petroleum industrial chemistry
TRANSCRIPT
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PETROLEUM INDUSTRIAL
CHEMISTRY
PROJECT
LIQUEFIED NATURAL GAS
PREPARED BY JAY JANI 08BT01088
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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.
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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.
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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.
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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.
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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
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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
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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
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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
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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.
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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
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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
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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
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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
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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.
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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.
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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,
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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.
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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
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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).
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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.
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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.
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LNG STORAGE TANKS AT DAHEJ,
GUJARAT
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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.
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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
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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.
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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.
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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.
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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
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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.
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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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