Executive Summary India is tipped to be a rapidly growing economy ...

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Nov 8, 2013 (3 years and 8 months ago)

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Executive Summary

India is tipped to be a rapidly growing economy heading towards occupying 3rd
place in the world. However, it needs to be remembered that the growth of
economy is dependent upon a crucial assumption that requisite amount of
energy will be

available at a price that does not adversely 'affect the
competitiveness of the nation's industry and service sector.

The oil prices have hovered around $50/barrel for long enough to dispel any
optimism about the oil prices coming down to lower levels in
foreseeable future.
The import bill for crude oil has jumped to almost double of what it was a year
ago. Some analysts predict that oil peak is nearby and oil prices could touch
even $100/barrel mark. Even if one were not to be carried away by this doom's
day predictions, we need to face the facts of life with open eyes and guide the
country's energy policy to ensure that the happenings in the world oil market
does not succeed in derailing the juggernaut of Indian economy.

Geopolitical maneuvers to tie up h
igher quantities of oil and gas, acquisition of oil
and gas equity abroad and intensive exploration of oil and gas at home are
indeed welcome steps but not sufficient to ensure energy security and economic
robustness for India. A premium needs to be attach
ed to indigenous resource
exploitation of energy sources
-

not just oil and gas.

India's energy use is mostly based on fossil fuels. Although the country has
significant coal and hydro resource potential, it is relatively poor in oil and gas
resources. As
a result it has to depend on imports to meet its energy supplies.

Coal is the major fossil fuel in India and continues to play a pivotal role in the
energy sector. Present use of coal is inefficient and polluting. Hence there is
need for technologies for u
tilisation of coal efficiently and cleanly, substitution of
lesser reserves of oil and gas with abundantly available coal and prolonging the
reserves of all the fossil fuels for use of future generations. These requirements
can be met through application o
f coal gasification technology and following the
principle of sustainable development.

While thinking about the energy strategy of India, the role of coal cannot be
wished away however inconvenient it may be in terms of utilisation efficiency and
environme
nt. We have to devise technological solutions to make the most out of
the indigenous resource. Here we shall talk about technologies that can not only
augment indigenous energy resources, but also extract energy from coal in forms
that can replace the impo
rted oil and gas products. This would call for a major
change in the mind set of energy managers so that Companies previously seen
as coal producers are now seen as energy producers.

The prime technologies for achieving the objectives of replacement of liq
uid fuels
and substitution of natural gas would be:



CBM (Coal Bed Methane) Extraction



CMM (Coal Mine methane)/ AMM (Abandoned Mine Methane)/V AM

(ventilation Air Methane) capture and utilisation



UCG (Underground Coal Gasification)



IGCC (Integrated Gasif
ication Combined Cycle power generation)



CTL (Coal to Liquid)

CBM/ CMM/ AMM/VAM will provide gas in areas which are far away from gas
supply sources and thus expand the usage of clean fuel. Mine gas utilisation
schemes, therefore, significantly benefit t
he environment by:



Reducing greenhouse gas emissions as the carbon dioxide produced by
combustion is more than 20 times less harmful to the atmosphere than
methane



Displacing coal use in environmentally sensitive areas

UCG has the potential to virtually
eliminate methane emissions to the
atmosphere from coal seams whilst allowing the energy stored in the coal to be
recovered. UCG will help unearthing the unreachable indigenous resource and
substitute LNG import.

IGCC will provide a clean coal technology f
or power generation.

CTL will provide a way of substituting liquid fuels which are imported either in
form of crude or the products themselves. Especially, if UCG and GTL are
combined, it can provide energy security to India on a sustained basis by
satisfy
ing the largest user of energy
-

the transport sector. This along with
biodiesel has the potential of lending total energy independence to India.

Natural gas is being used for power generation in the country and it is rightly so
for accelerated growth of po
wer sector. There are plans for import of liquefied
natural gas (LNG) and naphtha etc. for power sector mostly by independent
power producers. This could be allowed as a short term measure as dictated by
the market forces. But as a medium to long term meas
ure the natural gas and
liquid fuels need to be replaced by coal gas.

The medium to long term targets can be: i) Replacing the natural gas with coal
gas in the existing combined cycle power plants ii) Establishment of advanced


power generation technologie
s based on coal gas Le., fuel cell. iii) Commercial
plants for coal to oil and coal refinery. iv) Self reliance and security in energy
sector v) Substitution of exhaustible with renewable energy sources.

Integrated Development of coal reserves



Ongoing mini
ng activities

1.

Continue mining in zone already opened for mining. Recover Methane gas
for vent and generate power.

2.

Coal mine methane recovery

3.

The zones which are yet to be opened, plan for full CBM recovery first ad
then open zones for mining

4.

UCG produc
tion from. "un mineable zones"



New mines yet to be opened

1.

First complete full CBM recovery

2.

Open mines for coal production

3.

UCG production from zones below mining range



Abandoned mines


1. Recover CBM from pillars, compartments by drilling wells

2. If C
oal seams are available below "mineable zone", evaluate
possibilities of UCG.



Coal seam below" mineable zone"

1.

CBM recovery

2.

UCG project

It can thus be seen that coal in solid form can continue to support power
generation and other applications, CBM can
supplement Natural Gas
requirements and through UCG route, syngas so generated can be used either
for power generation (IGCC) or for chemicals or liquid petroleum fuel for
transportation network.

As integrated development as proposed would make it imperati
ve that
exploration or oil and gas and exploitation of coal resources be carried in unison.
For example, in Cambay basis in Gujarat more than 4000 well have been drilled
for oil exploration / production. Many of these exploratory and development wells
were

dry and abandoned where coal seams were encountered. If petroleum /
coal activities were to be performed under "single" licence, UCG operation could
have started much sooner. As can be seen, exploration / exploitation of oil / gas
and coal are both techno
logically and geologically linked.


Policy initiatives for proposed development of coal fuels



Unified license for Coal, CBM and UCG production along with CO2
sequestration.



Unified license for Petroleum, CBM and UCG in those basins where
hydrocarbon (crud
e oil or natural gas) occurs in coal beds.



Incentives for CBM and UCG production as non
-
conventional energy
source and for emission reduction. Policy options to promote CBM and
UCG practiced by U.K., Australia and U.S. include market based
incentives, tax

breaks, feed
-
in tariffs, direct grants/ supports.



Optimization of energy mix apportioning full role for coal
-
fuels.





National awareness and the focus commensurate with importance of the
energy security need to be created.



Expediting the process of gran
ting licenses for remaining blocks for
exploration of CBM and UCG.



Supervisory agency to co
-
ordinate and promote integrated development of
all coal fuels.

Introduction


It is very aptly propounded that: "Sustainable development aims to promote
economic g
rowth, efficient use of natural resources and their secured long term
supply and protection of environment to ensure survival of the future
generations."

India is tipped to be a rapidly growing economy heading towards occupying 3rd
place in the world. Howe
ver, it needs to be remembered that the growth of
economy is dependent upon a crucial assumption that requisite amount of
energy will be available at a price that does not adversely affect the
competitiveness of the nation's industry and service sector.

Pr
oper attention needs to be paid to the fragility of this crucial assumption in view
of the current events and what is expected in the future. The oil prices have
hovered around $50/barrel for long enough to dispel any optimism about the oil
prices coming d
own to lower levels in foreseeable future. The import bill for crude
oil has jumped to almost double of what it was a year ago. Some analysts predict
that oil peak is nearby and oil prices could touch even $100/barrel mark. Even if
one were not to be carri
ed away by this doom's day predictions, we need to face
the facts of life with open eyes and guide the country's energy policy to ensure
that the happenings in the world oil market does not succeed in derailing the
juggernaut of Indian economy. Geopolitica
l maneuvers to tie up higher quantities
of oil and gas, acquisition of oil and gas equity abroad and intensive exploration
of oil and gas at home are indeed welcome steps but not sufficient to ensure
energy security and economic robustness for India. A pre
mium needs to be
attached to indigenous resource exploitation of energy sources
-

not just oil and
gas.

With a gross domestic product (GDP) growth of 8 per cent set for the Tenth Five
Year Plan (2002
-
07), the energy demand is expected to grow at 5.2 per cen
t.
India's incremental energy demand for the next decade is projected to be among
the highest in the world, spurred by sustained economic growth, rise in income
levels and increased availability of goods and services.

The projected requirement of commercia
l energy is estimated at about 412
MTOE and 554 MTOE respectively in 2007 and 2012; the commercial energy
demand is estimated to grow at an average rate of 6.6 per cent and 6.1 per cent
respectively during the period 2002
-
07 and 2007
-
12. However, the deman
d may
be less by 5 per cent and 10 per cent during 2006
-
07 and 2011
-
12 respectively
due to increasing use of information technology (IT) and prevalence of e
-
Commerce, which will mainly affect the demand of energy in transport sector.

Estimated Energy Deman
d in India based on extrapolation of "Business as
Usual" scenario as reported by Asean India Business Portal website report is:



Primary

Unit

Demand in (Original Units)

Demand (MTOE)





2006
-
07

2011
-
12

2006
-
07

2011
-
12

Coal

Mt

460.50

620.00

190.00

254.9
3

Lignite

Mt

57.79

81.54

15.51

22.05

Oil

Mt

134.50

172.47

144.58

185.40

Natural Gas

BCM

47.45

64.00

42.70

57.60

Hydro Power

BKwh

148.08

215.66

12.73

18.54

Nuclear Power

BKwh

23.15

54.74

6.04

14.16

Wind

BKwh

4.00

11.62

0.35

1.00

Power











Tota
l Commercial Energy







411.91

553.68

Non
-
Commercial Energy







151.30

170.25

Total Energy Demand







563.21

723.93


India's energy use is mostly based on fossil fuels. Although the country has
significant coal and hydro resource potential, it is
relatively poor in oil and gas
resources. As a result it has to depend on imports to meet its energy supplies.
The geographical distribution of available primary commercial energy sources in
the country is quite skewed, with 77 per cent of the hydro potent
ial located in the
northern and north
-
eastern region of the country. Similarly, about 70 per cent of
the total coal reserves are located in the eastern region while most of the
hydrocarbon reserves lie in the west.

As per current projections, India's depen
dence on oil imports is expected to
increase. The demand of natural gas also outpaces supply and efforts are being
made to import natural gas in the form of liquefied natural gas (LNG) and piped
gas. If the present trend continues, India's oil import depen
dency is likely to grow
beyond the current level of 70 per cent.

The success of liberalization policy and economic reforms introduced in the
country is largely dependent on adequate availability of energy resources at
affordable prices and oil has a signif
icant place in it. Therefore any disruptions in
oil supplies would hamper progress of the country. Thus from consideration of
national self reliance, security and assured energy supply, production of oil in
India from alternate source i.e. coal is justifie
d.

Coal is the major fossil fuel in India and continues to playa pivotal role in the
energy sector. Oil and natural gas are very limited hence India is a net importer
of hydrocarbons. India is heavily dependent on oil imports and the trend is likely
to rem
ain same. Economic growth of the country is tied up with regular supply of
oil and any disruptions could drastically arrest the growth. Oil imports are a drain
on foreign exchange reserves since they constitute about 26% of import bill.
More and more of na
tural gas is being used for power generation leaving lesser
allocations for fertilisers and chemicals etc where it is essential and convenient.
Indian coals in general are of inferior quality.

Present use of coal is inefficient and polluting. Hence there i
s need for
technologies for utilisation of coals efficiently and cleanly, substitution of lesser
reserves of oil and gas with abundantly available coals and prolonging the
reserves of all the fossil fuels for use of future generations. These requirements
c
an be met through application of coal gasification technology and following the
principle of sustainable development.

While thinking about the energy strategy of India, the role of coal cannot he
wished away however inconvenient it may be in terms of utili
sation efficiency and
environment. We have to devise technological solutions to make the most out of
the indigenous resource. Here we shall talk about technologies that can not only
augment indigenous energy resources, but also extract energy from coal in
forms
that can replace the imported oil and gas products. This would call for a major
change in the mind set of energy managers so that Companies previously
-
seen
as coal producers are now seen as energy producers.

The prime technologies for achieving the
objectives of replacement of liquid fuels
and substitution of natural gas would be:



CBM (Coal Bed Methane) Extraction



CMM (Coal Mine methane)/ AMM (Abandoned Mine Methane)/VAM

(ventilation Air Methane) capture and utilisation



UCG (Underground Coal Gasifi
cation)




CTL (Coal to Liquid)

CBM/CMM/ AMM/VAM will provide gas in areas which are far away from gas
supply sources and thus expand the usage of clean fuel. Mine gas utilisation
schemes, therefore, significantly benefit the environment by:



Reducing green
house gas emissions as the carbon dioxide produced by
combustion is more than 20 times less harmful to the atmosphere than
methane



Displacing coal use in environmentally sensitive areas

UCG has the potential to virtually eliminate methane emissions to th
e
atmosphere from coal seams whilst allowing the energy stored in the coal to be
recovered. UCG will help unearthing the unreachable indigenous resource and
substitute LNG import.

IGCC will provide a clean coal technology for power generation.

CTL will pro
vide a way of substituting liquid fuels which are imported either in
form of crude or the products themselves. Especially, if UCG and GTL are
combined, it can provide energy security to India on a sustained basis by


satisfying the largest user of energy
-

the transport sector. This along with
biodiesel has the potential of lending total energy independence to India.

India's Energy Puzzle

As per the available estimates, India's 2020 consumption of energy is expected
co be somewhere approximately 800 Mtre. To

realise the target, each segment
of the value chain needs two and half times growth between now and 2020 thus
calling for massive investments in infrastructure creation on grand scale through
efforts from public, private sector and joint partnerships. The

investments would
also need the policy makers to work towards creating an environment with
appropriate policy, legislative and regulatory framework.

Considering the limited reserve potentiality of petroleum & natural gas, eco
-
conservation restriction on h
ydel project and geo
-
political perception 'of nuclear
power, coal will continue to occupy centre
-
stage of India's energy scenario.

All energy sources need to be explored and exploited to the hilt while determining
optimum fuel mix with options of coal, oil
, gas, hydel, renewables and nuclear.

It is essential to understand internalization of environment cost imposed by
different forms of energy and what this means for energy choices to be made
keeping the long
-
term perspective in mind.

For India to join the
league of developed nations, we must ensure that the power
is produced at affordable rates and competition is introduced in the sector to
enhance efficiency, consumer responsiveness and reduced prices.

Keeping electricity prices affordable and competitive
internationally, will depend
on the price of fuel viz. coal, oil product or gas as fuel constitutes 60% of the cost
of gas.

India has relatively large reserves of coal (250 billion tonnes) compared to crude
oil (728 million tonnes) and natural gas (686 bil
lion cubic meters). Coal meets
about 60% of the commercial energy needs and about 70% of the electricity
produced in India comes from coal.

Advanced technologies when applied to Indian coal resources, can improve the
efficiency and minimize environmental i
mpacts of coal utilisation. A balance is
necessary between short term imperatives and long term possibilities to enable
sustainable development. To pursue such a strategy technologies are available
and are also under development.

Since reserves of oil and
natural gas are meager, they need to be substituted
with coal to the extent feasible. At the same time all the three fuels, especially
coal needs to be conserved for the future generations. The energy sector
requires


efficient, clean and dependable energy

supplies. Hence coal has to be
utilized with multi pronged strategy i.e. higher efficiency, environmental
acceptance, prolonging its availability and as replacement for oil etc. which is
possible only through sustainable development by use of modern techn
ologies.

If the gaseous form of fuels could be obtained on a large scale from mineable
and unmineable coal resources the versatility of coal as a fuel resource could be
greatly enhanced. The major advantage of gasification is that coal is converted
into a
gaseous fuel which is easy to handle and is a clean form of energy. In the
gaseous form it enables substitution of petroleum products and natural gas. The
synthesis gas has wide range of applications. It can be used in a combined cycle
system for efficient

and clean generation of electric power. It is suitable for the
manufacturing of hydrogen and chemicals such as ammonia, methanol, acetic
acid; as substitute natural gas, and as a reducing gas for metallurgical purposes
etc. It can be used in multipurpose
plants for the simultaneous production of
electric power, chemicals/ fertilisers and fuels which also improve the economics
of coal gasification.

India's Coal Resources


India is endowed with rich deposits of coal and lignite in different sedimentary
basin
s of varying dimensions. The bulk of the coal resource of 235 billion tonnes
is contained in older basins like the Gondwana basin. Large lignite deposits of
100 billion tonnes occur in younger basins of Gujarat, Rajasthan and Tamil Nadu.
A characteristic f
eature of these basins is the development of very thick coal and
lignite seams (20
-
80m) over a large stretch of the coal/lignite fields. In fact, one
of the thickest seams (138m) of the world is in Indian coal fields.

The present updated total coal resourc
es of the country as per the latest national
inventory as on 1.1.2004 is 2,45,692.42 million tonne for coal seams of 0.9m and
above in thickness and upto 1200m depth from surface. The inventory is based
on sub
-
surface data accrued from regional (including
promotional) and detailed
drilling carried out by GSI, CMPDI, SCCL and MECL. Out of the total resources,
Gondwana coalfields contribute 2, 44,785.47 million tonne while the Tertiary
coalfields account 906.95 million tonne.

The depth
-
wise breakup of the tot
al resource reveals that about 65.6% of coal
resource are confined within 0
-
300m depth level in which maximum share comes
from Orissa (43.9 bt), followed by Jharkhand (36.1 bt) excluding Jharia coalfield,

Chhattisgarh (31.4 bt), West Bengal (12.3 bt) and o
thers. Resources available
within 300
-
600m and 600
-
1200m depth ranges are 61836.31mt and 17882.30mt
respectively. In addition, there occur 14212.42 mt of resource in Jharia coalfield
confined to 0
-
600m depth.

TECHNOLOGY
-
WISE COAL PRODUCTION

Depth
-
Wise Coa
l Reserves in India

(Billion Tonnes As on 01/01/2003)

Depth Range

Proved

Indicated

Inferred

Total

% Share

0
-
300m

68.6

64.5

15.6

148.7

62

300
-
600m

6.1

37

16.8

60

25

0
-
600m (JFCF)

13.7

0.5

0

14.2

6

600
-
1200M

1.7

10.5

5.6

17.8

7

Total

90

113.6

38

240.7

1
00

% Share

37

47

16

100



Demand & Availability of Raw Coal

Year

Demand

Availability

Gap

2003
-
04

381

351

30

2006
-
07

461

405

56

2011
-
12

620

515

105

Underground production of coal peaked in the late seventies and has fallen
slowly since then. Surface
mining, on the other hand, has soared from16 to 160
million tonnes per annum. Of the 588 mines in India, 355 are under
-
ground, but
opencast accounts for 75 percent of production and employs only 16 percent of
the total mining work force. Productivity is hi
gher in the opencast sector.

Almost 80% of today's coal comes from surface strip mines (opencast mines),
which is much safer.

The above estimates do not show large reserves of deep seated coal in Gujarat.

Coalbed Methane potential of India

Indian's coals h
ave gas content values ranging from 1 to 23 m
3
/ tonne.

The CBM resources as per Directorate General of Hydrocarbons (DGH), Ministry
of Petroleum & Natural Gas (MoP&NG) is tabulated here under:

Table Prognosticated Resource of CBM

S.No.

State

Coal
field/Bl
ock

Area of
delineated
block (Sq.
KM)

Prognosticated
CBM Resource
as per DGH

Remarks

1

West
Bengal





In trillion
cubic
feet

In
billion
cubic
meter

Marginal
resource may
be in
Jharkhand

North
Raniganj

232

1.030

29.17

Eastern
Raniganj

500

1.850

52
.38

Birbhum

250

1.000

28.32

Sub Total

982

3.88

109.87



2

Jharkhand

Jharia

69.20





East &
West
Bokaro

93.37





North
aranpura

340.54





Sub Total


503.11

6.178

174.93



3

Madhya
Pradesh

Sohagpur

495

3.030

85.79





Sohagpur

500









Satpura

500

1.000

28.32

4

Gujarat

Cambay
Basin

2400
-
3218*

11* to
19.4

311*
-
549.39

May not be
immediately
availabl3e
because
ONGC has
active
conventional
Oil& Gas
operations.


*As per
Advanced
Resources
Inc.

Grand
Total





2980.11
-

3798.11

25.088
-

33.488

710.39

948.73



In India, the Reliance Gas has carried out comprehensive geologic assessment
of coal/lignite basins based on which about 20,000 km
2
of area has been
identified as prospective for CBM with estimated in place resource of about
20,00
0 billion cubic metres. The recoverable reserve of about 800 billion cubic
metres and gas production potential of about 105 million metre cum per day over
a period of 20 years has been estimated. CBM potential is thus about 1.5 times
the present natural ga
s production in India, which is capable of generating about
19000 MW of electricity. The potential of gas production in India is given in Table
below:

CBM production potential in India

CBM
Prospects

Ref.No.

CBM Production
Potential

Energy
Equivalent

Basin
/Area

(million cubic
metres/day)

Power
Gen.,
(MW)

LNG
(MMtpa)

Cambay
Basin









North Gujarat

15

30

5500

7.50

Barmer Basin









South
Rajasthan

16

19

3500

4.75

Damodar
Basin









Raniganj

3

12

2200

300

Jharia

4

3.5

650

1.00

East Bokaro

5

2.5

450

0.60

North
Karanpura

6

6.0

1100

1.50

Rajmahal
Basin









Rajmahal

1

4.5

800

1.20

Birbhum

2

6.0

1100

1.50

Others









Singrauli

7

1.0

180

0.25

Sohagpur

8

4.0

720

1.00

Satpura

9

1.5

270

0.40

Jb
-
River

10

5.0

900

1.25

Talcher

11

2.5

45
0

0.60

Wardha Valley

12

1.5

270

0.40

Godavari
Valley

13

4.0

720

1.00

Cauvry Basin

14

2.5

450

0.60

All India

1
-
16

105.5

19260

26.55

(Source: Coal bed Methane: A Survey by Reliance Gas (P) Limited)

A resource assessment undertaken by Dominion Energy/Adv
isors (USA)
estimates the CBM resources at 30 trillion cubic feet or 850 bn cubic meters.

Reliance Industries Ltd has discovered reserves of 3.76 trillion cubic feet (TCF)
of coal bed methane gas at one of its blocks in Madhya Pradesh.

Essar has already dr
illed three wells to a depth of 1450 metres and is producing
the gas experimentally.

Neyveli Lignite Corporation (NLC) proposes to taken up a Underground Coal
Gasification (UCG) project in a suitable lignite block in Rajasthan under Ministry
of Coal's S&T
programme and Department of Science & Technology funding at a
total cost of Rs.1,125 lakhs part of a joint venture project with Coal India Limited
(CIL). Great Eastern Energy Corporation Limited (GEECL) and Essar are also
involved in initial field studies
in Raniganj South and Gujarat respectively.

The coal occurs in the Lower Gondwana (Permian) coal
-
bearing Karharbari/
Barakar and Raniganj formations where there can be in excess of 100m of total
coal thickness. The Barakar formation contains some 50 coal s
eams that are
greater than l.5m thick whilst the Raniganj formation includes 10 seams ranging
from 1m to 11m thick. The Damodar Valley basin is the most heavily mined area
in India containing high rank, gassy coal. It is suggested that based on these
chara
cteristics Jharia, Bokaro, North Karanpura, and the Raniganj coalfields
should be the primary targets for CBM development.

Test results for the Barakar coals in the Jharia coalfield report the majority of gas
contents to be between 7 and 17m3/t (dry ash fr
ee). The results indicate the gas
content increases uniformly with the depth of coal.

A number of encouraging factors are reported:



Average cumulative coal thickness (surface to 1200m) in the order of 90m




measured gas content of between 7 and 17m3/t



Gas

content and langmuir isotherm data suggest coal near to 100% gas
saturation



Results from test wells show gas flows of 1000
-
2000 m3/ d from a single
seam at depth



average gas production from a single test well (5 coal seams farce) of
6500m
3
/ d over a 1.5

year period (production testing continuing) with an
initial maximum gas flow of 23,000m3/ d, and cumulative gas flow of 7
million m3



Water production of about 6m3/ d, which has been shown to be of a good
quality suitable for agricultural use and also rec
ycling for field operations



local market for CBM for power generation with a larger market identified
within 30km.

The main Gondwana coal basins are rifted intra
-
cratonic grabens having thick
sequence of coal seams, and hold considerable prospects for co
al bed methane.
The major part of Indian Gondwana coals (mostly up to 300 m depth) is of low
rank, far below the threshold value of thermogenic methane generation.
However, high rank coals, amenable for generation of coal bed methane, mostly
occur in untap
ped deeper parts of basins covered by younger sediments.

Tertiary coals in petroliferous basins of Cambay, Upper Assam and Assam
-
Arakan may be prospective due to reported higher gas content, which is probably
stored in the coal after generation from deeper
-
lying hydrocarbon source beds or
may be of biogenic origin.

Government of India has awarded 16 CBM blocks for exploration and production
of Coal Bed Methane in different coal fields of India. The commercial production
of CBM from few of these awarded bloc
ks may start by 2006
-
07. These blocks
may yield a peak production of about 23 MMSCMD of CBM in the country.

CMM/AMM/VAM

An initial review of historic mining practices in India and discussions with CIL and
others would indicate few opportunities exist for A
MM development. This is due
to the relatively shallow depth of mining, low gas contents and use of non
caving
methods of underground coal mining (board and pillar). However, if longwall
mining expands, the potential application of AMM could increase in the

medium
to long term.

Methane emission studies from working mines of India reported most of the
degree three gassy mines (10 cubic m/ton), are confined in the four Damodar
Valley coal fields, viz. Raniganj, Jharia, Bokaro and North Karanpura in Bihar and
W
est Bengal. In these areas, the thickest bituminous coals are extensively
developed in the Barakar measurers and in Raniganj measures of Lower and
Upper Permian age, respectively. The Barakar coal seams are superior to
Raniganj coal seams as coal bed metha
ne targets. Based on thickness and
burial depth, rank and quality of coal has the greatest coalbed methane potential
in India.

Therefore, until deeper, gassier seams are tapped, India's potential for profitable
VAM oxidation projects will remain modest at
best. Singh (2001b) states that 66
percent of the underground mines emit less than 1 m3 per tonne of coal
produced, 27 percent of underground mines emit from 1 to 10 m3 per tonne, and
the remaining mines (7 percent) emit over 10 m3.

In India, underground c
oal production currently comprises approximately 25
percent of total production, and annual tonnage of underground coal produced
there has remained essentially steady over the past two decades (World Coal,
1999). Singh (2001a) observes India's trend toward

a decrease in the share of
underground coal production. That trend, however, appears to derive primarily
from a dramatic increase in surface production in recent years rather than from a
drop in absolute production from underground mines (World Coal, 1999
). The
coal seams currently being exploited are not particularly gassy, and methane
concentrations in ventilation airflows even at the gassiest mines are low, typically
below 0.3 percent.

Altering the Role of Coal in India's Energy Basket


Coal remains Ind
ia's principal source for meeting its primary and secondary
commercial energy requirements. Of the I, 04,917.50 MW of overall installed


power generation capacity in the country (as on 31 March 2002,) about 59,386
MW is coal based and 2,745 MW is lignite b
ased, totaling to 62,131 MW or 59
per cent.

Indigenous coal is likely to remain the most stable and least cost option for the
bulk of India's energy needs in the foreseeable future. This is so because coal
based thermal power generation capacity has a shor
ter gestation period and
lower specific investment costs when compared to other locally available
commercial energy resources like nuclear or hydropower. Thus, there is need for
concerted efforts for the overall developments of the sector in future Plans.
Energy security concerns underscore the need to further develop indigenous coal
production in the foreseeable future.

When technologies like CBM, CMM, AMM, VAM and UCG are employed in
conjunction with CTL technology the reach of coal based fuels will be wi
dened to
cover even transport fuels and substitution of natural gas which are both
imported and weigh heavily on the trade balance for the country. Apart from this
these technologies will harness those fuel resources which are hitherto
considered unreachab
le/ unusable.

Methane is a natural product arising out of the decay of organic matter and as
coal deposits were formed with increasing depths of burial and rising
temperatures and pressures over geological time, a proportion of the methane
produced was ads
orbed by the coal. Whereas in a natural gas reservoir such as
sandstone the gas is held in the void spaces within the rock, methane in coal is
retained on the surface of the coal within the micropore structure. Such
adsorption is maintained by the lithosta
tic and hydrostatic pressures. The release
of these pressures allow methane to escape from the coal. The presence of
significant amounts of methane in coal is familiar to coal miners as the gas is
released due to the relaxation of pressure and fracturing o
f the strata during
mining activity, and can give rise to serious safety concerns if not managed
properly. Many explosions have occurred over the years leading to tile
development of "methane drainage" where the gas is drained from the strata by
pumping fr
om boreholes drilled above the working face. This practise often
yielded significant quantities of methane, which was on occasion used to fire the
colliery boilers.

Methane. build
-
up in coal mines has caused many mine explosions, killing
thousands of miner
s worldwide. In gassy mining conditions, creating a safe work
environment requires that coal mining companies develop practices that allow
them to assess the amount of gas that will be liberated during the mining
process, and determine the best way to remo
ve the gas from the mine. No matter
whether the gas is drained from the seam or adjoining strata in advance of
mining or from the gob, the purpose is the same: remove enough gas from the
mine so that the ventilation system can dilute the remaining gas that

will be
emitted into the mine to acceptable levels. Gas drainage systems are often not
designed with the goal of optimizing gas recovery because of budget constraints
and the overriding concerns of safety. Furthermore, for the same reasons, data
available

to the investigator for assessing the potential of developing a
commercial coal mine methane resource estimate may be limited.

Successful development of a coalmine methane project requires a thorough
understanding of the size and production potential of
the gas resource. The coal
mine methane resource comprises the volume of gas distributed throughout the
coal and surrounding strata, often referred to as gas
-
in place.

100% recovery of the gas
-
in
-
place is virtually impossible. Tec1znically
recoverable coal

mine methane resources is the quantity of gas that is
recoverable by utilizing proven modes of extraction while employing existing
technology. The commercially extractable portion of the technically recoverable
resources is the resen1es. A developer's est
imate of reserves will vary
depending on assumptions regarding the technology used for recovery and
changes that may take place in future economic conditions.


The methane continues to emit from the mine after closure, and recently the
concept of collectin
g the gas from abandoned mines to provide an energy source
which would otherwise be waste has been developed. The concept is generally
referred to as Coal Mine Methane (CMM)

The amount of methane in a coal bed depends on the quality and depth of the
coal d
eposit. In general, the higher the energy value of the coal and the deeper
the coal bed beneath the surface
-

resulting in more pressure from overlying rock
formations
-

the more methane the deposit holds. Coal stores six to seven times
more gas than the e
quivalent rock volume of a conventional gas reservoir.

Many mining companies will pre
-
drill to allow some of this gas to escape, but as
the mining operation grows, new long walls are constructed. When coal is
extracted and the wall moved, gas escapes from
the now
-
collapsing roof. Gas
pockets could also be disrupted above and below the coal seam, something that
must be monitored and measured.

All underground coalmines employ ventilation systems to ensure that methane
levels remain within safe concentrations.

These systems can exhaust significant
amounts of methane to the atmosphere in low concentrations.

There are three things to consider in this process:



They want to drain the coalmine methane for mine safety and efficiency;




They want to sell the gas as f
uel and feedstock;



And, they want to certify that it qualifies for greenhouse gas emissions
reductions.



Methane from coal beds can be recovered from coal seams by:



Draining gas from working coal mines



Extracting gas from abandoned coal mines



Producing

gas from unmined (virgin) coal using surface boreholes

Mine gas utilisation schemes are encouraged by governments and international
agencies that recognise the energy benefits of a waste material and the net
reductions in greenhouse gas emissions achieva
ble. Virgin CBM production
schemes, which are independent of mining, contribute indirectly to a reduction in
greenhouse emissions by replacing coal burning.

CBM


Coalbed methane is located wherever coal is found.

Only a small percentage of these resources
can be recovered with current
technology, and a still smaller percentage can be recovered profitably.

Gas can be produced from coals of nearly every rank; however, some of the less
attractive coals (e.g., lignite) may require substantial thicknesses of coa
l to
develop adequate reserves.

A typical one
-
foot thickness of coal six hundred feet deep is capable of
containing as much gas as a typical sandstone reservoir five thousand feet deep.
Another unique characteristic of coalbed production is its producing b
ehavior. In
most cases, initial production of gas is quite low while water production may be
high. As the water is withdrawn, and the bottom
-
hole pressure decreases in the
reservoir near the well bore, gas production gradually increases. During the first
f
ew producing months the water
-
producing rate will continue to decrease
accompanied by an increase in the gas
-
producing rate, until a pseudo
-
steady
state occurs for both phases.

Water pressure holds methane in the coal bed. To release the gas, its partial
p
ressure must be reduced by removing water from the coal beds. Once the
pressure is lowered, the gas and water move through the coal bed and up the
wells.

At first, coalbed methane wells produce mostly water, but over time, the amount
of water declines and
gas production rises as the bed is dewatered. Water
removal may continue for several years. The water is usually discharged on the
surface or injected into aquifers.

Whether a coalbed will produce commercial quantities of methane gas depends
on the coal qu
ality, its content of natural gas per ton of coal, the thickness of the
coal bed (s), the reservoir pressure and the natural fractures and permeability of
the coal. CBM is generally more pure right out of the ground when compared with
conventional natural
gas reservoirs.

CBM is recovered from virgin coal (for this reason it is sometimes referred to as
VCBM) by releasing the gas located both within the coal and adsorbed onto the
surface of the coal. Coal seams are injected with a high pressure water, foam
an
d sand mix. The high pressure fractures the coal for some distance around the
borehole. The sand holds the fractures open, enabling the water and gas to flow
to the well bore and hence to the surface.

CBM offers a method of extracting methane from unworked

coal without
detrimentally affecting the physical properties of the coal. This provides many
benefits:



When carried out on its own it facilitates exploitation of the coal resource
in areas where the coal would be unlikely to be worked by traditional
minin
g methods.



As the coal remains in the ground there is no surface subsidence.



Alternatively it facilitates extraction of gas from coal seams prior to mining
the coal thus reducing the potentially dangerous methane gas prior to
carrying out traditional min
ing methods.



Methane quality is such that it has the potential to be fed directly into the
gas distribution network. This is one distinct difference with CMM which
has higher carbon dioxide content and so is not suitable for direct
introduction.

Coal bed

methane development is accompanied by a number of environmental
problems and human health hazards.

1. Disposal of water removed from coal bed methane wells

CBM produced water may have high concentrations of dissolved salts and other
solids. Water discharg
es may flood the property of landowners, causing erosion
and damaging soils and plants. Coalbed methane water in Montana, USA has an
average sodium adsorption ratio of 47, over 30 times the level that can damage
soils, causing crop yields to decline.

2. Dr
inking water levels drop in surrounding areas. The level of some drinking
water wells near coalbed methane development has dropped as water has been
removed from coal beds.

3. Contamination of aquifers Contamination of aquifers (or groundwater) from
coalbe
d methane development represents another environmental problem. There
is' some evidence that natural gas can migrate up through vertical fissures and
contaminate overlying aquifers.

4. Venting and seeping of methane and other chemicals

In the San Juan Basi
n, USA methane gas is seeping up in fields, forests and
rivers. Methane seeps. often have companion "dead zones"' where methane
-
saturated soils have starved the roots of vegetation, killing some trees nearly 100
years old. High levels of methane asphyxiate

rodents in burrows near seeps.
While such seeps are not new, they appear to be more frequent and severe
since the advent of coalbed methane, development. Some scientists and
residents believe that coalbed methane development is aggravating the problem.

Me
thane seeping into drinking water wells and under people's homes has caused
a health hazard. On the Pine River near Bayfield, Colorado, Amoco bought out
and relocated several families because of high levels of methane present in their
basements and drinkin
g water. Other chemicals may vent following coalbed
methane development, including carbon dioxide and hydrogen sulfide.

5. Underground fires

Underground fires plague coal
-
rich areas. They often strike where extensive
mining has occurred, because shafts and

tunnels help circulate the oxygen
needed for coal to burn below the earth's surface. Coalbed methane
development can exacerbate this problem when water is removed to release the
gas and oxygen gets in. Two underground coal fires are burning on the Souther
n
Ute Reservation in southwest Colorado in an area where coalbed methane has
been extracted. In June 2002, an underground coal fire in Glenwood Springs,
Colorado sparked a month
-
long wildfire in the area that destroyed people's
homes and property.

6. Destr
uction of land and harm to wildlife

The wells are then connected with pipelines, compressor stations and roads,
leaving scars on the land that will last for decades. Wildlife habitat is fragmented,
and migration corridors are disrupted. High road densities

and the constant
vehicular traffic needed to monitor and maintain wells and pipelines are
especially disruptive to wildlife.

CBM Produced Water

Coalbed methane produced water often has high sodium adsorption ratio (SAR)
values
-
the ratio of sodium, calciu
m and magnesium concentrations
-

high
concentrations of metals
-

iron, manganese and barium
-

and variable salt
content. These minerals may affect soil permeability or be toxic to certain plant
species. Ideal conditions for CBM produced water for irrigatio
n are areas with
coarse
-
textured soil and salt
-
tolerant crops.

Native high salt tolerant grasses and forbs can be planted around impoundments
and discharge sites to maximize the use of CBM produced water and reduce
erosion, as well as being used in bioreme
diation of brine contaminated soils.

Economics of CBM production depend on reducing the cost of handling produced
water. Beneficial uses for produced water offer the best alternative to high
-
cost
re
-
injection procedures.

Various treatment or pretreatment a
pplications may be necessary before
produced water can be funneled for alternative uses.

Alternatives to re
-
injection of CBM produced water fall in five main categories:
water impoundments for stock and wildlife, irrigation, surface discharge, and
recreati
onal and industrial uses.

Water management options for CBM produced water include use in the
operational activities of industries in the producing region. Common industrial
uses include coal mines, animal feedlots, cooling towers, car washes, enhanced
oil
recovery and fire protection.

CMM/AMM

Coal mining releases the gases naturally occurring in coal seams. The methane
flow from the mine workings depends on the gas content of the coal seams,
thickness and distance of adjacent coal seams from the worked seam
s and the
method and rate of mining. Atmospheric emissions can be reduced by capturing
a proportion of the gas before it enters mine airways, piping it to the surface and
using it as fuel gas or as a chemical feedstock.

CMM drainage technologies only captu
re a proportion of the gas released into
mine workings. Captures achieved in individual mining panels can typically range
from 30% to 80% depending on the drainage technology used, the geology and
the mining conditions.

Coal mine methane is produced as a r
esult of the fracturing of coal and coal
measures strata as part of historical and current mining operations releasing the
methane which had been adsorbed within it.

However, the commercial exploitation of methane has the potential, now well
proven, of har
nessing the gas safely and beneficially to generate electricity and
can provide considerable benefits:



An uncontrolled danger and potential surface hazard to individuals and
property is harnessed and greatly reduced if not removed.



Harmful ventilation to
the atmosphere is reduced with a significant
reduction of greenhouse gas emissions.



Electricity available to local users, especially in cases where former
colliery sites are developed for industry and commerce.

The coal mining industry has made good prog
ress in delivering high
-
grade CMM
to natural gas markets. Using gob gas has proven more challenging, although
pioneers in the coal, gas, and power industries also have identified several
potentially beneficial gob gas uses, as listed below.



Fuel for coal d
ryers and
-
other gas
-
fueled mine equipment.



Fuel for electricity production.



Feedstock for gas enrichment systems that upgrade the gas to pipeline
quality.



Supplemental fuel for industrial and utility boilers (delivered in dedicated
pipelines).

Since go
b gas (as well as any medium
-

to high
-
quality methane) may be cofired
with the primary fuel in a variety of existing combustion units including boilers,
furnaces, and kilns, it can partially replace common fuels (e.g. coal, oil, and
natural gas). The fuel
that cofired gob gas replaces is referred to herein as
"avoided" fuel. Cofiring gob gas, as explained in the next section, can provide
greater value to the buyer than that of the avoided (replaced) primary fuel. This
report refers to an "enhanced" gob gas


value which is the sum of the avoided
fuel plus associated environmental and operational benefits.

Environmental Benefits

The most important and valuable environmental benefits can be achieved by
cofiring gob gas in quantities that are small as compared w
ith total boiler heat
(Glickert 1997). The benefits include reductions in NOx, SOx, and particulates
(opacity):

NOx Reduction. When properly configured and optimized, gob gas cofiring may
be able to reduce NOx emissions from the entire boiler.

SOx Reducti
on. Cofiring methane reduces SOx emissions.

Reduced Opacity. Utilities may be able to use gas to reduce stack opacity and
thereby avoid plant derating.

Operational Benefits

Improved Ash Quality. If a utility intends to sell its ash to the concrete industry

to
avoid high disposal costs, gob gas cofiring may enhance this possibility by
reducing carbon levels in the ash to saleable limits.

Utilities sometimes experience sparking problems in their electrostatic
precipitators. Studies show that gas cofiring may
mitigate the condition.

Derate Mitigation. H coal processing equipment inadequacies limit a boiler (either
during pulverizer or feeder outages or because the plant has been forced to use
low sulfur coal that contains less heat per pound), gob gas use may m
itigate the
derating condition by allowing more fuel to enter the boiler.

Rating Increase. In some cases, a boiler's operating limit may be driven by its
forced draft fan rating, even though it may not have reached its total heat release
capacity. In this
event, the operator may be able to cofire small increments of gob
gas without backing off the coal feed
-

thus ending up with an increased plant
rating.

Lower Turndown. If a boiler can rely primarily on gas during periods of low
demand, the minimum operati
ng load can be reduced by almost half of its coal
-
fired minimum (e.g. from 45 to 25 percent of


full load). Having lower turndowns
will result in fewer shutdowns and reduced boiler start
-
up costs. Not only does
gas retain its flame stability at low loads,
its heat rate is much better than coal in
this range. To gain this benefit, however, the boiler operator must have access to
larger gas flows than are typically available from a gob gas project.

Reduction of Slag Buildup. Some utilities have fired gas in c
oal boilers for short
periods or continuously to remove harmful slag deposits. This removal strategy is
much less expensive than shutting the boiler down and mechanically removing
the deposits. As with the improved turndown ratio described above, however,
an
operator must have access to an adequate gas supply.

The following two benefits are intangible and probably minor:

Increased Efficiency (Lower Heat Rate). Methane often burns in large coal
boilers with somewhat better combustion characteristics than th
e coal itself. This
results in a small efficiency gain that is partially offset by the need to evaporate
the water formed during methane combustion and the fact that the boilers were
built to maximize radiant heat transfer from coal and not gas.

Reduced O&
M Costs. There are many ancillary systems operating in a coal
fired
boiler that process, handle, and transport coal, as well as remove coal ash.

Theoretically, these systems will cost less to operate and maintain when gas is
fired as a partial substitute f
or coal because they are handling less coal.

CO2 Sequesterisation and CMM production

CO2 is preferentially adsorbed on coal, relative to methane and nitrogen.
Therefore, if CO2 is injected into an abandoned coal mine, the CO2 will displace
adsorbed methane
. Injection and subsequent adsorption of CO2 onto the carbon
contained in the coal remaining within and peripheral to an abandoned coal mine
will trap the CO2, effectively sequestering it from the atmosphere and thereby
reduce the amount of this greenhouse

gas (GHG) in the atmosphere.

Physical determinants for the effectiveness of this process are the adsorptive
capacity of the coal for the gases, the permeability of the coal, the amount of coal
exposed to the CO2, and the pressure at which the mine can hol
d the gas. The
economic feasibility of the envisioned project is determined by the unit cost of the
C02 sequestered versus the value of the greenhouse gas (GHG) reduction
credits that could be generated.

Abandoned coal mines could also be used as a carbon
sink because CO2 has
an affinity for adsorbing to coal, that is greater than methane, and will effectively
displace the methane molecules from the adsorption sites within the micro pore
structure of the coal. The advantages of injection into an abandoned c
oal mine
versus an unmined coal bed are identified below:

The large exposed surface area in the mine workings will facilitate the adsorption
of the CO2;

The mining process enhances fracturing of the coal and therefore the
permeability to the flow of gas in
to the unmined perimeter as well as into the coal
remaining as pillars;

The water saturation of the coal near the mine workings will be low because the
mining activity. has lowered the pressure and drained the water, facilitating
movement of gas into the c
oal; and

The injection pressure will be low, so the cost of compression will be low.

The following parameters are significant in determining the C02 storage capacity
of a mine:

The size of the mine workings;

The thickness of the coal;

The permeability of t
he coal;

The pressure at which the mine can be operated as a storage vessel;

The pressure at which methane is contained in the coal;

The adsorption isotherm of the coal for C02, methane, and nitrogen, and; and


The distance to which the C02 will penetrate
beyond the outer walls of the mine.

COAL MINE VENTILATION AIR METHANE (VAM)

Ventilation air methane (VAM), that is, methane in the exhaust air from
underground coal mines, is the largest source of coal mine methane, accounting
for about 60% of the methane
emitted from coal mines Unfortunately, because of
the low concentration of methane (0.3
-
1.5%) in ventilation air, it is difficult to use
the methane beneficially. However, oxidizing methane to CO2 and water reduces
its global warming potential by 87%. A po
tential way to oxidize the methane is by
use of a thermal flow reversal reactor (TFRR). Different technologies for gainfully
utilizing VAM are described below which are at different stages of development.

Thermal Flow
-
Reversal Reactor

Figure below shows a
schematic of the Thermal Flow
-
Reversal Reactor (TFRR).
The equipment consists of a bed of silica gravel or ceramic heat
-
exchange
medium with a set of electric heating elements in the center. The TFRR process
employs the principle of regenerative heat excha
nge between a gas and a solid
bed of heat exchange medium. To start the operation, electric heating elements
preheat the middle of the bed to the temperature required to initiate methane
oxidation (above l,000oC


[l,832°F]) or hotter. Ventilation


air at a
mbient
temperature enters and flows through the reactor in one direction and its
temperature increases until oxidation of the methane takes place near the center
of the bed.

The hot products of oxidation continue through the bed, losing heat to the far sid
e
of the bed in the process. When the far side of the bed is sufficiently hot, the
reactor automatically reverses the direction of ventilation airflow. The ventilation
air now enters the far (hot) side of the bed, where it encounters auto
-
oxidation
tempera
tures near the center of the bed and then" oxidizes. The hot gases again
transfer heat to the near (cold) side of the bed and exit the reactor., Then, the
process again reverses.

As USEPA (2000) points out, TFRR units are effectively employed worldwide to
oxidize industrial VOC streams. Furthermore, the ability of MEGTEC's
VOCSIDIZER to oxidize VAM has been demonstrated in the field.

Catalytic Flow
-
Reversal Reactor

Catalytic flow
-
reversal reactors adapt the thermal flow
-
reversal technology
described above b
y including a catalyst to reduce the auto
-
oxidation temperature
of methane by several hundred degrees Celsius (to as low as 350°C [662°F).
CANMET has demonstrated this system in pilot plants and is now in the process
of licensing Neill and Gunter (Nova Sco
tia) Ltd. of Dartmouth, Nova Scotia, to
commercialize the design (under the name VAMOX). CANMET is also studying
energy recovery options for profitable turbine electricity generation. Injecting a
small amount of methane (gob gas or other source) increases
the methane
concentration in ventilation air to make the turbine function efficiently. Waste heat
from the oxidizer is also used to pre
-
heat the compressed air before it enters the
expansion side of the gas turbine.

Energy Conversion from a Flow
-
Reversal R
eactor

There are several methods of converting the heat of oxidation from a flow

reversal reactor to electric power, which is the most marketable form of energy in
most locations. The two methods being studied by MEGTEC and CANMET are:

Use water as a wor
king fluid. Pressurize the water and force it through an air to

water heat exchanger in a section of the reactor that will provide a nondestructive
temperature environment (below 8000C [1472oF]). Flash the hot pressurized
water to steam and use the steam
to drive a steam turbine generator.

If a market for steam or hot water is available, send exhausted steam to that
market. If none is available, condense the steam and return the water to the
pump to repeat the process.

Use air as a working fluid. Pressuri
ze ventilation air or ambient air and send it
through an air
-
to
-
air heat exchanger that is embedded in a section of the reactor
that stays below 8000C (1472oF). Direct the compressed hot air through a gas
turbine
-
generator. If gob gas is available, use it
to raise the temperature of the
working fluid to more nearly match the design temperature of the turbine inlet.
Use the turbine exhaust for cogeneration, if thermal markets are available.

Since affordable heat exchanger temperature limits are below those u
sed in
modern prime movers, efficiencies for both of the energy conversion strategies
listed above will be fairly modest. The use of a gas turbine, the second method
listed, is the energy conversion technology assumed for the cost estimates in this
report.

At a VAM concentration of 0.5 percent one vendor expects an overall
plant efficiency in the neighborhood of 17 percent after accounting for power
allocated to drive the fans that force ventilation air through the reactor.

Other Technologies

Other technolo
gies that may prove to be able to playa role in and enhance
opportunities for VAM oxidation projects are briefly described below.

Concentrators

Volatile organic compound (VOC) concentrators are one possibly economical
option that is under evaluation by USE
PA for its application to VAM.

Ventilation air typically contains about 0.5 percent methane concentration by
volume, or 500 ppm. Conceivably, a concentrator might be capable of increasing
the methane concentration in ventilation air flows to about 20 perce
nt. This highly
reduced gas volume with a higher concentration of methane might serve
beneficially as a fuel in a gas turbine, reciprocating engine, etc.

The fluid bed concentrator consists of a series of perforated plates or trays
supporting the adsorbent

medium (activated carbon beads). The process
exhaust stream enters from the bottom, passing upward through the adsorption
trays, fluidizing the adsorbent medium to enhance capture of organic
compounds. The adsorbent medium, which is now heavier because of

the
adsorbed organic material, falls to the bottom of the adsorber section and is fed
to the desorbcr. The desorber increases the temperature of the medium, causing
it to release the concentrated organic material into a low volume, inert gas
stream.

Lean
-
Fuel Gas Turbines

A number of engineering teams are striving to modify selected gas turbine
models to operate directly on VAM or on VAM that has been enhanced with more
concentrated fuels, including concentrated VAM (see "Concentrator" section
above) or go
b gas. These efforts include:

Carbureted gas turbine.

A carbureted gas turbine (CGT) is a gas turbine in
which the fuel enters as a homogeneous mixture via the air inlet to an aspirated
turbine. It requires a fuel/air mixture of 1.6 percent by volume, so m
ost VAM
sources would require enrichment. Combustion takes place in an external
combustor where the reaction is at a lower temperature (1200°C [2192°F]) than
for a normal turbine thus eliminating any NOx emissions.

Lean
-
fueled turbine with catalytic combus
tor
. The CCGT technology being
developed oxidizes VAM in conjunction with a catalyst. The turbine compresses
a very lean fuel/air mixture and combusts it in a catalytic combustor. The catalyst
allows the methane to ignite at a lower, more easily achieved t
emperature.

Lean
-
fuel micro turbine
. Ingersol
-
Rand Energy Systems, is developing a
microtubine that is planned to operate on a methane
-

in
-
air mixture of less than 1
percent. The microturbine is rated at 70 kW and consists of a generator, gasifier
turbine,

combustor, recuperator, power turbine, and generator. The system is
enclosed in a sound
-
attenuating enclosure and can be located indoors or
outdoors. Ingersol
-
Rand recently introduced a 250 kW microturbine to the power
industry. Additional R&D effort is r
equired to complete the system design on the
70 kW unit and to adapt the 250 kW unit to run in a lean
-
fuel mode. Ingersol
Rand
is seeking funding to further pursue this market.

Lean
-
fueled catalytic microturbine
. Two US companies, FlexEnergy and
Capstone T
urbine Corporation, are jointly developing a line of microturbines,
starting at 30 kW, that will operate on a methane
-
in
-
air mixture of 1.3 percent.
Each unit's components fit inside a compact container that requires no field
assembly. The single moving pa
rt, rotating on an air bearing, is a shaft on which


is mounted the compressor and the turbine expander. Other components include:
a recuperator that preheats the VAM mixture, a catalytic combustion chamber
with low
-
temperature ignition, a generator, and a

generator cooling section. To
better serve the VAM market, FlexEnergy is investigating designs that will reduce
required VAM concentration to below 1.0 percent and increase unit sizes to over
100 kW.

Hybrid coal and YAM
-
fueled gas turbine
. CSIRO is also d
eveloping an
innovative system to oxidize and generate electricity with VAM in combination
with waste coal. CSIRO is constructing a 1.2
-
MW pilot plant that cofires waste
coal and VAM in a rotary kiln, captures the heat in a high
-
temperature air
-
to
-
air
exch
anger, and uses the clean, hot air to power a gas turbine. Depending on site
needs and economic conditions, VAM can provide from about 15 to over 80
percent (assuming a VAM mixture of 1.0 percent) of the system's fuel needs,
while waste coal provides the r
emainder.

VAM Used as an Ancillary Fuel

While the primary focus of this assessment is on strategies that oxidize major
fractions of global VAM emissions, a brief mention of technologies that use VAM
only as an ancillary or supplemental fuel is in order. Su
ch technologies rely on a
primary fuel other than VAM and are able to accept VAM as all or part of their
combustion air to replace a small fraction of the primary fuel. The largest
example of ancillary VAM use occurred at the Appin Colliery in Australia, w
here
54 one
-
MW Caterpillar engines used mine ventilation air containing VAM as
combustion air Similarly, the Australian utility, Powercoal, is installing a system to
use VAM as combustion air for a large coal
-
fired steam power plant. A working
example of t
his application is shown below:

Supplemental Fuel Example: Appin Colliery, Australia



Installed in 1995



54 xl MW IC Engines Produce Power from Gob Gas



VAM Used as Feed Air, Supplies 7% of Energy

Underground Coal Gasification

In comparison with convention
al coal mining and modern steam power plant,
UCG with combined cycle power generation offers the overall environmental
advantages of:



Lower particulate emissions, noise and visual impact on the surface



Less water used (this is important in many of the min
ing areas in China)



Lower risk of surface water pollution



Reduced methane emissions from coal mining



No dirt handling and disposal at mine sites



No coal washing and fines disposal at mine sites



No ash handling and disposal at power station sites



Less

SO2 and NOx



Lower energy consumption as less materials and product transport



Less heavy surface transport



Smaller land area occupied



Fewer liabilities after mine abandonment.

Additional benefits of the UCG power generation approach are:



Lower occupat
ional health and safety risks (fewer miners underground)



Lower capital and operating costs compared with conventional systems



Flexibility of access to mineral



Larger coal resource exploitable.

There are coal reserves deep underground in the State of Gu
jarat. The 'in
-
situ'
north Gujarat reserves which are estimated at 63 billion tonnes occur at a depth
of 800 to 1700 metres which is beyond the limits of conventional methods of
mining in India. If this resource is exploited on a large scale by using the l
atest
technologies of UCG, it could generate gas equivalent to 200,000 BCM.

Integrated Gasification Combined Cycle

Integrated coal Gasification Combined Cycle (IGCC) power plant is the most
environmentally friendly coal
-
fired power generation technology. M
ost
importantly, coal gasification offers the immediate opportunity to generate power
with near zero greenhouse gas emissions and the pathway to a future hydrogen
economy.

Description

Coal gasification is the process of converting coal to a gaseous fuel th
rough
partial oxidation. The coal is fed into a high
-

temperature pressurized container
along with steam and a limited amount of oxygen to produce a gas. The gas is
known as synthesis gas or syngas and mainly consists of carbon monoxide and
hydrogen. The g
as is cooled and undesirable components, such as carbon
dioxide and sulphur are removed. The gas can be used as a fuel or further
processed and concentrated into a chemical or liquid fuel.

Integrated gasification combined
-
cycle (IGCC) systems combine a coa
l
gasification unit with a gas fired combined cycle power generation unit. The first
stage is the coal gasification process as mentioned above. The second stage
takes the cleaned gas and burns it in a conventional gas turbine to produce
electrical energy,
and the hot exhaust gas is recovered and used to boil water,
creating steam for a steam turbine which also produces electrical energy. In
typical planes, about 65% of the electrical energy is produced by the gas turbine
and 35% by the steam turbine.

In gen
eral the advantages of IGCC are:



It can achieve up to 50% thermal efficiency. This is a higher efficiency
compared to conventional coal power plants meaning there is less coal
consumed to produce the same amount of energy, resulting in lower rates
of carbo
n dioxide (CO2) emissions



It produces about half the volume of solid wastes as a conventional coal
power plant.



It uses 20
-
50% less water compared to a conventional coal power station.



It can utilise a variety of fuels, like heavy oils, petroleum cokes,

and coals.



Up to 100% of the carbon dioxide can be captured from IGCC, making the
technology suitable for carbon dioxide storage.



Carbon capture is easier and costs less than capture from a pulverised
coal plant



A minimum of 95% of the sulphur is remov
ed and this exceeds the
performance of most advanced coal
-
fired generating units currently
installed.



Nitrogen oxides (NOx) emissions are below 50ppm. This is lower than
many of today a (TMs most advanced coal
-
fired generating units.



The syngas produce f
rom a gasifier unit can be burned in a gas turbine for
electricity generation, or used as a fuel in other applications, such as
hydrogen
-
powered fuel cell vehicles

Coal to Liquid Technology

Once Coal is gasified and converted to a mixture of CO + H2, thro
ugh Fischer
Tropsch reaction, the synthesis gas can be converted to liquids. This aspect has
been fully covered in our article of August 2005
-

GTL taking on to markets.
Executive Summary of the same is reproduced below:

GTL taking on to markets. Executive

Summary

Ever increasing consumption of fossil fuel and petroleum products has been a
matter of concern for the country for huge out
-
go of foreign exchange on the one
hand and increasing emission causing environmental hazards on the other. The
current annu
al import bill of crude oil in terms of foreign exchange is around Rs.
60, 400 crores. Diesel is mainly consumed for transport; road transport eats up
almost 75% while the Railways account for the rest.

Oil provides energy for 95% of transportation and the

demand of transport fuel
continues to rise. The requirement of Motor Spirit is expected to grow from little
over 7 MMT in 2001
-
02 to over 10 MMT in 2006
-
07 and 12.848 MMT in 2011
-
12
and that of diesel (HSD) from 39.815 MMT in 2001
-
02 to 52.324 MMT in 200
6
-
07
and just over 66 MMT in 2011
-
12.

The capitalization and infrastructure associated with diesel amounts to hundred
of billions of dollars, and it is safe to say that diesel will remain the fuel of choice
for some time to come. However, biodiesel1s contr
ibution could be substantial
and well timed in providing an option which will help meet the environmental and
strategic concerns of the country, while allowing the financial realities of
infrastructural investments in diesel technology to be compensated.

T
he same logic holds good for GTL
-
Diesel, which can not only provide a source
of environmentally compliant fuel but also help avoid capital expenditure on
setting up additional refining capacity and product upgradation schemes. To add
to it, if GTL is produ
ced by use of indigenous resources like CTL and BTL, it
would do the yeoman service of giving the Indian energy basket a semblance of
Energy Independence.

ONE OF THE HOTTEST TRENDS in the global petroleum industry in 1997
involved a technology that is thre
e fourths of a century old.

Economic conversion of natural gas to synthetic fuels, one of the "Holy Grails" of
the energy industry for decades, took startling steps in 1997.

For the first time since the discovery of the Fischer
-
Tropsch synthesis process in

1923, gas
-
to
-
liquids conversion processes may be competitive with conventional
petroleum products on the world market. And the technology doesn't require an
oil price of $30
-
40/bbl, as was the case with the failed synthetic fuels projects of
the late 1970
s and early 1980s. The oil price at present is close to touching
$70/bbl and is not likely to return to previous lows for the foreseeable future.

The GTL industry is poised for a major expansion based in Qatar, but also in
Nigeria and Australia. The expans
ion is being funded by the major oil companies,
in some cases in tandem with synthetic fuel companies and national oil
companies. The projected expansion of the industry is based on favourable
market conditions in addition to advances in technology. High o
il and natural gas
prices, declining capital investment costs, and improvements in technology that
allow large scale production facilities are important factors in the industry's
expansion.

India is slated to be a fast growth economy with predictions that
by 2050 it will be
the third largest economy in the world. However the achievement of the
envisioned growth is subject to a number of enabling factors being in the right
place. Energy is certainly one of the most important prime movers of the
economy. Any
disturbance in availability of energy in terms of either reliability or
economics can jam the wheels of the juggernaut of the economy.

India will have to look at alternative energy with a greater urgency and
GTL/CTL/BTL certainly merits being one of them.

Small Sized GTL Plants

Most world
-
class GTL technology is in large plants associated with gas fields of
5
-
500 Trillion cubic feet (Tcf). However it is essential to find a cost effective
solution for smaller GTL plants to monetise flared gas, associated gas
, Coal
based or biomass based production. M/s Syntroleum, Rentech and Synfuels
International are working in this direction and are willing to license the
technology.

F
-
T conversion of coal (CTL)

The main difference between processes for producing F
-
T liqui
ds from coal
compared to production from natural gas is in the syngas production step. The
reforming step is replaced by a pressurized oxygen
-
blown gasifier when using
coal.

F
-
T conversion of biomass (BTL)

According to Choren it takes 5 tons of biomass to
produce 1 ton of sundiesel and
1 hectare generates 4 tons of sundiesel. A plant producing 13,000 tons per year
would need the biomass of 50,000 ha. In recent years the German set
-
aside area
amounted to roughly 1 million ha. This could generate 4 million to
ns of sundiesel,
which is about 13 percent of .current diesel use in Germany.

Relevance of GTL to India

Despite two encouraging discoveries of natural gas in India and import of LNG
from two terminals on the West Coast, India will remain a supply driven ma
rket.
The available gas would better be transmitted and distributed by pipelines and
use for energy efficient applications in power generation, industry, commercial
establishments, residential sector and transport sector. For Gas to Liquids (GTL)
India wil
l. have to look outside India for gas resources. May be the gas equity
abroad could provide a suitable opportunity. Special political efforts could pay off
well if the landlocked countries like Kazakhstan, Turkmenistan and Russia were
targeted for booking
gas resources.

However Coal to Liquids (CTL) and Biosyngas to Liquids (BTL) are the
possibilities where India can use its own resources. While talking about CTL,

India has possibility of exploiting a large resource via Underground coal
gasification (UCG),

which is given up as unreachable. There are coal reserves
deep underground in the State of Gujarat. The 'in
-
situ' north Gujarat reserves
which are estimated at 63 billion tonnes occur at a depth of 800 to 1700 metres
which is beyond the limits of conventi
onal methods of mining in India. If this
resource is exploited on a large scale by using the latest technologies of UCG it
could generate gas equivalent to 200,000 BCM. UCG has a special attribute that
it helps enhance the quantity of indigenous fossil fue
ls that were hitherto
considered virtually non
-
existent
-
unexploitable. The technology of UCG is proven
elsewhere to some extent but, the use of the latest and the most cost

effective
technology available today (CRIP) needs to be imported and tried out ri
ght away
(zero date starts with the commencement of first trial) so that at least in
foreseeable future we will be able to increase the indigenous content in the
energy basket of India. .

UCG has a virtue that it will cut down the Syngas Production (Costin
g 50% of
GTL Project) from the GTL project. With the price of unmineable coal taken as
zero, UCG could provide an economic option for Syngas.

CBM is another source of gas which may not be large enough in size to afford its
transmission and distribution. He
re the small sized GTL technology being offered
by a number of companies may be of good use.

To top it all BTL would be from renewable resources and hence would never get
exhausted. India has a large base of agriculture and forests where this
technology (B
TL) being used in Germany could provide a significant degree of
Energy Independence as envisioned by the President of India.

Syngas, or synthesis gas, produced from fossil fuels or biomass, is shaping up to
become a crucial intermediate in emerging energy
and fuel solutions. Syngas
can be combined with emerging downstream technologies for gas
-
to
-
liquids
(GTL) processes, methanol
-
to
-
olefins (MTO) conversion, coal
-
to
-
liquids (CTL)
conversion and fuel cells. It also is used as a feedstock for high
-
value, chemi
cal
processes such as ammonia, hydrogen and methanol.



We need to procure several very large so
-
called stranded gas fields,
immense fields of natural gas that have been discovered but are too far
from developed gas markets to have any value (the landlocked
countries
like Kazakhstan, Turkmenistan and Russia were targeted for booking gas
resources). Indian government would have to forge agreements with a few
friendly nations to purchase rights to produce this gas and convert it to
liquid fuels on location.



We

need to commence UCG trials without any further loss of time and
import the best possible technology
-
to ensure commercial success of
large scale UCG projects which can then feed the GTL projects to produce
diesel which is the most dominant fuel in India'
s energy basket.



We may collaborate with countries like Germany and immediately import
the BTL technology and set up a number of plants based on biomass
waste which presently posses a disposal problem.



Obviously, the economics of GTL/CTL/BTL would improv
e over a period of
time. (May not be much of a problem at current price of crude oil.)
Requisite policy support may be given for the growth of this industry which
alone can give India the energy independence that it badly needs.

Conclusions

India is highl
y dependent on imported oil with. a heavy drain on foreign exchange
earnings. This trend is not likely to change very much in foreseeable future.
Finding of any large reserves of oil in the country is not in sight. Oil can be
substituted with coal, but for

certain applications it has to be converted into liquid
form. Several experts have already recommended the coal gasification route for
liquefaction of Indian coals. Considering several aspects, the option of coal to oil
seems to be an unavoidable strategy

for India.

Natural gas is being used for power generation in the country and it is rightly so
for accelerated growth of power sector. There are plans for import of liquefied
natural gas (LNG) and naphtha etc. for power sector mostly by independent
power p
roducers. This could be allowed as a short term measure as dictated by
the market forces. But as a medium to long term measure the natural gas and
liquid fuels need to be replaced by coal gas.

The medium to long term targets can be: i) Replacing the natura
l gas with coal
gas in the existing combined cycle power plants ii) Establishment of advanced
power generation technologies based on coal gas i.e., fuel cell. iii) Commercial
plants for coal to oil and coal refinery. iv) Sell reliance and security in energ
y
sector v) Substitution of exhaustible with renewable energy sources.

The present use of coal mostly through direct combustion is inefficient with high
levels of pollution. The efficiency cannot be improved much due to technological
limitations and it is

very expensive to control the pollution. India is looking for
alternate technologies, more efficient, environmentally benign and economically
attractive. Coal gasification fits into these requirements. IGCC technology is the
best alternate option for powe
r generation in India.

The setting up of coal to oil conversion plants should not be evaluated purely
from commercial angle, but security, sell reliance and conserving oil should merit
serious consideration. Coal to oil technology can be considered on the
same
footing as atomic energy which had paid dividends by bringing the country to sell
reliant status.

A concept of coal refinery is mooted now and may be put in practice as a long
term strategy to substitute the imported oil.

To progress on the technolog
y front, for next 20
-
30 years our country should take
pro
-
active leads on technologies like
-

in
-

situ coal gassification, clean coal
technologies and coal bed methane. It is expected that, hydrogen and other
hybrid technologies will assume significant rol
e in transportation sector.

CBM/CMM/ AMM/VAM

Methane capture and its utilization from coal mines is not being undertaken in
India due to:



Lack of latest technology



Lack of expertise and experience



Pervasive perception that commercial viability of exploit
ation and
utilization of Methane is doubtful.

Opportunities exist for the development of a range of clean coal energies from in
-
situ coal seams focused on CBM and UCG. The development and exploitation of
these fuels is likely to provide environmental, saf
ety and financial benefits.
Technology is being developed for using low methane concentrations in mine
ventilation air but it is unlikely to be commercially viable without support from
government. VAM utilisation might also divert effort from improving gas

capture
and utilisation at working coal mines, which could have safety implications.

Evaluation of coal properties, construction of adsorption isotherm, and study of
geological setting of coal basins should be an integral part of initial research
efforts.

It is desirable to work out the techno
-
economic viability of a project after
R&D efforts are completed and before exploration and exploitation are taken up.

The potential production rate of a virgin CBM reservoir can be under
-
estimated, if
care is not tak
en to protect seam permeability from damage during drilling and
testing. 'Clean drilling' techniques, as practiced by leading operators in the UK,
should therefore be introduced to ensure that CBM prospects are correctly
characterized and optimum CBM produ
ction rates are attained.

UCG

The technology is highly relevant and very promising to India. Two sites in India
one in Rajasthan and another in Bengal
-
Bihar initially appear to be suitable for
application of underground coal gasification. Many more areas c
ould be
amenable.

There are coal reserves deep underground in the State of Gujarat. The 'in
-
situ'
north Gujarat reserves which are estimated at 63 billion tonnes occur at a depth
of 800 to 1700 metres which is beyond the limits of conventional methods of
m
ining in India. If this resource is exploited on a large scale by using the latest
technologies of UCG, it could generate gas equivalent to 200,000 BCM.

UCG provides a radical approach to mine mouth power generation that enables
the energy in coal to be re
leased without the need to extract, process, transport
and combust it. UCG virtually eliminates greenhouse gas emissions associated
with coal extraction. Hitherto, the potential net greenhouse gas emission
mitigation benefits of UCG power generation compar
ed with conventional coal
extraction and coal
-
fired power plant has received little attention.

Integrated Development of coal reserves

Ongoing mining activities

1.

Continue mining in zone already opened for mining. Recover Methane gas
for vent and generate po
wer.

2.

Coal mine methane recovery .

3.

The zones which are yet to be opened, plan for full CBM recovery first ad
then open zones for mining

4.

UCG production from "un mineable zones"

New mines yet to be opened

1.

First complete full CBM recovery

2.

Open mines for c
oal production

3.

UCG production from zones below mining range

Abandoned mines

1.

Recover CBM from pillars, compartments by drilling wells

2.

If Coal seams are available below "mineable zone", evaluate possibilities
of UCG.

Coal seam below" mineable zone"

1.

CBM r
ecovery

2.

UCG project

It can thus be seen that coal in solid form can continue to support power
generation and other applications, CBM can supplement Natural Gas
requirements and through UCG route, syngas so generated can be used either
for power generatio
n (IGCC)' or for chemicals or liquid petroleum fuel for
transportation network.

As integrated development as proposed would make it imperative that
exploration or oil and gas and exploitation of coal resources be carried in unison.
For example, in Cambay b
asis in Gujarat more than 4000 well have been drilled
for oil exploration / production. Many of these exploratory and development wells
were dry and abandoned where coal seams were encountered. If petroleum /
coal activities were to be performed under "sin
gle" licence, UCG operation could
have started much sooner. As can be seen, exploration / exploitation of oil / gas
and coal are both technologically and geologically linked.

Policy initiatives for proposed development of coal fuels



Unified license for Co
al, CBM and UCG production along with CO2
sequestration.



Unified license for Petroleum, CBM and UCG in those basins where
hydrocarbon (crude oil or natural gas) occurs in coal beds.



Incentives for CBM and UCG production as non
-
conventional energy
source
and for emission reduction. Policy options to promote CBM and
UCG practiced by U.K., Australia and U.S. include market based
incentives, tax breaks, feed
-
in tariffs, direct grants/ supports.



Optimization of energy mix apportioning full role for coal
-
fuels
.



National awareness and the focus commensurate with importance of the
energy security need. to be created.



Expediting the process of granting licenses for remaining blocks for
exploration of CBM and UCG.



Supervisory agency to co
-
ordinate and promote in
tegrated development of
all coal fuels.