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Power projects using methane from coal mines
Technical Report · August 2006
DOI: 10.13140/RG.2.2.10861.54245
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Power projects using methane
from coal mines
Lesley L Sloss
CCC/112
August 2006
Copyright © IEA Clean Coal Centre
ISBN 92-9029-428-0
Abstract
Methane gas has at least twenty times the global warming potential of carbon dioxide. Recently, methane from coal mines has
been receiving attention as both a cause for concern to the environment as well as a potential source of energy.
CMM (coal mine methane) fired power plants are being constructed in several countries around the world, most notably in
Australia, Germany and China. This report identifies the CMM gas-fired power plant currently in operation, under construction
and at the planning and development stage. Where possible, details are included on location, capacity, process configuration and
equipment manufacturer.
Acronyms and abbreviations
ACARP
A(C)MM
APF
bm3
CANMET
CBM
CCUJ
CDM
CFBC
CFRR
CHP
CIDA
CIS
CMC
CMM
CMOP
CMR
CO2-e
CSIRO
DITR
DME
DSA
ECBM
EU ETS
FBC
FCE
FIGT
GAIL
GEF
gensets
GHG
GWP
IC
IR
IRR
IREEDD
JBIC
JCoal
JICA
kW
kWh
LHV
LNG
M2M
METI
Mm3
MWe
MWth
NETL
NIIDP
PEER
TDA
TFRR
UK DTI
UN
UNDP
UNF
UN FCCC
2
Australian Coal Association Research Programme
abandoned (coal) mine methane
absorption with pressure fluctuation
billion cubic metres
Canadian Mineral and Energy Technologies
coalbed methane
Centre for Coal Utilisation, Japan
clean development mechanism
circulating fluidised bed combustion
catalytic flow reverse reactors
combined heat and power
Canadian International Development Agency
Commonwealth of Independent States
Chinese Ministry of Commerce
coal mine methane
Coalbed Methane Outreach Programme, US EPA
catalytic monolith reactor
carbon dioxide equivalent greenhouse gas potential
Commonwealth Scientific and Industrial Research Organisation, Australia
Department of Industry, Tourism and Resources, Australia
Dimethyl-ether
Deutsche Steinkohle Aktiengesellschaft, Germany
enhanced coalbed methane
European Union emissions trading scheme
fluidised bed combustion
Fuel Cell Energy Inc
fuel injected gas turbine system
Gas Authority of India Ltd
Global Environment Facility
generator sets (internal combustion engine array)
greenhouse gas
global warming potential
internal combustion (engines)
Ingersol-Rand Ltd
internal rate of return
UN ECE Industrial Restructuring, Energy and Enterprise Division
Japan Bank for International Cooperation
Japan Coal Energy Centre
Japan International Cooperation Agency
kilowatt
kilowatt hour
lower heating value
liquified natural gas
Methane to Markets Partnership, US EPA
Ministry of Economy, Trade and Industry, Japan
million cubic metres
megawatt, electric
megawatt, thermal
National Energy Technology Laboratory, US DOE
National Industrial Innovation Development Programme, Kazakhstan
Partnership for Energy and Environmental Reform, the Ukraine
Trade and Development Agency, USA
thermal flow reverse reactors
UK Department of Trade and Industry
United Nations
United Nations Development Programme
United Nations Foundation
United Nations Framework Convention on Climate Change
IEA CLEAN COAL CENTRE
UNIDO
US DOE
US EPA
VAM
VCBM
VOC
United Nations Industrial Development Organisation
US Department of Energy
US Environmental Protection Agency
ventilation air methane
virgin coalbed methane
volatile organic compounds
Power projects using methane from coal mines
3
Contents
Acronyms and abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Contents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
1
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
2
CMM for power production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.1 Pipeline injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.2 Power generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
2.2.1 Gas engines/internal combustion engines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
2.2.2 Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
2.2.3 Cogeneration systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
2.2.4 Oxidation technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
2.2.5 Fuel cells. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
2.3 Cofiring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
2.3.1 CMM as additional fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
2.3.2 VAM as intake air . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
2.4 Selecting the most appropriate technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
2.5 Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
3
Projects in operation worldwide. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.1 Australia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.2 Asia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
3.3 Europe – Western . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
3.3.1 France . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
3.3.2 Germany . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
3.3.3 UK. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
3.4 Europe – Eastern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
3.4.1 Croatia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
3.4.2 Czech Republic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
3.4.3 Hungary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
3.4.4 Romania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
3.4.5 Slovenia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
3.4.6 Poland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
3.5 Russian Federation and the CIS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
3.5.1 Russian Federation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
3.5.2 Ukraine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
3.6 North America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
3.7 Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
4
Projects planned or under construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
4.1 Australia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
4.2 Asia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
4.3 Europe – western . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
4.3.1 Bulgaria. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
4.3.2 Germany . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
4.3.3 Italy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
4.3.4 Turkey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
4.3.5 UK. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
4.4 Europe – eastern. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
4.4.1 Croatia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
4.4.2 Czech Republic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
4.4.3 Slovenia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
4.5 Russian Federation and the CIS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
4.6 North America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
4.7 Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
4.8 Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
4
IEA CLEAN COAL CENTRE
5
Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
6
References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
Appendix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
CMM-to-power equipment suppliers: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Cogeneration systems: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Oxidisers: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Other useful sources of information: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Power projects using methane from coal mines
5
6
IEA CLEAN COAL CENTRE
1 Introduction
Methane is a fuel and is also a potent greenhouse gas. The
utilisation of methane which would otherwise simply leak
from coal mines therefore gives double value to any project
by providing cheap and clean power and at the same time
reducing methane emissions.
A previous report by IEA CCC (Sloss, 2005) reviewed
emissions from coal mining activities and included details on
potential reserves, legislation, environmental considerations
and a short summary of activities under way around the
world. This complementary report concentrates on
methane-to-power projects currently in operation, under
construction or planned in the near future.
There are four main categories of methane produced from
coal mines (Creedy and Tilley, 2003):
●
VCBM: virgin coalbed methane, from coal seams which
have not been actively mined and which may never be
actively mined. Only the methane is being captured and
the coal seam is otherwise left untouched. Typical
methane concentrations are >95% with flow rates of
1000–18,000 m3/d (pure methane);
●
CBM/CMM: coalbed methane/coal mine methane
drained from mines either prior to or during mining
activities. The definitions of CBM and CMM vary from
reference to reference. Some regard CBM as methane
captured prior to mining and CMM as that captured
during mining. However, the uses of these acronyms in
the literature cited in this report are often too varied
and/or indistinct for them to be regarded as consistent.
Where possible the definitions of CBM and CMM as
described above are used. However, in this report the
term CMM is used to apply to any methane drained at a
working mine. Typical methane concentrations are
35–75% with flow rates of 6000–195,000 m3/d (pure
methane);
●
VAM: ventilation air methane, dilute methane which
seeps from the seam during mining and escapes through
the ventilation shafts and workings. Typical methane
concentrations are 0.05–0.8% with flow rates of
4000–140,000 m3/d (pure methane);
●
ACMM: abandoned coal mine methane, from
abandoned, but previously worked, mines. Typical
methane concentrations are 35–90% with flow rates of
11,000–86,000 m3/d (pure methane).
concentrated methane can be used as a replacement for
natural gas in national gas pipeline networks or more locally
in residential cooking and heating. Concentrated methane can
also be used as a vehicle fuel. Medium quality gas is suitable
for power generation as a primary or secondary fuel. This can
be in steam boilers, combined heat and power systems or
district heating plants. Other options for the heat produced
include coal drying and mine heating or cooling. Lower
quality, more dilute, methane can be used in lean-burn
engines or turbines, as combustion air in other fuel-fired
processes or can be oxidised to produce useful heat. All of
these options are described in Chapter 2 of this report. The
report also includes a short Appendix listing suppliers of
these various technologies. The possibility of combining
CMM extraction with CO2 capture and storage, known as
enhanced coalbed methane (ECBM) is not covered in this
report. However it is covered in several reports by our sister
organisation which can be contacted at
http://www.ieagreen.org.uk
Chapter 3 reviews the different projects which are currently
operational around the world emphasising, where possible,
why these projects have proven successful. Chapter 4 then
provides information on proposed projects and projects under
construction.
A previous and complementary report by IEA CCC (Sloss,
2005) discusses the different types of methane released from
coal mines, typical volumes and flow rates, and the available
methodology for capturing this gas in greater detail. This
report concentrates on technologies for the utilisation of
methane which would otherwise escape from existing
(CMM) or abandoned mines (ACMM). However, interesting
examples of projects using VCBM for power generation or
pipeline injection are included for comparison.
Methane can be used as a fuel in several different ways,
depending on the quality of the gas. High quality,
Power projects using methane from coal mines
7
2 CMM for power production
Methane is a useful and clean source of energy which is
leaking into the atmosphere from thousands of mines around
the world. The potential to capture this methane and use it to
supply power whilst simultaneously reducing greenhouse gas
emissions is largely untapped in most countries.
Schneider (2003) cites the following statistics (based on 40%
electrical efficiency and normal operating conditions,
8000 h/y):
0.18 kg CH4
=
1 kWhe
=
3.76 kg CO2-e [CO2-equivalent,
in terms of global warming
potential (GWP), where CH4 has
over 21 times the GWP of CO2]
=
1 MWe from CMM
=
4.72 kg/kWhe CO2 reduction by
combined heat and power from
CMM (includes both heat and
electrical generation)
around 34,000 t CO2-e reduction
potential
There is therefore a significant advantage to using CMM in
methane-to-power projects. Schultz (2006) has reviewed the
potential value of CMM in selected markets around the world
and estimated the following (assuming 4 €/MBtu (3.8 €/GJ)
and 10 €/t CO2-e):
Ukraine:
1.1 billion m3/y = €160 million in energy
+ €157 million in carbon credits
Russia:
0.8 billion m3/y = €120 million in energy
+ €114 million in carbon credits
Poland:
0.5 billion m3/y = €80 million in energy
+ €71 in carbon credits
Czech Rep:
0.3 billion m3/y = €50 million in energy
+ €43 in carbon credits
Table 1
Although these figures are based on relatively gross
assumptions on the quality of the gas and the likely sales
prices, the theoretical potential for these countries to turn a
waste gas into a profit is clearly enormous. However, the
success of CMM-to-power projects is very case specific,
depending on such factors as the quality of the gas and the
suitability of the different utilisation options at each
individual site. Table 1 shows the different gas characteristics
at several mines in the Australia, Germany and the UK
(Schneider, 2003). Each of these mines produces a CMM of a
distinct quality and each would require a site-specific
approach to making the best use of this gas.
Figure 1 shows the quantity of CMM projects around the
world based on project type. Pipeline injection (largely in the
USA) and town gas are the most popular uses of CMM. As of
2004, power generation accounted for only 2 billion m3/y
(CME, 2004).
The following sections review the principles of the most
common methane-to-power options with examples where
appropriate. Chapters 3 and 4 list the actual projects currently
operating and planned throughout the world. The use of
CMM for chemical feedstock or other industrial uses is not
discussed here but is dealt with briefly in a complementary
IEA CCC report (Sloss, 2005).
2.1
Pipeline injection
The worldwide demand for natural gas is predicted to
increase by 50% between 2005 and 2025 and so there is an
opportunity for promoting CMM as an alternative source of
methane (Talkington, 2004). In some situations, CMM can be
produced in a sufficiently pure and concentrated form that it
can be used as a replacement for natural gas. This gas is
distributed by a network of pipes for combustion by utilities,
industry and in residential cooking and heating. Almost all of
the 1 billion m3 of CMM used in the USA is put directly into
the natural gas system (CME, 2002).
In order to ensure that the gas is suitable for pipeline
injection the gas quality has to be assured along with a
Properties and characteristics of coal mine gas versus natural gas (Schneider, 2003; HT, 2006)
Parameter
Tahmoor Colliery,
Australia
active mine
Mont-Cernis Herne, Lohberg Dinslaken,
Germany
Germany
closed mine
active mine
Shirebrook Colliery,
UK
Natural gas
closed mine
CH4
31.5%
68.6%
43.8%
76.0%
CnHm
-0.9%
0.4%
2.6%
0–20%
CO2
31.7%
11.3%
2.2%
10.6%
0–8%
N2
31.0%
18.9%
43.7%
10.7%
0–5%
O2
5.8%
0.5%
9.8%
0.1%
0–0.2%
LHV, kWh/m3
3.1
6.9
4.5
8.2
9.61
8
70–90%
IEA CLEAN COAL CENTRE
3000
85
2500
71
2000
57
1500
42
1000
28
500
14
Billion m3/y
Billion ft3/y
CMM for power production
0/0
0
0
Power generation
Figure 1
Pipeline injection
& town gas
Flaring
Industrial use
Global CMM use by project type, as of 2004
consistent supply. There are stringent specifications for
natural gas and commonly it may not contain more than 2%
CO2 and 5% N2. An exception is the Methamine project in
the Nord Pas de Calais, France, where mine gas at only 56%
methane is injected into a natural gas pipeline operated by
Gaz de France. The calorific value of gas in the gas grid in
France is lower than that elsewhere (34.2–37.8 MJ/m3
compared with 37.5–43.0 MJ/m3 for Transco in the UK). The
CMM can be injected into the French pipeline as long as the
combined gas concentration does not fall below the required
concentration (UK DTI, 2004).
CMM from some mines is simply not of a high enough
quality to be used as a replacement for natural gas. However,
in certain situations, the amount of CMM available and the
market for gas will make it commercially appropriate to
invest in gas cleaning technologies. The enrichment of CMM
to pipeline quality gas is possible with techniques such as
phased extraction treatment to remove oxygen, carbonic acid,
water steam and nitrogen:
●
O2 is extracted by oxidation with a catalyst;
●
CO2 is removed by reacting the gas with the solvent
amine di-glycol;
●
water steam is removed with a system of molecular sieves;
●
N2 can be removed by the patented Nitech technology or,
at greater expense, by absorption with pressure
fluctuation (APF).
Plants for this type of treatment are designed to treat over
30,000 m3/d and would cost over $5.5 million (excluding the
cost of the compressor station required to supply the gas into
the pipeline). The lifetime of such plants is estimated at over
30 years due to the lack of any rotating parts or elements
which are prone to corrosion. The prime cost of 1000 m3 of
methane enriched at such a plant (50,000 m3/d) would be
around US$2.37. Since the market price of methane is $50
for 1000 m3, the profit would be $47.6 per 1000 m3 and the
period of payback would be around two years (Bulat and
Zaloznova, 2003). A photograph of a CMM cleaning system
is shown in Figure 2 (Schultz, 2006).
Power projects using methane from coal mines
In southern Illinois, USA, gas from an abandoned mine
(unspecified) is cleaned using a new Engelhard ‘molecular
gate process’ to remove nitrogen and CO2. The system has a
95% methane recovery rate and produces a ACMM gas
which can be sold into the local pipeline. A second similar
facility was planned for another abandoned coal mine (also
unspecified), this time in southwestern Pennsylvania (Cote
and others, 2003, see also Engelhard details in Appendix).
According to Bulat and Zaloznova (2003), other methods for
enrichment of CMM gas such as membranes, separation or
vortical treatment are under development but have numerous
drawbacks including low performance and poor extraction of
methane.
CMM must be supplied in a compressed form so that it can
be added to the existing pipeline without causing pressure
loss in the system. At a discharge pressure of 7 bar, the
energy required to pump gas into the US grid represents
Figure 2
Cryogenic CMM gas cleaning system
(Schultz, 2006)
9
CMM for power production
approximately 5% of the electrical energy that would be
available from the gas (100 kW for a flow of 150 L/s)
(UK DTI, 2004).
would require costly cleaning to ensure it is suitable for this
use. A cryogenic liquefaction plant is installed at the Blue
Creek mine in the USA. The gas is passed through heat
exchangers to remove O2, then CO2, water vapour and then
nitrogen in a similar manner to that described for natural gas
(UK DTI, 2004). Extracting methane from methane-air
mixtures by fluidisation with cryogenesis requires ‘large’
capital outlay (unspecified) and power consumption –
around 0.30–0.85 kWth/kg of liquid methane. The market
for liquid methane is often very limited (Bulat and
Zaloznova, 2003)
As mentioned above, the cost for connection can be
significant. In the UK it has been estimated that the cost
would be from £300,000–£1,000,000 depending on various
site-specific factors. This puts pipeline injection low on the
list of economic options for CMM usage in the UK (UK DTI,
2004). The Government of India is considering extending
current pipelines to take them closer to potential sources of
VCBM and CMM. Whether such projects will be
economically viable will vary on a case by case basis,
depending on factors such as the distance the pipeline must
cover, the relative cost of producing and delivering the CMM,
and the specific market situation at each location (Wight,
2004).
2.2
Power generation
CMM is a valuable fuel. Figures 3 and 4 show the CMM
based power generation capacity and the mitigation capacity,
by country, for 2004 (CME, 2005a,b). The graphs indicate
that the majority of CMM-to-power projects are located in
Germany. Australia, China, the Ukraine, the UK and the USA
also have a significant number of projects under way. Each of
these projects will be discussed in Chapter 3. This section
concentrates on the principles behind the use of CMM in
these methane-to-power projects.
A simpler way to utilise CMM as a replacement for natural
gas is to use it for local residential cooking and heating.
Local gas distribution systems commonly have lower
requirements for gas quality. For example, in the Ukraine
CMM is fed into gas pipelines for short or long distance
distribution as a replacement for natural gas. Several Chinese
coal mines supply local communities with CMM for
residential use (see Chapter 3).
There are a few options for producing power from CMM and,
for the moment, there is no single approach which is suitable
for all projects. The appropriate system must be identified on
a case by case basis as each system has its own requirements
as well as advantages and disadvantages. Table 2 lists the
three main types of power generation technologies and their
typical parameters. Each of these systems is discussed
separately in more detail below.
In some cases dilute mine gas can be mixed with more
concentrated gas, such as that from VCBM, to produce a mix
which is suitable for use as domestic fuel. This approach has
been proposed for the local pipeline systems at Fushun and
Tiefa in Liaoning, China. Pipelines for CMM distribution
have been constructed for this purpose (Creedy, 2002;
see Chapter 3).
2.2.1 Gas engines/internal combustion
engines
CMM can also be used as a replacement for liquefied natural
gas (LNG). If the methane concentration is over 90%, the
CMM gas can be liquefied by cooling to a volume up
1/600th of its gas phase volume. This makes transport of the
methane simpler and more economic than via a pipeline.
LNG can be used as a vehicle fuel or can be transported and
fed into a natural gas pipeline at another location. CMM
Internal combustion (IC) engines are simple, readily available
and can be converted from diesel to fire CMM gas quite
simply. The US EPA (2004b) list the advantages of using
CMM in IC engines as follows:
300
200
MW
150
100
50
US
ne
rai
Uk
UK
Ru
ss
ia
Ro
ma
nia
lan
d
0
Po
kh
sta
n
0
Ka
za
pa
n
Ja
an
y
Ge
rm
Fra
n
c
0.2
Cz
ec
h
Re
p
ub
li
Ch
ina
ali
a
Au
str
0
ce
0
0
Figure 3
10
CMM-based power generation capacity as of 2004
IEA CLEAN COAL CENTRE
CMM for power production
250
0.71
0.57
200
Billion ft3/y
0.28
100
0.14
50
Billion m3/y
0.42
150
0.28
US
ne
rai
Uk
UK
a
Ru
ssi
ia
Ro
ma
n
d
Po
kh
Ka
za
lan
n
sta
n
Ja
pa
an
rm
nc
e
Ge
ep
hR
0.00/0.0
Cz
ec
Fra
lic
ub
ina
Ch
lia
Au
str
a
0.01/0.0 0.00/0.0
y
0.00/0.0 0.00/0.0
0
Figure 4
Table 2
CMM-based power generation methane mitigation capacity as of 2004 (CME, 2005a,b)
Typical power generation technology parameters (CMOP, 2006)
Parameter
Gas turbines
IC engines
Micro turbines
Typical output range, MWe
1.5–180
1.0–30
0.03–0.25
Average required CMM emissions
cubic feet per day
cubic metres per day
500,000
14,158
300,000
8495
100,000
2832
Output flexibility
fair
good
excellent
Compatibility with VAM
fair
good
unknown
Waste heat recovery
excellent
good
fair to poor
Other benefits
accept lower CH4
concentrations
high efficiency
suitable for decreasing
CH4 production at
abandoned mines
Typical installation cost, $/kW*
650–1000
800–1200
1500–2000
Typical maintenance cost, $/kWh*
0.003–0.008
0.006–0.01
0.003–0.01
*
●
●
●
●
●
●
●
highly case specific
improved on-site power supply reliability;
the modular design accommodates fluctuations in gas
supply;
based on commercially proven technologies;
reduced mine emissions;
IC engines operate on gas at atmospheric pressure and
therefore do not require compressed fuels as do gas
turbines;
the maintenance and parts for IC engines are readily
available;
IC engines can operate on gas with ‘low’ methane
concentrations (~20%).
Companies such as General Motors and GE Jenbacher have
developed IC engines specifically for CMM. As shown in
Table 2, IC engines range in size from around 1 MWe to
30 MWe. IC systems generally require relatively high methane
concentrations (>45%). However, membrane systems have
Power projects using methane from coal mines
been developed which can help to use gases with methane
concentrations of 25–40%. Properly configured carburetors can
allow the use of fuels from 20–100% methane (Mader, 2006).
Methane from coal mines can fluctuate rapidly in
concentration which will affect combustion in a gas engine.
Some gas engine systems, such as those produced by GE
Jenbacher in Germany, combine the mine gas with fuel gas so
that the feed to the engine can be kept relatively constant.
The BHP’s Appin, Tower and West Cliff Collieries in
Australia use IC engines to produce power from CMM for
the local grid and, in order to ensure consistency of supply,
natural gas is used to supplement the CMM when necessary
(US EPA, 2004b).
A similar situation is in operation at the Thoresby Colliery in
the UK. The project produces electricity from 2 x 1412 kWe
Jenbacher engines. The gas produced from the mine must be
11
CMM for power production
pre-heated and passed through a cyclone separator and filter
before entering the engine. The methane content of the gas
being fed to gas engines is commonly monitored on-line in a
continuous manner to ensure a reliable flow of fuel to the
engine. Any fluctuation in the heating value of the gas will
result in a power fluctuation and also a fluctuation in NOx
emissions. Problems such as knocking, misfiring and an
engine shut-down can occur. To avoid this happening, some
plants have control systems which provide an alternative
methane supply (from a natural gas pipeline) to ensure that
the intake fuel can be maintained at a constant concentration
(Schneider, 2003).
Combustion of methane in CO2 requires a minimum CH4
content of 40%. In N2 rich air, this can be reduced to 28%
CH4. Altering the gas content of the intake air could therefore
maximise combustion efficiency according to the methane
content of the mine gas (Schneider, 2003). However, no
examples of this approach to combustion have been found
elsewhere.
According to Mader (2006) CMM for power generation
needs to be removed from the mine with a compressor which
can lead to low pressure in the shaft. The compressor must
create a constant pressure of around 80 mbar which then
channels the gas into a gas engine.
IC engines can generally provide service for over
12,000 hours (over 18 months) before any significant
maintenance is required. Following maintenance, most IC
engines can be placed back into service for a further
8–10 thousand hours before they are retired and replaced
(US EPA, 2004b).
One of the longest running CMM projects using IC engines
is North West Fuel’s project at Nelms No 1 in Ohio, USA,
which has been operational since 1994. Around 6370 m3/d of
methane is produced and used in twelve IC engines to create
675 kW of electricity. The electricity produced (3-phase at
480 V) is used on-site at the neighbouring Nelms Cadiz
Portal mine. Excess electricity is also sold to a local utility.
The installed cost of the generator sets and the utility
required protective relays are less than 800 $/kW. The power
is produced for less than 0.025 $/kWh (US EPA, 2004b).
Several small IC engines rather than one large engine are
commonly used to allow flexibility of output according to the
gas supply available. For example, a total of 94 x 1 MWe
Caterpillar IC engines are used at the Appin and Tower
Project in Australia (see Chapter 3). By having a large
number of small engines, it is simple for the engineers to use
only the units required at the time (CMOP, 2005).The IC
engines used are 16-cylinder Caterpillar G3516 bulldozer
engines connected to a CAT SR4 brushless generator. The
generator sets (‘gensets’) are housed in soundproof sheds.
Each genset is expected to operate for up to 8000 h/y. Each
engine directly drives one 415 V, 1 MWe generator and runs
on 50–85% methane, 0–5% CO2 and up to 50% air. IC
engines were chosen over a turbine system as they were
considered more cost-effective since no gas compression
would be required. The IC engines were also considered to
require less maintenance than a turbine. The modular design
12
Table 3
CMM pojects worldwide (1993-2005),
using Jenbacher AG engines (Hoffman
2006)
Engines
Australia
MW
25
26
2
3
Germany
36
76
Great Britain
23
40
Poland
2
1
Ukraine
14
42
102
188
China
Total
allows for off-site fabrication, ease of relocation and staged
expansion.
As in the case of the Nelms No 1 project, mentioned above,
the electrical energy from IC engines can be used at the mine
itself and/or fed directly into the public network. The
potential for making a profit from this electricity has led to
the development of many ‘off the shelf’ commercial systems
for CMM-to-power projects. For example, Jenbacher
produces various sizes of engines which have been used in
CMM projects worldwide, as shown in Table 3
(Hoffman, 2006).
Most commercially produced engines are supplied in
modular form so that they can be moved from project to
project at minimal further cost. CMM to power generation
units normally comprise (Mader, 2006):
●
a suction plant – a self-contained unit with compressor
inside. The unit also contains controlling switchgear, gas
analysis systems and safety equipment;
●
a cogeneration plant – a sound-proofed container with
the engine generator unit inside, controlling switchgear,
units for heat exchange, cooling facilities and exhaust
gas sound absorber;
●
a transformer station – a container with the transformer
and switchgear to connect to a medium high voltage
grid.
Several companies produce such units which, due to their
flexibility and compact construction, can be delivered and
start operating within one week. Figure 5 shows a photograph
of a typical containerised module of IC engines housed at a
mine in Germany (Mader, 2006).
Sporer (2002) reviewed the use of modular gas engines for
CMM-to-power projects in Germany and concluded the
following:
●
the operation of the engines is dependent on the CMM
quality but is generally satisfactory;
●
availabilities of 96% have been achieved;
●
oil change intervals vary between 500 and 2000 hours;
●
the high levels of sulphur in mine gas can cause
corrosion in the flue gas heat exchangers (no more
information was found on this problem);
●
condensation in the gas train must be avoided.
IEA CLEAN COAL CENTRE
CMM for power production
shown in Figure 6. Some turbines use a reheat combustor to
maximise the combustion and expansion of the gas through
the turbine. The hot exhaust gas is then passed through the
heat recuperator to preheat the incoming compressed air. Gas
turbines are reported to have efficiencies of 21–42%
compared with 12–20% for internal combustion engines
(US EPA, 1998b). Turbines suitable for CMM-to-power
projects are produced by companies such as Caterpillar, who
produce the Solar, Saturn, Centaur, Mercury, Taurus, Mars
and Titan turbines (see Appendix 1).
As shown in Table 2, turbines require high flow rates of
methane but can use methane at lower concentrations than IC
engines. The exhaust gas from turbines is generally hotter
than that from IC engines and this heat can be used as
thermal energy for coal drying, mine heating or to generate
additional heat through cogeneration. Turbines can be used in
combined cycle systems where the turbine exhaust is used as
a power source for a waste heat boiler which generates steam
to run a separate steam turbine which drives another
generator (CMOP, 2005; see Section 2.2.3).
Figure 5
Minegas power unit at Haus Aden,
Germany, housing twelve IC engines
producing a total of 16,000 kWe
(Mader, 2006)
IC engines can be used for cogeneration of heat and power
(see Section 2.2.3) (CMOP, 2005).
In addition to using CMM as the primary fuel, IC engines
can use VAM as the combustion air, thus utilising more
methane and reducing potential greenhouse gas emissions
further. This is discussed in more detail in Section 2.3.2.
2.2.2 Turbines
Turbines operate by compressing air and then injecting CMM
to produce combustion. The resulting hot compressed gas
expands, passes through the turbine and moves the rotors to
produce electricity. The basic operation of a gas turbine is
According to a report by the US EPA (US EPA 1998b), the
benefits of turbines for CMM are:
●
the potential for off-grid self-generation of electricity at
remote gas production sites;
●
the wide range of available sizes (500 kW–25 MWe);
●
the option for cogeneration and combined cycle
technologies;
●
they are ideal for gob gas (minemouth gas) use, as they
can operate on gas with a heating value as low as 350 Btu;
●
they are a reliable and proven technology.
Turbines can use gas with 35–75% methane, although several
organisations are developing lean-burn turbines to use low
quality fuel (<7.5% methane, see below). Continued
improvements in turbine technology, such as greater
efficiency, longer service life, and lower overall maintenance
costs, may mean that turbines will be capable of running on
enriched VAM in the future (US EPA, 1998b).
Turbines are not as popular as IC engines for CMM-to-power
Reheat
combustor
Compressor
Turbine
Exhaust
Air intake
Recuperator
Generator
Intercooler
Fuel (eg methane)
Combustor
Preheated air
Cooling water
Figure 6
How a gas turbine operates (US EPA, 1998b)
Power projects using methane from coal mines
13
CMM for power production
projects. As of September 2005, only a few turbines
worldwide were used for this purpose (CMOP, 2005). Gas
turbines have been used at UK coal mines since the late
1970s and combined cycle gas turbines since the early 1990s
(UK DTI, 2004). The combined cycle plant at Harworth
Colliery, UK, has two producing a total of 7 MWe power plus
exhaust heat that is utilised for a steam turbine. Output from
all three turbines can exceed 12 MWe when supplementary
firing is used. The plant has been operating since 1993
(CMOP, 2005). A turbine is used in the 373 kW
CMM-to-power cogeneration unit at an active mine in Lunen,
Germany. Further turbines (6400 kW) are used at the Mont
Cenis abandoned mine, also in Lunen, Germany (CME,
2002). Australia has two full scale gas-fired power plants
(turbines) which use CMM as a fuel at least some of the time
(see Section 3.1).
In the USA, Consol has two 44 MWe simple cycle turbines
producing electricity for peak demand at the VP/Buchanan
mines. Both VCBM (virgin) and CMM are used and so the
system is very reliable. The large turbines have the advantage
over small IC engines at this plant in that they can be
switched on quickly at periods of peak power generation
(CME, 2002; CME 2005).
Microturbines are smaller versions of the same basic turbine
systems. The US EPA lists the benefits of microturbines as
follows (US EPA, 2004a):
●
the potential for off-grid self-generation of electricity at
remote gas production sites;
●
they are available in 30 kW to 2500 kW systems using
cogeneration technologies such as discharge heat
recovery;
●
they produce low air and noise emissions;
●
they have low installation and operating costs;
●
they are ideal for gob gas use operating on gas with a
heating value as low as 370 kJ (350 Btu).
Microturbines have an efficiency in the range 22–30%.
Microturbines have only one moving part which drastically
reduces maintenance costs and use air-bearing technologies
that eliminate the need for lubricants. They have a high
power-to weight ratio and volume ratio compared to diesel
generators. Exhaust temperatures for a single 30 kW system
exceed 260°C (500°F) with an airflow of 93.0 kg (204.0 lb)
per minute. Natural gas, diesel, gasoline or fuel oil can be
used as a back-up fuel (US EPA, 2004a).
As shown in Table 2, microturbines have a smaller output
range than larger systems. However, they are quiet, compact,
clean and reliable and are suitable for smaller projects. A
photograph of a series of microturbines is shown in Figure 7
to give an idea of scale.
The Akabira coal mine in Japan used five Capstone C30
microturbines of 30 kW (CMOP, 2005). The electricity
generated was used on-site to power facility loads while the
surplus was sold to a nearby factory. Exhaust from the
system was sequestered back into the mine, eliminating
emissions and liberating more methane to power the
microturbine array (US EPA, 1998b). This project has now
been terminated.
14
Figure 7
Microturbines (Schultz, 2006)
Lean-burn gas turbines are being developed to run on CMM
at low methane concentrations. This means that they could
run on VAM or very dilute CMM from working mines. The
available lean-burn systems are summarised in Table 4. The
EDL technology is a recuperative gas turbine which uses heat
from the combustion process to preheat the methane
containing air to the auto-ignition temperature. The
combusted gas is then used to drive a turbine. EDL has
received $11 million to install and operate 4 x 2.7 MWe of
these generators at Anglo Coal’s German Creek mine in
Central Queensland, Australia (Mallett and Su, 2003). The
patented CSIRO system can use a much greater proportion of
VAM compared with the EDL gas turbine (Su and others,
2003). Ingersol-Rand (IR) in the USA is also developing a
microturbine with a catalytic combustor to fire 1% methane
in air (Mallett and Su, 2003).
2.2.3 Cogeneration systems
Cogeneration systems can use either IC engines or turbines to
produce electricity while using waste heat to heat buildings
or mines. Alternatively they can produce steam for
condensing steam turbines or absorption chiller units. Coal
preparation plants can also use recovered steam for
electricity, indirect drying of coal or hot air for direct drying.
Cogeneration systems, also known as combined heat and
power (CHP) systems offer several advantages over simple
power systems (US EPA, 1998c):
●
they can operate at over 80% efficiency using medium
quality gas;
●
they can produce enough on-site electricity to meet the
needs of a typical coal mine;
●
recovered heat can provide heating and/or cooling for
mine facilities;
●
they can produce thermal energy for nearby industries
with boilers or steam turbines.
IEA CLEAN COAL CENTRE
CMM for power production
Table 4
Comparison of lean-burn engines for CMM (Mallett and Su, 2003)
Feature
EDL
Recuperative turbine
CSIRO
Catalytic turbine
IR
Catalytic microturbine
Principles of operation
air heater inside combustion
chamber
monolith reactor
monolith reactor
Catalyst
no
yes
yes
Auto-ignition temperature
700–1000°C
500°C
n/a
Experience
pilot-scale trial
bench-scale study
conventional microturbine
development continuous
continuous
continuous
Cycle period length
Minimum CH4 concentration
1.6%
1%
1%
Applicability
CH4 mitigation and power
generation, need additional
fuel
CH4 mitigation and power
generation, need additional
fuel
CH4 mitigation and power
generation, need additional
fuel
Possibility of recovering heat
feasible (power generation)
feasible (power generation)
feasible (power generation)
Variability of CH4
concentration
constant
constant
constant
Operation
simple and stable
simple and stable
simple and stable
Lifetime
may be shorter due to high
temp
>8000 hours for catalyst and
20 years for turbine
n/a
NOx emission
higher
low (<3 ppm)
low
CO emission
low
low (~0 ppm)
low
Conventional power generation systems operate at
efficiencies of 25–45%. Cogeneration can increase this to
over 80%, depending on the thermal energy use.
Cogeneration plants can range in size from 500 kW up to
500 MWe, with systems producing more heat having higher
efficiencies. The option to sell excess heat and power can
make cogeneration cost-effective and revenue-generating.
Pre-constructed cogeneration plants can be bought and
delivered to a site for installation and be operational within a
relatively short period of time (months). They are designed to
require little maintenance and for remote operation. Systems
in the 1–5 MWe range cost between 600 and 1000 $/kW,
depending on site-specific requirements. These costs are
slightly lower than those quoted in Table 2, possibly due to
the data in Table 2 being more recent (2005). A typical
small-scale cogeneration system would have the following
characteristics (US EPA, 1998c):
●
1.5–4.5 MWe electricity produced;
●
13,607 kg/h (30,000 lbs/h) steam produced;
●
3.45–28.96 bar (50–420 psig) steam pressure;
●
21.1–63.3 kJ/h (20–60 MBtu/h) max fuel use;
●
50–75% system efficiency;
●
20–80 ppm NOx.
Figure 8 shows containerised module options produced by
GAS Energietechnologie GmbH in Germany (Mader, 2005b).
These modules can be bought pre-prepared and delivered to a
site for immediate installation and operation with the size and
Power projects using methane from coal mines
output being selected according to the specific characteristics
of each mine.
According to the US EPA (1998c), most coal mines produce
enough methane to fuel small-scale (1–5 MWe) cogeneration
systems. Around 62% of today’s cogeneration systems are
fuelled by gas. Many more systems using CMM could be
established relatively easily in many mines around the world.
The Zofiowka mine in Poland uses CMM in a cogeneration
plant. The plant provides heat and power to the mine and to
the nearby town of Jastrzebie (see Chapter 3).
2.2.4 Oxidation technologies
The oxidation of methane to CO2 reduces its GWP by over
an order of magnitude. This is enough to make it a useful
process in terms of reducing greenhouse gas emissions.
However, energy is produced during this oxidation which, in
some cases, can be harnessed for useful heat and/or power.
When methane in air is sufficiently heated, oxidation will
take place. The rate of oxidation is slow until the temperature
reaches around 800°C. At around 900°C, all the methane will
be oxidised. This type of oxidation has been used in industry
to clean volatile organic compounds, VOCs, from flue gases
for many years. Recently the technology has been applied to
producing power from VAM (Mattus, 2006).
15
CMM for power production
Module
GCA 8K 616
GCA 12K 616
GCA 2016 V 12
GCA 16K 616
GCA 2016 V 16
GCA 12K 620
GCA 320 GS
GCA 2020 V 12
GCA 16K 620
GCA 420 GS
GCA 2020 V 16
GCA 2020 V 20
Figure 8
Genset
Deutz TBG 616 V 8 K
Deutz TBG 616 V 12 K
Deutz TCG 2016 V 12
Deutz TBG 616 V 16 K
Deutz TCG 2016 V 16
Deutz TBG 620 V 12 K
Jenbacher JMS 320 GS-S, L
Deutz TCG 2020 V 12
Deutz TBG 620 V 16 K
Jenbacher JMS 420 GS-S, L
Deutz TCG 2020 V 16
Deutz TCG 2020 V 20
Electricity
output
337 kW
508 kW
580 kW
678 kW
775 kW
1022 kW
1048 kW
1166 kW
1365 kW
1413 kW
1555 kW
1942 kW
Consumption
914 kW
1340 kW
1446 kW
1795 kW
1928 kW
2545 kW
2692 kW
2793 kW
3393 kW
3375 kW
3724 kW
4728 kW
Dimensions container
(length x width x height)
12.0 m x 2.4 m x 4.0 m
12.0 m x 2.4 m x 4.0 m
12.0 m x 2.4 m x 4.0 m
12.0 m x 2.4 m x 4.0 m
12.0 m x 2.4 m x 4.0 m
12.0 m x 3.0 m x 4.4 m
12.0 m x 3.0 m x 4.4 m
12.0 m x 3.0 m x 4.4 m
12.0 m x 3.0 m x 4.4 m
12.0 m x 3.0 m x 4.4 m
12.0 m x 3.0 m x 4.4 m
12.0 m x 3.0 m x 4.4 m
Containerised cogeneration modules for CMM-to-power projects (Mader, 2005b)
VAM is difficult to use as an energy source as the methane is
dilute and variable in concentration. Technologies such as
TFRR – thermal flow reversal reactors, function by
maintaining the core temperature above the auto-ignition
temperature of methane and can thus run at methane
concentrations as low as 0.3%. Catalytic versions of this
technology – CFRR, can work with methane concentrations
as low as 0.1%. Both TFRR and CFRR systems can cope
with the variability of methane concentrations in VAM due to
their thermal inertia (Su and others, 2003). A third oxidation
technology is CMR – catalytic monolith reactor. This system,
produced by CSIRO in Australia, is compared with TFRR
and CFRR in Table 5.
Heat can be recovered from these oxidation systems but they
are prone to instability because of the methane concentration
variation. This makes it difficult to maintain the working
16
Thermal
rating
442 kW
642 kW
388 kW
857 kW
785 kW
1156 kW
1310 kW
1233 kW
1548 kW
1525 kW
1645 kW
2035 kW
fluid that recovers the heat at a constant temperature and flow
rate (Su and others, 2003).
MEGTEC is a TFRR system which does not use a catalyst.
The system comprises a flameless single bed, regenerative
oxidiser which can oxidise low (<1%) methane
concentrations in large volumes of air flow. There is no
generation of thermal NOx. As shown in Figure 9, the unit
consists of a well insulated steel container with a bed of
ceramic material inside. There is an air plenum above and
below the ceramic bed. At the start of the process, the
electrical coils are used to heat the centre of the ceramic bed
to 1000°C. The coils are then shut off and a fan blows the
coal mine ventilation air vertically through the ceramic bed.
Since the system is well insulated, the ceramic bed retains its
heat and the methane in the air is oxidised. This oxidation
process itself releases heat – this helps to maintain the bed at
IEA CLEAN COAL CENTRE
CMM for power production
Table 5
Comparison of VAM oxidation technologies (Mallett and Su, 2003)
Feature
MEGTEC
TFRR
CANMET CH4min
CFRR
CSIRO
CMR
Principles of operation
flow reversal
flow reversal
monolith reactor
Catalyst
no
yes
yes
Auto-ignition temperature
1000°C
350-800°C
500°C
Experience
600+ units, some operating
on methane
bench-scale trials with
simulated mine exhaust
bench-scale study
Cycle period length
shorter
longer
continuous
Minimum CH4 concentration
0.2%
0.1%
0.4%
Applicability
CH4 mitigation
CH4 mitigation
CH4 mitigation
Possibility of heat recovery for
power
need additional fuel
need additional fuel
need additional fuel
Variability of CH4 concentration
variable
variable
variable
Plant size
huge
larger
compact
Operation
complicated
complicated
simple
Lifetime
n/a
n/a
>8000 hours for catalyst
NOx emission
high
low
low (<1 ppm)
CO emission
low
low
low (~0 ppm)
20°C
1000°C
60°C
Figure 9
MEGTEC oxidiser (Mattus, 2006)
the temperature required to continue oxidation. In order to
keep the heat zone centered in the ceramic bed, the direction
of air flow is changed every few minutes. Since more heat is
produced than is required to maintain the bed temperature,
the excess heat can be retrieved by embedded steam tubes in
the ceramic centre. The steam is separated in a steam drum
and recirculated in another set of embedded tubes creating
superheated steam which is suitable for a conventional steam
turbine (Mattus, 2006). A photograph of an operational
MEGTEC system is shown in Figure 10 (Schultz, 2006).
It is estimated that, with the MEGTEC system, the energy
from the VAM from a typical coal mine (800,000 m3/h) could
produce around 70 MWth (thermal energy). With a total
efficiency of 30%, this would convert to around 20 MWe
(Mattus, 2006).
The first MEGTEC installation at a coal mine was in the UK
Power projects using methane from coal mines
Figure 10 MEGTEC system (Schultz, 2006)
in 1994 where it ran for around six months at 3 m3/s (CMOP,
2006). Over 8000 m3 of VAM with a methane concentration
of 0.3–0.6% methane was oxidised. The second installation
was at the Appin Colliery in Australia between 2001 and
2002. During the 12 months of operation, 6000 m3 of VAM
was treated with 90% heat recovery. In 2005, this temporary
demonstration project received the award Best Greenhouse
Gas Project funded by ACARP (Australian Coal Association
Research Programme) (Mattus, 2006).
The first permanent full-scale MEGTEC VAM oxidisation
system is being installed at BHP Billiton West Cliff Colliery
17
CMM for power production
of the CH4min system which suggested that the technology
would be financially viable even if used only for methane
destruction if CO2 credits are over 6.0 US$/t. The cost of
actually producing electricity with the system is
1.97 US$/kWh, although this would be reduced to
1.15 US$/kWh if a credit rate of 1.5 US$/t of avoided CO2 is
assumed. A project has been proposed to install a commercial
CH4min plant alongside a cogeneration plant in China. The
system could oxidise methane equivalent to 117,500 t CO2/y
and recover 7 MWth energy, including 2 MWe energy through
the cogeneration plant. Although sulphur contamination of the
catalysts in CFRR may be a potential problem, no information
was found on this subject in the literature.
For both CFRR and TFRR systems, the simplest and least
capital-intensive option for producing energy from VAM is to
produce thermal energy for local uses such as (CMOP, 2006):
●
district heating;
●
industrial process heating;
●
coal drying;
●
mine wastewater desalination;
●
heating ventilation air inflows during winter months.
Figure 11 CANMET CFRR system (Schultz, 2006)
in Australia. The large-scale demonstration plant will
generate 6 MWe from the <1% methane ventilation air from
the mine shaft. This will reduce methane emissions
corresponding to 200 kt CO2-e/y. The project is partially
funded by ACARP under the Australian Government’s
Greenhouse Gas Abatement Programme with a grant of up to
A$6 million. Four Vocsidizer units were installed at the site
in July 2005 and the steam turbine was installed in
September. Start-up of the power plant is expected in 2006
(Mattus, 2006).
CANMET (Canadian Mineral and Energy Technologies), of
Natural Resources Canada, have developed a CFRR system
called CH4min, as shown in Table 5. As mentioned above
CFRR is of the same principle as TFRR except that the
reaction involves a catalyst and therefore can take place at
lower temperatures. This results in a more stable reaction and
longer cycle times.
For a typical coal mine ventilation air content of 0.5% v/v
methane, the heat recovery efficiency can be 75%, although it
is lower at lower methane concentrations. Methane as low as
0.1% can be eliminated with no requirement for external
heat. The system can operate at a high airflow rate –
30–50 m3/s ventilation air (Grou, 2004). It is estimated that a
full-scale CH4min reactor could produce 115 kt CO2-e
reduction per year while producing 200,000 GJ/y of
‘pollution free’ energy (SO2 and NOx emissions are claimed
to be ‘low’). A photograph of the CANMET system is shown
in Figure 11 (Schultz, 2006).
Sapoundiev and others (2003) carried out an economic analysis
18
If the oxidation systems were used as an unfired boiler with a
condensing turbine, the overall efficiency would be limited to
15–20% because of the pressure limitations and lack of
superheat. If other fuels are available to superheat the steam
then the efficiency could reach 25%. However, the preferred
energy production option is likely to be a gas turbine
operating in a cogeneration mode by recovering waste heat,
as shown in Figure 12. This could produce efficiencies of
28–35% when operating under design conditions. To produce
the most efficient system, supplementary fuel such as CMM
would be used to raise the working fluid temperature to
design levels (CMOP, 2006).
CMOP produced an excellent review of TFRR and CFRR
technologies and the interested reader is referred to this
document for further information (CMOP, 2006). The report
concluded that CFRR may be the more promising technology
since it can sustain operation at a lower concentration.
However, supplementary information from MEGTEC
suggests that TFRR may be just as efficient in practice
(Mader, 2006).
The CMOP (2006) study also included a detailed economic
analysis of theoretical plants based on TFRR combined with
either a gas turbine cogeneration or a waste heat boiler. Both
projects appeared to be in or close to the profitability range
when operating in appropriate energy markets and taking into
account credits for greenhouse gas emission reductions.
Except in the situation where the technologies were
combined with an unfired cogeneration system, the model
suggested that most options were resilient to selected
unfavourable changes in major revenue, cost, or methane
supply assumptions. However, in all cases, carbon credits
lifted each project into the profitability range and, if credits
were unavailable, the projects would not be economically
attractive.
Bulat and Zaloznova (2003) considered the use of VAM from
the Skochinsky mine in the central Donbass, Ukraine, in a
IEA CLEAN COAL CENTRE
CMM for power production
Gob gas to combustor (optional)
Ambient air
Electricity
Compressor
Turbine
Generator
Air (and products of combustion)
Heated
compressed
air
Waste
heat boiler
Steam or hot water
Air (and products of combustion)
Vent air
Heat exchanger
Oxidiser (TFRR or CFRR)
Figure 12 Schematic of a cogeneration system incorporating an oxidation system (CMOP, 2006)
TFRR. Capital outlays were estimated at 250 $/kWth and the
profit would be $37.8 per 1000 m3. The payback period
would be 6.4 years if the flow is 100 m3/s and the methane at
0.5%. If a carbon credit of 1.5 $/t CO2-e is taken into
account, the payback would be reduced to 3.7 years.
2.2.5 Fuel cells
To date, there has only been one project using CMM in a fuel
cell. Fuel Cell Energy Inc (FCE) have constructed a
demonstration plant in conjunction with the US Department
of Energy (US DOE) National Energy Technology
Laboratory (NETL). The project was run with Northwest
Fuel Development, the operator of the Rose Valley test site in
Hopedale, Ohio, USA (Steinfeld and Hunt, 2004). The plant
was a first generation sub-megawatt plant running on CMM.
A deoxidation catalyst was installed to remove the oxygen
expected in the CMM. The system was a direct carbonate
fuel cell with 341 cells of 0.84 m2 area, stacked horizontally.
The unit operated at 590–650°C with a fuel utilisation of
68%. Figure 13 shows a simplified flow diagram. The CMM
Coal mine methane
Fuel
clean up
Anode exhaust oxidiser
Water
treatment
Humi-Hex
Water
Exhaust
CO2 + air
Deoxidiser
pre-reformer
Anode
-
Cathode
+
DC to AC
inverter
Figure 13 Simplified process flow diagram for a CMM fuel cell (Steinfeld and Hunt, 2004)
Power projects using methane from coal mines
19
CMM for power production
gas enters the plant and sulphur is removed in two carbon
beds. Deionised water and desulphurised fuel are used in a
humidifying heat exchanger to dehumidify the gas. The fuel
then flows into a deoxidiser to remove any oxygen, a preconverter to remove higher hydrocarbons and then into the
fuel cell stack module.
The test ran from 1 August 2003 until 13 December 2003 for
a total of 1456 hours on-load. The power produced,
134 MWh, was connected to the American Electric Power
grid by a 69 kV transformer. The plant used 42%, low Btu,
CMM. The maximum power level achieved was 140 kW and
the efficiency of power generation was 40%, based on the
lower heating value (LHV) of the CMM. When the CMM
was compressed and dried, the efficiency was reduced to
36% LHV. By comparison, the IC engines running on CMM
at the same site ran at an overall efficiency of 20%. The
efficiency of the fuel cell was 80% higher than the IC
engines. If the fuel cell plant were to become fully
operational at 250 kW, over 520,000 m3 of methane would be
used per year, equivalent to avoiding 7428 t of CO2-e
(Steinfeld and Hunt, 2004). More details can be found on the
NETL website (NETL, 2003).
2.3
Cofiring
Natural gas is often used as an additional fuel in solid fuel
boilers to increase the efficiency of combustion and reduce
pollutant emissions. CMM can provide a cheap alternative to
natural gas. The use of CMM as a supplementary fuel in
full-scale boilers, industrial units and steel manufacture is
discussed in Section 2.3.1. Section 2.3.2 discusses the use of
VAM as a replacement for the intake air of boilers.
2.3.1 CMM as additional fuel
As mentioned in Section 2.2, CMM can be cofired with
natural gas in IC and turbine based power systems. CMM can
also be cofired with solid fuels in utility and industrial
boilers. Using CMM with coal in a coal-fired boiler is a
simple way of increasing output and, in some situations,
reducing pollutant emissions. The US EPA (1998d) list the
advantages of this approach as follows:
●
it reduces pollutant emissions (SO2, NOx, CO2 and
methane);
●
it reduces operating and maintenance costs, improves
stack opacity (visual emissions of particulates and light
absorbing gases) and ash quality;
●
it is ideal for medium-quality (below pipeline
specification) gas from gob areas;
●
it is commercially proven using conventional natural gas
in the USA and elsewhere;
●
it is commercially proven with CMM.
Gas, including CMM, is a convenient cocombustion fuel as it
requires little or no storage or preparation for combustion. It
contains no ash, little or no sulphur and is low in nitrogen
and therefore can help reduce pollutant emissions. In 1998
the US EPA produced a report which showed that cofiring
CMM could reduce particulate, SO2 and NOx emissions.
20
Cofiring with CMM improves carbon burnout and
combustion efficiency. By carefully selecting where to inject
the CMM, problems such as slag-build-up and slow boiler
start-up can be improved. CMM can also replace more
expensive start-up fuels such as oil. The cost of retrofitting
for CMM injection is ‘low’ with investment being repaid
within 1.4 to 3.1 years (CME, 1998).
Not only does the CMM provide inexpensive additional fuel,
it can also reduce costs in other ways:
●
improvement in plant operation and efficiency of
combustion can save 0.085 $/GJ (0.09 $/MBtu);
●
reduction in SO2 emissions may be equivalent to
0.057 $/GJ (0.06 $/MBtu) (at 1998 prices for trading in
the US);
●
reduction in NOx emissions may be equivalent to
0.52 $/GJ (0.55 $/MBtu) (at 1998 prices for trading in
the US);
●
reduction in coal requirements can save 1.23 $/GJ
(1.30 $/MBtu).
The total reduction in costs is therefore almost 1.9 $/GJ
(2.00 $/MBtu) (CME, 1998).
Table 6 shows the predicted benefits of cofiring CMM at
several utility and industrial boilers in the USA. Clearly the
use of CMM would be beneficial in the long-run for all the
plants shown in the table. The distance the CMM would have
to be transported to the boiler is an important issue and this
must be factored into any proposal. No information was
found on the practical limitations of methane delivery. More
than 370 coal-fired boilers in the USA have the capability to
cofire and, in 1995, more than 2 billion m3 of conventional
natural gas was used for ignition, warm-up and load carrying.
Despite the report, it seems few, if any, plants in the US have
adopted CMM for cofiring.
Gassy coal mines in China, the Czech Republic, Poland,
Russia and the Ukraine have used CMM for cofiring with
coal at their on-site boilers to produce heat and/or electricity.
Mines can also pipe methane to nearby plants or industries
for cofiring (US EPA, 1998d).
Mallett and Su (2003) reviewed the use of CMM as a
subsidiary fuel in combustion systems firing coal
waste/tailings. CSIRO in Australia are developing a system
which will fire waste coal with CMM and recover waste
energy for power generation. The waste coal will be
combusted with the CMM in a rotating kiln. It is thought that
the drainage gas flame from the mine could be used to
stabilise the combustion process inside the kiln. A 1.2 MWth
kiln has been used for preliminary tests which indicate some
problems with stability of the combustion. It is thought that
fluidised bed combustion (FBC) systems may be better suited
for such cocombustion of coal waste with CMM. FBC
systems use a turbulent mix of gas and solids during
combustion and typically burn at lower temperatures
(800–950°C) than conventional coal-fired units. At the
moment, there have been no experimental studies performed
which prove that methane could be fully oxidised in an FBC
system, even though this would be expected. Further work is
needed (Mallett and Su, 2003).
IEA CLEAN COAL CENTRE
CMM for power production
Table 6
Industrial boiler case studies cofiring CMM (US EPA, 1998d)
Industry/Plant
Dover Light and Power,
17 MWe
Oberlin College
The Hoover Company
Boiler type (all stoker), kg/h
74,843
18,144
34,019
% of gas cofired
8–15
20
40
Benefits (emission reduction, improved
operation, efficiency), $/GJ ($/MBtu)
0.28 (0.29)
1.58 (1.67)
1.14 (1.20)
Costs (fuel price increase, annualised
capital cost), $/GJ ($/MBtu)
0.14 (0.15)
0.49 (0.52)
0.74 (0.78)
Net cost savings, $/GJ ($/MBtu)
0.13 (0.14)
1.09 (1.15)
0.40 (0.42)
Payback (simple), y
1.4
1.8
3.1
Benefits realised
–
–
–
–
– eliminated use of
separate boiler for low
steam demand periods
– improved efficiency
–
–
–
–
efficiency up 3–4%
particulates down 33%
recovered lost capacity
clean, fast light-off
Circulating fluidised bed combustion systems (CFBC) are
relatively common in Japan. It has been shown that in such
systems, CMM can be fired along with low calorie coal
whilst reducing emissions of other pollutants at the same
time (M2M, 2005).
Cummings (2003) described a fuel injected gas turbine
system (FIGT) which uses VAM (at around 1.6% methane)
for use as either a primary fuel or as a secondary fuel for
combustion alongside coalmine tailings in an advanced
integrated drying and gasification system. Cummings
estimated that the global market for such systems for VAM
could be as much as 25,000 MWe, with 33% efficient
systems and ventilation air supplying 40% of the turbine fuel.
A Centaur 3000R turbine, fitted with the FIGT system has
been installed at the Appin mine site in New South Wales,
Australia.
CMM can also be used as a supplementary fuel in blast
furnaces with the following advantages (US EPA, 1998e):
●
reduced coke usage and improved furnace stability;
●
increased iron-making productivity and reduced
operating costs;
●
reduced air pollution from coke;
●
reduced requirement for more expensive natural gas.
Most blast furnaces inject some form of supplemental fuel
such as natural gas, coke oven gas or coal to form additional
CO and hydrogen for combustion and chemical reduction of
the iron-bearing materials into molten iron. Natural gas
consumption can reduce coke consumption by up to 30%
whilst increasing iron-making production by 40%. The use of
natural gas also decreases pollutant emissions. CMM could
easily be substituted for natural gas in such situations,
although it would need to have a low sulphur content and
contain at least 94% methane. At the moment, there do not
seem to be any examples of where this use of CMM has been
Power projects using methane from coal mines
emission reductions
load following capability
improved opacity
gas-only start-up
applied in practice. It is suggested that the installation of a
pipeline for CMM delivery to such furnaces would not be
economically viable. However, in a situation where a blast
furnace was located close to a gassy mine, the economics
may be far more favourable (US EPA, 1998e).
2.3.2 VAM as intake air
Perhaps the simplest application of VAM for power
generation is as combustion air in conventional coal-fired
plants. VAM from the mine shaft can be delivered via simple
pipeline to the intake air at an adjacent coal-fired power
plant. A ventilation shaft emitting over 55,000 m3/d methane
could supply enough combustion air for a minemouth,
coal-fired plant rated at around 125 MWe (CMOP, 2005).
Although inexpensive and simple, this approach is very
limited in application in that it will only work in situations
where a coal mine is located close to a power station. Further,
some plants may express concern over the stability of
operation of the plant with fluctuating methane
concentrations. It is possible that a rapid increase in methane
concentration from 0% to 0.8% could result in flame
instability leading to an explosion. There is also the
possibility of damage to the boiler from excessive
combustion temperatures, slagging and fouling. These
negative effects could be limited if the methane concentration
of the intake could be controlled or managed (Mallett and Su,
2003).
Bulat and Zaloznova (2003) considered the use of VAM from
the Skochinsky mine in the central Donbass, Ukraine, as
intake air in the mine power system. The power system can
use CMM from degasification wells which is delivered to the
gas burners of the steam-boilers which are CFBC systems.
The boilers can also take VAM as the intake air. The mine air
is at 27.2°C with a methane content of 0.5%, a calorific value
21
CMM for power production
of 35.82 MJ/m3 (8555 kcal/m3), a relative humidity of 100%
and air consumption at 170 m3/s. The use of VAM as intake
air for the CFBC boilers will save around 60 kt coal/y and
provide an annual profit of $878,000 during the 8400
working hours of the power system. In addition, the flow of
VAM provides heat to the mine saving a further 11.3 kt
coal/y and increasing the total reduction in cost of the mine
to $1 million. The greenhouse gas reduction would be
353 kt CO2-e/y. At a credit rate of 1.5 $/t CO2-e this would
mean an additional profit for the mine of 530,000 $/y.
Emissions of SO2, NOx and particulates from the power
system would also be reduced by 16.5%. No mention was
made of any potential problem incurred by any pressure drop
from using VAM in this way.
The US EPA CMOP has reviewed the possibility of using
VAM as combustion air in IC engines (CMOP, 2006). This
approach has already been used in the BHP Appin project
discussed in Section 2.2.1. VAM (0.3–0.7% methane) is used
as the intake air to the engines and supplies between 4% and
10% of the engine fuel whilst consuming around 20% of the
VAM emissions from the mine. A diagram of the system is
shown in Figure 14. There are no fans taking the VAM to the
engines because the turbochargers on each engine have
enough suction power to overcome any pressure loss through
the system. The inlet to the duct is a collection hood sited
1.52 m above the discharge of the mine ventilation fan. An
electronic control system is used to balance the volume of
drained CMM, VAM and natural gas in the engines to ensure
they run efficiently. The use of VAM is economic for the
plant, saving up to 10% of natural gas purchased and saving
US$200,000 per year. The extra power produced also
produces revenue – a 10% increase during off-peak periods at
20 US$/MWh would produce 54 US$/h. If running for
4400 h/y, this means an annual increase of US$240,000.
Installation of the ventilation air transport and processing
system was around $500,000, therefore the payback was just
over one year. Powercoal in Australia is considering a direct
connection between mine ventilation fans and forced draft
fans at an existing adjacent coal-fired plant. The VAM will be
fed at around 220 m3/s into the intake of a power station
(CMOP, 2006).
Gas turbine systems can use VAM but generally the VAM
provides only a small percentage of the turbine’s fuel. The
use of VAM for combustion dilution and cooling of the
turbine in normal industrial systems will actually result in a
significant fraction of the methane passing through the
Ventilation air
0.7% CH4
Primary fuels:
CMM (in seam and gob gas)
Natural gas (when necessary)
turbine without combusting. If an operator were to use VAM
with a Solar turbine the company would insist that the VAM
methane content remain below 0.5% to maintain the unit’s
cooling system. A higher concentration could support
combustion and cause a dangerous temperature increase in
the interior of the rotor (Mallett and Su, 2003).
The US DOE have studied the possibility of using VAM
(<1% methane) as combustion air in gas fired turbines and
the results were reviewed and summarised by the US EPA
CMOP (CMOP, 2006). It was found that auto-ignition can
occur inside the rotor when the saturated ventilation air reacts
with methane in the presence of nickel alloys, forming
combustible amounts of hydrogen and CO. This auto-ignition
occurs quickly (less than one millisecond) and causes an
increase in turbine external and internal temperatures. Further
research was suggested to determine just how severely this
would affect turbine operation (CMOP, 2006).
If the methane concentration in the VAM combustion air
remains below <0.5%, CO is unlikely to ignite in the rotor
and this will lead to increased emissions of CO and unburned
hydrocarbons. This could be dealt with by converting to
cogeneration (fitting a supplementary-fired heat recovery
steam generator producing steam as a by-product) or to
combined cycle (fitting a supplementary-fired heat recovery
steam generator to a steam turbine generator to produce
additional electrical power). Alternatively, a catalytic
oxidation system may have to be fitted as a post-combustion
pollution control option (CMOP, 2006).
If the methane concentration of the VAM fluctuates then an
additional air inlet may be required with controls to ensure
that the methane content does not exceed 0.05%. If the VAM
air is used to pressurise the oil return system then there is a
chance that methane could dissolve in the oil and decrease
the lubrication. Gas stripper systems would need to be
installed to remove the dissolved methane. Methane in the
exhaust of this would be explosive and would require flame
traps to ensure against ignition. VAM air may also contain
coal fines which would need to be removed by a commercial
wet scrubber.
The amount of VAM used can be increased to conserve the
cost of primary fuel but, due to the problems discussed
above, the rotor temperature would have to be reduced and
this lowers the turbine efficiency and output making the
approach uneconomic (CMOP, 2006).
No references were found relating to the possibility of using
VAM in air-blown gasifiers.
2.4
Exhaust fan
Ventilation shaft
IC engine-generator
Figure 14 Schematic diagram of VAM and CMM use
in IC engines at the Appin Project,
Australia (CMOP, 2006)
22
Selecting the most appropriate
technology
As implied throughout this Chapter, the selection of the most
appropriate use for CMM at any mine will be on a
case-by-case basis and very dependent on the particular
qualities of the gas and the local market. Decisions on what
type of plant would be made based on several factors
including (CMOP, 2006):
IEA CLEAN COAL CENTRE
CMM for power production
●
●
●
●
●
●
projected gas flow rate;
gas heating value (average methane concentration);
duration of gas production;
noise, air and water pollution constraints;
installation and maintenance costs;
market – for example, use at mine, sale to grid, space
heating, cooling for deep mining.
If the methane is of high quality and high concentration then
perhaps the most obvious market is as a replacement for
natural gas in a national or local pipeline. However, this
option would only be economically viable if there was a local
network near enough to connect to without having to provide
long connection pipes. The quality and supply of the gas
would also need to be guaranteed in most situations and this
option may be too onerous for some mines to consider.
As discussed in Section 2.2, medium quality gas (>40%
methane) can be used to generated electricity in IC engines or
turbines. According to CMOP (2006), IC engines are the
most popular choice for methane-to-power projects and, in
many cases, are the default option for such projects.
Cogeneration systems, which make the most of both
electrical output and waste heat may offer the most efficient
use of CMM but, unless the waste heat can be harnessed
efficiently for local use, the extra expense used to capture it
will be wasted. Further, the sale of electricity to local users or
to the grid will only be worthwhile if the profit made from
selling the electricity is greater than the cost of producing the
electricity. So the choice of CMM-to-power system will have
to be made on a case by case basis based on the CMM
production, location, available equipment and markets for the
electricity and/or heat produced. Plus there will need to be an
initial significant investment in installing the power systems
and, in some situations, there is simply no interest in
investing in such new technology which may not provide an
immediate financial return.
Schultz (2006) has studied the potential for successful
CMM-to-power projects under different scenarios and
suggests that the amount of gas available is a major factor is
deciding which utilisation option would work best. For small
CMM projects, producing less than 5 Mm3/y, the most
appropriate options are local/mine heating and/or small-scale
on-site power generation systems. Production at greater than
5 Mm3/y opens up the larger options of large scale power
generation or pipeline uses. Schultz (2006) breaks down the
factors which will decide the technical feasibility of a
CMM-to-power project into the following considerations:
●
reliability of the gas supply: fluctuations will limit the
capacity of the plant and any threat of mine closure will
affect future economics;
●
reliability of the gas quality: reduces the technical
options and increases the cost of gas treatment;
●
hardware choices: local options may be cheaper but
international options may be more reliable. Servicing
skills and spare parts must be available locally;
●
project management: skills must be available locally and
contractors must be legitimate. A developer may charge
significant equity to manage a project;
●
local customers: local monopolies or problems with
pipeline access will reduce the choices available. The
Power projects using methane from coal mines
●
local customers must have the ability to pay through the
lifetime of the project;
finance: perhaps the most difficult factor – who will pay
for the project?
Kirchgessner and others (2002) used a mathematical model
to perform an economic analysis of the most appropriate uses
of CMM in various coal fields in the USA. Although the
results of the study were specific to the US coal fields, the
following general conclusions were drawn which are
applicable to most situations:
●
highest returns are achieved when existing technologies,
such as in-place degasification systems, are used as this
assures lower additional capital costs and minimal
changes in normal methane control practices;
●
on-site power generation with gas turbines offers better
economic performance than pipeline gas injection if the
gas requires enrichment. However, this is also
dependent on the ability of the site to use all the power
generated by the turbine and the ability to sell excess
power at the assumed rate of 50% of the electricity
purchase price;
●
multizone vertical wells provide better economic
performance at seven of the nine mines examined. This
is due to the significant amount of gas that can be
recovered from multiple seams. However, this
technology usually requires significant capital outlay and
longer investment periods;
●
gas injection processes, currently under development to
increase methane production, have high capital and
operating costs and are not likely to be as economically
viable as other, well-utilised, technologies.
Bulat and Zaloznova (2003) compared different utilisation
technologies for CMM in the central Donbass, Ukraine. The
estimates were based on capital outlay per kW of rated
capacity, profit per 1000 m3 of pure methane, period payback
and rate of equipment use. The study also took into account
the loss of capacity with variations in air temperature at
input. Gas turbines lose 1% of capacity per 1°C drop in
temperature whereas IC engines lose only 0.4%.
Cogeneration systems utilising the waste heat were also
considered in the study. Table 7 was produced which
compares the different plant options with their outlay,
potential profit and payback timescale. The study concluded
that gas engines would be superior to gas turbines due to
higher efficiency (37.0% for available IC engines compared
to 28.5% for gas turbines). Gas turbines also required a
greater capital outlay and a longer payback period (>4 years).
Cogeneration systems were the most cost-effective options
being both inexpensive and profitable.
The study considered options for the
Krasnoarmeskaya-Zapadnaya (Donbass) mine. The CMM
degasification rate is 120 m3/min with a methane content of
around 40%. Maximum energy used by the mine itself is
14 MWth. Installation of IC engines totalling 4 MW
electrical capacity and 4.4 gcal/h heat capacity would provide
32 million kWh of electric power and 35.2 thousand gcal of
heat. Prime cost of the electricity is 0.009 $/kWth. The
saving in coal requirement at the mine would be 8000 t/y.
This all gives an annual profit of $1 million and a payback on
23
CMM for power production
Table 7
Comparison of CMM use options (Bulat and Zaloznova, 2003)
Plant type
Capital outlay, US$/kWt
Profit per 1000 m3
Payback period, years
480,000
37,000
4.25
313,000
56,000
2.38
247,000
98,000
1.86
259,000
92,000
4.00
259,000
105,000
2.05
Methane-fired gas turbine
Without cogeneration
Methane-fired IC engines
Without cogeneration
Methane-fired IC
With cogeneration
CMM-fired IC engines
Without cogeneration
CMM-fired IC engines
With cogeneration
investment of 1.5 years. Pollutant emissions from the mine
boiler-house would also be reduced by 30%.
2.5
Comments
There are several different options for using CMM or VAM
for profit. High quality gas can be used as a replacement for
natural gas in gas pipelines whilst medium quality gas can be
used as a combustion fuel in internal combustion engines and
turbines. CMM can be cofired with natural gas, coal, waste
coal and even in steel furnaces to provide an additional fuel
source whilst, in most cases, reducing pollutant emissions.
The most efficient of these are cogeneration systems which
harness both the power and heat produced. Even low quality
VAM (<1% methane) can produce power either through
oxidation or by providing a further source of fuel in the
intake air of combustion plants.
The choice of which utilisation option is most appropriate for
each mine depends on the quality of the gas, the availability
of local markets for heat and/or power, the state of the
thermal energy market and the investment capability. To
ensure the maximum return at each potential CMM project,
each option would need to be considered and the decision
made on a case by case basis. Chapter 3, to follow, lists the
CMM-to-power projects currently in operation around the
world.
24
IEA CLEAN COAL CENTRE
3 Projects in operation worldwide
Many countries have established CMM-to-power projects. A
previous report from IEA CCC (Sloss, 2005) reviewed the
action being taken by different countries to promote CMM
activities worldwide. Some countries are setting up projects
under international agreements such as the Kyoto Protocol or
the EU Emissions Trading Scheme (EU ETS). Others are
developing CMM-to-power projects to broaden the national
power supply and promote green energy. This chapter lists the
projects under way around the world and, as much as possible,
indicates why the project suited the location. Although pipeline
gas injection is included, the following sections concentrate
largely on projects utilising CMM for power generation at or
close to the mine itself and with CMM as the primary fuel.
3.1
Australia
Outside the USA, Australia is the larger producer and user of
VCBM. Queensland first saw commercial production of
pipeline quality gas in 1996 (M2M, 2005). Most of the
activity is in New South Wales (NSW) and Queensland,
although exploration is under way in Victoria. For example,
at the Moura Colliery, Queensland, CBM is drained several
years in advance of mining and around 3 PJ of methane is
supplied to the regional gas transmission line. The production
is scheduled to increase to up to 6.9 PJ methane per year and
so the Cleaner Energy Strategy in Queensland is promoting
the use of CMM as a replacement for natural gas. Enertrade
is establishing a gas pipeline in the area which may be
extended into the central and southern parts of the Moranbah
coalfields. Further extension to the pipeline could mean that
CMM from Grosvenor and North Goonyella fields could also
be fed into the system (AG, 2005).
Total emissions of methane from coal mining activities in
Australia amounted to 18.4 MtCO2-e in 2000. Australia is
currently the most active country with respect to developing
new and innovative power generation from CMM. As shown
in Figure 3, after Germany, Australia has the largest capacity
of CMM-based power generation. The continuing success of
the Australian CMM projects is due largely to the positive
and active role played by the Australian government in both
promoting and funding CMM projects (Sloss, 2005). The
Australian Government has awarded A$30 million
(US$21 million) specifically to CMM projects. Over and
above this, COAL 21 has been established. Coal 21 is a
collaborative partnership between government, industry and
the research community to address greenhouse gas emissions
from the coal sector. This project has identified CMM
recovery as an important and viable greenhouse gas
abatement option (US EPA, 2005). At the moment there are
between 10 and 15 projects at active mines ranging from
simple flaring to power generation, pipeline injection and
VAM oxidation. The US EPA Methane to Markets Project
(M2M, 2005) reports that there are around 11 CMM and
VAM projects in Australia which are mitigating a total of
over 455 Mm3/y methane. Through these, almost 170 MWe
of power is being generated.
Power projects using methane from coal mines
The largest CMM-to-power projects in Australia are
full-scale power plants. Enertrade won the contract to convert
the Transfield Services 160 MWe open cycle peaking plant at
Yabulu, North Queensland, into a 220 MWe CMM-fired base
load power station. The plant, previously fired by kerosene
(Jet A1), was converted through alteration of the existing
turbine to run on natural gas and the addition of a heat
recovery steam generator which uses exhaust heat from the
gas turbine to drive an 80 MWe steam turbine. The project
cost $115 million and was completed February 2005 (AJM,
2004; QGMJ, 2005).
Oakey Power Station, completed in 2000, is located 150 km
to the west of Brisbane. It is the newest of Enertrade’s two
peaking plants. The plant is powered by two Siemens V94.2
gas turbines and this ensures that it is a fast starting peaking
plant which can be operated either on natural gas or liquid
fuel. Much of the gas used at this station is sourced from coal
seam methane produced from the Oakey 1 and Oakey North
coal mines situation on either side of the plant. The plant can
provide up to 320 MWe, and is owned and operated by
Oakey Power Holdings Pty Ltd (AJM, 2004; QGMJ, 2005).
Australia has also established several CMM-to-power
projects using IC engines. During the 1990s a significant
CMM project was established at the BHP Billiton Appin and
Tower collieries in NSW. The project involves 94 x 1 MWe
Caterpillar 3516 engines generating power from 651,000 m3
methane per day. In addition, 54 of the engines can utilise
mine ventilation air at less than 1% methane as combustion
air. These 54 engines are sited at the Appin Colliery part of
the project. Mine design at the Tower Colliery prohibits the
use of this approach at the remaining IC engines. The
methane content feeding the generators ranges from 50% to
80%, 0–5% CO2 and up to 50% air. A diagram of the project
is shown in Figure 15. The modular design of the unit is
typical of IC engine based systems (see Chapter 2) and
allows for ease of relocation and staged expansion as and
when necessary. The project as a whole captures half of the
mine’s methane emissions, equivalent to almost 3 Mt
CO2-e/y making it one of the largest greenhouse gas projects
in Australia (US EPA, 2005). The project is still running as a
94 MWe power station, although between 4 and 9 MWe is
fed back from the utility grid to meet the mine’s equipment
and energy requirements. The project is estimated to save
local customers more than US$2.4 million per year (AG,
2005; M2M, 2005; US EPA, 1998c).
Envirogen have a 7 MWe power generation system at the
Tahmoor Colliery (Tahmoor Coal Pty Ltd, Wollongong,
NSW). The existing 5 MWe station was upgraded by 2 MWe
in 2003. A 7 MWe system has also been established at the
Teralba and Billambi Mines (Oceanic Coal Australia Ltd,
NSW). Both systems are based on Jennbacher IC engines
(M2M, 2005) (see also Table 3).
A one-year project (2001-02) at the BHPs Appin Colliery
demonstrated that the TFRR oxidation technology
25
Projects in operation worldwide
Methane
collection
pipeline
Gas enriched air
fed to power plant
Exhaust mine air
containing low
% methane
Transformer
Methane drainage
plant
Fresh air into mine
Generator
Mine fan
Mine workings
approximately
500 m below surface
Holes drilled
in coal seam
Holes drilled
in coal seam
Figure 15 CMM/VAM use at the Appin Colliery, Australia (US EPA, 1998c)
(see Section 2.2.4) could handle variations in VAM flow and
produce enough power to boil water. The project is now
under full scale development at the West Cliff Colliery
(see Chapter 4) (CME, 2005a,b).
Between 2002 and 2004, Centennial Coal simulated VAM
(0.1–0.25% methane) using CMM from the abandoned
Newvale mine. The gas was used as combustion air at the
Vales Point coal-fired power plant, as discussed in Section
2.3.2. Following the success of this demonstration,
PowerCoal are developing the system to use genuine VAM
from the Endeavour and Munmorrah collieries as combustion
air in the same plant (M2M, 2005).
3.2
Asia
Rapid population growth and a significant growth in energy
demand means that CMM may have its largest marketplace in
Asia. Although some mines in India drain coal methane,
there are currently no projects for recovery or utilisation of
CMM (CME, 2004). In Japan, the Sumitomo Mining
Company’s Akabira coal mine used to produce 0.15 MWe in
microturbines (5 x 30 kW) but the unit was closed in March
2005. An initial study at the mine in 2001 reviewed the
potential of the mine to store CO2 following removal of the
CMM (Saito and others, 2001). NKK Corporation, in
conjunction with Sumitomo Metal Industries and Taiheiyo
Coal Mine, produce methane from the abandoned Kushiro
coal mine and use this as industrial feedstock for DME
production (M2M, 2005; Talkington, 2004).
The majority of CMM activity in Asia is based in China and
the rest of this Section concentrates on this area.
Although over 200 VCBM wells had been drilled by 2000 in
China, mostly in coal mining areas, VCBM is still not
advancing at a rate which will allow the proposed production
targets to be met. None of the VCBM projects has been
commercialised yet, mainly due to the lack of pipeline
infrastructure. However, new natural gas pipelines are
planned (Creedy, 2002; see Chapter 4). Companies such as
Texaco, BP, Phillips, Greka, Lowell and Virgin have invested
26
money in pilot wells in China, mostly in the Shanxi area
(Shengchu, 2004).
China is demonstrating a very positive thrust in
VCBM/CMM activities. Policies at central, provincial and
local level are supportive of CMM development. However,
investment in CMM-to-power projects from the Chinese
private sector is rare. The majority of projects are funded by
international investors (Pilcher, 2004).
China has increased its CMM utilisation from around
360 Mm3 in 1998 to almost 630 Mm3 in 2004. Most of the
usage is as boiler fuel and town gas (CME, 2004). The largest
current project using CMM as a replacement for natural gas
is at Fushun where gas is supplied for residential use in the
local community. Not all the 126 Mm3/y of the drained CMM
gas is used locally so the excess is fed into the Shenyang
pipeline network and transported 33 km to Shenyang city.
The gas supply capacity is reported to be 104 Mm3/y.
However, the actual quantities are lower due to purity
problems. New VCBM are being sought and developed to
provide high purity gas to enrich the current supply and
increase the amount of gas available.
Creedy and others (2004) list several other CMM-to-pipeline
projects:
●
Nanshan coal mine in Hegang – around 28,000 houses in
the area are supplied via a 12 km distribution pipeline
supplying up to 30,000 m3/d;
●
six mines in the Songzao area supply CMM to 222,000
residential users and other public bodies;
●
up to 5000 residential users and public welfare users are
supplied with CMM from the Huaibei mine, Anhui
province;
●
11 mines in the Yangquan area supply CMM via pipeline
to 134,000 residential users;
●
Panjiang, Guizhou, has six mines supplying 3500
residential users.
There are a few other projects that are not listed by Creedy
and others (2004). These include the project at the Tiefa mine
in Tieling City where CMM is used for pipeline injection
(CME, 2004; M2M, 2005). Further, two mines in the
IEA CLEAN COAL CENTRE
Projects in operation worldwide
Table 8
CMM projects under the CUCBM in China (Schengchu and Xin, 2004)
Capacity
Investment,
million Yuan
IRR,
%
Projected time,
years
CMM power generation
1200 MW
454.95
unknown
6.7
Semi-reinforced carbon black
1300 t/y
3.91
64
3
CMM fuelled vehicle project
3.6 Mm3/y
10.03
31
5
CMM power generation
11 MW
64.60
unknown
unknown
CMM methanol
50,000 t/y
270.40
10
10
CMM surface development
20,000 m3/y
694.68
unknown
unknown
CMM residential use
163.72 Mm3/y
112.00
19
6
CMM power generation
11 MW
75.00
22
7
155.59
23
7
CMM residential use
7397 Mm3/y
177.64
16
8
CMM power generation
3 MW
17.81
21
8
CMM residential use
4,000 Mm3/y
163.95
22
8
CMM power generation
4 MW
17.00
36
4
CMM residential use
2000 Mm3/y
74.00
22
8
CMM surface development
1000 Mm3/y
200.00
23
8
CMM power generation project
6000 Mm3/y
36.20
23
7
CMM surface development
9000 Mm3/y
2,000.00
18
12
Project
Jincheng
Yangquan
Panjiang
Fushun
CMM development and utilisation
Huainan
Huaibei
Jiaozuo
Pingdingshan
Huainan area – Xieyi and Xie’er – are actively capturing
CMM (totalling 50 Mm3). However, only 17% of this
resource is used, primarily for cooking and heating purposes
at the mine and surrounding houses. The remaining gas is
vented.
Although the largest current use of CMM in China is as
domestic fuel, there are several CMM-to-power projects
under way or under development which amount to 147 MWe
of power. This gives China the third highest
methane-to-power capacity in the world (see Table 3). At
least 93 small scale power generators have been installed to
run on CMM. These range in size from 400 kW to 2000 kW
(Schengchu and Xin, 2004). Table 8 shows the CMM projects
listed by the China United Coalbed Methane Company
(CUCBM). Where possible, further descriptions of these
Power projects using methane from coal mines
projects are given below. However, in some cases, no further
information could be found.
The Jincheng Coal Mining Group operates three non-gassy
mines and two gassy mines. CMM drainage is in operation at
both the gassy mines – Sihe and Chengzhuang mines (Creedy
and others, 2004). The Jincheng Mining Administration
(JMA) built a 240 kW CMM plant in 1995 at the Fushun
mine in the Shanxi Province. In 1997, 4 x 400 kW units were
added at the Sihe mine. By 2000 the mine housed 2 x 2 MWe
gas turbine and a 3 MWe steam turbine. A further two
2 MWe gas turbine units were added by 2002. Although the
systems, manufactured in China, have proven reliable since
installation, the electrical efficiency is poor (20–23%).
However, the use of the heat for the steam turbine increases
the efficiency to around 28% (Creedy and others, 2004). The
27
Projects in operation worldwide
200
900
180
800
160
700
140
Number of operated sites (A)
Number of installed CHPs (A)
Installed engine power in MW (B)
600
Electricity generation GWh (B)
500
01/04/2000:
renewable energy law
100
B
A
120
400
80
300
60
40
200
20
100
0
0
1998
1999
2000
2001
2002
2003
2004
2005
Figure 16 Growth in CMM utilisation in Germany, 1998-2005 (Thielemann, 2006)
Jincheng mine currently vents large quantities (202,000 m3/d)
of relatively concentrated methane (40%). The Jincheng
project has been granted a further $100 million loan from the
Asian Development Bank which will create the largest CMM
effort worldwide (see Chapter 4).
There are two power plants cofiring CMM, operated at
abandoned seams in the Nord-Pas de Calais Basin:
Hournaing and Emile Huchet Groupe V. Both sites are
operated by SNET, a subsidiary of Charbonnages de France
(US EPA, 2005).
Jincheng also houses a 1300 t/y plant which uses CMM to
produce semi-reinforced carbon black and a CMM fuelled
vehicle project producing 3.6 Mm3/y (Sloss, 2005).
3.3.2 Germany
Internal combustion engines are used for power generation at
the Fushun mine (1.5 MWe, run by Fushun Coal Mining
Authority), Shiucheng (6 MWe) and Songzao (5 MWe)
mines. Jenbacher IC engines are used in two CMM-to-power
projects in the Huainan Province (see Table 3)
The Yangquan mine is reported to have an 11 MWe power
generation system (unspecified; CMOP, 2005). However, no
further information could be found on this project.
CMM from Mine 5 at Yangquan is used as alumina roaster
fuel as industrial feedstock (Sloss, 2005). Buses fuelled by
CMM (using around 5.49 Mm3/y methane) are used in the
Furong mining area (M2M, 2005).
3.3
Europe – Western
Several countries in Europe have had minor success with
CMM projects. Although interest has been shown in CMM
projects in Italy, no projects have been established as yet
(Sloss, 2005). The majority of CMM activity is in Germany
and the UK, with a few units in France.
3.3.1 France
Although France has had numerous CMM projects in the
past, many of these disappeared as the coal mining industry
in France disappeared. The Methamine project in Northern
France and a similar project in Divion, also Northern France,
have produced methane for pipeline injection since 1990.
Both are abandoned mines (US EPA, 2005).
28
Germany is very active in CMM-to power projects due to the
Renewables Energy Act of 2000. The act means that
Germany is one of the few European countries who define
CMM as a renewable energy source. The Act promotes the
use of renewable energies by guaranteeing fixed rates of
payment for renewable sources of energy supplying
electricity to the national supply. For CMM this means fixed
payment rates for 20 years of 0.076 €/kWh or 0.066 €/kWh
for plant capacities over 500 kW. These rates ensure that the
investment needed in CMM recovery is a secure long-term
commitment and has caused a significant move towards this
form of power generation. By 2001, over 40 individual
CMM projects were under way amounting to around
270 MWe and a reduction of >640 Mm3 methane annually
(Stoppa, 2002). Figure 16 shows the growth in CMM
utilisation in Germany from 1998 to 2005. The Renewables
Energy Act caused a distinct increase in both the number of
projects and the total amount of power produced from CMM
(Thielemann, 2006).
Small scale CMM units are located at many German mines
to provide heat output for the mines themselves. For
example, at Lohberg/Osterfeld two boilers are run with a
heat output of 7 MWth each. Other heat production plants
are found at West, Prosper-Haniel and Ost coal mines. At the
Ost mine, the gas is used to produce steam and heat for mine
use as well as for power generation in a 6 MWe steam
turbine (Stoppa, 2002).
Minegas (a joint venture of Ruhrkohle Ag, GAS
Energietechnologie GmbH and Lambda Gesellschaft fur
Deponiegastechnik GmbH) operates almost 50 mine gas
recovery units in the Rhine/Ruhr region and more projects
are in the planning stage (Mader, 2005a). The projects run
IEA CLEAN COAL CENTRE
Projects in operation worldwide
Table 9
CMM-to-power units within the GAS Energietechnologie GmbH portfolio (Mader, 2005b)
Plant
Customer
Year
built
Electrical
output,
kWe
Thermal
output,
kWth
Module type
Schacht Achenbach IV Lunen
EnD-I Grubengas GmbH
1999
1.019
200
1 x GCA 12 K620
Dortmund Derne
GED
2001
4.074
4.644
3 x GCA 16 K620
Schacht Kurl 3
Minegas GmbH
2001/2
4.074
–
3 x GCA 16 K620
Schacht Lothringen Bochum
EnD-I Grubengas GmbH
2002
5.432
6.000
4 x GCA 16 K620
Schacht Minister Stein
Minegas GmbH
2002
4.074
–
3 x GCA 16 K620
Schacht Schlagel u. Eisen 7
Minegas GmbH
2002
4.074
–
3 x GCA 16 K620
Schacht Westfalen 6
Minegas GmbH
2002
4.074
–
3 x GCA 16 K620
Schacht Victoria 1/2
Minegas GmbH
2002
4.074
–
3 x GCA 16 K620
Lohberg
Minegas-Power GmbH
2002
8.148
9.288
6 x GCA 16 K620
Ewald Fortsetzung Schacht 4
Minegas GmbH
2002/3
9.506
–
7 x GCA 16 K620
Schacht Westfalen 1/2
Minegas GmbH
2003
4.074
3.096
3 x GCA 16 K620
Schacht Hugo 1/4
Minegas GmbH
2003
4.074
–
3 x GCA 16 K620
Schacht Hugo 9
Minegas GmbH
2003
4.074
–
3 x GCA 16 K620
Waltrop Schacht 2
Minegas GmbH
2003
2.716
–
2 x GCA 16 K620
Schacht Consolidation 6
Minegas GmbH
2003
1.358
–
1 x GCA 16 K620
Schacht Hugo Ost
Minegas GmbH
2003
5.652
–
4 x GCA 16 K620
Schacht Ewald 1/2/7
Minegas GmbH
2003/4
6.790
–
5 x GCA 16 K620
Schacht EMU 2
Minegas GmbH
2003/4
5.432
–
4 x GCA 16 K620
Haus Aden
Minegas-Power GmbH
2003/4
16.296
–
12 x GCA 16 K620
Schacht Erin 6
EnD-I Grubengas GmbH
2004
2.730
–
2 x GCA 16 K620
Ewald Fortsetzung Schacht 4
Minegas GmbH
2004
0.986
-
1 x GCA 16 K620
Schacht Werne 3
Minegas GmbH
2004
2.716
–
2 x GCA 16 K620
Schacht Hugo Ost
Minegas GmbH
2004
2.196
–
2 x GCA 16 K620
Schacht Unser Fritz 2/3
Minegas GmbH
2004
4.074
–
3 x GCA 16 K620
Total (to 2004)
83 modules, 111.717 kWe, 23.228 kWth
Total operating mines
18 modules, 24.444 kWe
Total abandoned mines 65 modules, 87.273 kWe
with GAS Energietechnologi GmbH involvement are listed in
Table 9. Those mines with engines supplied by Jenbacher
were listed in Table 3 in Chapter 2. The estimated total
electricity production from CMM in the North Rhine
Westphalia region is 450 GWh. Minegas GmbH were
predicted to have created a decentralised power station output
of around 50 MWe by 2003-04, equivalent to 140,000
households and reducing CO2-e by around 2.5 Mt/y
(Mader, 2006).
By the end of 2002, Minegas GmbH had 35 modules at
abandoned coal mines and Minegas-Power GmbH (which
includes RWE as a partner) has 15 modules at active coal
mines. The active mines included (Stoppa, 2002):
BW West (1 unit)
BW Walsum (2 units)
BW Ost (1 unit).
BW Lohberg (6 units)
BW Prosper Haniel (3 units)
The abandoned mines were:
Power projects using methane from coal mines
Schlagel and Eisen (3 units)
Victoria (3 units)
Werne (2 units)
Consol (3 units)
Min. Stein (3 units)
Ewald Fortsetzung (6 units)
Westfalen (3 units)
Kurl (3 units)
Germania (1 unit)
Gneisenau (3 units)
Figure 17 shows the growth in CMM project development in
the North Rhine-Westphalia region alone between 2001 and
2002. Again this emphasises the distinct effect the 2000
Renewables Energy Act had on investment in CMM projects.
The majority of the projects (48.2 MWe) were based on
abandoned mines with 18.9 MWe at active mines.
Several of the projects operated by Minegas GmbH have
captured public interest and are the subject of numerous
papers. For example, in May 2001, Minegas GmbH began
operating three cogeneration plants at the abandoned Kurl
Shaft III, Gneisenau mine in Lünen. Three modules of
1.358 kW each convert CMM into electricity for the Lünen
area, providing electricity for around 9700 households
29
Projects in operation worldwide
active coal mines
Minegas-Power
Installed electric capacity
18.9 MW
>
2.0 MW
=450 million kWh/y
48.2 MW
38.1 MW
3.9 MW
15.0 MW
06-2001
12-2001
abandoned coal mines
Minegas
06-2002
12-2002
Figure 17 Growth in CMM project development in the North Rhine-Westphalia region between 2001 and 2002
(Stoppa, 2002)
(Mader, 2006; Sporer, 2002). The plant produces CO2-e
savings of 138,000 t/y (Mader, 2005b).
Minegas GmbH also have a 2 x 100 kWe project at Werne, a
4 x1258 kWe project at Ewald-Fortsetzung and a
2 x 1358 kWe project at Consolidation (Sporer, 2002). In
2001 the 5400 kWe combined heat and power plant in
Dortmund-Derne was converted from natural gas to mine gas,
taking CMM from the nearby Gneisenau mine. This was also
a Minegas GmbH project (Sporer, 2002). The plant now has
an electric output of 4074 kW and a thermal output of
4644 kW and reduces GHG emissions by 150,000 t/y CO2-e
(Mader, 2005b).
EnD-I Ag and Gas have established a company called EdD-I
Grubengas GmbH which operates CMM projects with a total
electrical power output of over 6 MWe. The company run a
‘model’ project at the Lothringen I/II colliery in Bochum.
The mine was closed in 1992 and the AMM is used to
generate 5.4 MWe and 6.1 MWth and is one of the largest of
its kind in Europe. The plant comprises 4 cogeneration units,
a compression station, medium voltage equipment and
connection to the local heating grid. The unit is contained,
has noise control and has been adapted to blend with
surrounding buildings, some of which are of historic
importance. The Bochum plant uses 2000 m3/h CMM and
reduces CO2-e emissions by 200 kt/y. The power produced,
equivalent to the requirements of over 13,000 households, is
fed into the public grid. In early 2004 the unit was
incorporated into Bochum’s district heating grid. The total
cost of the plant was €5 million and is expected to have a
service life of around 10 years. The construction of the
Bochum plant took less than three years from site
identification to continuous operation (Mader, 2005a, b).
In 1998 a CMM combined heat and power plant was
commission at Mont Cenis (Sporer, 2002). Currently the
Mont Cenis/Herne site has three Jenbacher AG engines (2 x
253 kWe and 1 x 1003 kWe) producing electricity for a local
educational establishment and other local consumers as well
as district heating (Scheider, 2003).
GAS Energietechnik GmbH, in conjunction with the
30
Fraunhofer Institute for Environment, Safety and Energy
Technology (UMSICHT) has built a cogeneration plant at the
abandoned Minister Achenbach mine in the Ruhr district. A
rotary compressor introduced gas from the mine at up to
90 mbar into the plant which produces 374 kW of electrical
power and 538 kW of thermal energy. The electrical energy is
run through a 0.4 kV/10 kV transformer until and fed into the
local electricity network. The plant began operation in 1998
and has suffered no CMM specific problems since then.
During operation the methane concentration increased from
50 to 65%. Following the initial success of the project, the
engine aggregate was changed to a container plant with an
electrical output of 941 kW in Jun 2000. The time taken to
change over the engine units to the bigger system was less
than two weeks due to the use of container-based engines.
The plant now runs at 1019 kW of electrical output and
200 kW of thermal output and saves 34,000 t/y of CO2-e
(Mader, 2005b).
In addition to the many CMM-to-power projects discussed
above, Germany also uses CMM as a replacement for natural
gas in pipeline networks. The first CMM pipeline at an
abandoned mine was installed at Mont Cenis in 1978,
although the methane was initially released to the atmosphere
(Schneider, 2003). There is a CMM pipeline network in
Saarland which was established in the 1950s and has been
continually extended to reach around 100 km. CMM/AMM
in the area is still mainly used in boilers for district heating
and cofiring in coal-fired power plants. More than 99% of the
CMM is delivered to third parties, the remainder is used in
four small heating plants used to heat the works at the mining
company. Over 40% of the gas is used by hard coal power
plants belonging to SaarEnergie GmbH in Volklingen, Fenne,
Bexbach and Weiher. Neunkirchen and Burbach of Saarstahl
Ag take another 30%. Saarberg Fernwarme use 15% and the
remainder is delivered to various medium and small scale
industrial enterprises (Stoppa, 2002).
3.3.3 UK
Alkane Energy has much experience in producing energy
from abandoned coal mines in the UK, as shown in Table 10.
IEA CLEAN COAL CENTRE
Projects in operation worldwide
Table 10 Methane-to-power projects run by Alkane Energy Plc, UK (Alkane, 2005)
Location
Capacity, MWe
Max CO2 mitigation, t
Bevercotes
Nottinghamshire
4.1
87,000
Markham
Derbyshire
1.35
29,000
Shirebrook
Derbyshire
5.5
211,000
Wheldale
West Yorkshire
5.5
144,000
Rexam
South Yorkshire
0.05 (equivalent)
2,000
Germany
1.8
43,000
Site
UK
Germany
Joarin
The company has established 9.7 MWe of power generation
(5 x 1940 kW GE Jenbacher gensets) at the abandoned
Shirebrook Colliery. The power generated is supplied directly
to the national grid. The same company run a similar project
producing 3 MWe from the Steetley Colliery and 10 MWe
from the Wheldale Colliery, again supplying the power
directly to the national grid. Alkane is also producing CMM
from a mine in Monkbretton and selling the gas directly to a
local glassworks (Alkane, 2005).
Warwick Energy (previously Stratagas) are producing
10.5 MWe from 3 x 3.5 MWe internal combustion engines at
the abandoned Annesley Bentinck Colliery. The energy is fed
into the local network (Sloss, 2005).
UK Coal Mining has two combined cycle gas turbines at
4 MWe and one steam turbine at 10 MWe at the operational
Harworth Colliery. The same company has the following
units established to date:
●
Kellingly (active mine)
1 x 212 kW GE
Jenbacher genset
●
Maltby colliery (active mine) 3 x 1413 kW GE
Jenbacher gensets
●
Stillingfleet (abandoned)
3 x 1413 kW GE
Jenbacher gensets
●
Thoresby (active mine)
2 x 1413 kW GE
Jenbacher gensets
●
Wellbeck (active mine)
1 x 1413 kW GE
Jenbacher genset
Octagon has 5.4 MWe being produced by internal
combustion engines at the abandoned Hickelton Colliery and
9 MWe from internal combustion engines at the Silverdale
abandoned mine. The same mine supplies 0.037 Mm3/d
methane for pipeline injection. Hyder Consulting produces
9 MWe from 6 x 1.5 MWe internal combustion engines at the
active Tower Colliery.
Power production from ACMM began at the Markham
Colliery, Derbyshire, in 1999. A larger, >2 MWe generation
project is under production (see Chapter 4).
Flaring is carried out at several UK mines including
Kellingley, Maltby and Rossington collieries.
Power projects using methane from coal mines
3.4
Europe – Eastern
Several studies, such as that by Irons and others (2004), have
indicated a large potential for CMM use in Eastern Europe.
The situation in each country are summarised in the sections
below.
3.4.1 Croatia
Mines which would be suitable for CMM projects have been
identified. However, external funding would be required for
any project to be developed (Irons and others, 2004).
3.4.2 Czech Republic
Mining is ongoing in the Ostrava-Karvina coal-field in the
Upper Silesian coal basin. The CMM utilisation rate in 1997
was just over 100 Mm3 which represented around one third
of the total methane captured. The rest was vented to the
atmosphere. End users of the gas included steelworks and
heating plants (Irons and others, 2004).
DPB Paskov AS owns and operates a 200 km pipeline which
links 12 abandoned mines, via 20 vacuum pumps and
compressors, to six gas extraction plants supplying an
extensive gas pipeline network. The pipeline supplies gas to
over 30 locations, including a town in neighbouring Poland.
The gas from all the mines is mixed and monitored to
maintain both quantity and quality (Sloss, 2005).
In 1997, four companies were granted licences for gas
exploration in the OKR coalfields in the Czech Republic.
Dulni Pruzkum a Bezpecnost AS has a licence for CMM
extraction from both virgin and abandoned coal fields. The
company captures CMM from abandoned mines and employs
>200 km pipeline to distribute 77 Mm3/y CMM and
32 Mm3/y AMM. Energie Kladno has three virgin mines in
the OKR fields but, as yet, it does not appear that any CMM
is in production. Geologicky Pruzkum Ostrava AS has also
started exploration in the area but, as yet, has not initiated
any projects. Technovent PTY (a subsidiary of CSIR in South
31
Projects in operation worldwide
Table 11 Drainage and utilisation of CMM in Poland, 2001 (Gatnar and Tor, 2003)
Utilisation of methane (100% CH4)
Mine
Methane drainage
(100% methane),
thousand m3/y
Total amount of
used methane,
thousand m3/y
% used
Specification amount
used, thousand m3/y
End use
Borynia
266.4
96.4
36
96.4
gas boilers, 2 x 1.2 MWt
Jas-Mos
8,670.0
8,388.6
97
8,388.6
CHP* Moszczenica
Krupisnki
20,124.0
11,586.1
58
7,202.9
power generation
2,007.1
boilers
2,376.1
coal-drying
6,666.0
CHP Moszczenica
3,616.3
CHP Zofiowka
1,4511.5
power generation
5,048.3
mine heating
20,821.2
CHP Zofiowka
Pniowek
42,100.5
29,842.1
71
Zofiowka
21119.9
20,2821.2
99
Total
92280.8
70,734.4
77
CHP - combined heat and power
Africa) is assisting in the implementation of technologies
appropriate for CMM use but again, as yet, there are no
reports of any projects under way (US EPA, 1998a; 2005).
chemical/industrial projects, there are several CMM-to-power
projects in Poland:
3.4.3 Hungary
Pniowek
Halemba
Bielszowice
Several mines have used degassing techniques to improve
mine safety. It is reported that, at some mines, the CMM was
used to provide domestic heating, hot water or simply flared
but, again, little information is available.
Several mines in the Jastrezbie coal field produce methane
which is piped to local companies to produce power. Table 11
summarises the different mines and the units to which they
supply methane (Gatnar and Tor, 2003).
3.4.4 Romania
Romania is reported to have a small CMM project under way
and two in development but little or no information is
available (CME, 2005a,b).
3.4.5 Slovenia
Mines which would be suitable for CMM projects have been
identified. However, external funding would be required for
any project to be developed (Irons and others, 2004).
3.4.6 Poland
The largest amount of CMM activity in Eastern Europe is in
Poland. The first cogeneration unit with 2.7 MWe was
installed at the Krupinski colliery in 1997. Since then, a total
of 15 MWe has been installed in Poland (Mader, 2005a). In
addition to numerous mine heating, coal drying and
32
3.2 MWe from 2 Deutz engines
0.543 MWe from Jenbacher gas engines
0.543 MWe from Jenbacher gas engines
The first CMM project for air-conditioning at a mine was
built at the Pniowek mine, listed above. The cooling system
is based on gas-powered engines and electrical energy
generating units integrated with absorptive and compression
coolers. Some of the electricity generated is used to power
the screw compressor. The remainder of the electrical and
thermal energy is used in the mine operation. The first stage
of the 2.5 MWe air conditioning system was operational in
June 2000. In December 2000 the target cooling power was
increased to 5 MWe (Szlazak and others, 2001).
The Pniowek mine had problems with excessive heat (>33°C)
in some of the underground mine headings which made it
impossible for mining to continue. The methane produced
from the mine drainage system was 50–60% methane,
although this varied from 80% in the winter to 40% in the
summer. The system installed at the mine is in two identical
units both comprising gas engines as well as absorptive water
and compression coolers. Figure 18 shows the schematic
diagram of the cooling system at the mine. The system uses
around 25 m3/min methane as fuel in two 4-stroke gas
engines (Deutz Energy GmbH) running generators at
IEA CLEAN COAL CENTRE
Projects in operation worldwide
Ventilation
cooler
Chimney
electric energy
2 x 3.2 MWe
6.3 kV
100°C
Heat
recovered
from fumes
125°C
2 gas
engines
G
2 current
generating
units
Heat
recovered
from engine
cooling
85°C
70°C
2 x absorption
coolers
1200 kW
14.5°C
2 x absorption
coolers
3460 kW
4.5°C
2 x compression
refrigerators
1140 kW
1.5°C
18.5°C
300 m3/h
powierzchnia
18°C
F
Cooled air
Underground cooling
installation with
DV 290K coolers
300 m3/h
5 MWch
3°C
Three chamber pressurre lock
* MWch - MW chilling power
Figure 18 Schematic diagram of interconnected power engineering cooling system in the Pniowek coal mine
(Szlazak and others, 2001)
3.194 kW. The heat produced in the process is used in the
chemical conversion of absorptive bromine-lithium coolers
for water cooling. Some of the electricity produced is used
for running the feeder screw compression coolers and further
cooling of water. The remainder of the heat and power is
used on-site at the mine itself. Although the CMM cooling
system was more expensive to build that normal compression
coolers, the returns for the electrical and thermal energy
produced are higher than the operational costs of the plant.
The return on investment was within five years of plant
operation. Figures 19 and 20 show the efficiency and output
of the plant. A total of 4200 MWh of electricity are produced
annually along with 41,000 MWh of low grade heat. Methane
emissions are reduced by around 13 Mm3/y (Szlazak and
others, 2001).
3.5
Russian Federation and the CIS
The previous report by IEA CCC (Sloss, 2005) noted that
investment in CMM projects in Russia would be harder to
obtain than elsewhere due to complications with property
rights and transparency of negotiation in the areas. Despite
this, several CMM projects have been established in Russia
and the Ukraine.
3.5.1 Russian Federation
The Russian CMM industry is not yet commercialised
although exploration is under way. For example, Gazprom
implemented a pilot well drilling programme in 2003.
Around 77% of coal now comes from independent producers
Power projects using methane from coal mines
which means that most projects would be implemented on a
mine-by-mine basis in agreement with individual producers.
The UN DP and GEF are working together to remove
barriers to financing and implementing CMM projects which
may help in the future. However, CMM faces a major
challenge in competing with cheap natural gas, lack of
appropriate technologies and complex rules on foreign
investment (Franklin, 2006).
Russia has several plants using CMM for power generation.
The Kosmolets mine uses CMM in both an electric generator
(1 MWe) and as fuel for a boiler. The Cherniskaya mine uses
CMM to produce 1.2 MWe from a 1 MWe caterpillar engine
and a 200 kW Russian-made engine. The Severnaya mine uses
CMM in a 1 MWe gas-engine. The gas is also used in two
autonomous gas fuelled air heaters and two dryer units at the
mine. CMM is used as boiler fuel at the Zapolyaranya mine
(three stoker boilers), the Komsomolskaya mine (five stoker
boilers) and the Vorkutinskaya mine (four stoker boilers).
3.5.2 Ukraine
In 2001, 134.5 billion m3 of CMM (50% of the total CMM
captured) was used either as boiler fuels at mines, as mine
vehicle fuel or in local housing (Triplett, 2003).
The US EPA Methane to Markets project (M2M, 2005) has
reviewed the CMM activity in the Ukraine. There appears to
be little information on the projects other than their size and
location. For example, a 1 MWe CMM-to-power
demonstration project was operated between 2000 and 2004
at the Komsomolets Donbassa mine. The CMM is used for
33
Projects in operation worldwide
Reduction methane
emission into the
atmosphere about
8 Mm3 CH4/y
Pniówek
coal mine
Own methane
removal appr.
52 Mm3 CH4/y
Improvement of working conditions and
increase in productivity (output) by
limiting the number of walls where
temperature exceeds 28°C
Decrease in
purchase of electric
energy about
42000 MWh/y
Methane
drainage
station in
Pniówek
coal mine
Professional
power
engineering
Sale of cooling
capacity about
41000 MWh/y
Sale of electric energy
about 42000 MWh/y
Interconnected power
engineering-cooling
system
Additional
consumption of
methane about
13 Mm3 CH4/y
Other gas
buyers
Figure 19 Energy effects resulting from the use of the a CMM cooling system at the Pniowek mine, Poland
(Szlazek and others, 2001)
II Stage
5 MWch
Own needs
260 kW
Gas recovered from methane drainage
150% CH4 + 50% (O2+N2)
Mechanical
losses
Gas
engines
MWM
DEUTZ
TBG
632V16
Electric energy
Sale for mines
5.6 MWe
6.4 MWe
38%
7.4 MWth
42%
280 kW
2 absorptive
coolers
In engines
cooling
system
1200 kWt
In system
of heat
recovery
from fumes
3460 kWt
2 compression
refrigerators
(ammonia)
1040 kWt
5.6 MWch
Transmission
loss
16%
Heat loss
Coolers in central air-conditioning system
* MWch - MW chilling power
5 MWch
SIEMAG
three-chamber
feeder
level 853
Feeder’s
losses
Figure 20 Energy balance resulting from the use of a CMM cooling system at the Pniowek mine, Poland
(Szlazak and others, 2001)
both heat and power generation. A 1.535 MWe heating and
power generation project has been ongoing since April 2004
at Khrustalskaya in the Lugansk area. A CMM project for the
34
degasification of coking coal has been in development since
May 2004 at the Krasonmeyerersk/Toetskaya Mine in the
Donetsk area.
IEA CLEAN COAL CENTRE
Projects in operation worldwide
Power is produced from CMM at at least four mines in the
Ukraine. The Don Ukraine mine in the Lugansk region has
two caterpillar internal combustion engines producing
1.5 MWe (CME, 2004). The Sasyadko mine in Donetsk has a
unit, run by Prospekt Zasyadko, which uses 22 Jenbacher
engines to produce 131 MWe. This may be the world’s
largest CMM project in terms of total power output. The
projected electrical efficiency of the units is 42.9% and the
thermal efficiency 41.3%. Installation of the equipment began
in June 2004 (CME, 2004).
Three mines in the Ukraine are using CMM for boiler fuel.
The Bazhanova Mine, Donetsk, has six boiler units, the
Glubokaya mine, Donetsk, has five boiler units and the
Holodnaya Balka Mine, Makeyevka, has seven boiler units
(M2M, 2005).
3.6
North America
Although Canada is actively pursuing VCBM projects to
supplement the natural gas supply, there are currently no
CMM-to-power projects in operation (Sloss, 2005).
The USA has significant VCBM and CMM resources –
between 4 and 11 trillion m3 (M2M, 2005). The San Juan
basin is the most successful VCBM development in the world
with over 23,000 m3 methane produced per day (Gale, 2004).
The established network of gas pipelines provided a suitable
market for the gas produced. In 2002, VCBM was providing
9% of the total annual US natural gas production. Around
25% of the total remaining US gas reserves are associated
with VCBM. Tax incentives helped to establish the market
(Wight, 2004). Several projects in southwestern Pennsylvania
and Indiana spike the AMM with propane prior to injection
into the gas pipeline to achieve the required gas quality
(Cote and others, 2003).
The success of CMM projects in the USA is often dependent
on the proximity of the site to the natural gas pipeline
systems. Mines in the Western USA often have little or no
access to pipelines and therefore the option for gas sales are
limited. The cost for feeder pipelines is usually prohibitive.
Unlike Europe or China, US mines are not commonly located
next to populated areas and, in the absence of pipelines, local
and industrial uses are not economically viable (M2M, 2005).
Power generation is deregulated in the USA and there is free
and open access to the wholesale market. At the moment,
18 states have renewable energy portfolios or standards. Only
one state, Pennsylvania, defines CMM as a renewable
(M2M, 2005).
As discussed in the previous IEA CCC report on CMM
(Sloss, 2005), the water produced during mining and CMM
extraction can be a significant environmental problem. The
economics of the use of disposal or use of this water have an
impact on whether a CMM project will succeed
commercially. This has been a particular problem in the
Powder River Basin in Wyoming. In some situations, the
produced waters can be reinjected into deeper water bearing
formations, transported to a regional injection well, allowed
Power projects using methane from coal mines
to evaporate on the surface or to evaporate using evaporator
technologies which leave salt residue for disposal or
chemical/pharmaceutical use. The US DOE’s National
Energy Technology Laboratory (NETL) has funded research
by Drake Engineering to develop a process for water cleaning
based around wetland plant species in artificial or modified
natural wetlands. The plants reduce the levels and negative
effects of the salts in the produced water so that it can be
discharged safely (NETL, 2006).
The USA probably has over 500 abandoned coal mines
scattered across 11 states, mostly in the Central and Northern
Appalachian basins and the Illinois basin. At the moment
there are around 20 AMM methane projects recovering gas
from over 30 coal mines (Cote and others, 2003). These are
discussed in a US EPA CMOP report (CMOP, 2004). The
only US CMM-to-power projects listed on the US EPA’s
CMOP website are those listed in Table 12 (CMOP, 2005).
One of the longest running CMM to power projects in the
USA is at the Nelms No 1 mine in Ohio. Around 10,000 m3/d
gas (70% methane) is sent to 12 IC engines to generate
around 1 MWe. A further 10–15,000 m3/d is enriched and
sold to the local gas pipeline. CMM from another abandoned
mine, Nelms No 2, is used by Northwest Fuels Development
to produce 1 MWe from General Motor 75kW internal
combustion engines.
Peabody Coal use CMM from the Federal No 2 mine to
produce 1.2 MWe power from General Motor internal
combustion engines. Grayson Hills Farm takes CMM from an
abandoned Indiana mine and produces 1.7 MWe in two
rebuilt Caterpillar IC engines (CAT 3512 model gensets).
Some of the electricity is used to run a greenhouse for
cucumbers and tomatoes and the remainder is sold to the
local utility. In the winter, waste heat is used to heat water for
the in-floor radiant heat system in the greenhouse. Caterpillar
internal combustion engines (2 x 850 kW at each mine) are
used at the O’Hara No 8 and Peabody No 46. Waste heat is
also used to heat water for a nearby greenhouse (Cote and
others, 2003).
Consol Energy and Allegheny Power produce 88 MWe with
General Electric turbines (2 x 44 MWe) at the VP/Buchanan
mines. The plant, which began operation in June 2002, fires a
mix of pre-drained CMM and working mine CMM in GE
LM6000 combustion turbines. The plant started operation in
June 2002 and will help meet peak electricity demand in the
Eastern USA. CMM is also used for coal drying at the
Consol VP/Buchanan mines. Excess CMM is occasionally
sold for industrial applications (Cote and others, 2003; CME,
2002; CME, 2005a,b).
The USA also hosted the first CMM powered fuel cell
demonstration project (see Section 2.2.5).
3.7
Comments
So far, the success in CMM utilisation varies from country to
country, depending on the regional market place and the
appropriate use of the gas at each individual location. In Asia
the majority of captured CMM is used as town gas, with the
35
Projects in operation worldwide
Table 12 Summary of existing methane recovery and use projects, USA
Mine name
Mine location
(State)
Approximate
amount of gas
used in 2001
Methan use option
Notes
Blue Creek No 4
Blue Creek No 5
Blue Creek No 7
Alabama
0.764 Mm3/d
Pipeline sales
The three mines collectively produced
0.96 Mm3/d of gas in 2001, but only
0.764 Mm3/d is credited to emissions
avoided
Oak Grove
Alabama
0.085 Mm3/d
Pipeline sales
Most of the production in the Oak Grove
Field is beyond the limits of the mine
plan
Shoal Creek
Alabama
0.198 Mm3/d
Pipeline sales
Most of the production from the White
Oak Field is outside the limits of the
mine plan
Pipeline sales
on-site use
These two mines collectively produced
3.030 Mm3/d of gas in 2001, of which
1.98 Mm3/d contributes to emissions
reduction a the mines. A small portion
(0.042 Mm3/d) of the total gas
production is used on-site in a thermal
dryer
Buchanan No 1
Virginia
3.030 Mm3/d
Blacksville No 1
Pennsylvania
1.246 Mm3/d
Pipeline sales
Gas is produced from three abandoned
mines that are part of the project, but
0.113 Mm3/d is from the active mine
alone
Federal No 2
West Virginia
0.028 Mm3/d
Pipeline sales,
Power generation
(planned)
Project continues to expand as mine
grows. A second project using methan
to generate electricity is planned
US Steel No 50
West Virginia
0.227 Mm3/d
Pipeline sales
A unique, horizontal pre-mine drainage
programme is utilised
methane being piped to the local community. CMM is also
used as boiler fuel, largely at the coal mines themselves, with
some being used for power generation. Western Europe has
had more success with power generation and uses less CMM
for pipeline injection. In Eastern Europe, Russia and the CIS
the major application of CMM is as mine boiler fuel with
limited power generation and power use projects. The USA
has a huge market for VCBM in natural gas pipeline injection
due to high natural gas prices and an excellent infrastructure.
Only a few CMM-to-power projects have been established in
the USA to date.
36
IEA CLEAN COAL CENTRE
4 Projects planned or under construction
There is great potential for CMM to be captured and utilised
for inexpensive and clean energy. The previous report from
IEA CCC (Sloss, 2005) reviewed the different ways in which
international agreements such as the EU ETS and the Kyoto
protocol could promote investment in CMM projects. Future
CMM-to-power projects will also be positively influenced by
factors such as (CME, 2002):
●
growing demand for power;
●
demand for power in remote mining areas;
●
attractive power prices;
●
strong markets for thermal energy by-products of
cogeneration plants;
●
special financial incentives that apply to CMM.
The following sections indicate where new CMM projects are
planned or under construction. Where possible, an indication
is also given of further locations where CMM may be viable
in the future.
4.1
Australia
Australia already has a well established natural gas pipeline
network which accepts suitable quality CMM (see
Section 3.1). Enertrade is planning to offer reliable CMM gas
as an energy source to Central Queensland industries. The
CMM gas will be sourced from the Bowen Basin and
delivered via pipeline to Central Queensland. The 420 km
high pressure transmission gas pipeline into Central
Queensland will service the area’s industrial needs and
provide potential for the region to expand and fulfil its
industrial capabilities. It is estimated that the pipeline will be
operational from 2007 (Enertrade, 2005).
As discussed in Section 3.1, Australia is the most active
country in the world with respect to establishing new and
innovative CMM projects. Many successful projects have
been established at pilot and full scale and more are being
developed. For example, Envirogen has been working on
three CMM projects (IC engine based) which should amount
to a total of 2.25 Mt CO2-e reduction. Two of the projects are
completed (Teralba and Tahmoor, discussed in Section 3.1).
The third project, the Oaky Creek project at the Mount Isa
Mines near German Creek, SW Queensland, is still under
early construction (AG, 2005).
The project, which is due to become operational during 2006,
will use 10 x 1 MWe IC engines (M2M, 2005).
Anglo Coal and Energy Developments Ltd have scheduled a
plant for construction during 2006. The plant will produce up
to 32 MWe from a series of 3 MWe IC engines at the German
Creek Coal mine. The plant is expected to reduce emissions
by up to 6.1 Mt CO2-e in 2008-12.The project is based on
reciprocating engines, probably Caterpillar engines from the
USA. The energy produced will be either exported to the
distribution network or purchased for on-site use.
Construction of the plant is under way (AG, 2005).
ComEnergy (CSIRO/Liquatec JV) plan to construct a 10 MWe
plant at the United Colliery. The plant will burn waste coal
with coal mine methane in a rotary kiln with 10 MWe of gas
turbine power production. It is envisaged that the plant will
start to produce power during 2006 (Talkington, 2004).
BHP Billiton are working in conjunction with MEGTEC
systems to establish a A$13 million VAM oxidation system at
the West Cliff Colliery called WestVAMP. This technology
was discussed in more detail in Section 2.2.4. A photograph
of the unit is shown in Figure 21. It is estimated that the
system could produce around 6 MWe for use at the colliery
itself. The project will deliver a greenhouse gas reduction
equivalent of up to 1.04 Mt CO2-e ien 2008-12. This project
is an extension of the previous BHP project at Appin which
operated in 2001-02 and which was awarded the Australian
Coal Association’s award for Best Greenhouse Gas Research
Project in 2005 (AG, 2005). The plant is due for completion
in mid-2006 (CM, 2005).
A new 1000 MWe gas plant is planned for Roma, eastern
Australia, using CMM. Origin Energy is proposing the
project which will be built with the ‘highest efficiency’
technology, probably combining gas and steam turbines.
Development requests have been submitted to the Queensland
Government and permits are expected to be granted by 2006
(Coal21, 2005).
Envirogen has also just been awarded up to a further
$9 million to construct two new plants:
●
United Coal Mine Ltd, Hunter Valley, NSW;
●
Glennies Coal Mine Ltd, Hunter Valley, NSW.
These plants are expected to reduce greenhouse gas
emissions by 3.61 Mt CO2-e between 2008-12. Construction
has not begun as yet (AG, 2005).
With up to $13 million funding, Envirogen are also in
development of a new plant at the North Goonyella mine.
Power projects using methane from coal mines
Figure 21 Photograph of the MEGTEC installation
at West Cliff, Australia (Mattus, 2006)
37
Projects planned or under construction
New mines are being opened in Newlands and Moranbah and
both projects are including pre-drainage of methane as part of
the project planning. There does not seem to have been any
decision made as yet as to how this gas could be used
(AG, 2005).
According to the CMOP at the US EPA (CME, 2004), ‘with
a strong government and industry commitment to methane
capture and use, in conjunction with continued growth in
coal production, Australia’s CMM industry will likely remain
vibrant for the foreseeable future.’
4.2
Asia
Within the current ‘5-year plan’ the Chinese government is
planning to invest a great amount of money in developing
and extending the natural gas pipelines in China. This may
make it easier for CMM to compete in the natural gas
marketplace, especially if new pipelines pass existing CMM
producing mines (CMOP, 2006).
Development is under way at the Sihe and Jincheng mines
(Jincheng Coal Mining Authority). The Sihe mine will
house 4 x 400 kW internal combustion engines producing
120 MWe. The Jincheng mine will have 4 x 40 kW internal
combustion engines and two larger 2 MWe combustion
units producing a total of 5.6 MWe (Talkington, 2004). As
discussed in Chapter 3, the Jincheng CMM-to-power project
is expanding to become the largest methane to power
project in the world by adding an additional 16.25 MWe to
the existing 5.6 MWe of energy produced. The project
would be IC engine based. The total investment required is
around 95 million yuan (US$11.5 million). The estimated
rate of return would be 26% with a payout after six years
and the project life projected to be 20 years. The Jincheng
group are also planning to establish a mine vehicle
refuelling project using CMM. The station would fuel
200 vehicles currently operating in the mine area. The
CMM would be extracted and transported to the refuelling
station where it would be purified and pressurised to
25 MPa. The combined capacity of the fuelling stations
would be 1500 m3/h. This project will require an investment
of $1.2 million and will cost $0.5 million per year to run.
The station would save 2.2 million kg of gasoline each year
equivalent to a saving of over 51 kt of CO2-e/y. Investors
are being sought. The Jincheng project is also hoping to
expand into carbon black production. Again, investors are
being sought before this project can commence
(Ravenridge, 2006).
Although there appears to be much interest in new projects in
China, many proposed projects have been unsuccessful in the
past. Although 19 new projects had been agreed by 2003,
none of the projects had entered commercial development. It
is suggested that the projects require better supervision and
management to ensure their success. Formulation of a clearer
tax and fee policy would also help attract more cooperative
partners. The introduction of tighter environmental protection
laws limiting the amount of methane which can be released
from mines would also help (Sloss, 2005).
There are numerous projects in China which have been
designed and evaluated and are waiting for investment in
order to put them into practice. For example, Ravenridge
Associates (Ravenridge, 2006) have evaluated the potential
for CMM-to-power projects at several Chinese mines. At the
Yangquan mine much of the captured methane is released to
the atmosphere (200,000 m3/d). However, it would be
possible to pipe much of this gas to Taiyuan, 100 km away.
The Yangquan mine could also house a CMM-to-power plant,
the most feasible design being an array of small (1 MWe)
reciprocating engines, similar to the system employed
successfully at the Tower and Appin mines (see Section 3.1).
Current gas supply would be sufficient for up to 51 MWe.
The reduction in methane emissions would be equivalent to
1.4 Mt/y of CO2-e.
The Huainan mining area has 11 working mines. However,
methane is only captured and used, for local heating and
cooking, at two of these mines (see Chapter 3). A project to
expand CMM use in the area has been proposed. Up to
74 Mm3 could be captured from existing drainage sites and
used to supply residents in Huainan city with domestic fuel.
Since the project would require investment in gas storage
tanks and pipeline networks, the cost would be over
$21 million. Around 70% external investment is being sought
by the mining company (Ravenridge, 2006).
The Huainan mining area could also house a power plant
with 3 x 1 MWe gas engines running on CMM. This project
would require an investment of US$2.1 million of which 65%
is being sought from outside investors (Ravenridge, 2006).
The Hegang Coal Mine Group is working on a joint venture
to produce 1.8 MWe power for on-site use at the mine
(Talkington, 2004).
Investors are being sought for a CMM-to-power project by the
Panjiang Coal and Electric Power Group in the Guizhou
Province. The existing pipeline supplying CMM to local
residents could be expanded at a cost of US$13.5 million. The
mining area could also house two CMM-to-power plants with
a total capacity of 11 MWe at a cost of US$9 million to build
the plants. Similarly, the Huaibei Mining Group in the Anhui
province are looking for investment of US$19.8 in establishing
a pipeline to deliver CMM to local residents in the city of
Suxian and a further US$2.1 million for 2 x 2 MWe turbines to
provide local heat and power to the grid (Ravenridge, 2006).
CMM is to be used as fuel in an industrial alumina roasting
project in the Yangquan mining area. This project would
increase alumina production by 1.2 Mt/y and would use
130 Mm3/y CMM. Another project in the Tiefa mining area is
to use CMM in ceramic furnaces. Up to 400,000 m3/d CMM
could be used. The project is due for completion at the end of
2006 (M2M, 2005).
These proposed projects will only come to fruition if external
(international) funding is obtained. The development of
CMM projects has been surprisingly slow in China,
considering the vast potential. The problem in the past has
been financing difficulties due to the marginality of many
projects. However, implementation of funding options under
agreements such as the Kyoto Protocol may lead to rapid
38
IEA CLEAN COAL CENTRE
Projects planned or under construction
developments in this area. For example, the Centre for Coal
Utilisation, Japan (CCUJ), began preliminary investigations
into the prospect of establishing a clean development
mechanism (CDM) with China for CMM projects. The study,
carried out during the 2003 financial year at selected mines,
indicated that gas turbines would be the superior technology at
many of the sites due to the efficiency of the turbines and their
suitability for large-scale cogeneration. Surplus gas could also
be used for town gas in the local area (M2M, 2005).
Many Japanese companies are keen to support CMM projects
in China. According to recent news reports, Sumitomo Corp,
Chugoku Electric Power Co, and Niigata Power Systems Co,
a subsidiary of Ishikawajima-Harima Heavy Industries Co,
plan to install a gas engine with an output capacity of
2000 kilowatts that will use methane gas produced at a coal
mine in China’s Heilongjiang Province. The project is
expected to reduce CO2 equivalent emissions by 80,000
tonnes annually (CMOP, 2006).
power. However, India may well develop CMM projects in
the future. The Government of India is working with the
Global Environment Facility (GEF) and the United Nations
Industrial Development Organisation (UNIDO) on an
$18 million project to demonstrate CMM technologies. The
ultimate aim is to use the CMM for electricity generation and
as a fuel for mine trucks. As discussed in the previous report
by IEA CCC on CMM (Sloss, 2005), India has released
blocks of VCBM potential areas for sale to interested
investors. The Bureau of Energy Efficiency is working with
the German government to promote projects to generate
electricity from CMM from both active and abandoned mines
using containerised IC engines. Proposed projects, which
may qualify to generate certified emission reductions under
the clean development mechanism of the Kyoto protocol,
must meet three criteria (CME, 2004):
●
production potential of 1500 m3/d equivalent of 100%
methane;
●
‘considerable potential’ for follow-up projects;
●
industrial electricity consumers close to the project site.
Basic information on planned CDM projects in China, as
listed by the Chinese Government, can be found on the
following website: http://cdm.ccchina.gov.cn/english/
NewsInfo.asp?NewsId=94
4.3
According to the CMOP at the US EPA, the combination of
China’s economic growth and vast coal reserves will continue
to attract investors in CMM (CME, 2004). Figure 22 shows
the predicted growth in CMM power generation in China
from now until 2020. Capacity is expected to reach 450 MWe
with an associated CO2-e emission reduction of 1600 Mt
(Wenbo, 2006).
According to Mader (2005b) there are international trends
which may help promote CMM to power projects in Europe.
These are:
●
the decline of coal mining in Europe (60% between 1980
and 2000) means an increased number of closed pits and a
subsequent increase in the relevance of mine gas recovery;
●
greater international efforts in connection with the Kyoto
Protocol and EU Emissions trading scheme to cut
emissions.
As mentioned in Section 3.2, China is the only country in
Asia at the moment which is actively pursuing CMM based
1600
1600
1400
1200
1050
Europe – western
4.3.1 Bulgaria
Initial investigations have taken place in Bulgaria in the
Dobroudja Coal Basin. Although initial funding had been
provided by the US Trade and Development Association to
the University of Mining and Geology in Sofia in 2000, it
appears that there has been no activity in this area since
(Ravenridge, 2006).
Title
1000
4.3.2 Germany
800
600
450
400
300
300
Due to the 2000 Renewables Energy Act (discussed in
Section 3.3.2) and the success of the many CMM-to-power
projects in Germany so far, it is likely that Germany will
continue to develop new projects for many years to come.
200
4.3.3 Italy
85
0
2004
Installed capacity (MW)
2010
2020
CO2-e (Mt)
Figure 22 Installed capacity of CMM power
generation in China in the future
(Wenbo, 2006)
Power projects using methane from coal mines
The Italian government has expressed interest in harnessing
and using CMM from the last remaining coal mine in
Sardinia. The mine is close to industrial and domestic gas
markets – a 340 MWe coal-fired power plant and an Alcoa
aluminium smelter. However, Italy lacks legal regulation for
the CMM industry. As yet, no project evaluation has been
completed (Sloss, 2005).
39
Projects planned or under construction
4.3.4 Turkey
Initial investigations into CMM potential in Turkey seem to
have led nowhere (Ravenridge, 2006).
4.3.5 UK
Greenpark Energy has a large portfolio of planned CMM
units at abandoned mines in the UK including:
5 MWe
●
Bently
●
Brodsworth
5 MWe
●
Frickley
5 MWe
●
Grimethorpe
5 MWe
●
Houghton main
5 MWe
Alkane is planning to develop a 4 MWe power unit at the
abandoned Bevercotes mine, a 2 MWe unit at the abandoned
Warsop mine, and a 2 MWe unit at the Whitwell abandoned
mine. Alkane was also seeking a new customer for 2.7 MWe
equivalent of gas production from the abandoned Markham
Colliery which could be used for industrial heat applications,
delivered by a dedicated pipeline (Davies, 2003). Alkane has
plans for two new plants at Mansfield Woodhouse,
Nottinghamshire and Whitwell, Derbyshire, with a combined
capacity of 2.7 MWe (Alkane, 2005).
Alkane had proposed a 50 MWe CMM-to-power project in
Ayrshire, Scotland, but is likely to drop this proposal and take
the project abroad to Germany where the economic
conditions are far more favourable (see Chapter 3). The UK
DTI has reviewed the UK government’s policy on CMM and
concluded that simple flaring of the methane will be the most
cost-effective choice. Any future CMM projects would need
to be profitable on a stand-alone basis (Sloss, 2005).
The UK industry trade association of the CMM industry
believes that, although CMM has the potential to fuel up to
400 MWe of generation in the UK by 2010, the UK
Government is not doing enough to promote such projects.
Although a 10 MWe CMM plant has been built in Wheldale,
Yorkshire, no further plants would be commercially viable in
the UK at the moment or even in the future without a change
in the legislation or grants from the government. Whereas in
Germany CMM has been defined as a renewable energy and
price incentives were provided to promote its use (see
Section 3.3.2) this is not the case in the UK. In fact, the price
in Germany for CMM is almost 400% better than that in the
UK (Davies, 2003).
4.4
Europe – eastern
On 23 September 2004, the US EPA and the United Nations
Economic Commission for Europe (UNECE) based in
Geneva, announced a three-year jointly sponsored program to
promote the implementation of coal mine methane projects in
Eastern Europe and the CIS. A new Ad Hoc Group of
Experts on Coal Mine Methane was launched to facilitate and
support implementation of this project. The goal of the
project is to develop bankable CMM projects in Central and
40
South-Eastern Europe and the CIS leading to additional
emission reductions. The expected project outcomes include:
●
three or more bankable project documents, which shall
be considered by investment funds ;
●
lessons learned and disseminated to project developers
from the Region and elsewhere on how to prepare the
most effective bankable project documents for approval
by financing organisations;
●
elaboration of a roadmap for financing additional CMM
projects in the region formulated by the end of the
project period.
4.4.1 Croatia
Projects in the Istra peninsula in south west Croatia show
potential but would require further financing to allow a full
evaluation. However, local availability of funding and
favourable tax allowances could enable further exploration
and testing to take place (Irons and others, 2004).
4.4.2 Czech Republic
Mines in the Jiu Valley area of the Czech Republic are known
to be particularly gassy. The Vulcan mine is investing in a
new degassing station which will use the drained methane to
heat the mine’s water supply and provide heating in the
winter (Irons and others, 2004).
4.4.3 Slovenia
Although some test wells have been drilled in the Velenje
coalfield in Slovenia, further financing would be needed to
fully evaluate the CMM potential (Irons and others, 2004).
4.5
Russian Federation and the CIS
The US Department of Labor and US AID have established
an in-mine drilling project at the Krasnolmanskaya mine in
the Ukraine to determine the potential for a CMM project.
Work at the Sasyadsko mine project, mentioned in Chapter 3,
is continuing with a target of 131 MWe generation. A further
US TDA grant has been obtained for a feasibility study for a
further CMM project in the Ukraine but no further details
have been found (Franklin, 2006).
Ecometan is a Ukranian joint venture between the Industrial
Union of Donbass and two other large industrial firms which
seeks to develop CMM in the Donesk region, the largest coal
producing area in the Ukraine. Two pilot projects are planned
at Krasnomeyrsk and Komsomolets and drilling is under way
(CME, 2004).
Tailakov and others (2003) have predicted the suitability of
different CMM options at several mines (Komsomolets,
Raspadskaya, Lenina, Usinskaya and Pervomayskaya) in the
Kuznetsky coal basin. The cheapest options (in terms of
capital investment) at most of the mines was the use of CMM
in the boiler house. The Kosmolets mines showed potential
IEA CLEAN COAL CENTRE
Projects planned or under construction
for cost-effective installation of IC generators. The
installation of IC generators at the other mines would be less
cost-effective, taking local and regional factors into account.
As mentioned in Section 3.5.2, a major CMM project in the
Donetsk region at the Zasyadko Mine is under way. The
project, reported to be the world’s largest in terms of total
power output, will utilise 22 complete gas engine
cogeneration systems to generate 131 MW of electrical and
thermal output. The cogeneration systems will be GE
Jenbacher JMS 620 GS-S-LC engines manufactured at GE
Jenbacher’s facilities in Austria. The projected electrical
efficiency of the units is 42.9%, and the thermal efficiency is
41.3%. The equipment is being installed in ten stages, and
construction began in June 2004.
4.6
North America
As mentioned in Chapter 3, the USA captures and uses a vast
amount of VCBM for use as natural gas – the total input to
the pipeline was over 45 Mm3 in 2003. Most of the VCBM is
produced in Colorado, New Mexico and Wyoming (see also
Sloss, 2005). Initial investment in VCBM in the USA was
significant several years ago due to a tax credit which helped
make most projects profitable. Kirchgessner and others
(2002) emphasise that, since this credit is no longer available,
companies are currently reluctant to invest in VCBM/CMM
projects since the economics can vary significantly with
slight variations in key assumptions. If a tax credit were
re-introduced, the impetus to invest would return. The use of
greenhouse gas offset credits could also be effective, if they
become available and suitable interest is shown by power
generators. Deregulations in the electricity utilities sector
could heighten the interest by power producers to offer
‘green energy’ from VCBM/CMM projects. Pennsylvania is
the only state which, like Germany, classifies CMM as
renewable energy and therefore CMM projects are likely to
be more successful in this region.
Kirchgessner and others (2002) evaluated the methane
production at coal mines in the USA and estimated the
potential for CMM recovery and use in each area. The study
assumed that the mines would use one of six turbine models
ranging from 1.0 MWe to 10.7 MWe, depending on the type of
gas expected to be produced at the model mines and the inlet
fuel load (volume of recovered gas multiplied by heating
value). The power produced was assumed to be used within the
mine’s existing power grid or interfaced, at addition cost, with
commercial power grids. The option for feeding the methane
into a local pipeline was also considered. An economic model
was used to prepare a cost analysis of coal mining production
factors and methane production and utilisation costs. Any
predicted income from the sale of electricity to the grid was
factored into the analyses.
The study concluded that investments in CMM-to-power
projects would yield higher returns in the Warrior and central
Appalachian regions than anywhere else in the US mines
studied. The option of feeding the gas into a pipeline network
gave the highest investment return due to the large volumes
of high quality gas available in the Mary Lee and Pocahontas
Power projects using methane from coal mines
No 3 coal beds. In general, the most cost-effective use of
CMM at most of the mines surveyed was to employ systems
currently in use at the mines. The use of existing
degasification systems obviously reduces capital expenditure
considerably. Less gassy room and pillar mines are unlikely
to produce profitable methane-to-power projects. However, it
was estimated that a 1–12% increase in coal production rate
could offset the cost of implementing CMM capture and
utilisation systems. Gas turbines were determined to be the
most economic option at gassy mines in the Appalachian
basin. The option of injection of CMM into pipelines would
be less profitable due to the requirement of significant
investment in gas enrichment technologies to make the gas
acceptable to the national pipelines.
The low volumes of CMM produced in the Illinois basin
suggests that gas use in this area would not be profitable. The
Western region of the basin could use gas turbines at a profit.
A pipeline in this region would be too expensive to construct
(Kirchgessner and others, 2002).
At the coal mine, Federal No 2, West Virginia, plans are
under development for a CMM power generation project.
CMM from the mine is already used for pipeline injection
(M2M, 2005).
Consol Energy are in the production phase of a VAM
oxidation unit. The unit which will run on mine ventilation
air from the Bailey/Enlow Fork mine, is funded by a US
government grant (M2M, 2005).
4.7
Other
The US EPA Methane to Markets project has suggested that
significant CMM development potential exist in Kazakhstan,
Mexico, Romania, South Africa, Botswana, Indonesia and
Vietnam. The project aims to provide information and
expertise to allow these countries to progress further into
harnessing this technology (Franklin, 2006).
There is currently no CMM activity in Mexico, but Minerales
Monclova, a mining company, is planning to collect drained
mine methane from working mines to fuel a power
generation system. However, nothing has been initiated as yet
(M2M, 2005).
According to preliminary data from the M2M project, Brazil
has a pilot CMM project at the Pribbenow Mine, in Cesar
Departamento. So far, it appears that the project is simply
evaluating methane emissions with no utilisation. Exploration
is also taking place at other sites in Brazil (M2M, 2005).
As mentioned in the previous IEA CCC report on CMM
(Sloss, 2005), there is no commercial activity in Africa at the
moment. However, there does seem to be some indication for
potential in several areas. CMM could be used to supplement
the natural gas supply. A possible USAID project, worth up
to $85 million over three years, aims to establish a gas
pipeline in Nigeria (Kelefant, 2004).
Initial studies into VCBM/CMM potential in the Shangani
41
Projects planned or under construction
River Valley, in northern Zimbabwe do not seem to have led
to any projects being developed in this area (Ravenridge,
2006).
Industrial sponsors in South Africa have funded a Coal Tech
2020 study to assess future power options including CMM
potential. The government consider CMM as an attractive
option for replacing coal for cooking and cleaning in rural
and densely populated township areas. CMM could also add
additional peaking electrical generation in future if and when
the predicted power crisis hits the country (CME, 2004).
4.8
Comments
The Australian government’s commitment to reducing
emissions of greenhouse gases and the associated funding
should ensure that CMM-to-power projects continue to
flourish and that new and innovative technologies will be
given every chance to show their potential. The recent
success of CMM-to-power projects in Germany implies that,
unless the financial incentive provided by government under
the Renewables Energy Act is removed, CMM-to-power
projects will continue to grow in number. The lack of such
financial assistance in the rest of Europe means that CMM
rely on independent investors and are not guaranteed success.
Although numerous CMM-power projects have been
established in the UK in the past, it is predicted that CMM
will not receive much investment in the immediate future.
There has been considerable interest shown in the potential
for CMM-to-power projects in Eastern Europe and several
projects are under construction in the Ukraine. Whether new
projects are established in the area will depend largely on
investment from international sponsors and banks, most
likely through agreements under the EU ETS or the Kyoto
Protocol.
China is expected to be the area of most rapid growth in the
CMM-to-power market. The rapid population growth and
associated increase in energy demand mean that new power
sources must be found. However, since CMM-to-power
projects are still relatively new technologies and, in many
cases, still have marginal economics, this means that many
planned projects still require international funding.
42
IEA CLEAN COAL CENTRE
5 Conclusions
There is double value to the capture and use of CMM –
greenhouse gas emissions are reduced and the captured
methane can be used as a cheap and clean source of energy.
However, the capture and use of CMM is often technically
challenging and, even now, many projects are not regarded as
guaranteed investments.
The simplest use of CMM is as a replacement for natural gas
in gas pipelines. However, for this to be possible, the gas
must be clean and pressurised. In some situations this means
investment in a gas processing system. The gas must also be
delivered to the site of use, usually by pipeline. The USA
currently has the largest market for VCBM in natural gas
pipeline injection due to high natural gas prices and an
excellent infrastructure. Gas is also fed into the natural gas
system in Australia and France. In Asia the majority of
captured CMM is used more locally as town gas, with the
methane being piped only to the local community. Eastern
European countries such as the Czech Republic also supply
CMM through a local pipeline for residential use. The
demand for energy for rapidly growing populations means
that significant investment is expected to extend the natural
gas pipeline network in China and this opens up the
opportunity for increased VCBM/CMM use. There is also
talk of investment in natural gas pipelines in Africa.
either through oxidation or by providing a further source of
fuel in the intake air of combustion plants. Australia is the
most active country with respect to developing these
innovative technologies, the first full-scale VAM-to-power
project being established at the West Cliff Colliery.
So far, the success in CMM utilisation varies from country to
country, depending on the regional market place, government
incentives or other financial assistance, and the technical
success of the most appropriate use of the gas at each
individual location. Germany has demonstrated the most
rapid growth in investment in CMM-to-power projects, due to
the favourable energy pricing, whilst Australia has
demonstrated the greatest innovative developments in novel
and advanced uses of CMM, largely due to significant
government investment. However, in future China is expected
to be the area of most rapid growth in the CMM-to-power
market simply because it has the most rapidly increasing
energy demand. Many countries in Eastern Europe, the CIS
and even areas in Africa and South America are either at the
development and planning stage with potential new projects
or are making preliminary investigations into the potential for
such projects. Most of these projects will require
international expertise and funding to ensure their success.
Medium quality CMM can be used as a combustion fuel in
internal combustion engines and turbines. CMM can be
cofired with natural gas, coal, waste coal and even in steel
furnaces to provide an additional fuel source whilst, in most
cases, reducing pollutant emissions. The most efficient of
these systems are cogeneration systems which harness both
the power and heat produced. The country with the most
success in CMM-to-power projects is Germany, largely due
to the financial incentive provided by government under the
Renewables Energy Act. This guarantees the sale of the
power produced from any CMM based project at a
guaranteed price. Within one year of the Act being
established, over 40 new CMM-to-power projects were being
established. This surge in investment is expected to continue.
The lack of such financial assistance in the rest of Europe
means that CMM projects are not guaranteed success and
independent power producers are expected to bear all the
technical, financial, market and regulatory risks. Although
several CMM-power projects have been established in the
UK in the past, it is predicted that CMM will not receive
much investment in the immediate future. In Eastern Europe,
Russia and the CIS the major application of CMM is as mine
boiler fuel with limited power generation and power use
projects. CMM is also used as boiler fuel in China, largely at
the coal mines themselves, with some being used for power
generation. At the moment, China is receiving a significant
amount of investment in CMM-to-power projects, largely
through incentives such as those created under the Kyoto
Protocol. The world’s largest CMM-to-power project
(120 MWe) is being established at the Jincheng coal mine.
Even low quality VAM (<1% methane) can produce power
Power projects using methane from coal mines
43
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45
Appendix
CMM-to-power equipment suppliers:
Oxidisers:
Deutz AG
Deutz AG
Hauptverwaltung Deutz-Mülheimer Strasse 147-149
51063 Köln, Germany
www.deutz.de
MEGTEC
http://www.megtec.com
Jenbacher AG
Jenbacher AG, Achenseestrasse 1-3,
A-6200 Jenbach, Austria
http://www.jenbacher.com/www_english/jenbacher_ie.html
Caterpillar
www.cat.com
General Electric
http://www.ge.com/en/
Siemens turbines
http://www.powergeneration.siemens.com/en/index.cfm
GAS Energietechnologie GmbH
Hessenstrasse 57
D-47809 Krefeld, Germany
www.g-a-s-energy.com
Solar Turbines Inc
6000 East Crescent Ave, Suite 305
Upper Saddle River, NJ 07458, USA
www.gasturbines.com
Capstone Turbine Corp
6025 Yolanda Ave
Tarzana, CA 91356, USA
www.capstoneturbine.com
Elliott Microturbines
Stuart, FL 34997, USA
www.elliottmicroturbines.com
California Energy Commission - Distributed Energy
Resource Guide
www.energy.ca.gov/distgen/equipment/equipment.html
CH4min
http://cetc-varennes.nrcan.gc.ca/en/indus/mc_cm/ch4min.html
Other useful sources of information:
China Coalbed Methane Clearinghouse
cbmc@public.bta.net.cn
US EPA Coalbed Methane Outreach Program, CMOP
US EPA (6202J)
401 M St SW,
Washington DC 20460, USA
www.epa.gov/coalbed
US Department of Energy Coalbed Initiatives
http://www.netl.doe.gov/technologies/oilgas/FutureSupply/CoalBedNG/CoalBed_NG.html
US EPA M2M - Methane to Markets Partnership
www.methanetomarkets.org
UNECE
United Nations Economic Commission for Europe
Palais des Nations Room 347
CH-1211 Geneva 10
Switzerland
Tel. +41 22 917 41 40
Fax. +41 22 917 00 38
www.unece.org/ie
Australian Coal 21 Programme
www.coal21.com.au
Ravenridge Resources Inc
http://www.ravenridge.com/
Alkane energy
http://www.alkane.co.uk/
Engelhard molecular gate gas cleaning
http://www.engelhard.com/documents/molecular%20gate%20
illinois%20case%20study.pdf
International Coal and Methane Centre - Uglemetan
21 Rukavishnikov St,
Kemerovo 650610, Russia
www.uglemetan.ru
Cogeneration systems:
Karl Schultz, Climate Mitigation Works, UK
www.climate-mitigation.com
Trigen Energy Corp.
One Water Street, White Plains,
NY 10601, USA
www.trigen.com
California Energy Commission - Distributed Energy
Resource Guide
www.energy.ca.gov/distgen/equipment/equipment.html
IEA CLEAN COAL CENTRE
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