CLAUS PROCESS by Ow5GgQ9

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									                                  CLAUS PROCESS
The Claus process is the most significant gas desulfurizing process, recovering elemental
sulfur from gaseous hydrogen sulfide. First invented over 100 years ago, the Claus process
has become the industry standard. The multi-step process recovers sulfur from the organic
sulfur compounds in crude oil. The final step involves oxidation of hydrogen sulfide.

Gases with a H2S content of over 25% are suitable for the recovery of sulfur in Claus plants.
These gases may also contain hydrogen cyanide, hydrocarbons, sulfur dioxide or ammonia.
They mainly originate from physical and chemical gas treatment units (Selexol, Rectisol,
Purisol and amine scrubbers) in refineries, gasification or synthesis gas plants. The sulfur
recovered in Claus plants is used for manufacturing medicine, cosmetics, fertilizers and
rubber products.

Hydrogen sulfide produced, for example, in the desulfurisation of mineral oils via
hydrodesulfurization, is converted to sulfur in Claus plants. The main reaction equation is:

       :2H2S + O2 ⇌ 2S + 2H2O

Process description




The Claus technology can be divided into two process steps, thermal and catalytic.

In the thermal step, hydrogen sulfide-laden gas reacts in a substoichiometric combustion at
temperatures above 850 °C such that elemental sulfur precipitates in the downstream process
gas cooler.

The H2S-content and the concentration of other combustible components (hydrocarbons or
ammonia) determine the location where the feed gas is burned. Claus gases (acid gas) with no
further combustible contents apart from H2S are burned in lances surrounding a central
muffle. Gases containing ammonia (SWS gas) or hydrocarbons are converted in the burner
muffle. Sufficient air is injected into the muffle for the complete combustion of all
hydrocarbons and ammonia. Air to the acid gas is controlled such that in total 1/3 of all
hydrogen sulfide (H2S) is converted to SO2.

       :2H2S + 3O2 ⇌ 2SO2 + 2H2O


The separation of the combustion processes ensures an accurate dosage of the required air
volume needed as a function of the feed gas composition. To reduce the process gas volume
or obtain higher combustion temperatures, the air requirement can also be covered by
injecting pure oxygen. Several technologies utilizing high-level and low-level oxygen
enrichment are available in industry, which requires the use of a special burner in the reaction
furnace for this process option.

Usually, 60 to 70% of the total amount of elemental sulfur produced in the process are
obtained in the thermal process step.

The main portion of the hot gas from the combustion chamber flows through the tube of the
process gas cooler and is cooled down such that the sulfur formed in the reaction step
condenses. The heat given off by the process gas and the condensation heat set free are
utilized to produce medium or low-pressure steam. The condensed sulfur is removed at the
gas outlet section of the process gas cooler.

A small portion of the process gas can be routed through a bypass inside of the process gas
cooler, as depicted in the figure. This hot bypass stream is added to the cold process gas
through a three-way valve to adjust the inlet temperature required for the first reactor.

Catalytic step

The Claus reaction continues in the catalytic step with activated alumina or titanium dioxide,
and serves to boost the sulfur yield. The hydrogen sulfide (H2S) reacts with the SO2 formed
during combustion in the reaction furnace, and results in gaseous, elemental sulfur. This is
called the Claus reaction:

       :2H2S + SO2 ⇌ 3/2 S2 + 2H2O


The catalytic recovery of sulfur consists of three substeps: heating, catalytic reaction and
cooling plus condensation. These three steps are normally repeated a maximum of three
times. Where an incineration or tail-gas treatment unit (TGTU) is added downstream of the
Claus plant, only two catalytic stages are usually installed.

The first process step in the catalytic stage is the process gas heating. It is necessary to
prevent sulfur condensation in the catalyst bed, which can lead to catalyst fouling. The
required bed operating temperature in the individual catalytic stages is achieved by heating
the process gas in a reheater until the desired operating bed temperature is reached.

Several methods of reheating are used in industry:
      Hotgas bypass: which involves mixing the two process gas streams from the process
       gas cooler (cold gas) and the bypass (hot gas) from the first pass of the Wasteheat
       boiler.
      Indirect Steam reheaters: the gas can also be heated with high pressure steam in a heat
       exchanger.
      Gas/Gas Exchangers: whereby the cooled gas from the process gas cooler is indirectly
       heated from the hot gas coming out of an upstream catalytic reactor in a gas-to-gas
       exchanger.
      Direct-fired Heaters: fired reheaters utilizing acid gas or fuel gas, which is burned
       substoichiometrically to avoid oxygen breakthrough with can damage Claus catalyst.

The typically recommended operating temperature of the first catalyst stage is 315°C to
330°C (bottom bed temperature). The high temperature in the first stage also helps to
hydrolyze COS and CS2, which is formed in the furnace and would not otherwise be
converted in the modified Claus process.

The catalytic conversion is maximized at lower temperatures, but care must be taken to
ensure that each bed is operated above the dewpoint of sulfur. The operating temperatures of
the subsequent catalytic stages are typically 240°C for the second stage and 200°C for the
third stage (bottom bed temperatures).

In the sulfur condenser, the process gas coming from the catalytic reactor is cooled to
between 150 and 130°C. The condensation heat is used to generate steam at the shell side of
the condenser.

Before storage and downstream processing, liquid sulfur streams from the process gas cooler,
the sulfur condensers and from the final sulfur separator are routed to the degassing unit,
where the gases (primarily H2S) dissolved in the sulfur are removed.

The tail gas from the Claus process still containing combustible components and sulfur
compounds (H2S, H2 and CO) is either burned in an incineration unit or further desulfurized
in a downstream tail gas treatment unit.

Process performance
Using two catalytic stages, the process will typically yield over 97% of the sulfur in the input
stream. Over 2.6 tons of steam will be generated for each ton of sulfur yield.
                                         Town gas

Town gas is a generic term referring to manufactured gas produced for sale to consumers and
municipalities. The terms coal gas, manufactured gas, syngas (SNG) and hygas are also
common. Depending on the processes used for its creation, the gas is a mixture of caloric
gases: hydrogen, carbon monoxide, methane, and volatile hydrocarbons with small amounts
of noncaloric gases carbon dioxide and nitrogen as impurities.

Prior to the development of natural gas supplies and transmission in the United States during
1940s and 1950s, virtually all fuel and lighting gas was manufactured, and the byproduct coal
tars were at some times an important chemical feedstock for the chemical industries. The
development of manufactured gas paralleled that of the industrial revolution and
urbanization.

Manufacturing process
       See also: Manufactured Gas Plant
       See also: Illuminating gas


Manufactured gas is made by two processes: carbonization or gasification. Carbonization
refers to the devolatilization of an organic feedstock to yield gas and char. Gasification is the
process of subjecting a feedstock to chemical reactions that produce gas.[1][2]

The first process used was the carbonization and partial pyrolysis of coal. The off gases
liberated in the high-temperature carbonization (coking) of coal in coke ovens were collected,
scrubbed and used as fuel. Depending on the goal of the plant, the desired product was either
a high quality coke for metallurgical use, with the gas being a side product or the production
of a high quality gas with coke being the side product. Coke plants are typically associated
with metallurgical facilities such as smelters, and blast furnaces, while gas works typically
served urban areas.

A facility used to manufacture coal gas, Carburetted Water Gas (CWG), and oil gas is today
generally referred to as a Manufactured Gas Plant (MGP).

In the early years of MGP operations, the goal of a utility gas works was to produce the
greatest amount of highly illuminating gas. The illuminating power of a gas was related to
amount of soot-forming hydrocarbons (“illuminants”) dissolved in it. These hydrocarbons
gave the gas flame its characteristic bright yellow color. Gas works would typically use oily
bituminous coals as feedstock. These coals would give off large amounts of volatile
hydrocarbons into the coal gas, but would leave behind a crumbly, low-quality coke not
suitable for metallurgical processes. Coal or Coke oven gas typically had a caloric value (CV)
between 10 and 20 MJ/m3 (250-550 Btu/ft3 (std)); with values around 20 MJ/m3 (550 Btu/ft3
(std)); being typical.

The advent of electric lighting forced utilities to search for other markets for manufactured
gas. MGPs that once produced gas almost exclusively for lighting shifted their efforts
towards supplying gas primarily for heating and cooking, and even refrigeration and cooling.
Gas for industrial use
Fuel gas for industrial use was made using producer gas technology. Producer gas is made
by blowing air through an incandescent fuel bed (commonly coke or coal) in a gas producer.
The reaction of fuel with insufficient air for total combustion produces CO: this reaction is
exothermic and self sustaining. It was discovered that adding steam to the input air of a
producer would increase the CV of the fuel gas by enriching it with CO and H2 produced by
water gas reactions. Producer gas has a very low CV of 3.7 to 5.6 MJ/m3 (100-150 Btu/ft3
(std)); because the calorific gases CO/H2 are diluted with lots of inert nitrogen (from air) and
CO2 (from combustion)

                           (Exothermic: Producer gas Reaction)

                                  (Endothermic: Water Gas Reaction)

                                 (Endothermic)

                               (Exothermic: Water Gas Shift reaction)

The problem of nitrogen dilution was overcome by the blue water gas (BWG) process,
developed in the 1850s by Sir William Siemens. The incandescent fuel bed would be
alternately blasted with air followed by steam. The air reactions during the blow cycle are
exothermic, heating up the bed, while the steam reactions during the make cycle, are
endothermic and cool down the bed. The products from the air cycle contain non-caloric
nitrogen and are exhausted out the stack while the products of the steam cycle are kept as
blue water gas. This gas is composed almost entirely of CO and H2, and burns with a pale
blue flame similar to natural gas. BWG has a CV of 11 MJ/m3 (300 Btu/ft3 (std)).

Because blue water gas lacked illuminants it would not burn with a luminous flame in a
simple fishtail gas jet as existed prior to the discovery of the Welsbach mantle in the 1890s.
Various attempts were made to enrich BWG with illuminants from gas oil in the 1860s. Gas
oil was the flammable waste product from kerosene refining, made from the lightest and most
volatile fractions (tops) of crude oil.

In 1875 Thaddeus S. C. Lowe invented the carburetted water gas process. This process
revolutionized the manufactured gas industry and was the standard technology until the end
of manufactured gas era. A CWG generating set consisted of three elements; a producer
(generator), carburettor and a super heater connected in series with gas pipes and valves.

During a make run, steam would be passed through the generator to make blue water gas.
From the generator the hot water gas would pass into the top of the carburetor where light
petroleum oils would be injected into the gas stream. The light oils would be thermocracked
as they came in contact with the white hot checkerwork firebricks inside the carburettor. The
hot enriched gas would then flow into the superheater, where the gas would be further
cracked by more hot fire bricks.
Early history of gas production by carbonization
The Flemish scientist Jan Baptista van Helmont (1577–1644) discovered that a 'wild spirit'
escaped from heated wood and coal, and, thinking that it 'differed little from the chaos of the
ancients', he named it gas in his Origins of Medicine (c. 1609). Among several others who
carried out similar experiments, were Johann Becker of Munich (c 1681) and about three
years later John Clayton of Wigan England, the latter amusing his friends by lighting, what
he called, "Spirit of the Coal". William Murdoch (later known as Murdock) (1754–1839) is
reputed to have heated coal in his mother's teapot to produce gas. From this beginning, he
discovered new ways of making, purifying and storing gas; illuminating his house at Redruth
(or his cottage at Soho) in 1792, the entrance to the Manchester Police Commissioners
premises in 1797, the exterior of the factory of Boulton and Watt in Birmingham, England,
and a large cotton mill in Salford, Lancashire in 1805.

Professor Jan Pieter Minckeleers lit his lecture room at the University of Louvain in 1783 and
Lord Dundonald lit his house at Culross, Scotland, in 1787, the gas being carried in sealed
vessels from the local tar works. In France, Phillipe Lebon patented a gas fire in 1799 and
demonstrated street lighting in 1801. Other demonstrations followed in France and in the
United States, but, it is generally recognised that the first commercial gas works was built by
the London and Westminster Gas Light and Coke Company in Great Peter Street in 1812
laying wooden pipes to illuminate Westminster Bridge with gas lights on New Year's Eve in
1813. In 1816, Rembrandt Peale and four others established the Gas Light Company of
Baltimore, the first manufactured gas company in America. In 1821, natural gas was being
used commercially in Fredonia, New York. The first German gas works was built in
Hannover in 1825 and by 1870 there were 340 gas works in Germany making town gas from
coal, wood, peat and other materials.

Working conditions in the Gas Light and Coke Company's Horseferry Road Works, London,
in the 1830s were described by a French visitor, Flora Tristan, in her Promenades Dans
Londres:
Two rows of furnaces on each side were fired up; the effect was not unlike the description of
Vulcan's forge, except that the Cyclops were animated with a divine spark, whereas the dusky
servants of the English furnaces were joyless, silent and benumbed. ... The foreman told me
that stokers were selected from among the strongest, but that nevertheless they all became
consumptive after seven or eight years of toil and died of pulmonary consumption. That
explained the sadness and apathy in the faces and every movement of the hapless men.[3]


The first public piped gas supply was to 13 gas lamps, each with three glass globes along the
length of Pall Mall, London in 1807. The credit for this goes to the inventor and entrepreneur
Fredrick Winsor and the plumber Thomas Sugg who made and laid the pipes. Digging up
streets to lay pipes required legislation and this delayed the development of street lighting and
gas for domestic use. Meanwhile William Murdock and his pupil Samuel Clegg were
installing gas lighting in factories and work places, encountering no such impediments.

Early history of gas production by gasification
1850s: Gas producers invented, water gas process discovered. Mond Gas: 1850s Europeans
discover that using coal instead of coke in a producer results in producer gas that contains
ammonia and coal tar, Ludwig Mond's Mond Gas is processed to recover these valuable
compounds.

1860s: Enrichment of BWG with illuminants from gas oil circa 1860s. Gas Oils, the volatile
fractions that evaporate above kerosene, are a major problem for kerosene industry.

1875: The invention of the Carburetted Water gas process by Prof. TSC Lowe in 1875. The
gas oil is fixed into the BWG via thermocracking in the carburettor and superheater of the
CWG generating set. CWG is the dominant technology from 1880s until 1950s, replacing
coal gasification. CWG has a CV of 20 MJ/m³ i.e slightly more than half that of natural gas.
Golden age of gas light develops with the Welsbach mantle.

The uses of gas and the later development of the gas
industry in UK
The advent of incandescent gas lighting in factories, homes and in the streets, replacing oil
lamps and candles with steady clear light, almost matching daylight in its colour, turned night
into day for many—making night shift work possible in industries where light was all
important—in spinning, weaving and making up garments etc. The social significance of this
change is difficult for generations brought up with lighting after dark available at the touch of
a switch to appreciate. Not only was industrial production accelerated, but streets were made
safe, social intercourse facilitated and reading and writing made more widespread. Gas works
were built in almost every town, main streets were brightly illuminated and gas was piped in
the streets to the majority of urban households. The invention of the gas meter and the pre-
payment meter in the late 1880s played an important role in selling town gas to domestic and
commercial customers.

The education and training of the large workforce, the attempts to standardise manufacturing
and commercial practices and the moderating of commercial rivalry between supply
companies prompted the founding of associations of gas managers, first in Scotland in 1861.
A British Association of Gas Managers was formed in 1863 in Manchester and this, after a
turbulent history, became the foundation of the Institute of Gas Engineers (IGE). In 1903, the
reconstructed Institution of Civil Engineers (IGE) initiated courses for students of gas
manufacture in the City and Guilds of London Institute. The IGE was granted the Royal
Charter in 1929. Universities were slow to respond to the needs of the industry and it was not
until 1908 that the first Professorship of Coal Gas and Fuel Industries was founded at the
University of Leeds. In 1926, the Gas Light and Coke Company opened Watson House
adjacent to Nine Elms Gas Works. At first, this was a scientific laboratory. Later it included a
centre for training apprentices but its major contribution to the industry was its gas appliance
testing facilities, which were made available to the whole industry, including gas appliance
manufacturers. Using this facility, the industry established not only safety but also
performance standards for both the manufacture of gas appliances and their servicing in
customer’s' homes and commercial premises.

During the first World War, the gas industry's by-products, phenol, toluene and ammonia and
sulpurous compounds were valuable ingredients for explosives. Much coal for the gas works
was shipped by sea and was vulnerable to enemy attack. The gas industry was a large
employer of clerks, mainly male before the war. But the advent of the typewriter and the
female typist made another important social change that was, unlike the employment of
women in war-time industry, to have long lasting effects.

The inter-war years were marked by the development of the continuous vertical retort which
replaced many of the batch fed horizontal retorts. There were improvements in storage,
especially the waterless gas holder, and distribution with the advent of 2 - 4 inch steel pipes
to convey gas at up to 50 psi as feeder mains to the traditional cast iron pipes working at an
average of 2 - 3 inches water gauge. Benzole as a vehicle fuel and coal tar as the main
feedstock for the emerging organic chemical industry provided the gas industry with
substantial revenues. Petroleum supplanted coal tar as the primary feedstock of the organic
chemical industry after World War II and the loss of this market contributed to the economic
problems of the gas industry after the war.

A wide variety of appliances and uses for gas developed over the years. Gas fires, gas
cookers, refrigerators, washing machines, hand irons, pokers for fire lighting, gas-heated
baths, remotely controlled clusters of gas lights, gas engines of various types and, in later
years, gas warm air and hot water central heating and air conditioning, all of which made
immense contributions to the improvement of the quality of life in cities and towns world
wide. The evolution of electric lighting made available from public supply extinguished the
gas light, except where colour matching was practised as in haberdashery shops.

The post-war house building programme put gas at a disadvantage. Whereas electricity had
long developed a national distribution grid, which enabled supplies to reach even small new
housing developments, gas was still distributed only locally. Many new housing estates were
beyond the reach of the gas main and the stringent Treasury rules about return on investment
made extension of mains uneconomic. Electricity made inroads into the home heating market
with underfloor heating and night storage heaters using cheap off-peak electricity supplies.

By the 1960s, manufactured gas, compared with its main rival in the energy market,
electricity, was considered "nasty, smelly, dirty and dangerous (to quote market research of
the time) and seemed doomed to lose market share still further, except for cooking where its
controlability gave it marked advantages over both electricity and solid fuel. The
development of more efficient gas fires assisted gas to resist competition in the market for
room heating. Concurrently a new market for whole house central heating by hot water was
being developed by the oil industry and the gas industry followed suit. Gas warm air heating
found a market niche in new local authority housing where low installation costs gave it an
advantage. These developments, the realignment of managerial thinking away from
commercial management (selling what the industry produced) to marketing management
(meeting the needs, wants and desires of customers) and the lifting of an early moratorium
preventing nationalised industries from using television advertising, saved the gas industry
for long enough to provide a viable market for what was to come.

In 1959 the British Gas Council demonstrated that liquid natural gas (LNG) could be
transported safely, efficiently and economically over long distances by sea. The Methane
Pioneer shipped a consignment of LNG from USA to a new LNG terminal on Canvey Island
and customers there were converted to use the new fuel. A 320 mile long high pressure trunk
pipeline was built from London to Leeds.

The slow death of the town gas industry in UK was signalled by the discovery of natural gas
by the ill-fated BP drilling rig Sea Gem 17th September 1965 some forty miles off Grimsby.
over 8000 feet below the sea bed. Subsequently the North Sea was found to have many rich
gas fields on both sides of the median line which defined which nations should have rights
over the reserves.

The Fuel Policy White paper of 1967 (Cmd. 3438) pointed the industry in the direction of
building up the use of natural gas speedily to 'enable the country to benefit as soon as
possible from the advantages of this new indigenous energy source'. As a result there was a
'rush to gas' for use in peak load electricity generation and in low grade uses in industry. The
effects on the coal industry were very significant; not only did coal lose its market for town
gas production, it came to be displaced from much of the bulk energy market also.

The exploitation of the North Sea gas reserves, entailing landing gas at Easington, Bacton and
St Fergus made viable the building of a national distribution grid, of over 3000 miles,
consisting of two parallel and interconnected pipelines running the length of the country. All
gas equipment in the whole of UK was converted from burning town gas to burn natural gas
(mainly methane) over the period from 1967 to 1977 at a cost of about £100 million including
the writing off of redundant town gas manufacturing plant. All the gas using equipment of
almost 13 million domestic, 400 thousand commercial and 60 thousand industrial customers
was converted. Many dangerous appliances were discovered in this exercise and were taken
out of service. The British town gas industry died on 1st September 1977 when the last town
gas burning appliances were converted to natural gas in Edinburgh.

The organisation of the British gas industry adapted to these changes, first, by the Gas Act
1965 by empowering the Gas Council to acquire and supply gas to the twelve area Boards.
Then, the Gas Act 1972 formed the British Gas Corporation as a single commercial entity,
embracing all the twelve Area Gas Boards, enabling to acquire, distribute and market gas and
gas appliances to industrial commercial and domestic customers throughout the UK. In 1986,
British Gas was privatised and dismembered and Government no longer has any direct
control over it. The most recent demergers are described at [1]

During the era of North Sea gas, many gas pipes made of metal for town gas have been
replaced by plastic. The idea of using them for Hydrogen gas (Molecular hydrogen, Chemical
code: H2 ) was muted too late for them to be saved.

As reported in the DTI Energy Review 'Our Energy Challenge' January 2006 North Sea gas
resources have been depleted at a faster rate than had been anticipated and gas supplies for
the UK are being sought from remote sources: a strategy made possible by developments in
the technologies of pipelaying that enable the transmission of gas over land and under sea
across and between continents. Natural gas is now a world commodity. Such sources of
supply are exposed to all the risks of any import. There are still substantial coal reserves in
UK and this fact prompts the thought that at some time in the future, town gas (gas produced
from coal) may once again feature as a reliable indigenous source of energy.

Development of Pacific coast oil gas process
1912. /Pintsch Railway oil Gas processes 1880s.

Massive problems with lampblack created from the Pacific coast process. Up to 20 to 30
lb/1000 ft³ (300 to 500 g/m³) of oily soot. Major pollution problem leads to passage of early
environmental legislation at the state level.
Layout of a typical gas plant
     1880s Coal gasification plant.
     1910 CWG plant

Issues in gas processing
     Tar aerosols (tar extractors, condensers/scrubbers, Electrostatic precipitators in 1912)
     Light oil vapors (oil washing)
     Naphthalene (oil/tar washing)
     Ammonia gas (scrubbers)
     Hydrogen sulfide gas (purifier boxes)
     Hydrogen cyanide gas (purifier)

WWI-interwar era developments
     Loss of high-quality gas oil (used as motor fuel) and feed coke (diverted for
      steelmaking) leads to massive tar problems. CWG tar is less valuable than coal
      gasification tar as a feed stock. Tar-water emulsions are uneconomical to process due
      to unsellable water and lower quality by products.

      : CWG tar is full of lighter PAH's, good for making pitch, but poor in chemical
      precursors.

     Various "back-run" procedures for CWG generation lower fuel consumption and help
      deal with issues from the use of bitumious coal in CWG sets.
     Development of high-pressure pipeline welding encourages the creation of large
      municipal gas plants and the consolidation of the MG industry. Sets the stage for rise
      natural gas.
     Electric lighting replaces gaslight. MG industry peak is sometime in mid 1920s
     1936 or so. Development of Lurgi gasifier. Germans continue work on
      gasification/synfuels due to oil shortages.
     Public Utility Holding Company Act of 1935 forces break up of integrated coke and
      gas companies.
     Fischer-Tropsch process for synthesis of liquid fuels from CO/H2 gas.
     Haber-Bosch ammonia process creates a large demand for industrial hydrogen.

Post WWII: the decline of manufactured gas
     Development of natural gas industry. NG is 37 MJ/m³
     Petrochemicals kill much of the value coal tar as a source of chemical feed
      stocks.(BTX, Phenols, Pitch)
     Decline in creosote use for wood preserving.
     Direct coal/natural gas injection reduces demand for metallurgical coke. 25 to 40%
      less coke is needed in blast furnaces.
     BOF and EAF processes obsolete cupola furnaces. Reduce need for coke in recycling
      steel scrap. Less need for fresh steel/iron.
     Cast iron & steel are replaced with aluminum and plastics.
      Pthalic Anhydride production shifts from catalytic oxidation of naphthalene to o-xylol
       process.

Post WWII positive developments
      Catalytic upgrading of gas by use of hydrogen to react with tarry vapors in the gas
      The decline of coke making in the US leads to a coal tar crisis since coal tar pitch is
       vital for the production of carbon electrodes for EAF/Aluminum. US now has to
       import CT from china
      Development of process to make methanol via hydrogenation of CO/H2 mixtures.
      Mobil M-gas process for making gasoline from methanol
      SASOL coal process plant in South Africa.
      Direct hydrogenation of coal into liquid and gaseous fuels

Environmental effects
From its original development until the wide scale adoption of natural gas, more than 50,000
manufactured gas plants were in existence in the United States alone. The process of
manufacturing gas usually produced a number of by-products that contaminated the soil and
groundwater in and around the manufacturing plant, so many former town gas plants are a
serious environmental concern, and cleanup and remediation costs are often high. MGPs were
typically sited near or adjacent to waterways that were used for the discharge of wastewater
contaminated with tar, ammonia and/or drip oils, as well as outright waste tars and tar-water
emulsions.

In the earliest days of MGP operations, coal tar was considered a waste and often disposed
into the environment in and around the plant locations. While uses for coal tar developed by
the late-1800s, the market for tar varied and plants that could not sell tar at a given time could
either store tar for future use, attempt to burn it as fuel for the boilers, or dump the tar as
waste. Commonly, waste tars were disposed of in old gas holders, adits or even mine shafts
(if present). Over time, the waste tars degrade with phenols, benzene (and other mono-
aromatics - BTEX) and polycyclic aromatic hydrocarbons released as pollutant plumes that
can escape into the surrounding environment. Other wastes included "blue billy".[4]
which is a ferroferricyanide compound—the blue colour is from prussian blue which was
commercially used as a dye. Blue billy is typically a granular material and was sometimes
sold locally with the strap line "guaranteed weed free drives". The presence of blue billy can
give gas works waste a characteristic musty/bitter almonds or marzipan smell which is of
course associated with cyanide gas.

The shift to the CWG process initially resulted in a reduced output of water gas tar as
compared to the volume of coal tars. The advent of automobiles reduced the availability of
naphtha for carburetion oil, as that fraction was desirable as motor fuel. MGPs that shifted to
heavier grades of oil often experienced problems with the production of tar-water emulsions,
which were difficult, time consuming, and costly to break. [The cause of tar-water emulsions
is complex and was related to several factors, including free carbon in the carburetion oil and
the substitution of bituminous coal as a feedstock instead of coke.] The production of large
volumes of tar-water emulsions quickly filled up available storage capacity at MGPs and
plant management often dumped the emulsions in pits, from which they may or may not have
been later reclaimed. Even if the emulsions were reclaimed, the environmental damage from
placing tars in unlined pits remained. The dumping of emulsions (and other tarry residues
such as tar sludges, tank bottoms, and off-spec tars) into the soil and waters around MGPs is
a significant factor in the pollution found at FMGPs today.

Commonly associated with former manufactured gas plants (known as "FMGPs" in
environmental remediation) are contaminants including:

        BTEX
       o Diffused out from deposits of coal/gas tars
       o Leaks of carburetting oil/light oil
       o Leaks from drip pots, that collected condensible hydrocarbons from the gas
   o     Coal tar waste/sludge
       o Typically found in sumps of gas holders/decanting ponds.
       o Coal tar sludge has no resale value and so was always dumped.
   o     Volatile Organic Compounds
   o     Semi-volatile Organic Compounds
       o Many heavier coal tar compounds are not very volatile, i.e PAHs
   o     Polycyclic aromatic hydrocarbons
       o Found in copious quantities in coal tar, gas tar, and pitch.
   o     heavy metals
       o Leaded solder for gas mains, lead piping, coal ashes.
   o     cyanide
       o Purifier waste has large amounts of complex ferrocyanides in it.
   o     Lampblack
       o Only found where crude oil was used as gasification feedstock.
   o     Tar emulsions

In the UK, former gasworks have commonly been developed over for residential and other
uses (including the Millennium Dome), being seen as prime developable land in the confines
of city boundaries. Situations such as these are now lead to problems associated with
planning and the Contaminated Land Regime and have recently been debated in the House of
Commons.

It should be noted that the more modern coal gasification processes (circa 1970 to 2006) also
have environmental problems requiring various available technologies for mitigation.[4][4]
                        Thermal depolymerization (TDP)
Thermal depolymerization (TDP) is a process for the reduction of complex organic
materials (usually waste products of various sorts, often known as biomass and plastic) into
light crude oil. It mimics the natural geological processes thought to be involved in the
production of fossil fuels. Under pressure and heat, long chain polymers of hydrogen,
oxygen, and carbon decompose into short-chain petroleum hydrocarbons with a maximum
length of around 18 carbons.

Similar processes
Thermal depolymerization is sometimes mistaken for similar processes:

      Thermochemical conversion (TCC) is limited to the changing of manure to crude oil.
      Thermal conversion process (TCP) is limited to the changing of manure and vegetable
       waste to crude oil.

Thermal depolymerization can change many carbon-based materials into crude oil and
methane, and is not limited to manure or vegetable waste.

History
Thermal depolymerization, also known as thermal conversion, is similar to the geological
processes that produced the fossil fuels used today, except that the technological process
occurs in a timeframe measured in hours. Until recently, the human-designed processes were
not efficient enough to serve as a practical source of fuel—more energy was required than
was produced.

Many previous methods which create hydrocarbons through depolymerization used dry
materials (or anhydrous pyrolysis), which requires expending a lot of energy to remove
water. However, there has been work done on hydrous pyrolysis methods, in which the
depolymerization takes place with the materials in water. In U. S. patent 2,177,557, issued in
1939, Bergstrom and Cederquist discuss a method for obtaining oil from wood in which the
wood is heated under pressure in water with a significant amount of calcium hydroxide added
to the mixture. In the early 1970's Herbert R. Appell and coworkers worked with hydrous
pyrolysis methods, as exemplified by U. S. patent 3,733,255, issued in 1973, which discusses
the production of oil from sewer sludge and municipal refuse by heating the material in water
under pressure in the presence of carbon monoxide.

An approach that exceeded break-even was developed by Illinois microbiologist Paul Baskis
in the 1980s and refined over the next 15 years (see U. S. patent 5,269,947, issued in 1993).
The technology was finally developed for commercial use in 1996 by Changing World
Technologies. Brian S. Appel (CEO of Changing World Technologies) took the technology
in 2001 and expanded and changed it into what is now referred to as TCP and has applied for
several patents (see, for example, published patent application US 2004/0192980). A Thermal
Depolymerization demonstration plant was completed in 1999 in Philadelphia by Thermal
Depolymerization, LLC, and the first full-scale commercial plant was constructed in
Carthage, Missouri, about 100 yards (100 m) from ConAgra Foods' massive Butterball turkey
plant, where it is expected to process about 200 tons of turkey waste into 500 barrels (21,000
US gallons or 80 m³) of oil per day.

Theory and process
In the method used by CWT, the water improves the heating process and contributes
hydrogen to the reactions.

The feedstock material is first ground into small chunks, and mixed with water if it is
especially dry. It is then fed into a reaction chamber where it is heated to around 250 °C and
subjected to 600 lbf/in² (4 MPa) for approximately 15 minutes, after which the pressure is
rapidly released to boil off most of the water. The result is a mix of crude hydrocarbons and
solid minerals, which are separated out. The hydrocarbons are sent to a second-stage reactor
where they are heated to 500 °C, further breaking down the longer chains, and the resulting
mix of hydrocarbons is then distilled in a manner similar to conventional oil refining.

Working with turkey offal as the feedstock, the process proved to have yield efficiencies of
approximately 85%; in other words, the energy contained in the end products of the process is
85% of the energy contained in the inputs to the process (most notably the energy content of
the feedstock, but also including electricity for pumps and natural gas for heating).
Alternatively, if one considers the energy content of the feedstock to be free (i.e., waste
material from some other process), one could consider the energy efficiency of the process to
be 560% (85 units of energy made available for 15 units of energy consumed). The company
claims that 15 to 20% of feedstock energy is used to provide energy for the plant. The
remaining energy is available in the converted product. Higher efficiencies may be possible
with drier and more carbon-rich feedstocks, such as waste plastic.

By comparison, the current processes used to produce ethanol and biodiesel from agricultural
sources have energy efficiencies in the 320% range when the energy used to produce the
feedstocks is considered (in this case, usually sugar cane, corn, soybeans and the like). As
these energy efficiencies include the energy cost to produce the feedstock and the above TDP
energy efficiency does not, these values are not directly comparable.

The process breaks down almost all materials that are fed into it. TDP even efficiently breaks
down many types of hazardous materials, such as poisons and difficult-to-destroy biological
agents such as prions.

Feedstocks and outputs with thermal depolymerization
 Feedstock          Output        Feedstock       Output         Feedstock           Output
                              70                            39                 Oil            8%
              Oil                            Oil
                              %                             %                                  48
                                                                               Gas
                              16             Gas           6%                                  %
Plastic       Gas                                              Paper
                              % Turkey offal Carbon                            Carbon          24
bottles                                                    5 % (cellulose)
              Carbon                         solids                            solids          %
                             6%
              solids                                        50                                 20
                                             Water                             Water
              Water          8%                             %                                  %
                                                             65
                            26                 Oil                                            44
              Oil                                            %                  Oil
                            %                                                                 %
                                                             10
              Gas          9%                  Gas                                            10
Sewage                         Medical                       %                  Gas
              Carbon                                              Tires                       %
sludge                     8 % waste           Carbon
              solids                                       5%                   Carbon        42
                                               solids
                            57                                                  solids        %
              Water                                          20
                            %                  Water                            Water        4%
                                                             %

Carthage plant products
The yield from one ton (907kg) of turkey waste is 600 pounds (272 kg) petroleum, 100
pounds (45 kg) butane/methane, and 60 pounds ( 27kg ) minerals. In addition, the water is
recycled back into the system for reuse.

The Carthage, MO plant produces API 40+, a high value crude oil comparable to diesel fuel.
It contains light and heavy naphthas, a kerosene, and a gas oil fraction, with essentially no
heavy fuel oils, tars, asphaltenes, or waxes present.

Classification of TDP-40 Oil by PONA [1]
   PONA           wt%, D-5443 method
Paraffins                          22 %
Olefins                            14 %
Naphthenes                          3%
Aromatics                           6%
C14/C14+                           55 %
TOTAL                             100 %


The fixed carbon solids produced by the TDP process have multiple uses as a filter, a fuel
source and a fertilizer. It can be used as activated carbon in wastewater treatment, as a
fertilizer, or as a fuel similar to coal.

Advantages
The process can break down organic poisons, due to breaking chemical bonds and destroying
the molecular shape needed for the poison's activity. It is highly effective at killing
pathogens, specifically including prions. It can also safely remove heavy metals from the
samples by converting them from their ionized or organometallic forms to their stable oxides
which can be safely separated from the other products.

Potential sources of waste inputs
The Environmental Protection Agency estimates that in 2001 there were 229 million tons of
municipal solid waste, or 4.4 pounds generated per day per person in the USA. [2] Industrial
facilities in the USA create 7.6 billion tons of industrial wastes each year and, as a whole, the
USA creates over 12 billion tons of total waste[3].
Limitations
The process only breaks long molecular chains into shorter ones, so small molecules such as
carbon dioxide or methane cannot be converted to oil through this process. Neither can
thermal depolymerization be used to remove radioactivity from radioactive waste.

Many agricultural and animal wastes could be processed, but many of these are already used
as fertilizer, animal feed, and, in some cases, as feedstocks for paper mills or as boiler fuel.

Current status
According to a 2/1/2005 article by Fortune Magazine, the Carthage plant was producing
about 400 barrels per day of crude oil. This oil is being refined as No. 2 (a standard grade oil
which is used for diesel and residential heating oil) and No. 4 (a lower grade oil used in
industrial heating).

Reports in 2004 claimed that the facility was selling products at 10% below the price of
equivalent oil, but its production costs were low enough that the plant produced a profit. At
the time it was paying for turkey waste. The plant has consumed 270 tons of turkey offal (the
full output of the turkey processing plant) and 20 tons of egg production waste daily. In April
2005 the plant was reported to be running at a loss.

Price and design changes
Reports from 2005 summarized some economic setbacks which the Carthage plant
encountered since its planning stages. It was thought that concern over mad cow disease
would prevent the use of turkey waste and other animal products as cattle feed, and thus this
waste would be free. As it turns out, turkey waste may still be used as feed in the United
States, so that the facility must purchase that feed stock at a cost of $30 to $40 per ton, adding
$15 to $20 per barrel to the cost of the oil. Final cost, as of January 2005, was $80/barrel
($1.90/gal).

The above cost of production also excludes the operating cost of the thermal oxidizer and
scrubber added in May 2005 in response to odor complaints (see below).

A biofuel tax credit of roughly $1 per US gallon (26 ¢/L) on production costs was not
available because the oil produced did not meet the definition of "biodiesel" according to the
relevant American tax legislation. The Energy Policy Act of 2005 specifically added thermal
depolymerization to a $1 renewable diesel credit, which became effective at the end of 2005.

Company expansion
The company has explored expansion in California, Pennsylvania, and Virginia, and is
presently examining projects in Europe, where animal products cannot be used as cattle feed.
TDP is also being considered as an alternative means for sewage treatment in the United
States.[4]

Smell complaints
The pilot plant in Carthage was temporarily shut down due to smell complaints. It was soon
restarted when it was discovered that few of the odors were generated by the plant[5].
Furthermore, the plant agreed to install an enhanced thermal oxidizer and to upgrade its air
scrubber system under a court order[6]. Since the plant is located only four blocks from the
tourist-attracting town center, this has strained relations with the mayor and citizens of
Carthage.

According to a company spokeswoman, the plant has received complaints even on days when
it is not operating. She also contended that the odors may not have been produced by their
facility, which is located near several other agricultural processing plants[7].

In December 29, 2005, the plant was ordered by the state governor to shut down once again
over allegations of foul odors as reported by MSNBC[8].

As of March 7, 2006, the plant has begun limited test runs to validate it has resolved the odor
issue.[9].

As of August 24, 2006, the last lawsuit connected with the odor issue has been dismissed and
the problem is acknowledged as fixed.[10] In late November, however, another complaint was
filed over bad smells.[11]
                          Liquefied natural gas or LNG

Liquefied natural gas or LNG is natural gas that has been processed to remove either
valuable components e.g. helium, or those impurities that could cause difficulty downstream,
e.g. water, and heavy hydrocarbons and then condensed into a liquid at almost atmospheric
pressure (Maximum Transport Pressure set around 25 kPa) by cooling it to approximately -
163 degrees Celsius. LNG is transported by specially designed cryogenic sea vessels and
cryogenic road tankers; and stored in specially designed tanks. LNG is about 1/614th the
volume of natural gas at standard temperature and pressure (STP), making 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 LNG vessels, where
the most common tank types are membrane(prismatic), Moss Rosenberg (spheres) or Self-
Supporting Prismathic Type.

Basic Facts on LNG
LNG offers an energy density comparable to petrol and diesel fuels and produces less
pollution, but its relatively high cost of production and the need to store it in expensive
cryogenic tanks have prevented its widespread use in commercial applications.

Conditions required to condense natural gas depend on its precise composition, the market
that it will be sold to and the process being used, but typically involve temperatures between
−120 and −170 degrees Celsius (pure methane liquefies at −161.6 °C) and pressures of
between 101 and 6000 kPa (14.7 and 870 lbf/in²). High pressure natural gas that is condensed
is then reduced in pressure for storage and shipping.

The density of LNG is roughly 0.41 to 0.5 kg/L, depending on temperature, pressure and
composition. In comparison water has a density of 1.0 kg/L.

LNG does not have a specific heat value as it is made from natural gas, which is a mixture of
different gases. The heat value depends on the source of gas that is used and the process that
is used to liquefy the gas. The higher heating value of LNG is estimated to be 24 MJ/L at
−164 degrees Celsius. This corresponds to a lower heating value of 21 MJ/L.

The natural gas fed into the LNG plant will be treated to remove water, hydrogen sulfide,
carbon dioxide and other components that will freeze (e.g., benzene) under the low
temperatures needed for storage or be destructive to the liquefaction facility. Purified LNG
typically contains more than 90% methane. It also contains small amounts of ethane, propane,
butane and some heavier alkanes. The purification process can be designed to give almost
100% methane.

The most important infrastructure needed for LNG production and transportation is an LNG
plant consisting of one or more LNG trains, each of which is an independent unit for gas
liquefaction. The largest LNG train is the SEGAS Plant in Egypt with a capacity of 5mtpa.
Exxon Mobil operating Qatargas stage 2, of which one train has a production ability of 5
million ton per annum (mtpa). Other facilities needed are load-out terminals for loading the
LNG onto vehicles, LNG vessels for transportation, and a receiving terminal at the
destination for discharge and regasification, where the LNG is reheated and turned into gas.
Regasification terminals are usually connected to a storage and pipeline distribution network
to distribute natural gas to local distribution companies (LDCs) or Independent Power Plants
(IPPs).

In 1964 the UK and France were the LNG buyers under the world’s first LNG trade from
Algeria, witnessing a new era of energy. As most LNG plants are located in "stranded" areas
not served by pipelines, the costs of LNG treatment and transportation were so huge that
development has been slow during the past half century. The construction of an LNG plant
costs USD 1-3 billion, a receiving terminal costs USD 0.5-1 billion, and LNG vessels cost
USD 0.2-0.3 billion. Compared with the crude oil, the natural gas market is small but mature.
The commercial development of LNG is a style called value chain, which means LNG
suppliers first confirm the downstream buyers and then sign 20-25 year contracts with strict
terms and structures for gas pricing. Only when the customers were confirmed and the
development of a greenfield project deemed economically feasible could the sponsors of an
LNG project invest in their development and operation. Thus, the LNG business has been
regarded as a game of the rich, where only players with strong financial and political
resources could get involved. Major international oil companies (IOCs) such as BP,
ExxonMobil, Royal Dutch Shell; and national oil companies (NOCs) such as Pertamina,
Petronas were active players. Japan, South Korea and Taiwan imported large sums of LNG
due to their shortage of energy. In 2002 Japan imported 54 million tons of LNG, representing
48% of the LNG trade around the world that year. Also in 2002, South Korea imported 17.7
million tons and Taiwan 5.33 million tons. These three major buyers purchase approximately
70% of the world's LNG demand.

In recent years, as more players take part in investment, both in downstream and upstream,
and new technologies are adopted, the prices for construction of LNG plants, receiving
terminals and vessels have fallen, making LNG a more competitive means of energy
distribution. The standard price for a 125,000-cubic-meter LNG vessel built in European and
Japanese shipyards used to be USD 250 million. When Korean and Chinese shipyards entered
the race, increased competition reduced profit margins and improved efficiency, reducing
costs 60%. The per-ton construction cost of a LNG liquefaction plant fell steadily from the
1970s through the 1990s, with the cost reduced to approximately 35%.

Due to energy shortage concerns, many new LNG terminals are being contemplated in the
United States. Concerns over the safety of such facilities has created extensive controversy in
the regions where plans have been created to build such facilities. One such location is in the
Long Island Sound between Connecticut and Long Island. Broadwater Energy, an effort
between TransCanada Corp. and Shell (A British-Dutch Corporation) wishes to build a LNG
terminal in the sound on the New York side. Local politicians including the Suffolk County
Executive have raised questions about the terminal. New York Senators Chuck Schumer and
Hillary Clinton have both announced their opposition to the project. Several terminal
proposals along the coast of Maine have also been met with high levels of resistence and
questions.

Trade in LNG
LNG is shipped around the world in specially constructed seagoing vessels. The trade of
LNG is completed by signing a sale and purchase agreement (SPA) between a supplier and
receiving terminal, and by signing a gas sale agreement (GSA) between a receiving terminal
and end-users. Most of the contract terms used to be DEX or Ex Ship, which meant the seller
was responsible for the transportation. But with low shipbuilding costs, and the buyer
preferring to ensure reliable and stable supply, there are more and more contract terms of
FOB, under which the buyer is responsible for the transportation, which is realized by the
buyer owning the vessel or signing a long-term charter agreement with independent carriers.

The agreements for LNG trade used to be long-term portfolios that were relatively inflexible
both in price and volume. If the annual contract quantity is confirmed, the buyer is obliged to
take and pay for the product, or pay for it even if not taken, which is called the obligation of
take or pay (TOP).

In contrast to LNG imported to North America, where the price is pegged to Henry Hub,
most of the LNG imported to Asia is pegged to crude oil prices by a formula consisting of
indexation called the Japan Crude Cocktail (JCC).

The pricing structure that has been widely used in Asian LNG SPAs is as follows: PLNG =
A+B×Pcrude oil, where A refers to a term that represents various non-oil factors, but usually
a constant determined by negotiation at a level that can prevent LNG prices from falling
below a certain level. It thus varies regardless of oil price fluctuation. Typical figures of ex-
ship contracts range from USD 0.7 to 0.9. B is a degree of indexation to oil prices; typical
figures are 0.1485 or 0.1558, and Pcrude oil usually denominated in JCC. PLNG and Pcrude
oil stand for price of oil in USD per million British Thermal Unit (MMBTU (in the fuel
industry, M stands for 1000 and MM for 1 000 000)). With the demand of LNG moving up
and down, the price of LNG moves in a "S" curve. With new demand from China, India and
US increasing dramatically, and crude oil price skyrocketing, the LNG price is on the rise
too.

In the mid 1990s LNG was a buyer's market. At the request of buyers, the SPAs began to
adopt some flexibilities on volume and price. The buyers had more upward and downward
flexibilities in TOP, and short-term SPAs less than 15 years came into effect. At the same
time, alternative destinations for cargo and arbitrage were also allowed. By the turn of the
21st century, the market was again in favor of sellers. Sellers now propose rigid SPAs and
would like an association similar to OPEC to be established to protect their interests. It is
certain that the competition between sellers and buyers will go on.

Receiving terminals exist in several countries (see the list of importing countries in table
below; China is expected to move onto the list by 2006), allowing gas imports from other
areas (see list of exporting countries in table below).

The United States Department of Energy's Energy Information Administration provides
estimates of LNG trade in 2002 as follows:

                        Export volume                         Import volume
       Country                                Country
                        (109 ft³) (106 t)                    (109 ft³) (106 t)
      Indonesia          1,100    23.0          Japan         9,200    188.3
       Algeria             935    19.6      South Korea       2,000     40.7
      Malaysia             741    15.6         France           511     10.7
        Qatar              726    14.9         Taiwan           363      7.5
       Nigeria             394     8.2   United Kingdom        356       7.3
       Australia           367     7.7     United States       229       4.8
        Oman               356     7.3        Turkey           224       4.6
 Brunei Darussalam         351     7.2        Portugal         146       3.3
United Arab Emirates       278     5.7         Spain           131       2.7
        Russia             234     4.8          Italy          130       2.6
Trinidad and Tobago        189     4.0        Belgium          124       2.7
    United States           68     1.4          India          122       2.5



In 2005, Egyptian NG production outpaced consumption and it joined the LNG exporting
countries.

LNG safety and accidents
In its liquid state, LNG is not explosive. For an explosion to occur with LNG, it must first
vaporize and then mix with air in the proper proportions (the explosive range is 5% to 15%),
and then be ignited afterwards. Serious accidents involving LNG to date are listed below:

       1944, 20 October. The East Ohio Natural Gas Company experienced a failure of an
        LNG tank in Cleveland, Ohio. 128 people perished in the explosion and fire. The tank
        did not have a dike retaining wall, and it was made during World War II, when metal
        rationing was very strict. The steel of the tank was made with an extremely low
        amount of nickel, which made the tank brittle when exposed to the extreme cold of
        LNG, and the tank ruptured, spilling LNG into the city sewer system.
       1973, February,Staten Island, New York. While repairing the interior of an empty
        storage tank, a fire started. The pressure increased inside the tank so fast the concrete
        dome on the tank lifted and then collapsed falling inside the tank and killing the 37
        construction workers below.
       1979, Lusby, Maryland, at the Cove Point LNG facility a pump seal failed, releasing
        gas vapors, which entered and settled in an electrical conduit. A worker switched off a
        circuit breaker, igniting the gas vapors, killing a worker and causing heavy damage to
        the building. National fire codes were changed as a result of the accident.
       2004, 19 January, Skikda, Algeria. Explosion at Sonatrach LNG liquefaction facility.
        27 killed, 80 injured, three LNG trains destroyed, 2004 production was down 76% for
        the year. A cold hydrocarbon leak occurred introducing the high-pressure steam boiler
        with gases via a combustion air fan. The explosion inside the boiler fire box
        precipitated a larger explosion of vapors outside the box.

Seaborne LNG transport tankers (including their loading terminals) have not had a "major"
(term undefined) accident in over 33,000 voyages since maritime inception in 1959. There
have, however, been several significant incidents with LNG ships, but with no spills. In
addition to accidents, terrorism experts are concerned that intentional sabotage could lead to
unprecedented releases, resulting in massive fires and other damaging effects. The latter may
include detonations (producing large blast waves) and deflagration-to-detonation transition
phenomena. As the Department of Energy notes in its December 2004 report (Sandia
National Labs, SAND2004-6258), the available testing data on LNG spills are based on
releases of very small size in comparison to releases expected from intentional attacks.
Despite intense local opposition, the Federal Energy Regulatory Commission has approved a
site permit for an LNG terminal in Fall River, Massachusetts in a densely populated harbor
area

LNG storage
LNG above-ground tanks are mainly of double-wall, high-nickel steel construction with
extremely efficient insulation between the walls. Large tanks are low aspect ratio (height to
width) and cylindrical in design with a domed roof. Storage pressures in these tanks are very
low, less than 5 psig. Sometimes more expensive frozen-earth, underground storage is used.
Pre-stressed concrete backed up with suitable thermal insulation, are designed to be both
under and above ground to suit sites conditions and local safety regulations and requirements.
Smaller quantities, 190,000 US gallons (700 m³) and less, are stored in horizontal or vertical,
vacuum-jacketed, pressure vessels. These tanks may be at pressures any where from less than
5 psig to over 250 psig (35 to 1700 kPa gauge pressure).

LNG must be maintained cold (at least below −117 °F or −83 °C) to remain a liquid,
independent of pressure. There will inevitably be some degree of boil-off as a result of heat
gained from the outside ambient atmosphere. This gas is may be returned to storage by
recompression and reliquefaction, or used in the liquefaction process.

LNG refrigeration
The insulation, as efficient as it is, will not keep the temperature of LNG cold by itself. LNG
is stored as a "boiling cryogen," that is, it is a very cold liquid at its boiling point for the
pressure it is being stored. Stored LNG is analogous to boiling water, only 470 °F (260 °C)
colder. The temperature of boiling water (212 °F or 100 °C) does not change, even with
increased heat, as it is cooled by evaporation (steam generation). In much the same way,
LNG will stay at near constant temperature if kept at constant pressure. This phenomenon is
called "autorefrigeration". As long as the steam (LNG vapor boil off) is allowed to leave the
tea kettle (tank), the temperature will remain constant.

If the vapor is not drawn off, then the pressure and temperature inside the vessel will rise.
However, even at 100 psig (7 MPa), the LNG temperature will still be only about −200 °F
(−130 °C).

LNG, LPG, and CNG
Liquefied natural gas (LNG)
When natural gas is cooled to a temperature of approximately −260 °F (−160 °C) at
atmospheric pressure it condenses to a liquid called liquefied natural gas (LNG). One volume
of this liquid takes up about 1/600th the volume of natural gas at a stove burner tip. LNG is
only about 45% the density of water. LNG is odorless, colorless, non-corrosive, and non-
toxic. When vaporized it burns only in concentrations of 5% to 15% when mixed with air.
Neither LNG, nor its vapor, can explode in an unconfined environment.
Natural gas is composed primarily of methane (typically, at least 90%), but may also contain
ethane, propane and heavier hydrocarbons. Small quantities of nitrogen, oxygen, carbon
dioxide, sulfur compounds, and water may also be found in "pipeline" natural gas. The
liquefaction process removes the oxygen, carbon dioxide, sulfur compounds, and water. The
process can also be designed to purify the LNG to almost 100% methane.

Compressed natural gas (CNG)
Compressed natural gas (CNG) is natural gas pressurized and stored in welding bottle-like
tanks at pressures up to 3,600 psig (25 MPa). Typically, it is same composition of the local
"pipeline" gas, with some of the water removed. CNG and LNG are both delivered to the
engines as low pressure vapor (ozf/in² to 300 psig, up to 2.1 MPa). CNG is often
misrepresented as the only form natural gas can be used as vehicle fuel. LNG can be used to
make CNG. This process requires much less capital intensive equipment and about 15% of
the operating and maintenance costs.

Liquid petroleum gas (LPG)
Liquid petroleum gas (LPG, and sometimes called propane) is often confused with LNG and
vice versa. They are not the same and the differences are significant. Varieties of LPG bought
and sold include mixes that are primarily propane, mixes that are primarily butane, and mixes
including propane, propylene, n-butane, butylene and iso-butane. Depending on the season—
in winter more propane, in summer more butane. Vapor pressures, at 30 °C, are for
commercial propane in the range 10-12 barg (1 to 1.2 MPa), for commercial butane, 2-4 barg
(0.2 to 0.4 MPa). In some countries LPG is composed primarily of propane (upwards to 95%)
and smaller quantities of butane. The vapor pressure of commercial butane is generally too
low to release it from the top vapor space. Pumps and (hot water, steam, electricity or direct-
fired) vaporizers are frequently used. An alternative to using neat butane vapor which
overcomes the need for pipework heating, is to use a gas-air mixture (well outside
flammability limits). Air depresses the vapor dew-point temperature. Another advantage is
that the mixture can be made to "simulate" natural gas or town gas to produce the same heat
release through a burner under equal supply pressures, characterized by a term known as
Wobbe number or Wobbe index (see: Wobbe index).

LPG compared to natural gas has a significantly higher heating value and requires a different
air-to-gas mixture (propane: 24:1, butane: 30:1) for good combustion.

LPG can be stored as a liquid in tanks by applying pressure alone. While the distribution of
LNG requires heavy infrastructure investments (pipelines, etc.), LPG is portable. This fact
makes LPG very interesting for developing countries and rural areas. LPG (sometimes called
autogas) has also been used as fuel in light duty vehicles for many years. An increasing
number of petrol stations around the world offers LPG pumps as well. A final example that
should not be forgotten is that the "bottled gas" can often be found under barbecue grills.

LNG Terminals
The following LNG off-loading and processing terminals are located in the United States:

      Massachussets
      Maryland
     Louisiana

Proposed LNG Terminals

     Crown Landing LNG Terminal - A proposed LNG off-loading and processing
      terminal to be located along the Delaware River in Gloucester County, New Jersey.
      BP is working for regulatory approval and the LNG terminal is expected to be online
      by the end of 2008.

								
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