the temperatures

encountered in the heat exchangers. In addition, if the flash gas was recycled back to thefeed stream, the lower boiling ends, i.e., nitrogen, etc. of the feed mixture would increase

in the heat exchanger liquifier causing an imbalance in the system requiring additional

energy to liquify and cause thermodynamic inefficiency. This latter problem is not

apparent when there is only one pure material to be liquified such as nitrogen and oxygen,

but when dealing with the liquefaction of natural gases which contain a plurality of gases

having boiling points lower than methane, the problem is paramount.

In light of these inherent problems associated with the production of liquified

natural gas, the foregoing prior art processes do not aid in finding a practicable system for

liquifying natural gas in remote non-industrial parts of the world where the soil bearing is

poor.

Factors affecting quantity and quality of LNG

Condenser Feedstock Quality

The condenser feedstock (that is, the slipstream of the compressed residue gas

from the cryogenic plant) should contain less than 50 ppm of carbon dioxide and be

virtually free of water to prevent CO 2 freeze-ups and hydrate formation from occurring in

the LNG liquefaction process. Water is typically removed from natural gas upstream of

the cryogenic plant by glycol dehydration (absorption) followed by a molecular sieve

(adsorption) bed. Alternatively, a molecular sieve bed alone, or other conventional



methods, may be used to remove the water. Molecular sieve dehydration units are

normally installed upstream of the cryogenic plant to eliminate the water before the gas

enters the cooling train.

If the natural gas is not treated at the inlet of the cryogenic plant to remove CO 2 ,

it may be necessary to install a CO 2 removal system 79 for removing CO 2 from theresidue gas which is used as a feedstock for the inventive process, in which case said CO

2 removal system 79 would be placed between the outlet of the compression train 70 and

the inlet of the residue gas condensor 80. Some of the possible treating systems which

might be installed to remove the CO 2 are an amine system or a molecular sieve. If an

amine system is used, the outlet gas from this system must also be dehydrated. These

methods are well known to persons of ordinary skill in the art.

Before feed gas is introduced into the turboexpander or JT plant, the gas may be

treated to remove non-hydrocarbon components such as hydrogen sulfide (H 2 S), sulfur,

mercury, etc. if present in quantities that may adversely effect the operation of thecryogenic plant. Numerous methods which can be used to remove these components are

known to persons of ordinary skill in the art and will not be discussed here.

The amount of methane, inert gases (such as nitrogen), ethane, and hydrocarbons

heavier than ethane in the condenser feedstock will determine the quality of LNG

produced. The flash gases produced during the process will be predominantly methane

with a high percentage of nitrogen, while the ethane and heavy hydrocarbons will stay in

liquid form throughout the LNG liquefaction process. Consequently, the ethane and

heavy hydrocarbons tend to concentrate in the LNG, so that the molar fraction of ethane

and heavy hydrocarbons in the LNG contained in the storage tank will be higher than thatof the condenser feedstock. It is preferred that the cryogenic processes integrated with the

invention is capable of removing high percentages of the ethane and essentially all

propane and heavier hydrocarbons from the cryogenic plant inlet stream in order to meet

the high methane purity required for LNG vehicle fuel. The plant feedstock composition

and ethane recoveries required will depend on the desired LNG purity and the LNG

process conditions. It may be necessary to modify the cryogenic plant operation to

increase ethane recovery. Possibilities for increasing ethane increase ethane recovery.

Possibilities for increasing ethane recovery include the installation of an additional

fractionator (often called a cold fractionator), modifying the flow scheme with a deep

ethane recovery process and/or installing an additional residue gas recompressor whichwould allow the demathanizer operating pressure to be lowered.

Feed Stream Pressure

The pressure of the condenser feedstock entering the residue gas condenser is

critical to the process design as it determines the condensing temperature of the LNG feed

stream. Raising the condenser feedstock pressure will also raise the temperature required



to liquefy the LNG feed stream. The condensing pressure must be higher than the

demethanizer operating pressure but perferably less than the critical pressure of methane

(690 psia). The condenser feedstock must be of a high enough pressure that it can be

condensed by the cooling available from the demethanizer overheads stream, plus any

flash vapors routed to the residue gas condenser and any supplemental refrigeration (if

required). As discussed below (see Condensing Temperature), it is desirable to condensethe feedstock to its bubble point (100% saturated liquid), or to a lower temperature.

The feed pressure also affects the amount of flash vapors that are produced in the

flashing stages. If the condenser feedstock is condensed to its bubblepoint, the higher its

pressure, the more flash vapors will be generated during the flashing stages. Increasing

the amount of flash vapors also lowers the quality of the final LNG product as the ethane

and heavier components concentrate in the LNG product.

Condensing Temperature

The condensing temperature is another critical operating parameter. As noted

above, the condenser feedstock is preferably condensed to its bubble point temperature or

below at the pressure of the LNG feed stream. The bubble point temperature for a given

pressure is defined as the temperature at which the first bubble of vapor forms when a

liquid is heated at constant pressure. At the bubble point, the mixture is saturated liquid. If

the demethanizer overheads provide sufficient cooling, it is preferred that the feedstock is

not just condensed to its bubblepoint but further cooled to subcool the liquid. Sub -cooling

the liquid reduces the amount of vapors formed during the expansion steps. Therefore,

more liquid will be produced in the liquefaction process. A lower flowrate of the

condenser feedstock is then required to produce a given quantity of LNG liquid product if the feedstock is sub-cooled rather than just condensed to its bubblepoint.

Number of Flash Stages

Selecting the number of flash stages effects the quality and quantity of LNG

produced. In most cases, the number of flash stages and the flash pressures are set so that

the flash vapors can be used in other plant processes, such as the plant fuel systems,

without the need for recompression. Alternatively, the flash vapor can be recompressed to

the sales pipeline or recycled into the LNG production process should the amount of

vapors generated at these levels exceed the plant fuel gas demands. The larger the number

of flash chambers used (and thus the finer the increments of pressure between the flash

chambers) the less flash vapor is produced and the larger the amount of liquid natural gas

which can be retrieved. The amount of flash vapors produced affects the LNG quality as



well as the amount of LNG produced (or the amount of feed gas required to produce a

given quantity of LNG). As the number of flash stages is increased, the benefits of

reducing the amount of flash gas produced at each additional stage deteriorates very

quickly, however. As more flash chambers are used, the expense associated with the

purchase and maintenance of equipment increases. A compromise must thus be reached

between maximizing quantity and quality of LNG and minimizing equipment costs. In the preferred embodiment of the invention of Example 1 (shown in FIG. 2), it was considered

optimal to perform three flashes (i.e. into two flash drums and one storage tank).

However, a larger or smaller number of flash chambers might be preferable in a different

plant, and could be used without departing from the essential nature of the invention.

R efrigeration Capacity

The plant volume must be large enough that the demethanizer overhead is

sufficient to provide cooling to both the residue gas condenser and the inlet cooling train.

The temperature of the demethanizer overhead and the amount of demethanizer overheadthat can be utilized as a cooling medium (with equivalent loss of cooling in the cryogenic

plant inlet train) may limit the amount of cooling that can be carried out in the residue gas

condenser. By utilizing the demethanizer overheads to condense the residue gas, an

equivalent amount of refrigeration is lost in the inlet cooling train of the cryogenic plant

and NGL recoveries may be reduced. The cryogenic plant performance under the new

conditions needs to be evaluated. To compensate for this loss and to keep the plant natural

gas liquid (NGLs) recoveries high, additional refrigeration in the cryogenic plant inlet

cooling train may be required. In cases where enough demethanizer and flash vapors are

available to cool the LNG feed to its bubblepoint but additional refrigeration would be

required to subcool the liquid, the capital required to install such a refrigeration systemwould probably not be cost effective.



LNG TRANSPORTATION

LNG Shipping is a relatively low-risk low-profit activity with ships typically built

to order for specific trading routes and placed immediately on charters in excess of 15years. The LNG stored at -160º is transported onto LNG carrier ships or specially

designed cryogenic road tankers or cryogenic sea vessels and stored in specially designed

tanks.As such it is very economical to transport over long distances where pipelines do

not exist. Where moving LNG by pipelines is not economical or not possible, it can be

transported by LNG vessels. The most common tank types are Moss Rosenberg (spheres),

membrane (prismatic), or Self-Supporting Prismatic Type.

Liquefied natural gas is transported in special double-hulled ships built using two

different technologies known as Moss Rosenberg (spheres) and membrane (using material

with an expansion coefficient of practically nil). Off-loading takes approximately 24hours and is managed using tried and tested procedures common to all international

facilities.

The liquefied natural gas is off-loaded as a liquid and pumped from the jetty to

storage tanks at the terminal. The liquefied natural gas remains at -160º for the duration of

the process.

Liquefied Natural Gas [LNG] tank ships look different from regular tank ships

carrying oil and chemicals. Most LNG tank ships have two hulls, so that, if a collision or

grounding punctures the outer hull, the ship will still float and the LNG will not spill out.LNG tanks are either spherical (and the upper half of the sphere sticks out above the

deck), or box-shaped. The ships tend to ride high in the water, even when loaded. A

typical LNG ship is 950 feet long and 150 feet wide, and many new ships being built are

even bigger.

LNG is liquefied natural gas, which is the very cold liquid form of natural gas-the

fuel that's burned in gas stoves, home heaters, and electric power plants. When it warms

back up, LNG becomes natural gas again. You can't liquefy natural gas without cooling it.

Many countries export and many others import LNG by ship; the United States does both.

LNG is very cold natural gas that is in a liquid form rather than gas. Chemically,

it's mostly methane, with small amounts of ethane, propane, and butane. LPG (liquefied

petroleum gas), sometimes referred to as bottled gas, is a heavier gas that can be liquefied

under pressure or by refrigeration. It is mostly propane and butane. Gasoline is heavier

still and is a liquid at room temperature. Heating oil is even heavier and doesn't boil

unless heated. And asphalt is so heavy that it's a solid. But in a way they are all pretty

similar, because they all burn.



LNG comes from natural gas that's been cooled to below -256 degrees F, with

some impurities removed. Natural gas comes from underground gas fields by itself or in

oil fields, along with crude oil. There's very little difference between natural gas and

vaporized LNG; mostly LNG is a little purer; before liquefying the natural gas engineers

remove the pollutants, like sulfur. As of 2006 there were 17 terminals worldwide where

LNG is liquefied and pumped aboard LNG ships, and approximately 40 terminals whereLNG is pumped off LNG ships and stored in large tanks on land and vaporized as needed

by consumers.The steady march of technology has significantly reduced the cost of

natural gas liquefaction and transport, leading to a jump in the number of gas -producing

countries that are eager to supply our natural gas demands. These "supply and demand"

principles have united to fuel rapid growth in the international LNG market.

Normally natural gas is shipped by pipeline, but it is impossible to build a pipeline

from the Middle East or Africa to the United States, so engineers created ships capable of

carrying the liquid form of natural gas. Natural gas needs to be liquefied (cooled to below

-256 degrees F), because you'd need the volume capacity of 600 ships of natural gas atambient temperature/ pressure to equal one shipload of LNG. Since it is not affordable to

build and operate that many ships to carry that amount of natural gas, shipping LNG is

the only practical way to import the necessary quantities that America needs.

Gas carrier tanks, according to International Maritime Organization (IMO) rules,

must be one of three types. Those are ones built according to standard oil tank design

(Type A), others that are of pressure vessel design (Type C), and, finally, tanks that are

neither of the first two types (Type B). All LNG tanks are Type B from the Coast Guard

perspective, because Type B tanks must be designed without any general assumptions

that go into designing the other tank types. There are three general Type B tank designsfor LNG. The first type of design, the membrane tank, is supported by the hold it

occupies. The other two designs, spherical and prismatic, are self-supporting.

Membrane tanks are composed of a layer of metal (primary barrier), a layer of

insulation, another liquid-proof layer, and another layer of insulation. Those several

layers are then attached to the walls of the externally framed hold. In the case of the first

design, the primary and secondary barriers are sheets of Invar, an alloy of 36-percent

nickel steel. Unlike regular steel, Invar hardly contracts upon cooling. The insulation

layers are plywood boxes holding perlite, a glassy material. The Coast Guard, while

reviewing the design, requested testing that would show the integrity of bot h the primaryand secondary barriers. Secondary barrier testing and acceptance criteria were very hard

to develop but are necessary to ensure containment integrity. It should be noted that the

insulation for the Gaz Transport membranes has been discussed generally. All membranes

are built up from the surface of a hold using discrete units of insulation (called panels)

that are anchored to it. Special insulation is inserted around the anchors (called studs).

Also, there are special methods for sealing joints between panels. A membrane design,



therefore, is fairly complex, and a complete discussion of any one design's intricacies

would be too lengthy to completely detail.

The alternative to a membrane tank is a self-supporting tank. The most well

known is the Moss-designed spherical tank that many people equate with the appearance

of an LNG carrier. The large spherical tanks, almost half of which appear to protrudeabove a ship's deck, is often what people visualize when someone says "LNG carrier."

The early sphere designs were shells of 9-percent nickel steel. Subsequently, aluminum

was used. The sphere is installed in its own hold of a double-hulled ship, so that it is

supported around its equator by a steel cylinder (called a skirt). The covered insulation

surrounding the sphere can channel any leakage to a drip tray located under the sphere's

"south pole."

Some older 9-percent nickel steel tanks have shown significant amounts of swallow

cracking after years of service. The cracks develop next to the welds due to the effect of

the heat of the welding on the original material (known as the "heat-affected zone''). Thecracks can be repaired by gouging them out and welding in new material. Aluminum

tanks can have a different cracking problem. Attaching the aluminum tank to a steel

cylinder is a difficult process, due to the metals involved, and cracks are liable to develop

where those materials are joined.

The second type of self-supporting tank is the Self-supporting, Prismatic, Type B (SPB)

tanks by Ishikawajima Heavy Industries (IHI). These tanks are reminiscent of the tanks

on old single-skin oil tankers; the framing is internal to the tank. The material for tank

construction can be aluminum, 9-percent nickel steel, or stainless steel. Beside these types

of tank designs, there are several types that were proposed some years back but werenever built. Both the IHI "flat top" and the Hitachi Zosen (for LPG) prismatic designs

were not considered acceptable because carbon-manganese steel is not suitable for

prismatic designs. Gaz Transport and Technigaz make prismatic membrane tanks, but in

the early 1970s, both companies were interested in making spherical membrane tanks.

The Gaz Transport design was a joint effort with Pittsburgh-Des Moines Steel Company.

Mitsubishi Heavy Industries proposed a cylindrical design that was conceptually similar

to the Moss sphere design. That proposal was a hemispherical base (supported

equatorially by a skirt) with a short cylindrical section above the hemisphere, and all

topped with a shape that was oval in cross section.



LNG STORAGE

A liquef ied natural gas storage tank or LNG storage tank is a specialized type of

storage tank used for the storage of Liquefied Natural Gas. LNG storage tanks can befound in ground, above ground or in LNG carriers. The common characteristic of LNG

Storage tanks is the ability to store LNG at the very low temperature of -162°C. LNG

storage tanks have double containers, where the inner contains LNG and the outer

container contains insulation materials. The most common tank type is the full

containment tank. Tanks are roughly 180 feet high and 250 feet in diameter.

In LNG storage tanks if LNG vapours are not released, the pressure and

temperature within the tank will continue to rise. LNG is a cryogen, and is kept in its

liquid state at very low temperatures. The temperature within the tank will remain

constant if the pressure is kept constant by allowing the boil off gas to escape from thetank. This is known as auto-refrigeration.

Types of LNG Storage Tanks

Above-ground tanks

Above-ground tanks have been the most widely accepted and used method of

LNG storage primarily because they are less expensive to build and easier to maintain

than in-ground tanks. There are more than 200 above-ground tanks worldwide, and they

range in size from 45,000 barrels to 1,000,000 barrels (7,000 m3to 160,000m3 ). In Japan,Osaka Gas is building the world¶s largest above-ground tank (180,000m3), using new

technologies for pre-stressed concrete design and enhanced safety features, as well as a

technology for incorporating the protective dike within the storage tank (see description

of full containment systems in section Secondary Containment).

The world's largest above-ground tank (Delivered in 2000) is the 180 million liters

full containment type for Osaka Gas Co., Ltd. (2) The world's largest tank (Delivered in

2001) is the 200 million liters Membrane type for Toho Gas Co., Ltd.

Below-ground Storage Tanks

Below-ground LNG tanks are more expensive than above-ground tanks. They

harmonize with the surroundings. There are three different types of below-ground



In-ground Storage Tanks

The roof of the tank is above ground. Japan has the world¶s largest LNG in-

ground storage tank, which has been in operation since 1996. It has a capacity of 200,000

m3. There are 61 in-ground storage tanks in Japan.

Underground LNG Storage tank

Underground tanks are buried completely below ground and have concrete caps.

This design not only minimizes risk, but the ground surface can then be landscaped to

improve the aesthetics of the area.

Underground in-pit LNG storage tank

The tank has a double metal shell with an inner and outer tank. The inner tank is

made of metal with high resistance to low temperature. Additional insulation of thermal

insulating materials and dry nitrogen gas fills the space between the inner and outer tanks.

LNG Vaporization Facilities

Each LNG storage tank has send-out pumps that will transfer the LNG to the

vaporizers. Ambient air, seawater at roughly 59°F (15° C), or other media such as heated

water, can be used to pass across the cold LNG (through heat exchangers) and vaporize it

to a gas. The most commonly used types of vaporizers are the Open Rack (ORV) and the

Submerged Combustion (SCV). Other types include Shell & Tube exchanger (STV),

Double Tube Vaporizer (DTV), Plate Fin Vaporizer (PFV), and Air Fin Vaporizer

(HAV).



How Much Does LNG Cost?

Current estimates are that natural gas can be economically produced and delivered to the

U.S. as LNG in a price range of about $2.60-$4.80 per million Btu (MMBtu)depending

largely on terms established by producing countries for E&P investmentand shipping

distance and cost.25 The current estimate is about 30 percent higherthan the full value

chain cost we estimated in 2002. The increase in LNG value chain cost is a reflection of

general cost escalation in the global energy sector and

the LNG industry, a response to strong demand for energy and higher energy prices

and a consequence of competition for key inputs like materials and skilled labor.

Within this overall picture, a number of ga ins continue to be made.

Exploration and production costs have been declining due to improved

technologies such as 3-D (three-dimensional) seismic; drilling and completion of complex

well architectures; and improved subsea facilities. 3-D seismic allows detailed complex

imaging of rocks below the earth¶s surface, enabling exploration earth scientists to predict

better where accumulations of natural gas might exist and contributing to higher success

rates for new drilling. Drilling and completion of complex well architectures allow

petroleum engineers to target more precisely natural gas accumulations and to optimizeoil and gas reservoir recovery using multi-branched well architecture and ³intelligent´

completion systems. Improved sub-sea facilities allow companies to produce natural gas

from deep below the surface of the ocean.

Further along the LNG value chain, technical innovations in LNG liquefaction and

shipping are allowing more LNG projects to achieve commercial viability. Design

efficiencies and technology improvements are contributing to improved project

economics. With respect to ship design, costs for ships that typically have been used²

those capable of carrying about 120,000 cubic meters of LNG²have remained relatively

stable. Most new ship orders are for larger, more expensive tankers that also can

deliver larger volumes of LNG, thus improving ³economies of scale´. New technologies

are helping to reduce costs for ship operations. Propulsion systems that replace traditional

steam turbine engines with smaller units that are more efficient will not only reduce fuel

costs but also increase cargo carrying capacity. Enhanced tanker efficiencies²longer

operating lives, improved safety technology and improved fuel efficiency²have lowered

shipping costs substantially.



Petronetlng

Petronet LNG is at the forefront of India's all-out national drive to ensure the

country's energy security in the years to come.

Formed as a Joint Venture by the Government of India to import LNG and set up

LNG terminals in the country, it involves India's leading oil and natural gas industry

players. Our promoters are GAIL (India) Limited (GAIL), Oil & Natural Gas Corporation

Limited (ONGC), Indian Oil Corporation Limited (IOCL) and Bharat Petroleum

Corporation Limited (BPCL). The authorized capital is Rs. 1,200 crore ($240 million).

Petronet LNG is also drawing keen interest from global energy industry

stars.While French national gas company Gaz de France (GDF) is our strategic partner,

RasLaffan Liquefied Natural Gas Company Limited, Qatar, has signed an LNG sale and

purchase agreement (SPA) with us for the supply of LNG to India.

They have set up our first LNG Terminal at Dahej, Gujarat, with a capacity of 5

MMTPA, and are in the process of setting up another terminal at Kochi, Kerala, with a

capacity of 2.5 MMTPA.

Punj Lloyd is the only company to be involved in all three LNG terminals in India

with the securing of the prestigious order from IHI Japan for two liquefied natural gas

(LNG) storage tanks at Dahej in Gujarat. The Petronet LNG terminal at Dahej is being

ramped up by an additional two LNG tanks. Based on its excellent track record in

executing the Dabhol terminal and tanks at Hazira, Punj Lloyd was subcontracted thecivil and mechanical work for the tanks. Each tank has a storage capacity of 148,000 KL.

The tanks are designed for storing liquefied natural gas at -168º C. With an outer

diameter of 83.80 m, the dome roofed double integrity refrigerated tanks have a height of

63.5 m at the topmost point of the dome. The internal diameter of the tank is 79 m making

it almost as big as a full sized football field. The working height of the tank is 37 m. Each

tank rests on as many as 578 bored cast insitupiles, each having a diameter of 1 m, with a

depth 36 m.



LNG STORAGE TANKS AT DAHEJ,

GUJARAT



LNG SAFETY

LNG is natural gas that has been refrigerated into a cryogenic liquid so that it can

be shipped long distances in carriers. Once an LNG carrier reaches a receiving terminal,

the LNG is unloaded and stored in large tanks until it is revaporized and piped into the

natural gas distribution network. LNG is a hazardous liquid, because it is cryogenic and,

as natural gas, it is combustible.

LNG hazards result from three of its properties: cryogenic temperatures,

dispersion characteristics, and flammability characteristics. The extremely cold LNG can

directly cause injury or damage. A vapor cloud, formed by an LNG spill, could drift

downwind into populated areas. It can ignite if the concentration of natural gas is between

five and 15 percent in air and it encounters an ignition source. An LNG fire gives off a

tremendous amount of heat.

A large array of laws, regulations, standards, and guidelines are currently in place

to prevent and lessen the consequences of LNG releases. These requirements affect LNG

facilities' design, construction, operation, and maintenance.

To address terrorist risk, the Ship and Port Facility Security Code was adopted in

2003 by the member countries of the International Maritime Organization (IMO), an

agency of the United Nations responsible for maritime matters concerning ship safety.

This code requires both ships and ports to conduct vulnerability assessments and to

develop security plans. To heighten security of LNG facilities at American seaports,

Congress passed the U.S. Maritime Transportation Security Act of 2002, which requires

all ports to have federally-approved security plans. Detailed security assessments of LNG

facilities and vessels are also required.

The LNG industry has an excellent safety record. This strong safety record is a result of

several factors. First, the industry has technically and operationally evolved to ensure

safe and secure operations. Technical and operational advances include everything from

the engineering that underlies LNG facilities to operational procedures to technical

competency of personnel. Second, the physical and chemical properties of LNG are such

that risks and hazards are well understood and incorporated into technology and

operations. Third the standards, codes and regulations that apply to the LNG industry

further ensure safety.



Safety in the LNG industry is ensured by four elements that provide multiple

layers of protection both for the safety of LNG industry workers and the safety of

communities that surround LNG facilities.

Primary Containment is the first and most important requirement for containing

the LNG product. This first layer of protection involves the use of appropriate materialsfor LNG facilities as well as proper engineering design of storage tanks onshore and on

LNG ships and elsewhere. Secondary containment ensures that if leaks or spills occur at

the onshore LNG Facility, the LNG can be fully contained and isolated from the public.

Safeguard systems offers a third layer of protection. The goal is to minimize the

frequency and size of LNG releases both onshore and offshore and prevent harm from

potential associated hazards, such as fire. For this level of safety protection, LNG

operations use technologies such as high level alarms and multiple back -up safety

systems, which include Emergency Shutdown (ESD) systems. ESD systems can identify

problems and shut off operations in the event certain specified fault conditions or equipment failures occur, and which are designed to prevent or limit significantly the

amount of LNG and LNG vapor that could be released. Fire and gas detection and fire

fighting systems all combine to limit effects if there is a release. The LNG facility or ship

operator then takes action by establishing necessary operating procedures, training,

emergency response systems and regular maintenance to protect people, property and the

environment from any release.

Finally, LNG facility designs are required by regulation to maintain separation

distances to separate land-based facilities from communities and other public areas.

Safety zones are also required around LNG ships.

The physical and chemical properties of LNG necessitate these safety measures.

LNG is odorless, non-toxic, non-corrosive and less dense than water. LNG vapors

(primarily methane) are harder to ignite than other types of flammable liquid fuels.

Above approximately -110 deg C LNG vapor is lighter than air. If LNG spills on the

ground or on water and the resulting flammable mixture of vapor and air does not

encounter an ignition source, it will warm, rise and dissipate into the atmosphere.

Because of these properties, the potential hazards associated with LNG include

heat from ignited LNG vapors and direct exposure of skin or equipment to a cryogenic(extremely cold) substance. LNG vapor can be an asphyxiant. This is also true of vapors

of other liquid fuels stored or used in confined places without oxygen.

There is a very low probability of release of LNG during normal industry

operations due to the safety systems that are in place. Unexpected large releases of LNG,

such as might be associated with acts of terrorism, bear special consideration although

the consequences may well be similar to a catastrophic failure. In the case of a



catastrophic failure, emergency fire detection and protection would be used, and the

danger to the public would be reduced or eliminated by the separation distances of the

facility design. LNG operations are industrial activities, but safety and security designs

and protocols help to minimize even the most common kinds of industrial and

occupational incidents that might be expected.

LNG contains virtually no sulfur; therefore the combustion of re-gasified LNG

used as fuel has lower emissions of air contaminants than other fossil fuels. In crude oil

producing countries, as a general move towards lessening the environmental impact of oil

production, a larger percentage of the associated natural gas is being converted to LNG

instead of being flared. In many instances, this choice reduces the environmental impact

of the continuous flaring of large quantities of natural gas, while also capturing this

valuable resource for economic use. Thus, LNG development can have significant

environmental and economic benefits.

In order to define LNG safety, we must ask: When is LNG a hazard? The LNGindustry is subject to the same routine hazards and safety considerations that occur in any

industrial activity. Risk mitigation systems must be in place to reduce the possibility of

occupational hazards and to ensure protection of surrounding communities and the natural

environment. As with any industry, LNG operators must conform to all relevant national

and local regulations, standards and codes.

Beyond routine industrial hazards and safety considerations, LNG presents

specific safety considerations. In the event of an accidental release of LNG, the safety

zone around a facility protects neighboring communities from personal injury, property

damage or fire.

Industry standards are written to guide industry and also to enable public officials

to more efficiently evaluate safety, security and environmental impacts of LNG facilities

and industry activities. Regulatory compliance should ensure transparency and

accountability in the public domain.

The four requirements for safety ± primary containment, secondary containment,

safeguard systems and separation distance ± apply across the LNG value chain, from

production, liquefaction and shipping, to storage and re-gasification. (We use the term

³containment´ in this document to mean safe storage and isolation of LNG.) Later sections provide an overview of the LNG value chain and the details associated with the

risk mitigation measures employed across it.

Primary Containment. The first and most important safety requirement for the industry

is to contain LNG. This is accomplished by employing suitable materials for storage

tanks and other equipment, and by appropriate engineering design throughout the value

chain.



Secondary Containment. This second layer of protection ensures that if leaks or spills

occur, the LNG can be contained and isolated. For onshore installations dikes and berms

surround liquid storage tanks to capture the product in case of a spill. In some

installations a reinforced concrete tank surrounds the inner tank that normally holds theLNG. Secondary containment systems are designed to exceed the volume of the storage

tank. As will be explained later, double and full containment systems for onshore

storage tanks can eliminate the need for dikes and berms.

Safeguard Systems. In the third layer of protection, the goal is to minimize the release

of LNG and mitigate the effects of a release. For this level of safety protection, LNG

operations use systems such as gas, liquid and fire detection to rapidly identify any

breach in containment and remote and automatic shut off systems to minimize leaks and

spills in the case of failures. Operational systems (procedures, training and emergency

response) also help prevent/mitigate hazards. Regular maintenance of these systems isvital to ensure their reliability.

Separation Distance. Federal regulations have always required that LNG facilities be

sited at a safe distance from adjacent industrial, communities and other public areas.

Also, safety zones are established around LNG ships while underway in U.S. waters and

while moored. The safe distances or exclusion zones are based on LNG vapor dispersion

data, and thermal radiation contours and other considerations as specified in regulations.

Industry Standards/R egulatory Compliance. No systems are complete without

appropriate operating and maintenance procedures being in place and with ensurance thatthese are adhered to, and that the relevant personnel are appropriately trained.

Organizations such as the Society of International Gas Tanker and Terminal Operators

(SIGTTO), Gas Processors Association (GPA) and National Fire Protection Association

(NFPA) produce guidance which results from industry best practices.



LNG Properties and Potential Hazards

To consider whether LNG is a hazard, we must understand the properties of LNG

and the conditions required in order for specific potential hazards to occur.

LNG Properties

Natural gas produced from the wellhead consists of methane, ethane, propane and

heavier hydrocarbons, plus small quantities of nitrogen, helium, carbon dioxide, sulfur

compounds and water. LNG is liquefied natural gas. The liquefaction process first

requires pre-treatment of the natural gas stream to remove impurities such as water,

nitrogen, carbon dioxide, hydrogen sulfide and other sulfur compounds. By removing

these impurities, solids cannot be formed as the gas is refrigerated. The product then also

meets the quality specifications of LNG end users. The pretreated natural gas becomesliquefied at a temperature of approximately -256oF (-160 oC) and is then ready for

storage and shipping. LNG takes up only 1/600 th of the volume required for a comparable

amount of natural gas at room temperature and normal atmospheric pressure. Because the

LNG is an extremely cold liquid formed through refrigeration, it is not stored under

pressure. The common misperception of LNG as a pressurized substance has perhaps led

to an erroneous understanding of its danger.

LNG is a clear, non-corrosive, non-toxic, cryogenic liquid at normal atmospheric

pressure. It is odorless; in fact, odorants must be added to methane before it is distributed

by local gas utilities for end users to enable detection of natural gas leaks from hot-water

heaters and other natural gas appliances. Natural gas (methane) is not toxic. However, as

with any gaseous material besides air and oxygen, natural gas that is vaporized from LNG

can cause asphyxiation due to lack of oxygen if a concentration of gas develops in an

unventilated, confined area.

The density of LNG is about 3.9 pounds per gallon, compared to the density of

water, which is about 8.3 pounds per gallon. Thus, LNG, if spilled on water, floats on top

and vaporizes rapidly because it is lighter than water. Vapors released from LNG as it

returns to a gas phase, if not properly and safely managed, can become flammable but

explosive only under certain well-known conditions. Yet safety and security measures

contained in the engineering design and technologies and in the operating procedures of LNG facilities greatly reduce these potential dangers.

The flammability range is the range between the minimum and maximum

concentrations of vapor (percent by volume) in which air and LNG vapors form a

flammable mixture that can be ignited and burn.



T y pes of LNG Hazards

The potential hazards of most concern to operators of LNG facilities and

surrounding communities flow from the basic properties of natural gas. Primarycontainment, secondary containment, safeguard systems, and separation distance provide

multiple layers of protection. These measures provide protection against hazards

associated with LNG.

Explosion. An explosion happens when a substance rapidly changes its chemical state ±

i.e., is ignited ± or is uncontrollably released from a pressurized state. For an

uncontrolled release to happen, there must be a structural failure ± i.e., something must

puncture the container or the container must break from the inside. LNG tanks store the

liquid at an extremely low temperature, about -256°F (-160°C), so no pressure is required

to maintain its liquid state. Sophisticated containment systems prevent ignition sources

from coming in contact with the liquid. Since LNG is stored at atmospheric pressure ±

i.e., not pressurized ± a crack or puncture of the container will not create an immediate

explosion.

Vapor Clouds. As LNG leaves a temperature-controlled container, it begins to warm up,

returning the liquid to a gas. Initially, the gas is colder and heavier than the surrounding

air. It creates a fog ± a vapor cloud ± above the released liquid. As the gas warms up, it

mixes with the surrounding air and begins to disperse. The vapor cloud will only ignite if

it encounters an ignition source while concentrated. within its flammability range. Safety

devices and operational procedures are intended to minimize the probability of a release

and subsequent vapor cloud having an affect outside the facility boundary.

Freezing Liquid.If LNG is released, direct human contact with the cryogenic liquid will

freeze the point of contact. Containment systems surrounding an LNG storage tank, thus,

are designed to contain up to 110 percent of the tank¶s contents. Containment systems

also separate the tank from other equipment. Moreover, all facility personnel must wear

gloves, face masks and other protective clothing as a protection from the freezing liquid

when entering potentially hazardous areas. This potential hazard is restricted within the

facility boundaries and does not affect neighboring communities.

R ollover. When LNG supplies of multiple densities are loaded into a tank one at a time,

they do not mix at first. Instead, they layer themselves in unstable strata within the tank.

After a period of time, these strata may spontaneously rollover to stabilize the liquid in

the tank. As the lower LNG layer is heated by normal heat leak, it changes density until it

finally becomes lighter than the upper layer. At that point, a liquid rollover would occur

with a sudden vaporization of LNG that may be too large to be released through the

normal tank pressure release valves. At some point, the excess pressure can result in

cracks or other structural failures in the tank. To prevent stratification, operators



unloading an LNG ship measure the density of the cargo and, if necessary, adjust their

unloading procedures accordingly. LNG tanks have rollover protection systems, which

include distributed temperature sensors and pump-around mixing systems.

R apid Phase Transition. When released on water, LNG floats ± being less dense than

water ± and vaporizes. If large volumes of LNG are released on water, it may vaporize

too quickly causing a rapid phase transition (RPT). Water temperature and the presence

of substances other than methane also affect the likelihood of an RPT. An RPT can only

occur if there is mixing between the LNG and water. RPTs range from small pops to

blasts large enough to potentially damage lightweight structures. Other liquids with

widely differing temperatures and boiling points can create similar incidents when they

come in contact with each other.

Environmental Impacts

When LNG is vaporized and used as fuel, it reduces particle emissions to near

zero and carbon dioxide (CO2) emissions by 70 percent in comparison with heavier

hydrocarbon fuels. When burned for power generation, the results are even more

dramatic. Sulfur dioxide (SO2) emissions are virtually eliminated and CO2 emissions are

reduced significantly. If spilled on water or land, LNG will not mix with the water or

soil, but evaporates and dissipates into the air leaving no residue. It does not dissociate or

react as does other hydrocarbon gases and is not considered an emission source.

Additionally there are significant benefits when natural gas is used as fuel over other

fossil fuels. However, methane, a primary component of LNG, is considered to be agreenhouse gas and may add to the global climate change problem if released into the

atmosphere.



CONCLUSION

As mentioned in safety section, LNG has been handled safely for many years and

the industry has maintained an enviable safety record. Engineering and design andincreasing security measures are constantly improved to ensure the safety and security of

LNG facilities and ships.

As of Sept. 2003, the global LNG industry comprises 17 export (liquefaction)

facilities, 40 receiving (re-gasification) terminals, and 145 ships, altogether handling

more than 110 million metric tons of LNG every year. LNG has been safely delivered

via ocean-going transport for more than 40 years. During that time there have been more

than 40,000 LNG ship voyages, covering more than 60 million miles, without any major

incidents involving a major release of LNG either in port or on the high seas. LNG ships

frequently transit high traffic density areas.

LNG is a clear answer to the world¶s volatile gas supply and demand equation.

LNG is used to cook food, heat our homes, enjoy a hot shower and even light our streets.

One can easily save money on fuel by using LNG. Less noise, less congestion, and a

smoother operation for LNG vehicles. LNG can be pressurized and vaporised to give

LCNG, liquefied compressed natural gas. In other words, in LNG refueling stations can

dispense two fuels - LNG & CNG - offering a several supply options to fleet operators.

The benefits of LNG include greater energy density and low-pressure storage. As such,

LNG has the greatest potential application for medium to heavy vehicles. Using LNG

implies low-cost, low-weight fuel storage options and long driving range.

The purchase (commodity) cost of gas can vary over a great range. Some gas,

because of its location, pressure, and/or composition may have a very low inherent

marketability, hence, purchase cost. One of the beauties of LNG is that most of these

deficiencies can be overcome in its production and distribution.

The LNG Corridor is an evolving concept where a network of LNG fueling

stations is developed over specific high frequency routes such that over-the-road trucks

can move with a high level of confidence that fuel will be available to them. SuperCNG

station is the name CH·IV International has given to a new approach to fueling a large

quantity of CNG continuously to either a high population of light duty vehicles (taxis and

vans) or a large fleet of transit buses. The SuperCNG station has eliminated all of the

problems related to continuous capacity, energy consumption during. The SuperCNG

station is an optimum way of using LNG to produce CNG. Hence, LNG could be a fun

place to be over the next decade.



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