1- introduction (FF).pdf

Senior Project 2012
Liquefied Natural Gas

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LNG is the liquid form of natural gas people use in
their homes for cooking and heating. Natural gas is
also used as fuel for generating electricity. Natural
gas and its components are used as raw material to
manufacture a wide variety of products from fibers
for clothing to plastics for healthcare, computing,
and furnishings.
This chapter introduces an overview of natural gas,
LNG chain components of liquefaction, market
structure, imports and exports.

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History of Liquefied Natural Gas (LNG)
industry
 The early years: Natural gas liquefaction dates back to the 19th
century
when British chemist and physicist Michael Faraday experimented with
liquefying different types of gases, including natural gas. German
engineer Karl Von Linde built the first practical compressor
refrigeration machine in Munich in 1873. The first LNG plant was built
in West Virginia in 1912 and began operation in 1917. The first
commercial liquefaction plant was built in Cleveland, Ohio, in
1941. The LNG was stored in tanks at atmospheric pressure. The
liquefaction of natural gas raised the possibility of its transportation to
distant destinations. 1994 At an LNG peak-shaving plant in Cleveland,
an LNG storage tank with a low nickel steel content (only 3.5%) fails.
LNG spills into a sewer. Explosion within the sewer kills 128 people .
 1959 The historic voyage of the Methane Pioneer: world's first LNG
tanker, the Methane Pioneer. In February, a shipload of 2,000 tons of
natural gas from Louisiana is transported across the Atlantic and
landed in the UK at Convey Island on the Thames estuary, for use by
the state-owned North Thames Gas Board.
 1964 A first: The world's first commercial movement of LNG occurs
between Algeria and the UK.
 1995 Egypt: the Egyptian General Petroleum Corporation (EGPC)
signed a concession agreement with BG International Limited (BG)
and Edison International (Edison) to explore for hydrocarbons in the
West Delta Deep Marine (WDDM) region in the North Eastern
Mediterranean.
 1996 Egypt: The latest country to join the lengthening list of potential
LNG suppliers is Egypt. A memorandum of understanding is signed
in mid-November by the Egyptian General Petroleum (EGPC),
Amoco Egypt and Botas Petroleum Pipeline to supply LNG from the
Nile Delta to Turkey to. First deliveries of gas are expected to be
made in 2000

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 1998 Egypt :Snam has joined Amoco and EGPC in the planned LNG
export project. Shares in Egypt LNG, are now Amoco (45%), Snam
(45%) and EGPC (10%)
 2000 Egypt: Shell signs an agreement with the EGPC under which
the companies will build "at least one" LNG train based on Egyptian
gas reserves in the Mediterranean. Shell says the companies will
target LNG exports at other Mediterranean countries. The plant is
scheduled to be operational by mid-2004, and will be built alongside
a gas-to-liquids plant, due on stream in late 2005.
 2001 construction of The Spanish Egyptain Gas Company: This LNG
project was the first facility of its type in Egypt and is one of the
world's largest capacity single train facilities. Construction of the
facility began in September 2001. The operating company, SEGAS,
is controlled by Union Fenosa Gas in conjunction with ENI of Italy
(80%) and two state-owned Egyptian companies - Egyptian Natural
Gas Holding Company (EGAS - ten percent) and Egyptian General
Petroleum Corporation (EGPC - ten percent).Union Fenosa Gas is
owned in a 50/50 partnership by Union Fenosa of Spain and Eni of
Italy. The plant is situated on the Mediterranean Coast 60km west of
Port Said. The complex came on-stream during the final quarter of
2004 and exports LNG to the Spanish market via a receiving terminal
at Sagunto in Spain.
 2002 Construction of idkuEgyptain LNG plant: In January, a heads of
agreement was signed with Gaz de France (GdF) for the sale of 3.6
million tonnes per annum (mtpa) of LNG for 20 years. EGPC, the
Egyptian Natural Gas Holding Company (EGAS), BG Asia Pacific
Holdings Pte Limited (an affiliate of BG International), Edison and
GdF became the Sponsors of this new project and commissioned
Bechtel to construct a single-train liquefaction plant using the
ConocoPhillips Optimized Cascade Process by August and matching
the volumes to be sold to GdF.
 2003 Egypt: Edison sold its share in Egyptian LNG and the upstream
WDDM concession to a subsidiary of the Malaysian National Oil
Company, Petronas (PICL Egypt), who brought extensive LNG
experience to the project. Today, the Egyptian LNG project is well
underway with deliveries from Train 1 expected in the second quarter
of 2005 and Train 2 later in the same year.

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With two trains commissioned in one year, Egyptian LNG will
contribute to Egypt's leap into the 7th place in the elite club of LNG
exporting countries before the end of 2005.The Egyptian LNG plant
(ELNG) is located on approximately 165 hectares of land some 3
kilometres away from the town of Idku and 40 kilometers east of
Alexandria on the Egyptian Mediterranean coast and share holders
of the Egyptian LNG Companies are EGAS (12%) / EGPC (12%) /
BG (38%) / Petronas (38%).
 2005 Egypt: not long after the first LNG train opened, SEGAS
began considering plans for a second train with a 5.55 million t/yr
capacity at the Damietta complex - after securing a joint off-take
and feedstock agreement for Train 1 with Union Fenosa. With the
first phase (first train) of the project approaching completion and
commissioning in 2004, SEGAS started to raise investment capital
for a second train. SEGAS asked four banks to arrange a $600
million, five-year corporate loan for the project.
 2005 Egypt: The first LNG cargo was shipped on 29th May 2005
from IdkuEgyptian LNG plant, six months ahead of the contractual
schedule. The cargo, comprising approximately 129,000 cubic
meters of LNG, was lifted by Asian LNG Trading Company Limited
(ALTCO), a subsidiary of Petronas, one of the shareholders in the
project, for delivery into Spain.
 2006 Egypt: The first LNG carrier unloaded at the terminal in
February 2006, The LNG is received at a new terminal that was
constructed in Sagunto City, 50km north of Valencia. The terminal
receives tanker shipments of LNG from the Damietta facility,
allowing the facility to be brought on-stream in the first quarter of
2006.
FIGURE 1:TWO EGYPTIAN LNG PROJECT

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What is LNG?
Liquefied natural gas is natural gas, primarily composed of
methane (83-99%), which has been converted to liquid form
for ease of storage and transport. LNG takes up about
1/600th the volume of natural gas. The conversion of natural
gas to its liquefied form allows for the transport of greater
quantities.
Liquefaction describes the process of cooling natural gas to
-162°C (-259°F) at close to atmospheric pressure (maximum
transport pressure set at around 25 kPa/3.6 psi) until it
forms as a liquid. It is stored and transported at atmospheric
pressure as a boiling liquid. LNG must be turned back into a
gas for commercial use and this is done at regasification
plants.LNG is odorless, colorless, non-corrosive and non-
toxic. Its weight is less than one-half that of water.
FIGURE 2: LIQUEFIED NATURAL GAS
Difference between LNG, LPG & NGLs
 Liquefied Natural Gas (LNG):is made
up of mostly methane. The liquefaction
process requires the removal of the non-
methane components like carbon dioxide,
water, butane, pentane and heavier
components from the produced natural gas.
LNG is odorless, colorless, non-corrosive,
and non-toxic. When vaporized it burns only
in concentrations of 5% to 15% when mixed
with air.

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 Natural gas liquids (NGLs):are made up
mostly of molecules that are heavier than
methane. These molecules liquefy more
readily than methane. NGLs are the
hydrocarbon molecules that begin with ethane
and increase in size as additional carbon
atoms are added.
 Liquefied Petroleum Gas (LPG):LPG is
often incorrectly called propane. In fact, LPG is
predominantly a mixture of propane and butane in
a liquid state at room temperatures when under
moderate pressures of less than 200 psig. The
common interchanging of the terms LPG and
propane is explained by the fact that in the U.S.
and Canada LPG consists primarily of propane. In
many European countries, however, the propane
content in LPG can be lower than 50 per cent.
Difference between LNG, CNG & PNG
Compressed Natural Gas (CNG): Gas (not a liquid) can be
transported in containers at high pressures, typically 1800 psig for a
rich gas (significant amounts of ethane, propane, etc.) to roughly 3600
psig for a lean gas (mainly methane). Gas at these pressures is
termed compressed natural gas (CNG). The gas volume is reduced by
1/240 of its original volume at 3600 psig to be stored and transported
safely.
Compressed natural gas is used in some countries for vehicular
transport as an alternative to conventional fuels (gasoline or diesel).
The filling stations can be supplied by pipeline gas, but the
compressors needed to get the gas to 3000 psig can be expensive to
purchase, maintain, and operate. The gas has to be dried,
compressed, and chilled for storage onboard.

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TABLE 1: COMPARISON BETWEEN LNG, PNG AND CNG
PNG LNG CNG
Phase gas liquid gas
Experience in
gas industry
large medium Fair
Storage density No storage 600-620 volume per volume 240 volume per
volume at 3600 psig
Temperature In
tanks
- -162
o
C Ambient
Pressure in
tanks
- atmospheric 1800-3600 psig
Safety Record Excellent Very good Very good
Offshore
Transportation
Limited due to the
high cost of
construction,
installation and
maintenance
Widely used to transport large
volume of gas over a long
distance
Economic to used
for transporting a
small volume of gas
over a short
distances
On shore
Transportation
Widely used and the
most efficient method
Limited and may use for local
distribution by trucks
successfully
transported on land
by road-trailer
(trucking) for over
thirty years
Quality High quality to
meet the
consumer
specification
Highest quality due to the
treatment process to
separate the impurities and
reach to certain
specifications for LNG tech.
Medium quality
because the gas is
compressed directly
from the
transportation
pipeline.
Cost and
economics
Cost low for local
distribution
Costly due to many LNG
processing steps
Lower cost than
others
techniques
Environment Very friendly to
the environment
Polluted for the treatment
source but environmental
friendly for domestic
Lower pollution
emission in the
source. But
produce more
emissions
during
applications.

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Pipeline Natural Gas (PNG): Pipelines are a very convenient method
of transport but are not flexible as the gas will leave the source and arrive at
its (one) destination. If the pipeline has to be shut down, the production and
receiving facilities and refinery often also have to be shut down because
gas cannot be readily stored, except perhaps by increasing the pipeline
pressure by some percentage.
FIGURE 3: BEST CASE SCENARIOS FOR CNG, LNG AND PNG USAGE
Main units of Natural gas measurements
Natural Gas is measured in volume units, i.e. in cubic feet or cubic
meters. Gas production from wells and supplies to Power plants is
measured in Thousands or Millions cubic feet (Mcf or MMcf) / cubic
meter (MSCM or MMSCM). Resources and reserves are calculated
in Trillions of cubic feet (Tcf). For instance, a gas field containing
3.65 TCF is equivalent to around 12 MMSCMD gas for 25 years. A
rough way of visualizing a trillion cubic feet of gas would be to
imagine enough of product to fill a cube with its sides two miles long.
Another way of measuring the gas is in terms of Energy Values. The
amount of energy that is obtained from the burning of a unit volume of
Natural Gas is measured in British Thermal Unit (BTU).

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TABLE 2:GENERALLY USED CONVERSION FACTORS OF LNG
1Cubic meter liquid (CuM) = 600 Cubic meter of gas
1 Million Metric Ton/ annum (MMTPA) = 4 MMSCMD
1 Metric ton LNG (MT) =1420 Cubic meter of gas
1 Metric ton LNG (MT) =52 MMBTU
1000 Cubic meter of Gas (MCM) = 40 MMBTU
1British Thermal Unit (BTU) = 252 Calories
MMSCMD stands for Million Standard Cubic Meter per Day.
MMBTU stands for Million British Thermal Unit.
MT stands for Metric Ton
MMTPA means Million Metric Ton Per Annum.
LNG chain and component of liquefaction plant
Figure 4:the LNG value chain

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The major stages of the LNG value chain, excluding pipeline operations
between the stages, consist of the following.
1. PRODUCTION
The production stage involves the supply of gas and condensate from the
wells in the offshore/on-shore facilities, through a pipeline into the
processing facilities.
2. LIQUEFACTION
Raw Natural Gas and unstabilized condensate obtained offshore is
seldom pure, as it generally contains numerous types of contaminants.
Therefore the gas and condensate must be purified for reasons of safety,
compliance with environmental regulations, and product specification.
The process of condensate stabilization, gas treatment and liquefaction is
achieved in the LNG plant. The main units/facilities of an onshore LNG
plant are: Process units
 Storage and loading facilities.
 Utility and offsite systems and infrastructure.
Components of a Liquefaction Plant
The process unit includes inlet gas reception unit, condensate stabilization
unit, gas treatment & sweetening facilities gas liquefaction unit, sulfur
recovery unit. An LNG train is a set of process units consisting of all
process equipment necessary to produce LNG from a natural feed stock
and having a pre-determined design. In the liquefaction stage the
condensate is stabilized and the gas is treated to remove all impurities and
liquefied. The liquefaction of gas to LNG is achieved in six different steps:
 The first step involves the receipt of untreated sour gas and
unstabilized condensate from the offshore facilities to the inlet gas
reception unit.
 This is followed by stabilization of condensate and treatment of the
sour gas for removal of Mercury.
 The third step involves the gas sweetening step resulting in removal
of contaminants mainly sulfur compounds and carbon dioxide to
meet required product specification.

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 The fourth step involves dehydration or
drying for removal of water to prevent
hydrate formation, which would otherwise
freeze, and block the system, resulting in
operational malfunction.
 Next, a stripping step involving separation of
lighter hydrocarbon used to produce LNG
from the heavier hydrocarbons, which would
freeze at LNG temperature. The heavier
hydrocarbons are further treated in
fractionation unit to produce plant
condensate.
The sixth step is the cooling cycle, which
is the crux of the LNG plant. Here the
liquefaction takes place in a specially
constructed heat exchanger termed
―Cryogenic heat exchanger‖ because of the
low temperatures. The equipment employs
mixed refrigerant (MR) consisting of
nitrogen, methane, ethane, propane, and
butane that provides the refrigeration for
liquefying the natural gas. The fractionation
unit provides the ethane, propane make-up for
the refrigeration cycle and MR is pre-cooled
by a propane refrigeration system.
The LNG, now at -160 C and atmospheric pressure and reduced to 1/600 th of
its gaseous volume is stored in insulated tanks. These storage tanks are large,
typically between 60,000 and 140,000-m3 capacity each. The tanks
incorporate special cryogenic features, such as an insulation layer between
double contaminant walls, an inner shell made of exotic alloy, such as nickel
stainless steel to withstand the low temperatures, and an outer shell of carbon
steel.
The Field and Plant Condensate are stored in atmospheric floating roof tanks.
LNG and Condensate are transferred onto ships through their respective
loading systems.
FIGURE 5: COMPONENTS OF LNG
PLANT

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3. SHIPPING
LNG is transferred onto ships through a loading system. The present state
of the art in LNG ships has contributed to cost effectiveness by increases in
size from 40,000 to 135,000 m3 capacity. Unlike an oil tanker, an LNG
carrier is designed to handle extremely low temperatures. LNG is carried in
insulated metallic tanks constructed of exotic alloy, such as nickel stainless
steel, or other suitable materials to withstand the low temperatures. The
insulation system maintains the LNG temperature to prevent heat inflow
from the surrounding which would otherwise evaporate the liquid.
4. REGASIFICATION
An LNG receiving terminal consists of pipelines; ship berthing facilities,
unloading facilities, storage tanks, vaporization system, units for handling
boil-off from the tanks, metering station and ancillaries. The storage tanks
are of similar design to those in liquefaction plants.
At the receiving terminal, the LNG is re-gasified before distribution into
pipelines for customers. The main uses of the re-gasified LNG include fuel
source for boilers in the electrical power generation plants, and other
industrial processes, petrochemical feed stocks, as in methanol or fertilizer
production, and heating for domestic appliances, typically cooking stoves
FIGURE 6: LNG PROCESS DESCRIPTION

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Egypt energy demand and Natural Gas reserve
Egypt is currently the world’s 25th largest oil producer and is home to 4.5
billion barrels of crude reserves, 0.3 percent of the global total. With
diminishing production, however, the country is losing significance in the
rankings and is projected to have only 1.5 billion barrels of remaining
reserves by 2030, a marginal quantity compared to the 800 billion barrels of
global reserves.
Egypt is in a more favorable situation with natural gas than it is with oil. With
76 trillion cubic feet of remaining reserves, the country ranks 7th among
non-OPEC countries, and 16th worldwide. Egypt may continue to expand its
natural gas production to meet demand for exports, which could increase
slightly from the current 630 billion cubic feet to 800 billion cubic feet by
2030, and also meet rising domestic demand.
Egypt’s energy balance for 2007 indicates that the largest share of final
energy consumption occurs in the industrial sector (34.2 percent), followed
by transportation (24.2 percent), residential (18.8 percent), and agriculture
and mining (4.7 percent)—together accounting for 81.9 percent of total
consumption. By fuel type, oil products account for more than half of fuel
consumption (54.1 percent), followed by natural gas (20.6 percent), and
electricity (18.3 percent)— together comprising 93 percent of total demand.
The remainder is non-energy use.

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Energy transformation for the internal market occurs mainly via oil-refining
activities, natural gas treatment, and power generation (hydro and thermal).
Natural gas (56.2 percent) and oil (38.2 percent) account for the bulk of
primary energy supply, representing 94.4 percent of the total.
FIGURE 7:SHARE OF EGYPT’S TOTAL ENERGY CONSUMPTION, BY SECTOR AND
FUEL TYPE, 2007
FIGURE 8:SHARE OF EGYPT’S TOTAL PRIMARY ENERGY PRODUCTION, BY
SOURCE, 2007

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The rest is mainly electricity, generated with hydropower (3.9 percent,
according to IEA methodology) and other primary sources (1.7 percent).
Between the start of exploitation and early 2009, 32 percent of Egypt’s 142.6
trillion cubic feet (tcf) of total natural gas resource had been produced. An
estimated 54 percent of proven or identified reserves has been put in
commercial production, recoverable to 100 percent, and resources to be
discovered totaled 14 percent, with a recovery probability of about 10
percent.
Overall, the country has yet to recover 68 percent of its total gas resources,
weighted by their respective recovery factors, if no new resources are added.
Egypt has proven gas reserves of 76.6 tcf, or just over 1 percent of the world
total. The success rate of natural gas exploration has increased since 1991,
when foreign companies were first allowed to participate in the Egyptian gas
sector. Egypt has both medium-sized and small fields, especially offshore.
The largest existing fields include Abu Madi-El Qar´a, Port Fouad Marine
area, Raven, Sapphire, Temsah, and Wakar. Production from West Deep
Marine, the Khalda area, and Port Fouad is expected to account for nearly
half of the production in 2010. Development of new fields, from already
discovered reserves, will account for two-thirds of production in 2030. Egypt
settled for new drillings in order to increase its gas reserves, which has
helped the country become one of the 10 largest gas producers in the world.
FIGURE 9:EGYPT’S TOTAL NATURAL GAS RESOURCES, 2009

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Egyptian Natural gas pipeline and LNG export
In 2008, Egypt exported natural gas overseas both by international
pipeline (17 percent) and as Liquefied Natural Gas (LNG) (83 percent).
Exports for the year totaled 633.9 billion cubic feet (bcf). Based on an
unique expansion of capacity that facilitates export increments, total
exports under the three scenarios are calculated at 711.2 bcf in 2013,
750 bcf in 2020, and 803.1 bcf in 2026, representing a 27-percent
increase in capacity between 2009 and 2030.
Pipeline
Egypt’s most expansive export project is the
Arab Gas Pipeline that currently connects
Egypt to Jordan and Syria. In June 2003, a
270-kilometer gas pipeline between Egypt (El
Arish) and Jordan (Aqaba) was inaugurated. In
2008, the Jordan-Syria section of the Arab Gas
Pipeline was completed, and Egypt is expected
to export 77.3 bcf in 2013.
In 2008, Turkey and Syria also signed an
agreement to connect the pipeline to the
Turkish grid for use in 2011 and to extend the
pipeline into Europe for export to Austria via
Bulgaria, Romania, and Hungary.
There is also discussion of connecting the
pipeline to Lebanon and Cyprus. The Arish-
Ashkelon gas pipeline to Israel became
operational in 2008 and began transferring
what is expected to be 60 bcf per year.
Recently, Libya also agreed to build a natural
gas pipeline between Alexandria and the
eastern Libyan city of Tobruk to import gas
from the Nile Delta region and the
Mediterranean deep-water permits.
LNG
FIGURE 10:THE ARAB GAS PIPELINE

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In 2008, Egypt exported 525.1 bcf of LNG to progressively diversifying
market destinations. LNG represented 25.3 percent of natural gas production
and 83 percent of total gas exports.lxv (See Figure 44.) The country has
three LNG trains, and in 2006 LNG exports reached an estimated 528 bcf,
including 129 bcf to the United States. The Spanish firm Union Fenosa has
built a single-train liquefaction facility at Damietta, which started annual
production of 240 bcf in late 2004. In June 2006, partners ENI, BP, and
Union Fenosa signed a framework agreement for expansion of the plant and
production with a second train planned to begin in 2010–11. However, this
agreement may be put at risk by Egypt’s June 2008 announcement that all
export contracts are on hold until 2010. The Egyptian Petroleum Minister
warned that the second train faces opposition within parliament. Asecond
LNG export project called Egyptian LNG, at Idku, was built by BG in
partnership with Petronas and currently has two 173 bcf per year of trains.
The project is tied to natural gas production from BG's Simian/Sienna
offshore fields and began production in 2005. BG hopes to build a third
liquefaction plant, fed partly by gas from the Palestinian-controlled Gaza
Marine Field in the Mediterranean Sea, with targeted start up in 2011.
FIGURE 11:LNG EXPORTS FROM EGYPT, BY DESTINATION COUNTRY

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FIGURE 12:EGYPTIAN LNG EXPORTS
FIGURE 13: EGYPTAIN GAS TREATMENT FACILITIES

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LNG market structure, import and export
International trade in LNG centers on two geographic regions:
 The Atlantic Basin, involving trade in Europe, northern and western
Africa, and the U.S. Eastern and Gulf coasts.
 The Asia/Pacific Basin, involving trade in South Asia, India, Russia,
and Alaska.
 Middle Eastern LNG-exporting countries etween these regions supply
Asian customers primarily, although some cargoes are shipped to
Europe and the United States.
LNG importers. Worldwide in 2003 was a total of 13 countries
imported LNG. Three countries in the Asia/Pacific Basin—Japan, South
Korea, and Taiwan—accounted for 67 percent of global LNG imports,
while Atlantic Basin LNG importers took delivery of the remaining 33
percent. Last year, new LNG receiving terminals started up, bringing the
total to 83 in 22 countries, compared with 18 exporting countries.
Japan remains the world’s largest LNG consumer, although its share of
global LNG trade has fallen slightly over the past decade as the global
market has grown.
Japan’s largest LNG suppliers are Indonesia and Malaysia, with
substantial volumes also imported from Qatar, the United Arab Emirates,
Australia, Oman, and Brunei Darussalam. Early in 2004 India received its
first shipment of LNG from Qatar at the newly completed facility at Dahej in
Gujarat. Imports by Atlantic Basin countries are expected togrow as many
expand storage and regasificationterminal capacity. France, Europe’s
largest LNGimporter, plans two new erminals for receipt of gasfrom Qatar
and Egypt. Spain’s LNG imports, roughlyhalf from Algeria, increased by 21
percent in 2003. All Spanish regasification terminals are being expanded,
with several new terminals starting up by 2007.
FIGURE 14:2010 LNG IMPORTERS

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LNG exporters. Asia/Pacific Basin LNG producers accounted for nearly half
of total world LNG exports in 2003 while Atlantic Basin LNG producers
accounted for about 32 percent. Liquefaction capacity in both regions is
increasing steadily. Indonesia was the world’s largest LNG producer and
exporter, accounting for about 21 percent of the world’s total LNG exports.
The majority of Indonesia’s LNG is imported by Japan, with smaller volumes
going to Taiwan and South Korea. But now it come in the second place since
Qatar, with a mighty 900 trillion cubic feet of gas reserves, swept Indonesia
off the LNG production throne as the new industry leader in output during
this period. Malaysia, the world’s third-largest LNG exporter, ships primarily
to Japan with smaller volumes to Taiwan and South Korea. Australia exports
LNG from the Northwest Shelf, primarily to supply Japanese utilities. About
90 percent of Brunei Darussalam output goes to Japanese customers.
The only liquefaction facility in the United States was constructed in Kenai,
Alaska, in 1969. This facility, owned by ConocoPhillips and Marathon Oil, has
exported LNG to Japan for more than 30 years.
Algeria, the world’s seventh-largest LNG exporter, serves mainly Europe
(France, Belgium, Spain, and Turkey) and the United States via Sonatrach’s
four liquefaction complexes. Nigeria exports mainly to Turkey, Italy, France,
Portugal, and Spain but also has delivered cargos under short-term contracts
to the United States. Trinidad and Tobago exports LNG to the United States,
Puerto Rico, Spain, and the Dominican Republic. An Egyptian facility
exported its first cargo in 2005 and it is in the tenth place, it is expected to
supply France, Italy, and the United States. World Liquefaction Supply is Set
to Increase Over the Next 12 Years
FIGURE 15: 2010 LNG EXPORTERS

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FIGURE 16: world movement of lng
Figure 17: LNG growth, 2007 to 2021

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LNG peak shaving and baseload plant
Peaking power plants, also known as peaker plants, and occasionally just
"peakers," are power plants that generally run only when there is a high
demand, known as peak demand.
Peak demand, peak load or on-peak are terms used in energy demand
management describing a period in which power is expected to be provided
for a sustained period at a significantly higher than average supply level.
Peak demand fluctuations may occur on daily, monthly, seasonal and yearly
cycles. the actual point of peak demand is a single half hour or hourly
period which represents the highest point of customer consumption of
energy (see figure).
The opposite of a peaking plant are base load power plants, which operate
continuously, stopping only for maintenance or unexpected outages. Base
load power is the level of minimum power demand. Intermediate load
following power plants operate between these extremes, curtailing their
output in periods of low demand, such as during the night. It is getting
difficult to construct power stations and transmission facilities which cover
peak power demands not only from the point of construction cost but also
conservation of resources. If we succeed to reduce these fluctuations, we
can contribute to efficient operation at power stations, decrease of operation
cost, and conservation of resources
Figure 18:daily swing load curve and power demand

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LNG Peak Shaving plant
In LNG Peak shaving plants, natural gas is liquefied and LNG is stored. If a
gas demand is high (peak), LNG can be vaporized and sent to a gas
grid.Figure shows a block diagram of the common steps involved in a peak
shaving facility. Gas treating, liquefaction, liquid storage, and regasification.
Odorant injection may or may not be required at the peak shaving plant.
The first peak shaving plant built in the United States was in Cleveland,
Ohio, in 1941 (Miller and Clark, 1941). Although the plant performed
successfully for several years, in October 1943, a metallurgical failure in a
Storage tank resulted in a fire and explosion (GAO, 1978) that destroyed
the plant, with a heavy loss of life. Although this disaster was a major
setback to the industry, in 2004 the United States had 59 peak shaving
plants, 39 satellite facilities, four LNG marine-import terminals, and one
LNG marine-export terminal.
FIGURE 19:SCHEMATIC OF PEAK-SHAVING FACILITY.

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LNG baseload Plant
Large plants which are directly based on a specific gas field development
andare the main plants for handling the gas. A base-load plant has typically
aproduction capacity of above 2 mtpa (million tons per annum) of LNG. The
mainworld-wide LNG production capacity comes from this type of plants
Baseload plants exist to provide the industrial world with gas from stranded
reserves in remote places. Stranded gas reserves are located where no
economic use for the natural gas exists at the point of origin and where
transportation of the gas by pipeline to a point of end use is not feasible.
Romanow (2001) estimates that approximately 60% of the world’s gas
reserves are considered stranded. When compressed gas pipelines are
impractical or impossible, a limited number of conventional options are open
(Taylor et al., 2001), such as compression and transport of the gas in
specially built ships (Wagner, 2002), conversion of the natural gas into a
liquid through gas-to-liquid (GTL) technology, and liquefaction and shipment
of the gas in specially built LNG vessels. Leibon et al. (1986) as well as
Taylor et al. (2001) evaluate the status of several of the technologies.
Hidayati et al. (1998) compare the cost of a compressed gas pipeline to LNG
carriers for a large Indonesian project. Some unconventional methods that
have been considered include conversion of the natural gas to hydrates for
shipping (Gudmundsson and Mork, 2001) and even use of a train of airships
that contain natural gas. Presently, LNG is the most viable option in almost
all situations involving stranded reserves, if the gas can be pipelined to a
seaport. However, to economically justify a traditional baseload LNG plant
requires reserves of approximately 3 Tcf (80 Bm3). Newer designs have
reduced the reserve volumes down to around 1 Tcf (30 Bm3) (Price et al.,
2000).
As Figure shows, bringing the gas from the field to the customer involves four
steps (Energy Information Administration, 2003b):
1. Gas production, gathering, and processing
2. LNG production, including gas treating, liquefaction, NGL condensate
3. removal, and LNG storage and loading
4. LNG shipping
5. LNG receiving facilities, which include unloading, storage,
regasification, and distribution
Depending on the specific situation, not all plants will have all the processes
shown, and some plants may have additional processes.

26
LNG Small-scale plants
Small-scale plants are plants that are connected to a gas network
forcontinuous LNG production in a smaller scale. The LNG is distributed
locally byLNG trucks, in a range of about 300 km from the production
facility, to variouscustomers with a small to moderate need of energy or
fuel. This type of LNGplants typically has a production capacity below
100 000 tpa. In Norway threeplants within this category is in operation
FIGURE 20: SCHEMATIC OF A BASELOAD PLANT COMBINED WITH TRANSPORTING, RECEIVING, AND
REGASIFI CATION

27
LNG uses, advantages and limitation
TABLE 3: USES, ADVANTAGES & LIMITATIONS
Common uses Advantages Limitation
 Peak Shaving
 Base Load
 Growing the
Business
 Maintaining
the Gas
System
 Emergency
Response
 Currently LNG
represents more than
15% of the EU’s gas
imports
 One thing that LNG still
misses is cost-
competitiveness
 One thing that LNG is
definitely superior to
pipeline gas is its
quality. This is because
LNG is purer, has more
methane as well as other
energy content
 Storage availability
 LNG energy projects are
among the most
expensive in all energy
sectors
 the amounts of
greenhouse gas
emissions LNG supply
chain emits more
greenhouse gases than
for instance the supply
chain for pipeline gas,
primarily because of the
extra processing steps
needed for LNG
shipment
FIGURE 21: LNG APPLICATION

28
LNG Properties
A basic knowledge of LNG must begin with an examination of its chemical
and physical properties. Chemical and physical properties are fundamental
to understanding LNG correctly. The very properties which make LNG a
good source of energy can also make it hazardous if not adequately
contained. These properties determine how LNG behaves, affect our
predictions about its behaviours, and influence how we assess and
manage safety risks. Furthermore, to accurately understand and predict
LNG behavior, one must clearly distinguish its properties as a liquid from
its properties as a gas or vapour. The reader will note that discussions of
the properties of LNG often contain ominous caveats like ―depending upon
its exact composition‖ because such specifics matter. It is inexact and
inappropriate to make universal generalizations about LNG. It is especially
important to be clear in thinking through how LNG would behave if
accidentally or intentionally released (e.g., from aterrorist attack), because
the outcome would be profoundly influenced by the actual situation and
sitespecific conditions.
LNG is natural gas which has been converted to liquid form for ease of
storage or transport. LNG takes up about 1/600th of the volume of natural
gas. Depending upon its exact composition, natural gas becomes a
liquidat approximately -162°C (-259°F) at atmospheric pressure.
LNG’s extremely low temperature makes it a cryogenic liquid. Generally,
substances which are -100°C (-48°F) or less are considered cryogenic and
involve special technologies for handling. In comparison, the coldest
recorded natural temperatures on earth are -89.4°C(-129°F) at the height
of winter in
The cryogenic temperature of LNG means it will freeze any issue (plant or
animal) upon contact and can cause other materials to become brittle and
lose their strength or functionality. This is why the selection of materials
used to contain LNG is so important.
LNG is odorless, colorless, non-corrosive, nonflammable, and non-toxic.
Natural gas in your home may have been liquefied at some point but was
converted into its vapour form for your use. The reason the natural gas
you use in your home has a smell is because an odorizing substance is
added to natural gas before it is sent into the distribution grid. This odour
enables gas leaks to be detected more easily. Key liquid and gas
properties for LNG are:
 Chemical Composition.
 Boiling Point.
 Density and Specific Gravity.
 Flammability.
 Ignition and Flame Temperatures.

29
Chemical Composition
Natural gas is a fossil fuel, meaning it has been created by organic
material deposited and buried in the earth millions of years ago. Crude oil
and natural gas constitute types of fossil fuel known as ―hydrocarbons‖
because these fuels contain chemical combinations of hydrogen and
carbon atoms. The chemical composition of natural gas is a function of
the gas source and type of processing. It is a mixture of methane,
ethane, propane and butane with small amounts of heavier hydrocarbons
and some impurities, notably nitrogen and complexsulphur compounds,
water, carbon dioxide and hydrogensulphide which may exist in the feed
gas but are removed before liquefaction the hydrocarbon compounds
which make up natural gas,and the volume ranges in which they may be
present in LNG.
TABLE 4 TYPICAL CHEMICAL COMPOSITION OF LNG IN SEGAS
Component Units Min. Range Max. Range
Methane Mol % 91.00
n-Butane Mol % 0.01 0.5
i-Butane Mol % 0.01 0.5
C5+ Mol % 0.15
Inerts Mol % 0.00 1.00
CO2 Mol % 0.01
Total Sulphur Mg/Nm3 15.00
Water Traces
Mercaptans (S from RSH) Mg/Nm3 6.00
Carbonyl Sulphide (COS) Mg/Nm3 4.00
Hydrogen Sulphide Mg/Nm3 5.00
Dust content ppm 15.00
Particle size of dust micrometer 5.00
Higher heating value Kcal/Nm³ 9387.00 10795

30
Boiling Point
Boiling point is one of the most significant properties because it defines
when gas becomes a liquid. defines ―boiling point‖ as ―the temperature at
which a liquid boils‖ or converts rapidly from a liquid to a vapour or gas at
atmospheric pressure. The boiling point of pure water at atmospheric
pressure is 100°C (212°F). The boiling point of LNG varies with its basic
composition, but typically is -162°C (-259°F).
TABLE 5BOILING POINT
Country Propane Butane
Belgium 50 50
France 35 65
Ireland 100 100
Italy 25 75
Germany 90 10
UK 100 100
Greece 20 80
Netherlands 50 50
Sweden 95 5
When cold LNG comes in contact with warmer air, water, or the
environment, it begins to ―boil‖ at that interface because the surrounding
temperatures are warmer than the LNG’s boiling point .the boiling points of
water and common gases. The liquefaction process cools natural gas to
change it to a liquid which reduces the volume occupied by the gas by
approximately 600 times. LNG is converted back into natural gas for
distribution to industrial and residential consumers. The LNG regasification
process warms the LNG and converts it back into its gaseous form.
Density and Specific Gravity
Density is a measurement of mass per unit of volume and is an absolute
quantity. Because LNG is not a pure substance, the density of LNG varies
slightly with its actual composition. The density of LNG falls between 430
kg/m3 and 470 kg/m3 (3.5 to 4 lb/US gal). LNG is less than half the density
of water; therefore, as a liquid, LNG will float if spilled on water. Specific
gravity is a relative quantity.

31
Fahrenheit (o
F) Celsius (o
C) Occurrence
212 100 Water Boils
31 -0.5 Butane Boils
-27 -33 Ammonia Boils
-44 -42 Propane Boils
-259 -162 LNG Boils
-298 -183 Oxygen Boils
-319 -195 Nitrogen Boils
-422 -252 Hydrogen Boils
-454 -270 Helium Boils
-460 -273 Absolute Zero
The specific gravity of a liquid is the ratio of of density that liquid to density
of water (at 15.6°C/60°F). The specific gravity of a gas is the ratio of the
density of that gas to the density of air (at 15.6°C). Any gas with a specific
gravity of less than 1.0 is lighter than air (buoyant). When specific gravity or
relative density is significantly less than air, a gas will easily disperse in
open or well-ventilated areas. On the other hand, any gas with a specific
gravity of greater than 1.0 is heavier than air (negatively buoyant).
At ambient temperatures, natural gas has a specific gravity of about 0.6,
which means that natural gas vapors are much lighter than air and will rise
quickly. Cold LNG vapour (below -110°C/-166°F) is negatively buoyant
and more likely to accumulate in low areas until the vapour warm.
Therefore, a release of LNG that occurs in an enclosed space or low spot
will tend to replace the air (and oxygen) and make the area a hazard for
breathing.
FIGURE 22LNG “BOILING” AT ATMOSPHERIC PRESSURE AND TEMPERATURE

32
The rate of LNG vapour ascent depends upon the quantity of LNG released,
ambient weather conditions, and where the LNG is released, e.g., confined
or unconfined, low or elevated area, on land or on water. One strategy to
manage the vapour is to create a downwind water curtain which helps block
and/or divert the vapour away from possible ignition sources until thevapour
warm and become buoyant, and/or dilute to alesser concentration outside
the flammable limits, which are discussed in the next section.
Heat input to LNG in any form will enhance vaporization and dispersion.
Such heat may be transferred frompassive sources such as atmospheric
humidity (which isa significant source), the ground or spill catchment areas,
impoundments, pits and structures. LNG vaporizes five times more quickly
on water than on land, depending upon the soil condition.
LNG Quality and wobbe index
The Wobbe Index is a Measure of energy input to the flame of a burner. It is
an indicator of the interchangeability since gases within WI band achieve:
Control of NOx and other emissions, High efficiency of burners and Safe
operation of equipment.
Natural Gas Interchangeability is a measure of the degree to which the
combustion characteristics of one gas resemble those of another gas. Two
gases are said to be interchangeable when one gas may be substituted for
the other without affecting the operation of gas burning appliances or
equipment.
Heating value: is the heat released from one kilogram of fuel burned
completely. upper heating value (UHV) is determined by bringing all the
products of combustion back to the original pre-combustion temperature,
and in particular condensing any vapor produced. Lower heating value
(LHV) is determined by subtracting the heat of vaporization of the water
vapor from the higher heating value.
The final LNG product has requirements for heating value and wobbe index
so the LNG quality can be determined focuses on
 High Heating value (HHV) (energy content)
 Wobbe index (Gas interchangeability)
 Higher hydrocarbon content: C2, C3, C4, C5+
 Sulphur components
 Nitrogen (inert – link to ageing)

33
The wobbe index
√ √
Where:
 GHV: Gross Heating Value (MJ/Sm3) (same as Upper Heating Value)
 spgr: specific gravity (-)
 MW: Molecular weight (kg/kmol)
TABLE 6: HEATING VALUES
Substance UHV
(kJ/kg)
UHV
(kWh/kg)
UHV
(MJ/Sm3
)
LHV
(kJ/kg)
LHV
(kWh/kg)
LHV
(MJ/Sm3
)
Nitrogen 0 0 0 0 0 0
Methane 55496 15,42 37,66 50010 13,89 33,93
Ethane 51875 14,41 65,97 47484 13,19 60,39
Propane 50345 13,98 93,90 46353 12,88 86,45
Butane 49500 13,75 121,69 45714 12,70 112,38
Pentane 49011 13,61 149,56 45351 12,60 138,39
Flammability
Flammability is the property which makes natural gas desirable as an
energy source, and yet for the same reason flammability can be a safety
hazard. It is very important to be clear: natural gas is flammable but
LNG(the liquid form of natural gas) is not because of the lack of oxygen in
the liquid. Since LNG begins vaporizing immediately upon its release from
a container, the important issue is when will the vapors be flammable and
for how long?

34
Flammability Limits
Three things are needed to support a fire:
 A source of fuel (e.g., flammable gas or vapor),
 Air (oxygen), and
 A source of ignition (e.g., spark, open flame, or high-temperature
surface).
FIGURE 23THE FIRE TRIANGLE
This ―Flammable Range‖ is the range of a concentration of a gas or vapour
that will burn if an ignition source is introduced. The limits are commonly
called the "Lower Flammable Limit" (LFL) and the "Upper Flammable Limit"
(UFL) .The flammability limits for methane are 5% LFL and 15% UFL by
volume in air. Outside of this range, the methane/air mixture is not
flammable. Many materials around us are flammable and it isimportant to
be aware of each substance’s flammability limits to assure safe handling
and use. Materials that have wide flammable ranges make them dangerous
to
emergency responders because there is a longer time that they are within
the flammable limits.
FIGURE 24FLAMMABILITY RANGE FOR METHANE
Over RICH
WILL NOT
BURN
FLAMABLE

35
In a closed storage tank or vessel, the percentage of methane is essentially
100% (mostly liquid and some vapour). Any small leak of LNG vapour from a
tank in a well-ventilated area is likely to rapidly mix and quickly the rapid
mixing, only a small area near the leak would have the necessary
concentration to allow the fuel to ignite. All LNG terminals use several types of
equipment on and around the storage tanks and piping throughout the facility
to detect any unlikely leakages and combustible gas mixtures.
TABLE 7:FLAMMABILITY LIMITS OF HYDROCARBON FUELS
Ignition and Flame Temperatures
The ignition temperature, also known as auto-ignition temperature, is the lowest
temperature at which a gas orvapour in air (e.g., natural gas) will ignite
spontaneously without a spark or flame being present. This temperature
depends on factors such as air-fuel mixture and pressure. In an air-fuel mixture
of about 10% methane in air, the auto ignition temperature is approximately
540°C(1,000°F). Temperatures higher than the auto ignition temperature will
cause ignition after a shorter exposure time to the high temperature
The precise auto ignition temperature of natural gas varies with its composition.
If the concentration of heavier hydrocarbons in LNG increases, the auto ignition
temperature decreases.
In addition to ignition from exposure to heat, the vapours from LNG can be
ignited immediately from the energy in a spark, open flame, or static electricity
when they are within the flammable limits.
TABLE 8 AUTO-IGNITION TEMPERATURE OF SOME FUELS AT
Natural Gas
Diesel Oil Gasoline
Auto-ignition
temperature 599°C 260-371°C 226-471°C
Fuel LFL UFL
Methane 5.0 15.0
Butane 1.86 7.6
Kerosene 0.7 5.0
Propane 2.1 10.1
Hydrogen 4.0 75.0
Acetylene 2.5 >82.0

36
References
1. J. Kidnay and William R. Parrish, "Fundamentals of Natural Gas
Processing", 2006.
2. Petroleum Economist Ltd, "fundamental of the global LNG industry",
March2008.
3. California Energy Commission - www.energy.ca.gov/lng/ safety.html
4. Center for LNG - www.lngfacts.org
5. Foss, Michelle. 2003. LNG Safety and Security. Center for Energy
Economics at the Bureau of Economic Geology, The University of
Texas at Austin –http://www.beg.utexas.edu/energyecon/lng/
documents/CEE_LNG_Safety_and_Security.pdf
6. The International Group of Liquefied Natural Gas Importers (GIIGNL)
website - www.GIIGNL.org
7. National Fire Protection Association (NFPA) 2008
8. Flammable and Combustible Liquids Code Handbook.
9. National Fire Protection Association (NFPA) 2008 edition. Fire
Protection Handbook.
10.Raj, Phani K. 2006. Where in a LNG vapour cloud is the flammable
concentration relative to the visible cloud boundary? NFPA Journal,
May/June

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