ROLE OF SYNTHETIC NATURAL GAS IN INDIA
Ravi Kumar Gupta1
1
Ravi Kumar Gupta, B.Tech, Chemical Engineering, IIT Delhi, [email protected]
ABSTRACT
Energy security is defined in terms of reasonable assurance of access to energy and relevant technologies at
all times with an ability to cope with sudden shocks. Energy security does not mean complete energy
independence; it only means an ability to meet reasonable requirements with reasonable assurance of stable
supply or an ability to pay for import needs. As per the report by U.S Energy Information Administration,
India’s energy basket contained 44% coal & 7% natural gas in the year 2012 and is expected to reach
approximately 53% & 11% respectively by the year 2035.
As per the data from Ministry of Petroleum & Natural Gas (Economic Division), India has 1354
billion cubic feet of recoverable natural gas reserves as on 01.04.2013 and natural gas import was 17610
Million Standard Cubic Metres in the year 2012 as compared to 6040 Million Standard Cubic Metres in the
year 2005. It is evident that India has very nominal amount of natural gas reserve and its dependence on
energy imports is increasing. As an alternative of conventional natural gas production from depleting natural
gas reserves, production for natural gas from coal has been started and is being done worldwide; this natural
gas produced is termed as Synthetic Natural Gas (SNG).
To assess production of synthetic natural gas from high ash (40-45% ash content) Indian coal is a
challenge and a techno – economic evaluation is done for production of synthetic natural gas from coal.
Technologies for coal gasification and methanation have been discussed. Research design constitutes review
of literature available for production of SNG from coal. For example technologies available for SNG
production from coal, plants being setup or already being set up.
Chapter 1: Introduction
1.1 Overview
Natural gas is one of the cleanest and most efficient of all energy sources and
provides almost 24% of the world’s energy. It provides 23% of Indian energy
consumed. It has become a major feedstock and fuel for the country’s chemical and
manufacturing industries and as of 2007 powered approximately 30% of all Indian
power plants. Unfortunately the reserves of natural gas are limited compared with
its consumption in India. India has been the largest importer of natural gas in the
world. The United States Department of Energy has planned for 90% of all new
baseload power plants to be fueled by natural gas. This sudden increase in demand
for natural gas will make its price increase over time. This presents an opportunity
for novel technologies to introduce supply into the marketplace. One of these novel
technologies includes the conversion of coal, from abundant sources found in the
United States, to SNG (Substitute Natural Gas). SNG may also be produced from
petroleum coke, biomass, or solid waste. From a national security standpoint, SNG
represents a means to alleviate the reliance on imported energy resources by making
the most of an abundant U.S. resource. SNG could be liquefied and transported
throughout the United States via the pipeline infrastructure already in place. What
makes coal an attractive resource is that its resource base is much more evenly
distributed throughout the world compared to oil and natural gas, and it remains
the world’s most abundant source of fossil fuel; it has a reserves to production ratio
of more than 130 years, twice that of natural gas. For countries with significant
proven reserves of coal, but a relative scarcity of natural gas, the coal-to-SNG
process is a promising technology that may provide clean substitute natural gas for
the growing demands of power generation and home utilization.
The following table is a representation of the recoverable energy reserves and
distribution of energy resources.
Table 1.1
RECOVERABLE ENERGY RESERVES AND DISTRIBUTION OF ENERGY
RESOURCES
Confirmed Global
Recoverable Reserves
(R)
North America
Central and South
America
Europe
Middle East
Asia-Pacific
Africa
The Former Soviet
Union
Yearly Global
Production (P)
(Oil Equivalent)
Reserve Production
Ratio (R/P)
Oil
Natural
Gas
Coal
Uranium
1.338 trillion
barrels
5,156
trillion ft3
984 billion
tons
4.36 billion
tons
6.2%
5.0%
36.1%
17.4%
8.6%
4.3%
2.2%
6.2%
3.0%
65.4%
4.3%
7.2%
3.5%
33.8%
7.0%
7.7%
12.4%
0%
29.7%
6.2%
3.0%
0%
25.1%
17.2%
6.3%
38.7%
23.4%
31.0%
71.9 billion
barrels/day
(3.6 billion
tons)
61.2 trillion
ft3
(2.3 billion
tons)
4.28 billion
tons
(3 billion
tons)
96 thousand
tons
(600 million
tons)
42 years
62 years
230 years*
73 years
Assumes most known global coal reserves are accessible and usable. This may not be true
for coal reserves in remote locations or for high ash (low quality) coal. Thus the uncertainty
variance on the size of the usable coal reserve resource base from high to low estimate is
40%.
Source: BP Statistical Review—2008
As shown in Table 1.1 above, the reserve/production (R/P) ratios of fossil fuels are
estimated to be 230 years for coal, 42 years for oil, and 62 years for natural gas.
Although the R/P ratios of coal and natural gas are higher than those of oil, they
may be depleted faster in some world regions than others. The same can be said for
uranium. In addition, the regions in which they are reserved are grouped in certain
areas. In particular, approximately 65% of oil reserves and 73% of the natural gas
reserves are in the Middle East and the former Soviet Union. On the other hand, coal
and uranium reserves are relatively evenly distributed all over the world in
comparison with oil and natural gas. By considering the shortage of reserves of
energy sources except coal in the Asia-Pacific region, the importance of coal usage in
the future can be understood. It is known that the dependence on oil and natural gas
fuels to meet the increase in demand is limited due to the small reserve/production
ratio. Thus on the demand side, it is necessary to try to conserve energy, while on
the supply side, it is necessary to reduce the dependence on oil in the short term and
convert to renewable energy forms in the long term.
Gasification technology has the ability to produce syngas in quantities that meet the
economy of scale required for large scale SNG production. Some the current projects
being approved and proposed in China for production ranges of SNG are from 50 to
over 200 billion standard cubic feet per year.
Coal is in abundant supply in China and the United States. In Japan, coal gasification
can decrease their dependence on imported gas priced by the international market.
On the other hand, most of the new coal gasification units recently installed in China
were mostly designed for chemical use.
1.2 Purpose of the Study
The main purpose of this research is to determine techno economic feasibility of
synthetic natural gas production from coal for India’s energy basket. Some 600
million Indians do not have access to electricity and about 700 million Indians use
biomass as their primary energy resource for cooking. Ensuring lifeline supply of
clean energy is essential to all so as to nurture inclusive growth, meeting the
millennium development goals and raising India’s human development index that
compares poorly with several countries that are currently below India’s level of
development. Energy is needed for economic growth, for improving the quality of
life and for increasing opportunities for development. Increasing natural gas prices
are increasing the cost of development in India. Natural gas reserves in India are
depleting very fast. Even if India wants to import low priced shale gas from USA,
4$/MMBTU gas will cost around 15$/MMBTU at Indian Port.
Coal is much more abundant than oil and gas and global availability ensures
security of supply and relative price stability for the foreseeable future. Coal will
even play a greater role in power generation, chemical industry (e.g. in India, China
and Africa) and in the production of liquid fuels (gasoline, diesel, etc.). Gasification
technology offers environment-friendly, efficient solutions for these applications. In
power generation, for example, gasification can achieve high thermal efficiencies
and also forms a basis for Carbon Capture and Storage (CCS). The study of
production of synthetic natural gas (SNG) from Coal will enable India to get energy
security on long-term basis. SNG thence produced can be fed to vast Natural gas
pipeline grid in India.
1.4 Literature Review
The Indian Economy presently is believed to have established itself on a healthy
growth path and this would increase the energy consumption in India. This increase
in energy consumption is expected to be supplemented by an alteration in the
primary energy mix of India. Depleting gas reserves are forcing major diversion
from natural gas to coal worldwide.
As per the report by Energy Information Administration report, 2014 “India was the
fourth largest energy consumer in the world after China, the United States, and
Russia in 2011, and despite having notable fossil fuel resources, the country has
become increasingly dependent on energy imports”.
What initially prompted the production of synthetic natural gas (SNG) in the United
States was the concern over volatile natural gas prices, declining gas production and
domestic energy security. These factors sparked a revival of interest in developing
reliable domestic sources that are decoupled from the world oil market. SNG
presents an opportunity for production from cheap and plentiful Indian coal
supplies, and has costs driven by coal prices and plant construction, rather than
international energy markets.
The United States and China has many projects on the horizon for coal-to-SNG.
Many projects, which were under construction based on natural gas, are being
redesigned into coal-based projects even after recent fall in U.S. gas prices. China’s
coal-to-SNG projects are progressing at full speed, as China’s gas prices are
approximately 2–3 times higher than those in the United States. China has
traditionally imported most of its gas either via pipeline from Russia or it has been
shipped in as liquefied natural gas (LNG). Making its own Synthetic Natural Gas
(SNG) is one way for China to use its large coal assets rather than importing energy.
China already has excellent logistics for moving coal with the existing rails and
roadways. Therefore the delivery of SNG energy to the marketplace may occur
through the existing and expanding pipeline infrastructure.
On the same line as China, India should also start towards production of synthetic
natural gas coal to reduce its dependence on energy imports. Oil and gas imports
constitute one third of total imports in India. Liquefied Natural Gas (LNG) imports
count for 30% of total natural gas demand in India. Production of SNG from will
reduce the dependence on LNG imports.
Chapter 2: INDUSTRY STATUS
This chapter covers uses of substitute natural gas, energy demand in India and brief
history of the first commercial coal to SNG facility in the United States.
Substitute natural gas (SNG) is functionally identical to natural gas and is derived
from the coal gasification process, and has costs driven by coal prices and plant
construction, rather than international energy markets. SNG is similar to pure
methane (CH4) and is utilized in the following applications:




Industrial use
Heating
Power generation
Fertilizer production
When compared to natural gas, the SNG can be produced at a plant and distributed
by pipeline at the location required, were as natural gas is only produced where it
naturally occurs and often has to be transported several hundreds or thousands of
miles to market. On a price comparison what’s behind the price that drives both
gases, is different for SNG and natural gas.
 SNG cost are derived from:
– Capital costs for plant construction.
– Cost of coal.
 Natural gas cost is derived from:
– International oil price.
– Regional availability, supply and demand.
In the 1970s as a result of the oil crises a great deal of interest grew in the coal to gas
technology, the U.S. government teamed up with industry to investigate the viability
of domestically produced gas from the nation’s abundant coal supply. Since the
domestic gas prices were rising at the time it was the intention of the government to
encourage the development of natural gas supplies that would not be impacted or
connected to the unreliable and volatile international markets.
The support of the U.S. government generated the feasibility of the construction of
the Great Plains Gasification Plant in North Dakota. This plant is the first
commercialized plant in the United States today and the construction of the plant
was completed in 1984. By the time the plant came online the gas prices had
plummeted because of government deregulation, an oil glut, and the increase in
construction cost beyond initial estimates
In the last five years a resurgent interest in SNG has peaked. This is mainly due to
the increase concerns of cost for oil, gas, energy security, and advancement of carbon
capture and sequestration technology. There have been several major proposals for
SNG plants with studies done by government, industry organizations, and
universities, below is a list of some of these studies:






Indiana SNG—2006
Power Holdings—2006
Reuters—2008
Syngas Refiner—2008
KY Study—2007
GL Group—2007
Although many studies have been done however, the Great Plains plant is the only
commercialized plant in operation in the United States, despite the attractiveness to
have a domestic source of energy that is not dependent on world oil or influenced by
foreign regional natural gas markets.
Gasification, and in particular, coal gasification is reemerging as an industry in a
new technical form and of course in a new economic environment in the early part of
the 21st century. A growing number of new gasification projects have been
announced in various parts of the world in the past few years. The United States is
very much focused on Integrated Gasification Combined Cycle (IGCC) power
generation and Fischer-Tropsch (FT) fuel liquids. Europe is focused on
environmentally related issues such as Carbon Dioxide Capture and Storage (CCS)
and energy diversity, while countries such as China are investing heavily in
technologies to convert coal into chemicals/fuels. Alternatively, Qatar, a country
with huge natural gas reserves, is investing in world-scale complexes to produce FT
liquids via natural gas gasification.
In the United States, government initiatives are largely centered on the promotion of
clean coal utilization. The amount of federal funding, federal plus state incentives,
and the active engagement of the U.S. EPA in setting more stringent emission
standards, along with the possibility of higher oil/gas prices in the future has
resulted in large investments in coal based gasification projects. The interest in
gasification, however, has been mainly on power generation.
Eastman Chemical manufactures acetyls and other chemicals entirely from coal
gasification. The company is based in Kingsport, TN, in close proximity to a large
supply of coal. The company began to develop coal gasification technology after the
OPEC oil crisis in the mid- 1970s. In July 2007, the company began construction of
another plant in Beaumont, Texas, U.S. with a capacity of about five times larger
than the facility in Kingsport, Tennessee, U.S. The plant will produce methanol,
hydrogen and ammonia.
China is currently the most active country in the world in investing in new coal
gasification technologies. Coal based syngas has always been an important raw
material for chemical production in China as it is used extensively in the production
of ammonia and methanol. Most of the new coal gasification projects in China will
include ammonia, methanol, and SNG production.
Japan, with no domestic hydrocarbon resources, imports oil, gas and coal for its
energy needs. The price of LNG in the international market is determined by supply
and demand. Furthermore, LNG requires expensive infrastructure (LNG terminals).
Therefore, Japan’s motivation in coal gasification is largely due to coal’s relatively
more stable price in the import market. The following figure presents world
gasification capacity.
Chapter 3: TECHNICAL REVIEW
In this section review of different technologies in development for the conversion of
coal to substitute natural gas (SNG) is done.
First technologies for Production of synthesis gas from coal gasification are
discussed followed by technologies for methanation process.
3.1 Coal Gasification Technologies
To evaluate the available proven coal gasification technologies, 40-45% ash content
coal has been taken as basis. The processes have been classified in the basis of type of
gasifier and described below. Some of the technology suppliers can only process
lower ash content coal normally within 20-25% and they require washing of coal
from 40-45% to 20-25 % as there is no possibility of getting raw coal of 20%-25% ash
content. While some of the technology suppliers have no difficulty in processing coal
feed up to 45% ash content yet some others have given the ash limit up to 25%. In
fact, coal considered for SNG plant is of ‘F’ Grade with following composition:

Ash
-
around 40-45%

Moisture
-
6-8%

VM %
-
23-25%

Gross Calorific value
-
3850-4520 kcal/kg
Considering these aspects, the design basis for coal gasification plant is fixed as

Ash
-
40% (After Washing)

Moisture
-
10-12%
Three representative technologies based on type of gasifier and ash content in coal
feed to gasifier have been considered for comparing the technological and financial
details and described in following Chapter.
The different coal gasification process technologies broadly classified on the basis of
type of gasifiers in use are as follows:
 Moving bed fixed bottom (MBDB) such as Lurgi
 Entrained Bed such as Shell and Texaco
 Fluidized Bed such as Winkler and U Gas
The process technology suppliers mentioned above have some merits and demerits,
which are evaluated during technology evaluation.
3.1.1 Shell Entrained Bed Gasification Process
Shell technology can process coal upto maximum of 25% ash in their process. As the
coal available has ash content in the range of 40-45% after washing, it has to be
washed to bring down the ash content below 25%.
The Shell entrained bed gasification process uses a dry coal feed system which is
sensitive to the coal moisture content. Coal moisture consists of two sources, surface
moisture and inherent moisture. For the coal to flow smoothly through the dry feed
lock hoppers, the surface moisture must be removed. The coal must be dried to total
of about 5% moisture for proper feed flow through the dry feed system.
The coal is simultaneously crushed and dried in a coal mill. The drying medium is
supplied by combining off gas from the Claus tail gas treatment unit with a
slipstream of clean syngas. In our design, the coal is drawn from surge hoppers and
fed through a pressurization lock hopper system which uses carbon dioxide from the
CO2 removal section to convey the coal to gasifiers at about 615 psia, although N2
may also be used as a transport gas. The Shell coal gasifier has the following key
characteristics:
• Oxygen blown, entrained flow type of gasifier.
• Dry coal feed (using inert gas as the solids transporting agent to charge
dried fine coal into the gasification chamber).
• No internal refractory—the gasification chamber is enclosed in gas-tight,
watercooled membrane walls that are protected by molten slag that
solidifies onto the cooled walls.
• Dry fly-ash removal via ceramic candle filters.
Within the gasifier, coal reacts with oxygen and steam at a wall temperature of about
1,427°C (2,600°F) to produce principally hydrogen and carbon monoxide. Because of
high reaction temperature and short residence time, the product from the Shell
gasifier is mainly H2 and CO, and a small portion of CO2. The raw syngas is almost
free of hydrocarbons and tars.
The process is thus attractive for syngas production. Moreover, according to Shell,
this gasifier has the flexibility to handle all ranks of coal, although it is not
necessarily the optimal choice for all of them. Depending on the physical properties
of the feed coal, a small portion of live steam and fluxant (e.g., CaCO3) may be
required in the feed stream in order to regulate the reaction temperature and
improve slag flow in the gasifier.
3.1.2 Lurgi Fixed Bed Dry Bottom (FBDB) Gasification Process
Sasol Lurgi joint venture Company Sasol Lurgi is the sole licensor of Lurgi fixed bed
dry bottom gasification process. Air Liquide now owns Lurgi. A summary of the
main units together with their process functions is given below.
3.1.2.1 Gasification
Pressure gasification of coal with steam & oxygen is done to produce a raw synthesis
gas that comprises mainly of H2, CO2, CO and CH4. Raw synthesis gas is quench
cooled in the wash cooler and low-pressure steam is generated in the primary waste
heat boiler. A range of co-products including oil, naphtha, ammonia and phenols are
produced. Ash & water condensate are also produced.
3.1.2.2 Gas Cooling
Raw synthesis gas from gasification is cooled. Tars, oils and gas liquor which are
condensed from the raw gas in a series of heat exchangers, are sent to the Gas Liquor
Separation Unit. Additional low pressure steam is produced in the secondary waste
heat boilers.
3.1.2.3 Gas Liquor Separation
The product streams from gas cooling are expanded to atmospheric pressure and
different liquid fractions are separated from each other via gravity separation and
settling. The tar and dust separated from the gas condensate stream is recycled to the
gasifiers. Oils are separated and sent to storage while the gas liquor (consisting
primarily of water) is sent to the Phenosolvan and Ammonia Recovery units for
phenol and ammonia recovery.
3.1.2.4 Phenosolvan Ammonia Recovery
A liquid solvent extraction process is used to extract the phenols from the gas liquor
from gas liquor separation unit. The de-phenolised gas liquor is sent to the
Ammonia Recovery Unit utilising the Chemie Linz–Lurgi (CLL) Process where
ammonia is recovered. The Ammonia Recovery Unit generates stripped gas liquor
that is sent for biotreatment. The gases leaving Ammonia Recovery are routed to the
coal lock gas re-compressor within the Gasification battery limit and combined with
raw synthesis gas sent to Gas Purification (Rectisol) unit.
3.1.2.5 Gas Purification (Rectisol)
The Rectisol process is a cold methanol wash process in which lighter hydrocarbons
(“naphtha”), CO2, HCN and volatile sulphur components contained in raw synthesis
gas from coal gasification process are selectively removed. CO2 is separated and
used in urea production. An H2S-rich off-gas stream is sent to the Sulphur Recovery
(Claus) Unit.
3.1.2.6 Sulphur Recovery
The H2S-rich Rectisol off-gas stream is processed in the SRU, comprising of Oxy
Claus process and a Tail Gas Treatment (TGT) unit. The SRU reduces the sulphur
emissions to ppm levels by producing saleable elemental sulphur.
3.1.3
U Gas Fluidized Bed Gasification Process
The U-Gas technology is propriety of GTI gasification process. It is based on a singlestage fluidized bed for production of synthesis gas or ‘syngas’ from a variety of
feedstock. Two versions of the process were developed more or less in parallel, with
the U-GAS® technology developed for gasification of all ranks of coal and the
RENUGAS® technology for gasification of highly reactive fuels such as peat,
biomass, pulp mill residues and wastes. The inherent fuel flexibility of fluidized bed
gasifiers permits the use of lower cost opportunity fuels including all ranks of coal,
petroleum coke, biomass and industrial wastes, either alone or in combination.
3.1.3.1 Fuel Flexibility - Range of Feedstock Properties
The flexi fuel processing which is the specialty of this process is given bellow:
Feedstock Property
• Moisture Content, %
Tested Range
1 - 45
• Volatile Matter, %
3 – 69
• Fixed Carbon, %
6 – 83
• Sulfur, %
0.2 - 4.6
• Free Swelling Index (FSI)
0–8
• Ash Content, %
0 – 45
• Ash Softening Temp, T1, °C
1045 – 1370
• Heating Value, HHV, kJ/kg
12770 – 31600
Synthesis Energy Systems, Inc. (SES) has worldwide exclusive rights for coal
applications of GTI’s gasification technology (coal is defined in the license terms and
includes coke), and for coal and biomass blends with biomass less than 40% of the
fuel supply. SES has non-exclusive license for biomass applications including blends
in which biomass is greater than 40% of the fuel supply. Carbona Corporation has
developed a biomass gasification offering based on the GTI fluidized bed technology
which they had licensed on a non-exclusive basis, and have an agreement with GTI
for joint development of this gasifier for biomass-to-liquids applications.
Gasification Process
In the GTI/U-Gas gasification process, fuel is dried to the extent required for
handling purposes and conveyed into the gasifier from a lock hopper system. Within
the fluidized bed, the fuel reacts with steam and air or oxygen at a temperature of
840 °C to 1100 °C. The temperature for gasification depends on the type of fuel used
and is controlled to maintain high carbon conversion and non-slagging conditions
for the ash.
The process accomplishes four important functions in a single-stage fluidized bed
gasifier. It de-cakes, de-volatilizes, and gasifies fuel, and if necessary, agglomerates
and separates ash from the reacting char. The operating pressure of the gasifier
depends on the end use for the syngas and may vary from 3 to 30 bar (40 to 435 psia)
or more. If the operating temperature required to achieve acceptable carbon
conversion exceeds the fuel ash softening temperature, the ash concentration of the
fluidized bed is allowed to increase until a condition is reached that allows the ash
particles to agglomerate into larger particles. The agglomerated particles are denser
than the surrounding bed material and can thus be selectively removed from the
bed. Reactant gases, including steam, air and/or oxygen are introduced into the
gasifier in two areas: 1) through a sloping distribution grid at the bottom of the bed,
and 2) through a terminal velocity-controlled ash discharge port at the center of the
distribution grid. In both agglomerating and non-agglomerating operating modes,
ash is removed by gravity from the fluidized bed and discharged into a lock hopper
system for depressurization and disposal. In both operating modes, the gasifier
maintains a low level of carbon in the bottom ash discharge stream, making overall
carbon conversion of 95% or higher possible. Cold gas efficiencies of over 80% can be
achieved.
Fines elutriated from the fluidized bed are typically separated from the product
syngas by up to three stages of external cyclone separators, one or two of which may
return the fines to the fluidized bed for increased carbon conversion. The product
syngas is essentially free of tars and oils due to the temperature and residence time
of the gases in the fluidized bed, simplifying downstream heat recovery and gas
cleaning operations.
Due to its dry feeding system (as opposed to slurry or paste feeding), non-slagging
Operation and increased gas and solids residence times are available compared to
entrained bed Gasification technology. The GTI gasification process is capable of
handling a wide range of fuels with a broad range of fuel properties
SES currently has three active projects, all in China, that are at different stages of
Development:
Table-5.3
Comparative Parameters of Major Coal Gasification Processes
Item
Moving/ Fixed Bed
Type
Lurgi &
Operating Pressure,
ata
Fluidized Bed Type
BGL
20-30
Entrained Bed Type
Winkler / U-Gas
Texaco
Shell
Kopper Totzek
Atmospheric/
Pressurized
20-35 even as high
as 90
20-40
Atmospheric
1300-1500
1500--1800
1500
U-Gas: 1-35 bar a
Operating
Temperature, oC
Coal size, mm
Residence time Secs
450-600-780
1000
800-1000/ 900-1100 Bed
temp below ash fusion
point
5-50
2-10
60-1800 sec
for U Gas:0.05-5 mm
5-50 sec
Feedstock Flexibility
Non-coking coal with Ash content 4-46% can
fairly
high
ash be handled. Moisture
content
upto
12%
can
be
tolerated
Form of Feed
Dry
Ash Disposal
Bottom ash disposal
Dry
30%
ash
leaves
Ground coal as 60- Ground coal 90% 90%
below
65% by wt.
by wt. <100 micron, micron
10%
max.
95
1-10sec
micron 1-10 sec.
90
Ash content 25%
can be handled.
Insensitive
to
physical properties
of coal like particle
size
moisture
content etc.
Design ash content
17% gives above
80% efficiency. Ash
content of 0.5 to
30% can be handled
economically. No
NOx generation.
Upto 40% ash in
coal
can
be
processed.
Moisture below 1%
to avoid feeding
problem.
Slurry pulverized
Dry pulverized
Pulverized
from Removes as molten Molten
slag Ash
is
mainly
Item
Moving/ Fixed Bed
Type
Lurgi &
BGL
ensure no formation
of clinke.
Slagging or
Non Slagging
Fluidized Bed Type
Entrained Bed Type
Winkler / U-Gas
Texaco
Shell
bottom
and
rest slag at the bottom.
separated from overhead
gas by cyclones.
Slagging
Non Slagging
Kopper Totzek
flowing down to removed in liquid
bottom of gasifier form at the bottom
will be quenched
and
discharged
after
steam
generation.
Slagging
Special Process
Features
Coal is fed to high
pressure
gasifier
from top by two coal
lock
chambers.
Distributors
are
provided inside the
gasifier top for even
distribution of coal
inside the gasifier
bed.
Gasifier
is
refractory lined.
Typical gas
composition for noncoking Indian coal
Lurgi
This is originally a
fluidized
bed
coal
gasification
process
operated at atmospheric
pressure & 800-1000oC
temperature. Gasifier is
refractory lined
This is coal slurry
gasification (>65%
solid). The slurry
fed
technology
provides
greater
operational
simplicity
and
control, eliminates
dust problem &
facilitates
high
pressure operation.
Gasifier
has
ceramic liner.
The
gasifier
consists
of
a
pressure
vessel,
with a water-cooled
membrane
wall
gasification
chamber. No liner
or refractory is
used.
Dried pulverized
coal is fed into
mixing nozzles of
two-headed gasifier
where coal is mixed
with oxygen and
steam at about
130oC
before
passing
into the
burners
BGL
-
H2
39
28
H2
44
H2
35
H2
26.7
H2
27-28
CO
19
54
CO
31
CO
46
CO
63.3
CO
54-58
Item
Moving/ Fixed Bed
Type
Lurgi &
(Bituminous) % vol
BGL
Fluidized Bed Type
Winkler / U-Gas
Texaco
Shell
Kopper Totzek
CO2 29
6
CO2
21
CO2
17
CO2
1.5
CO2
7-12
CH4 12
7
CH4
2
CH4
<0.1
CH4
Nil
CH4
0-1
Others rest
Typical
consumption of
Steam & Oxygen
Entrained Bed Type
-
Others
1.9
Others rest
-
Steam - 1.5
Steam
0.37
Steam
1.0
Oxygen - 0.37-0.39
Oxygen
0.37
Oxygen
1.0
(kg/kg of Coal)
Oxygen 1.0
Steam
0.3
Oxygen 0.9
 Typical Cold Gas
efficiency
85-95%
85-90 %
70-75 %
75-80 %
75-80 %
 Typical Thermal
efficiency
<92%
90%
90%
92%
90%
0.64-0.68
-
-
0.48 - 0.53
-
14
2
20
More than 10
Merged with Uhde
Typical
consumption of coal
(moisture & ash free
basis) kg/Nm3
(H2+CO)
Approx nos. of
plants
3.2 Methanation Technologies
Methanation reactions have been well known for more than 70 years and have been
used in a variety of industrial processes such as:



Ammonia synthesis
Hydrogen plant purification
Production of substitute natural gas (SNG)
Methanation is normally used as a gas purification process to remove traces of carbon
oxides from gases, such as synthesis gas (syngas). In addition, methanation has been
used to produce synthetic natural gas (methane) and can also convert syngas to
produce methane suitable for pipeline quality.
There are different types of methanation processes:




Catalytic methanation
Direct methanation
HICOM fixed-bed process
Liquid phase methanation
Catalytic Methanation
The catalytic methanation process has been studied extensively since 1902. Catalytic
methanation is an exothermic formation of methane usually starting with a mixture of
H2 and CO, and methanation may be achieved with mixtures of H2 and CO2. Methane
is formed in many coal gasifiers, with the lower temperature gasifiers producing
relatively more methane. Some amount of methane may be present in the feed gas to
the catalytic reactor from the syngas. Steam may be added to the feed gas to avoid
carbon deposition. The heat release depends on the amount of CO present in the feed
gas. For each 1% of CO, an adiabatic reaction will experience a 140°F (60°C)
temperature rise.
The reactions related to methanation are:
Name of Reaction
Methanation Reactions
Boudouard Reaction
Water Gas Shift Reaction
Units (KJ/mol @ 27°C [77°F])
3H2 + CO = CH4 + H2O
-206
2H2 +2CO=CH4 +CO2
-248
4H2 +CO2 = CH4 + 2H2O -165
2CO = C + CO2
-173
CO + H2O= CO2 + H2
-41
16
All the reactions are exothermic reactions and the last reaction of water gas shift is
strongly exothermic.
Methanation occurs when a mixture of H2 and CO is reacted together with a nickelbased catalyst. The ratio of H2/CO is 3:1, which is shown in the first reaction.
The second reaction uses a sulfur-tolerant methanation catalyst with an H2/CO ratio of
1:1 to form methane and carbon dioxide.
The reaction for direct methanation is as follows:
2H2 +2CO=CH4 +CO2
Direct Methanation
Direct methanation is based on a product that is equi-molar for the concentrations of H2
and CO, producing CO2 rather than steam as a product of the reaction. For the process,
no steam is required either for shifting of the H2/CO ratio to 3:1. Sulfur removal is not
required prior to methanation since any sulfur compound present in coal-derived gas
does not poison the catalyst. The process can be used to methanate the quench gas from
a coal gasifier with little pretreatment. Acid gas removal may be used for a reduced
volume of gas and a polishing methanation may be used to bring the gas to U.S.
pipeline specifications.
HICOM Methanation
This is in development by the British Gas Corporation (BGC) to serve the low H2/CO
ratio syngas produced by the following gasifiers:
•
BGC/Lurgi slagging gasifier
•
KRW (Westinghouse)
•
U-Gas
•
Shell (entrained-flow)
•
Texaco (entrained-flow)
The HICOM process employs a series of methanation stages and each has a fixed-bed of
catalyst. The method utilized to control the exothermic heat is to recycle equilibrated
product gas to dilute the feed gas. The amount of recycle can be maintained at a
minimized amount by passing it through at least two stages, with the fresh gas added
to each stage. This can be referred to as a split stream operation for temperature control.
17
The HICOM process uses a nickel based catalyst and excess steam in the feed gas to
prevent carbon deposition. A semicommercial-scale test was performed with a
BGC/Lurgi slagging gasifier at Westfield, Scotland. The test was a success and
processed 4.5 MMSCF/day of purified gases from the gasifier.
Liquid Phase Methanation
Chem Systems has developed the liquid phase methanation system in which a very
small amount of Ni catalyst is immersed into mineral oil coolant by a circulation bath
for temperature control. Fluidization of the catalyst occurs by circulating the oil and the
fresh syngas upward through the reactor. For a large scale process, heat would have to
be recovered from the oil and hot product gases. If a feed stream has an H2/CO ratio of
less than 3, an adjustment can be made by adding steam to the feed and forcing the shift
reaction. Usually more than one reactor is required to obtain the required CO
concentration below 0.1%. The operating conditions are in the range of 572–716°F (300–
380°C) and 300–1,000 psi. Although a desirable CO conversion has been demonstrated
the carbon deposition and catalyst disintegration have been problematic in some of the
operating ranges.
Haldor Topsoe TREMPTM Methanation Technology
This is the technology chosen in this report represented for financial analysis. Haldor
Topsoe offers the TREMPTM (Topsoe Recycle Energy-efficient Methanation Process)
methanation technology including the proprietary catalyst MCR-2X (high temperature
methanation catalyst). This company is in a unique position to optimize the process
since both the catalyst and TREMPTM are developed in-house.
The operating experience of the TREMPTM technology dates back to the late 1970s and
substantial process demonstrations have taken place ensuring the technology is ready
for large-scale applications.
The operational long-term stability for production ranges between 7.5 and 75 MSCFH of
SNG product has been tested under realistic industrial conditions using the MCR-2X
catalyst.
Also the catalyst, MCR-2X has been demonstrated independently through over 40,000
hours of operation.
18
This process has been demonstrated on a semi commercial scale in various plants in
Topsoe pilot facilities as well as in a pilot plant of Union Kraftstoff Wesseling (UKW),
Germany. The catalyst charge lasted 10,000 hours for the MCR-2X, which was run at the
pilot plant and proved to be a very stable catalyst.
The Haldor Topsoe main technology characteristics are as follows:
 High-energy efficiency; 20% of the heating value of the synthesis gas is recovered
from the highly exothermic methanation reactions.
 Production of high pressure superheated steam with the properties of 1,450 psig
and 1,000°F (538°C).
 An SNG product with compatible pipeline specifications of natural gas as shown
below.
–
–
–
–
–
–
CH4
CO2
H2
CO
N2+Ar
HHV
94–98 mol %
0.2–2 mol %
0.05–2 mol %
<100 ppm
2–3mol%
950–975 Btu/scf
The feed gas goes to an adiabatic fixed bed reactor. Since the reaction results in a high
temperature increase, a recycle is used to control the temperature rise in the first
methanation reactor. The process is designed for a minimum recycle. This is only
possible because of the MCR-2X catalyst’s high temperature stability.
The exit gas from the first reactor is cooled by production of superheated high-pressure
steam. The gas then enters the next methanation stage. Note that the number of reaction
stages will depend on the specific application. After the final reaction stage, low
temperature is recovered and process condensate is removed from the natural gas
product.
19
Figure 1: HALDOR TOPSE TREMP PROCESS FLOW
3.3 Selected Technology:
Since Indian coal is of high ash content i.e. of the order of 40-45% ash, out of all the coal
gasification technologies discussed here, only U-gas can process coal upto 45%.
Shell technology is very energy efficient and gives high H2+CO content in Syn gas, but
it can handle ash content only 25%. Washing of coal can be an option but, washing coal
from 45% to 25% is difficult to achieve and even if it can be achieved, rejects and
middlings will be very high and coal requirement will increase.
Lurgi FBDB can process coal upto 35% and coal can be washed from 45% to 35% but
this technology produces lower H2+CO content in syn gas as compared to other
technologies and also generates a lot of byproducts that are difficult to handle and sell.
U – Gas can process coal upto 45% ash content coal available is of the range of 40-45%
ash content, the suitable technology for coal gasification is U-Gas of Synthesis Energy
Systems. Further for methanation, Haldor Topse TREMP TM methanation process has
been chosen.
3.4 Process description for production of Substitute Natural Gas from Coal
by Haldor Topsoe TREMPTM Methanation Process using U – Gas
Haldor Topsoe (HT) TREMP™ technology takes coal based syngas from gasification
and through methanation produces a substitute natural gas. The process is a high
temperature methanation process in which the feed syngas is passed through a sulfur
20
tolerant shift and acid gas removal unit for the removal of H2S and excess carbon in the
form of carbon dioxide. Next the sulfur free syngas enters the TREMP™ unit with a
hydrogen to carbon ratio of approximately 3 or slightly below. In order to protect
downstream methanation catalyst from sulfur poisoning the feed is passed through a
sulfur guard bed for removal of traces of sulfur components that may not have been
removed by the acid gas removal unit upstream. Next the desulfurized feed is then
mixed with recycle gas to control the maximum temperature rise and passed to the first
adiabatic methanation reactor.
The highly exothermic methanation reactions result in high outlet temperatures, were
heat is recovered for generation of superheated high pressure steam in the downstream
exchangers. After cooling from the first methanation reactor the partly methanated
syngas passes through a series of two or more adiabatic methanation reactors for
complete conversion of the carbon monoxide and carbon dioxide into methane.
The number of adiabatic methanation reactors will depend on the following:
• Operating conditions
• SNG product specification
The substitute natural gas process stream that leaves the final methanation reactor is
cooled, dried and compressed to meet the pipeline specifications of natural gas.
MAIN REACTIONS
The Haldor Topsoe TREMP™ methanation technology is designed to operate on syngas
originating from coal and petcoke.
The following table presents the main reactions involved in syngas production from
coal.
21
GASIFICATION CHEMISTRY
Reaction Type
Combustion
Combustion
Boudard
Boudard
Hydrogen Gasification
Water Gas Shift
COS Hydrolysis
Equation
C + ½ O2 = CO
CO + ½ O2 = CO2
C + H2O = CO + H2
C + CO2 = 2 CO
H2 + ½ O2 = H2O
C + 2 H2 = CH4
CO+ H2O = H2 + CO2
COS + H2O = H2S + CO2
kJ/mole No.
-47.6
-121.7
56.5
74.2
-104.0
-32.2
-17.7
-30.1
The syngas composition in terms of H2/CO molar ratio, depending on such parameters
as feedstock, temperature, pressure, catalyst, oxygen-to-carbon and steam-to-carbon
ratios, typically varies. For methanation synthesis, for the feed syngas composition, a
stoichiometric molecular factor defined by Haldor Topsoe as equivalent to [H2 - CO2] /
[CO + CO2], as a recommended design parameter whose value is slightly less than 3.
Note that CO2 is a major byproduct in syngas. The symbols in parenthesis denote
respective moles of the gases.
Next for the methanation processes the formation of methane from carbon oxides and
hydrogen proceeds quickly to equilibrium in the presence of a catalyst and in
accordance with either or both of the following reactions below.
The following table presents Haldor Topsoe’s reaction scheme for methanation to
produce SNG.
CATALYSTS
22
The TREMP™ technology is based on the unique Topsoe MCR-2X methanation catalyst,
which has high and stable activity in a wide temperature range of 482°F to 1,292°F. The
properties of the MCR-2X catalyst have several advantages in the process design.
Sulfur compounds will poison and deactivate the catalyst in the methanation section.
Thus, any sulfur compounds present in the feed must be removed. A small amount of
steam is added to the synthesis gas in order to facilitate the abatement of COS in the
downstream sulfur guard. The steam is added upstream the sulfur guard.
The feed enters the sulfur guard in which COS is hydrolyzed by the added steam
according to the following reaction:
COS + H2O ⇔CO2 + H2S
The H2S present in the synthesis feed gas or produced by COS hydrolysis is absorbed in
the guard bed according to:
H2S + ZnO ⇔ZnS + H2O
The sulfur guard is loaded with Haldor Topsoe catalyst HTZ-51 which is specially
promoted and suitable for removal of H2S and COS.
23
In Figure 5.1 the overall process has been divided into eight sections for ease of
understanding and process economics cost break down. Each of the major process steps
are described next.
Section 100—Coal Receiving and Storage
The coal supply is for both the gasifiers and the supplementary coal-fired steam boiler.
This plant receives, stores, and reclaims coal from storage, and delivers coal to the
pulverizer feed silos. The facilities are designed to ensure a reliable and steady flow of
coal to the gasifiers.
Washed coal is delivered to the plant by rail or by barge, depending on the plant
location. The coal gasifiers feed rate is 967.9 thousand pounds per hour.
The coal is unloaded in a surge receiver, from which it is conveyed by belt-conveyers.
The coal is piled by traveling stackers. Provided are 4 days live storage and 30 days’
dead storage. A rotary reclaimer blends coal from the live storage pile. The coal is then
stored in surge silos before being transferred to the coal grinding/drying and
transportation section of the plant.
24
Equipment designs are mainly mechanical and we assume that the plant will be
constructed by a qualified constructor on a turnkey basis.
Section 200—Air Separation Plant
The air separation plant (ASU) used includes dedicated air compressors to deliver air to
the cryogenic section.
In the design configuration, the air compressor train consists of two compressors, each
of which is followed by a water cooled heat exchanger. The oxygen is compressed at a
delivery pressure required by the gasifier. The oxygen compressor train consists of
three compressors and two intercoolers.
Ambient air, at 14.7 psia is compressed and cooled in two stages by water cooled heat
exchangers. The compressed air, now at 75 psia is fed to the air separation plant. The
discharge from the ASU units contains mostly nitrogen with small amounts of argon
and CO2.
The oxygen-rich air, from the ASU at 37.5 psia and 59°F (15°C) is compressed and
cooled in stages. There are three compressors and two intercoolers. Cooling takes place
after each compression stage. The final pressure of the oxygen rich air is at 786.8 psia
and at a temperature of 262°F (127°C). This stream is fed to the gasifier at a rate 675
thousand pounds per hour gaseous O2 (99.5 vol % basis).
The power consumption is based on the thermodynamic compression power required.
Section 300—Coal Preparation and Gasification
Coal grinding, drying, pressurization, and conveying are mature unit operation
processes.
The process flow diagram depicts this section as a block. An important aspect of coal
grinding and drying is the prevention of coal dust explosion. As a result the process is
carried out under inert conditions.
Coal (Stream 1) at a rate of 967.9 thousand lb/hr at 77°F (25°C) is pneumatically
transported to the coal pressurization and feeding system with transport carbon dioxide
(Stream 2) at a rate of 92.18 thousand lb/hr at 197°F (91.6°C) and 1,200 psia. The system
consists of a receiving vessel and two lock hoppers, and a feed lock hopper. Coal is
25
separated from the CO2 carrier gas in the receiving vessel and then transferred to one of
the two lock hoppers which operate on a time cycle (while one is being filled, the other
is being emptied). Once a lock hopper has been charged with coal from the receiving
vessel, it is then pressurized with CO2 and its contents are discharged into the feed
hopper.
Pressurized fine coal is continuously withdrawn from the feed hopper via a distribution
ring and pneumatically conveyed with CO2 to the coal burners of the gasifier.
At the gasifier burners, oxygen is concurrently injected with fine coal carried in CO2
medium through six opposed burners. The temperature of the gasifier is controlled at
c.a. 2,600°F (1,426°C) by adjusting the flow rate of oxygen and the amount of steam
generation from the membrane walls. From the combustion zone, the hot raw gas flows
upwards while the molten slag flows downward. The hot gas is cooled by refractory
cooling in the gasifier generating 22,793 Btu/s of heat. This gas quench solidifies ashes
entrained in the hot gas and prevents “sticky” ashes being carried downstream to the
syngas cooler. The waste heat in the mixture of raw gas of hot and cold gases is
successively recovered in the syngas cooler by generating high pressure steam.
Molten slag (Stream 7) vitrifies when dropped into the water-bath at the bottom of the
gasifier at 92.36 thousand lb/hr, forming glassy inert solid granules. The granules then
fall down into a collecting vessel located beneath the slag bath. Crushed slag at the
outlet of the gasifier is drained out through pressure locks into a pair of lock hoppers
operated on a time cycle. After one lock hopper is filled and the slag granules settled to
the bottom, part of the hot water in the lock hopper is pumped out, through an
exchanger that warms up boiler feed water. The slag is then sprayed with clean makeup
water to remove entrained gas and contaminants. The lock hopper is then
depressurized and the contents drained to a dewatering bin. The settled solids are then
lifted off the bottom of the bin by an inclined screw and deposited on a conveyor belt
for delivery or sent to disposal. The water circuit for processing slag incorporates a
rotary or belt filter for removing fine solids in suspension (so-called fine slag). Water
cleared of fine slag is then combined with the water from the BFW heat exchanger, air
cooled and pumped back to the water bath of the gasifier.
Solidified fines (including fine ashes and unconverted carbon particles) from the syngas
cooler are recovered in the HTHP ceramic filters and recycled to the gasifier to recover
additional carbon and to enhance slag yields.
A portion of syngas (Stream 8) is recycled on the Shell gasifier as a temperate controller.
26
The remaining syngas from gasification (Stream 9) is sent to the BFW pre-heater and
then to the wet scrubber. After scrubbing, the syngas (Stream 10) is cooled to 392°F
(200°C). Stream 11, wet scrubber water, consists of fresh make up water and the return
water from the NH3 stripper.
The syngas flows into a Venturi/wet-scrubber assembly to remove entrained small
solid particles and to increase the moisture content in the gas by evaporative cooling.
The scrubbed syngas flows forward to the shift conversion and gas cooling Section 400.
The pH of the cleaning process is controlled by adding an aqueous solution of 25%
NaOH to the re-circulated liquid stream from the bottom of the wet scrubber into the
Venturi scrubber. The addition of caustic helps to neutralize acids such as HCl and HF
formed during gasification process. Wet scrubbing also helps to remove a small portion
of NH3, HCN, H2S, as well as heavy metal compounds and halides by dissolving them
in the water. Wet scrubbing also reduces the fine particles’ concentration down to 1
mg/NM3 or less (suitable for downstream chemical synthesis). The “dirty” water at the
bottom of the scrubber is sent to a rotary filter to filter out the particles scrubbed from
the syngas.
A portion of this stream is extracted from the circuit, and sent to a rotary filter to filter
out the fine solids to mitigate continuous increase in the content of contaminants in the
recirculated water. The filtered water is then sent to the sour water treatment plant. An
aqueous solution of 25% NaOH is added into the sour water stream to adjust the pH
value and to facilitate acid gas stripping. The acid gases (NH3 and H2S) are stripped in
the stripper and sent to the Claus plant for further treatment and the water at the
bottom of the stripper is sent to the effluent treatment plant.
Section 400—Shift, Cooling and Mercury Removal
The syngas exiting the scrubber is sent to COS hydrolysis reactor where the water vapor
reacts with COS to produce H2S based on the following reaction:
COS + H2O = CO2 + H2S
The syngas temperature is cooled in a series of three coolers and water knock out
drums. The gas is cooled from 391.5°F (199°C) to 100°F (37.8°C). The total condensed
water in the three knock out drums is shown in (Stream 12). In the first cooler, the clean
syngas exiting the CO2 removal is reheated while the raw syngas is cooled. The second
cooler heats condensate while the third cooler, is air cooled in order to achieve the
27
desired syngas exit temperature. The process condensate (Stream 12) is sent to an acid
gas stripper.
The presence of mercury is not shown in the stream flows, but it is presumed to be
present. A mercury removal system captures traces of mercury and other heavy metals
such as arsenic compounds, which can be harmful to catalysts in downstream
methanation. Carbon beds are used in each train. The vessels and carbon loading are
scaled in accordance with the design specifications. Mercury removal in the syngas is
modeled using Calgon Carbon HGR® sulfur impregnated activated carbon. More than
90% of the mercury is removed by adsorption on the activated carbon. The carbon bed
is expected to have a life of over 3 years, after which it is discarded. The cooled syngas
then passes through a carbon bed to remove 95% of the Hg. The syngas is then sent for
acid gas removal.
The syngas leaving the AGR unit (Stream 17) is sent for clean shift conversion. The
clean shift conversion is selected to support smaller equipment sizes for three parallel
trains of two low temperature shift reactors in series. The two-stage shift reactors have
inter-stage cooling to control the shift reaction exotherm. In the shift reaction, CO reacts
with steam to form H2 and CO2 based on the equation:
CO + H2O = CO2 + H2
The reaction is equilibrium based and not driven by the kinetics. The waste heat in the
shifted gas stream is used to heat low pressure condensate based on the integrated
thermoflow GT Pro model.
The clean syngas (Stream 14) enters the shift reactor at 550.4 psia and 95°F (35°C). Steam
(Stream 15) at 1,100 psia and 596°F (313°C) is fed to the shift reactor system. Over half of
the CO in the syngas feed is shifted, 61.5% to form CO2 and H2. The shifted syngas at
550 psia and 296°F (147°C) is cooled to 113°F (45°C) before entering the CO 2 absorber
unit.
The shifted syngas (Stream 16) is then fed to the bottom of CO 2 absorber column. In the
absorber, as the gas flows upward, CO2 is absorbed by the countercurrent methanol
solvent stream. The CO2 rich solvent stream from the absorber sump is sent to a series
of flash tanks. As the solvent is progressively depressurized, CO2 is released in the flash
tanks. The CO2 lean solvent stream exiting the last flash tank (lowest pressure), is
pumped and cooled before looping back to the absorber. Captured CO2 released from
the flash tanks, is emitted to the atmosphere.
28
The clean syngas at 550 psia and 95°F (35°C) leaves the top of the CO2 absorber column
is heated in an economizer to 383.5°F (195°C) by the hydrolyzed syngas stream. The
clean syngas (Stream 18) is sent for Methanation to Section 700.
Section 500—CO2 Removal and Rectisol
The cooled syngas from gas cooling and mercury removal undergoes removal of sulfur
compounds such as H2S via physical absorption in the Rectisol plant. The plant uses
circulating methanol at low temperatures to reduce the H2S content of the syngas to
under 0.5 parts per million by volume (ppmv), as required for downstream
methanation.
A Rectisol methanol solvent unit (licensed by Lurgi) is used to remove H 2S, CO2 and
most of the residual COS in the raw gas (Stream 13). The main acid gases are absorbed
at 490 psig and -35°F (2°C) on the top of the column. External propylene refrigeration is
used in the process at 50°F (10°C) and -45°F (-42°C). Rectisol produces a desulfurized
product (Stream 14) which goes to the sweet shift unit operation in Section 400, and a
H2S-rich (Stream 17) that is recovered from the acid gases, for sulfur production in a
downstream Claus plant in Section 600. Flash of CO2 laden methanol solvent has been
described in Section 400.
Section 600—Claus/SCOT
For sulfur recovery and tailgas treating we use the Claus process with two reactors and
the basic SCOT process.
Claus Sub-Section
The H2S-rich gas stream, containing mostly H2S and CO2 is sent to a Claus sulfur
furnace in which H2S is burned in air (or oxygen enriched air) to form SO2.
The overall Claus reaction is as follows:
2H2S + SO2 → 2 H2O + 3S
The concentrated acid gas stream from the AGR unit, a recycled H2S stream from the
downstream SCOT tailgas treatment section, acid gas streams from the sour water
treatment and NH3 stripper are fed to a reaction furnace. Inside the furnace, one-third
of the H2S in the gases is oxidized to SO2 with air or oxygen-enriched air depending on
sulfur load. The SO2 formed reacts further with the remaining two-thirds of the H2S to
29
produce elemental sulfur. Traces of carbonyl sulfide and CS2 are also formed. The
residual hydrocarbons are completely burned to CO2 and H2O. The oxidation reactions
are highly exothermic, raising the furnace gas temperature to about 2,630°F (1,443°C).
The hot reaction gas stream immediately passes to a waste heat boiler where the hot gas
is cooled to 600°F (316°C) with boiler feed water. The sensible heat in the gas is
recovered by generating 600 psig medium-pressure steam. In a second cooling step, the
temperature of the hot gas is lowered further with boiler feed water to 370°F (188°C),
which is below the sulfur dew point, by generating 100 psig low-pressure steam.
During this cooling step, the sulfur formed in the reaction furnace stage is condensed,
separated from the gaseous stream and transferred to sulfur pit.
The heated gas passes through the first stage of Claus reactor. The gas temperature is
elevated to 641°F (338°C). The sulfur vapor in the hot gas is immediately condensed at
350°F (177°C) with boiler feedwater by generating 50 psig steam. The same procedure is
repeated in the Claus second reactor at a declining temperature. At the end of the
second catalytic stage, S recovery from Claus is about 98.5%. After liquid S separation at
the end of the Claus second stage the tailgas passes to the SCOT process.
SCOT Sub-Section
The Claus reactor tailgas stream is fed to combustion furnace, where the reducing gas
(H2 +CO) required for the downstream catalytic reactor is provided by a slip stream of
cleaned syngas. The heat required by the reaction is generated by combusting the
syngas in a sub-stoichiometric ratio, because of thermal balance. The temperature of the
resulting mixture of combustion gas and the Claus reactor tailgas is controlled at 549°F
(287°C) as the gaseous mixture exits from the combustion furnace.
From there, it flows down through a catalytic reactor in which all residual sulfur and
sulfurous compounds are converted to H2S over a Co-Mo catalyst supported on
alumina. The heat of reactions elevates the converter gas to 557°F (292°C) as it exits the
catalytic reactor. The hot gas is cooled to 334°F (167°C) with boiler feed water to
generate 50 psig steam. Then, the gas is water-quenched to 120°F (49°C). The quench
water is air-cooled in a pump around circuit. The excess water condensed in the quench
tower is collected in a bottom separator and pumped from there to the wastewater
treatment facility.
The water-cooled gaseous stream exits the top of the quench tower and flows to a
column absorber where H2S and the remaining CO2 in the gas are absorbed in an
aqueous solution of MDEA. The off-gas from the top of the absorber passes to a gas30
fired off-gas incinerator where all residual sulfur compounds are oxidized to SO2. The
waste heat from incineration is recovered for steam generation.
After two heat exchanges with two lean MDEA solution streams, the rich MDEA
solution stream passes to interconnected twin section stripper, each section contains 12
valve trays. A less thoroughly regenerated lean solution is collected at the bottom of the
top section and after heat exchange with the rich solvent stream and is returned to the
lower section of the MDEA absorber for bulk removal of acid gases. The more
rigorously regenerated MDEA solution at the bottom section of the stripper, after heat
exchange with the rich solution, is returned to the top of the MDEA absorber. This
division of the lean MDEA solution streams reduces energy consumption in solvent
regeneration and permits a lower acid gas content in the off-gas stream to the
incinerator.
The acid gases recovered at the top of the stripper are recycled to the Claus reaction
furnace. Total sulfur recovery rate (in wt % of sulfur) from the Claus process is 98.4%,
together with the H2S recovered from the SCOT unit and recycled to Claus furnace, the
overall sulfur recovery rate is 99.9%.
Section 700—Haldor Topsoe TREMP™ Methanation Process
This process description covers in general a description of the major chemical and
physical processes in the methanation plant.
Clean syngas coming from Section 400 (Stream 18) still has some residual sulfur
compounds left in it that need to be eliminated because the sulfur compounds will
poison and deactivate the catalyst in the methanation reactors. Any sulfur compounds
left in the feed syngas must be completely removed. To achieve that objective, a small
amount of steam is added upstream of the feed syngas in order to facilitate the
abatement of COS in the downstream sulfur guard, R-701. The feed syngas enters the
sulfur guard in which COS is hydrolyzed by the added steam to create hydrogen
sulfide and carbon dioxide. The H2S present in the synthesis feed gas or produced by
COS hydrolysis is absorbed in the guard bed by reacting with zinc oxide to make zinc
sulfide and water. The sulfur guard is loaded with Haldor Topsoe catalyst HTZ-51
which is specially promoted and suitable for removal of H2S and COS.
Next the desulfurized feed syngas will go through a series of four adiabatic reactors,
which are highly exothermic with cooling in between to achieve complete conversion of
carbon monoxide to methane rich SNG and water.
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The desulfurized feed gas goes to the first methanation reactors, R-702 A&B two
reactors in parallel operation because the high flowrate results in an impractical high
diameter for the reactors. Because of the high heat and sensitivity to the Haldor Topsoe
methanation catalyst, MCR-2X a recycle stream of reactor, R-702 A&B effluent is used
for temperature control. The main reason for this recycle stream is to maintain the outlet
temperature safely below the maximum allowable temperature for the catalyst 482–
1,292°F (250–700°C). The outlet temperature for the first methanation reactor is 1,247°F
(675°C) within the acceptable range for catalyst activity.
The SNG production rate for this methanation process is 78 billion scf/yr which
requires two Haldor Topsoe TREMP™ methanation trains operating at 50% to
accommodate the first methanation reactor diameter. The diameter would be too large
to be feasible for a one train operation. It is because of the high temperature and 74.2%
CO conversion in the first reactor that makes this the rate limiting process unit. The
recycle (Stream 19) for our design is approximately 50% for this first reactor. The main
objective is to keep the recycle to a minimum to reduce reactor size.
The first reactor effluent is cooled in the HP steam superheat, E-701, and then it is
further cooled in the first waste heat boiler, E-702, for production of HP steam. Next this
stream is split where 50% of the reactor effluent goes to the second methanation reactor,
R-703, and the recycle flow is conditioned through a loop. The recycle flow is first
cooled in the loop feed/effluent exchanger, E-703 and then further cooled in a low
pressure boiler, E-704 producing LP steam.
Then next the recycle flow’s water is knocked out in a drum V-701 before compression
in compressor, K-701 to a pressure of 538 psig. Then finally the recycle flow stream is
reheated and combined with desulfurized syngas to go back as feed to reactor one
again.
Then reactor effluent from the first reactor (Stream 20) that goes to the second
methanation reactor, R-703. The effluent out of reactor two is cooled down in a second
waste heat boiler, E-705 and further cooled in a second BFW preheater, E-706.
Out of the third methanation reactor, R-704 (Stream 22) is cooled in the first BFW
preheater, E-707 and then further cooling occurs in an air cooler, E-708 to remove water
from the process gas it is still further cooled in E-709, the first water cooler. The
condensate is removed in the first separator, V-702 in order to maximize the conversion
of CO and CO2 in the last methanation reactor.
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Prior to the last step of methanation the gas is compressed to 475 psig in K-702 and
reheated in the feed/effluent exchanger, E-710. The final carbon oxide conversion takes
place in R-705.
The fourth reactor effluent is cooled downstream by the feed/effluent exchanger, E-710
and further cooled by E-711 to 104°F (40°C), second water cooler. Finally process
condensate (Stream 25) is removed by the second separator, V-703, before the SNG is
sent to Section 800 (Stream 23) for the drying process.
Section 800—SNG Drying
The SNG from methanation Section 800 (Stream 23) (see Appendix E, Figure 5.2) is fed
to an inlet separator, V-801 to knock out any water in the gas. Next the SNG is
dehydrated by molecular sieve dryers C-801 A, B. The sieves are regenerated using dry
gas heated up to 600°F (316°C); usually 525–550°F (274–288°C) is adequate. The
regeneration gas is heated in E-801 by the hot exhaust leaving the gas turbine that
drives the residue gas compressor, K-801. On leaving the mole sieve bed, regeneration
gas is cooled in an air cooler, E-802 and free water is separated by water knock out
drum, V-802 before the gas is returned and combined with the inlet SNG feed going to
inlet separator V-801. Finally dehydrated SNG gas is compressed in a centrifugal 5 stage
compressor, G-801 which is steam turbine driven. The final SNG gas conditions in
(Stream 24) are 120°F (49°C), and 1,015 psia for pipeline transport.
Chapter 6: Conclusions and Scope for Future Work
Synthetic Natural Gas produced is suitable for transportation through pipeline mode.
SNG hence produced may be injected to the national gas grid and can be used as for
City Gas Distribution as the gas is methane rich. This gas produced will help to cater
supply demand gap of natural gas in India and will reduce LNG import dependence.
Availability of coal is still an issue due to regulatory framework for coal block allocation
in India. Apart from coal allocation, cost of SNG produced is assumed to be sold at $
13/MMBTU and it can only be sold if LNG being imported is costlier than $
13/MMBTU. Processing of high ash coal at U-Gas gasifier is proven but plants setup at
Yima and Zao Zhuang in China are based on coal rejects feel i.e. 45% ash content. If
been fully
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