Research Report
No 566
Research Reports
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COORETEC Lighthouse Concept
The path to fossil-fired power plants for the future
www.bmwi.de
Concept:
Projektträger Jülich
Forschungszentrum Jülich GmbH
Dr. Jochen Seier, Dr. Horst Markus
www.fz-juelich.de/ptj
Editorial team:
Dr. Thomas Rüggeberg, Bundesministerium für Wirtschaft und Technologie
Dr. Jochen Seier, Forschungszentrum Jülich GmbH, PTJ
Armin Schimkat, Alstom Power Generation
Prof. Manfred Aigner, Deutsches Zentrum für Luft- und Raumfahrt e.V.
Prof. Dr. Günter Scheffknecht, IVD-Universität Stuttgart
Dr. Jörg Kruhl, E.ON Energie AG
Dr. Johannes Ewers, RWE Power AG
Prof. Bernd Meyer, TU Freiberg
Dr. Frank Schwendig, RWE Power AG
Dr. Karl-Josef Wolf, RWE Power AG
Hubertus Altmann, Vattenfall Europe Generation AG & Co. KG
Prof. Alfons Kather, TU Hamburg-Harburg
Christian Hermsdorf, TU Hamburg-Harburg
Prof. Günter Borm, GFZ Potsdam
Tim Schröder, freier Journalist
Editorial team:
Translation: Language Services Forschungszentrum Jülich GmbH
Photo credits:
Siemens Power Generation, Alstom Power, Hitachi Power Europe GmbH, MAN Turbomaschinen, RWE Power AG, E.ON Energie AG,
TU Dresden, Vattenfall Europe Generation AG & Co. KG, TU Hamburg-Harburg, GFZ Potsdam, N.V. Nuon, Universität Stuttgart
Printed by:
Grafische Betriebe
Forschungszentrum Jülich GmbH
Published by:
Federal Ministry of Economics and Technology (BMWi)
Public Relations /IA8
11019 Berlin
www.bmwi.de
As of:
April 2008
Research Reports
COORETEC Lighthouse Concept
The path to fossil-fired power plants for the future
Contents
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 04
Initial situation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
Objectives of the COORETEC Lighthouse Concept . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
Gas Combined Cycle Power Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
What combined cycle power plants can do today . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Challenges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Step by step to 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Where do we go after 2020? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Overview of development needs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
08
08
09
10
20
21
Steam Power Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
What steam power plants can do today . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Challenges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Step by step to 2020
for steam power plants with maximum efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
for post-combustion capture of CO 2 from flue gases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Where do we go after 2020? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Overview of development needs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
22
22
24
26
29
33
34
Coal Combined Cycle Power Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
What coal combined cycle power plants can do today . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Challenges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Step by step to 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Where do we go after 2020? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Overview of development needs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
36
36
38
40
45
47
Oxyfuel Power Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
What the oxyfuel process can do today . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Challenges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Step by step to 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Where do we go after 2020? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Overview of development needs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
48
48
50
51
57
59
CO 2 Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
What geological CO 2 storage can do today . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Challenges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Step by step to 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Overview of development needs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
60
60
62
63
70
4
Summary
Summary
The demands of the 21st century in the energy sector
and the area of climate policy provide the frame of
action for the German federal government's energy
research policy. The fossil energy resources coal and
gas will continue to play an indispensable role for
decades to come in the energy supply sector in
Germany and throughout the world. Against this
background, a key task in research funding is to exert
a positive influence on the response and flexibility
of Germany’s energy supply by safeguarding and
expanding the technological options. All the technological options that contribute to this goal in the
medium and long term are included in the German
federal government's funding policy.
The Federal Ministry of Economics and Technology is supporting the development of innovative
technologies with the COORETEC (CO2 reduction
technologies) research and development concept,
which aims to realize low-emission power plants
based on fossil fuels.
Initial situation
Industry and research are the main actors involved
in developing new technologies. The energy industry
is faced with the task of constructing new power
plants in order to modernize existing power plant
capacity. The first ground-breaking projects making
use of state-of-the-art technologies have already been
announced.
With these projects, the energy industry is setting up milestones in the classical priority topics of
efficiency and cost effectiveness. Siemens is building
a gas turbine plant at E.ON’s Irsching site, where they
will test the prototype of a new generation of gas turbines. If the facility operates successfully, it will be
extended into a combined cycle power plant and will
be the first plant worldwide with an efficiency level of
over 60 %. E.ON Energie plans to commission a power
plant with steam parameters of 700 °C by the year
2014 and will thus set a world record of over 50 %
efficiency in steam power plants.
It was long held that neither of these figures
could be improved. The success of these projects is
therefore to be regarded as the result of joint efforts
in research and development by government, industry and research. The COORETEC concept is playing
its part in this success.
Other milestones will have been passed by the
construction of power plants in which CO2 is removed
from the flue gas. Various technologies have been
proposed for this purpose. Vattenfall Europe is setting up a pilot plant for oxyfuel combustion on a scale
of 30 MWth. RWE Power is planning an IGCC power
plant with an electric power of 450 MW, which is to
go into operation in 2014. After separation from the
waste gas, the CO2 will be transported by pipeline for
storage in geological formations.
Objectives
of the COORETEC Lighthouse
Concept
The COORETEC Lighthouse Concept will focus and
intensify the efforts of the energy economy, and of
research and government policy, towards a sustainable power plant based on fossil fuels. Security of
supply, economic efficiency and environmental compatibility of new power plant concepts are the
central guidelines. The COORETEC Lighthouse
Concept is focused on the year 2020. By this time the
sustainable power plant should be available on the
market.
The technological goals of the COORETEC Lighthouse
Concept comprise:
Reducing the cost of CO2 capture and CO2 storage
from currently € 50 - € 70 per tonne of CO2 to less
than € 20 per tonne in future
Reducing efficiency losses from at present
9 - 13 % to 6 - 11 %
Achieving a high degree of reliability and
flexibility in order to be able to react fast and
efficiently to volatile electricity and energy
markets
Expanding gasification technologies
(provision of synthetic fuels and base materials
for the chemical industry).
5
Building blocks of the Lighthouse Concept
The foundation of the COORETEC Lighthouse Concept
is the current COORETEC programme. As part of the
Federal Government's High-Tech Strategy, additional
funds have been made available for the Lighthouse
project in order to selectively expand the R&D work
begun with COORETEC.
In order to maintain an effective energy policy in
the future, different technology lines must be developed simultaneously now. To this end, the concepts
of the various groups working on "Combined Cycle
Power Plants”, “Steam Power Plants”, “IGCC with
Integrated CO2 Separation”, “Oxyfuel” and “CO2
Storage” are integrated in the Lighthouse. The working groups have already provided valuable ideas for
the “COORETEC Lighthouse” and will in future exploit
the considerable synergy potential. The Lighthouse
therefore takes on the following form.
pre-c
ombu
focussed research
objectives
oxyfu
technological
political
stion
ombu
stion
post-c
CO2 st
orage
el
sustainability
climate protection
leadership in technology
WG5: CO2 storage
WG5
WG4: oxyfuel
WG4
maximum efficiencies. Apart from classical turbomachines, i.e. gas turbines and steam turbines, the
COORETEC Lighthouse Concept will consider compressors for captured CO2, whose levels of efficiency
must be significantly increased.
The demand for higher efficiency goes far
beyond the actual power plant process. It extends to
the processes involved in CO2 capture both before
and after combustion. Different approaches for
reducing energy demand are currently at various
stages of development. They must be assessed holistically. Apart from CO2, consideration must be given,
for example, to emissions from scrubbing fluids or
from reaction products.
The envisaged CO2 capture means that power
plant processes which cannot be implemented today,
or which can only be deployed in individual cases, are
becoming more important. The further development
of processes that involve the conversion of fossil fuel
without the nitrogen component of air is promising
(oxyfuel). The optimization goal here is the reduction
of the energy required for air separation using the
innovative air separation units or membrane process.
Membranes for oxyfuel and other processes are a
promising field of research and have a high innovation potential. It will probably only be possible to
exploit these processes fully after 2020.
Of major importance for development in the shortterm is a continued increase in the efficiency of
power plants and their components. This includes
accelerated exploration and qualification of materials that are resistant to high-temperatures as well as
the further development of turbomachines with
Besides the development of techniques for CO2
separation, another important task lies in ensuring
that CO2 storage is environmentally friendly. To this
end, studies are needed on topics such as the behaviour of CO2 in saline aquifers and exhausted natural
gas fields, on its interaction with rock, and on the
basis
Need for R&D within the COORETEC
Lighthouse Concept
The technology of the integrated gasification
combined cycle (IGCC) power plant is gaining significance because it displays a number of promising
advantages in terms of CO2 capture. One benefit is
that apart from electricity and heat other products
can also be generated in the power plant. Examples
include: synthetic fuels and base materials for the
chemical industry. This means that alternatives will
be available for the power plant industry thus reducing their dependence on oil. Another benefit is that
the gasification unit and combined cycle power
plants can be separated in time and space.
WG3: IGCC with
pre-combustion
capture
WG3
WG2: steam power plants
and post-combustion
capture
WG2
WG1: combined cycle
power plants
WG1
research concept
COORETEC
6
Summary
long-term safety of geological storage. The interaction between CO2 and rock is largely determined by
the impurities in the CO2 to be stored, which in turn
depend on the choice and dimensioning of the CO2
separation process used in the power plant. This is
why the two processes, CO2 capture and CO2 storage,
are closely linked.
Schedule for the COORETEC Lighthouse
Concept
Apart from technical aspects, other issues in
CO2 sequestration also remain to be clarified.
Considerable significance is attached to the licensability of storage facilities, the form of the licensing
procedure and public acceptance of the technology.
In order to make progress with these aspects, the
activities are being closely coordinated with the
Federal Ministry of Economics and Technology, the
Federal Ministry of Education and Research, and the
Federal Ministry for the Environment, Nature
Conservation and Nuclear Safety.
2010: Milestones in process and component
development
increased efficiency (700 °C technology and
further development of turbomachines)
increased operational flexibility
post-combustion capture process
IGCC process with pre-combustion capture
oxyfuel process
membrane technology
CO2 sequestration
2015: CO2 storage tests
technology trials
implementation of experience gained from
demo and pilot power plants
Incorporating the international perspective
The COORETEC Lighthouse Concept, as an initiative
of the German Federal government, complements
the initiatives that have begun on the European and
international level. Activities within the framework of
the COORETEC Lighthouse Concept will therefore be
harmonized with the implementation of the Strategic
Research Agenda of the Zero Emission Technology
Platform (ETP-ZEP) and with work carried out by the
Carbon Sequestration Leadership Forum (CSLF). In
this way, the benefits of the synergy effects will be utilized. Another link in the collaboration between various European countries with national research programmes on CCS technology is the ERA-NET “Fossil
Energy Coalition” (FENCO).
2020: The sustainable power plant with fossil fuels
Marketability of the technology
After 2020: Visionary technologies
Coupling of gasification technology, gas turbines
and fuel cells
(hybrid power plants)
Membrane processes for air separation
Membrane processes for hydrogen or CO2
separation
Power plants with “chemical looping”
Catalytic combustion
Process intensification
7
8
Gas Combined Cycle Power Plants
Gas Combined Cycle Power Plants
What combined cycle power
plants can do today
Gas-fired combined cycle power plants, also known
as gas and steam turbine power plants, represent an
important segment of the world power plant market.
If the necessary research and development efforts
are made, it will be possible to achieve efficiencies of
63 % by 2020. The previous technical progress made
with turbomachines can be continuously further
enhanced. However, this will still not exhaust the
potential of this technology. Many power plant
processes with carbon capture are based on the
key components of gas combined cycle power plants
and can be further refined into pioneering hybrid
designs with the aid of visionary approaches.
At present, we are experiencing an enormous
expansion in power plant capacities. Worldwide, new
plants with a total capacity of 120 to 160 gigawatts
(GW) are connected to the grid each year (Fig. 1). This
corresponds to approximately 150 large power plants.
Above all the increasing requirements in Asia, especially in China, will in the long term lead to greater
demand. The majority of the new plants (about 75 %)
are based on electricity generation using the fossil
energy carriers of coal and natural gas. Mainly, steam
power plants fired by fossil, nuclear or renewable
orders for power plants, 5-years-average
fuels will be put into operation for electricity generation, or gas turbine plants powered by natural gas
using thermal turbomachines.
Whereas in the 1950s to 1980s steam power
plants using oil and natural gas were the dominant
technology, in the past twenty-five years combined
cycle power plants have established themselves as an
additional standard design. With combined cycle
power plants, about two thirds of the electricity is
generated by gas turbines and one third via steam
turbines.
Modern gas combined cycle power plants
Modern gas combined cycle power plants are usually
supplied as complete, highly standardized systems
and represent classic export technologies. Germany is
regarded a leading nation for research and development, engineering services and the production of
power plant components and facilities of this type.
Leading world companies supplying this technology
are represented in Germany or have their headquarters here. Furthermore, German utilities also promote
progress with gas combined cycle plants by investing
in the best state-of-the-art technology thus providing
a basis for reference plants in Germany.
market share of different types of power plants
nuclear power plants other renewables
block power plants, micro turbines
hydropower plants
gas turbine power plants
combined
cycle power plants
steam power plants
Figure 1: Development of orders for power plants and market shares of various power plant types worldwide
9
Figure 2: Modern gas combined cycle design Alstom KA26 ICS
with 857.7 MW and 59.0 % efficiency
Figure 3: Planned combined cycle power plant unit Siemens
SCC5-8000H in Irsching with an expected 530 MW and 60 %
efficiency.
Since the technology of combined gas and steam
turbine power plants is, moreover, a core component
of combined cycle power plants with integrated coal
gasification (IGCC), progress with this type of power
plant plays a central role in economic and research
policy.
With an efficiency of at least 60 %, the high-tech
power plant will set new standards for environmentally friendly and cost-effective electricity generation.
If trial operation proves successful, E.ON will take
over the plant and turn it into a commercial operation.
At present, an electric net efficiency of 59 % is
regarded as the best achievable performance for
large gas-fired combined cycle plants. This state of
the art, documented by the overall plant concept
KA26 ICSTM 1) from Alstom (Figure 2) is commercially
available. Recent technological developments in turbomachines and advances in plant integration have
contributed to this success. Progress in this field has
been decisively promoted by the COORETEC concept.
However, the development potential of this
power plant type is by no means exhausted. Power
and efficiency can be further increased as has been
demonstrated by the new Siemens gas turbine, SGT58000H, the prototype of which is currently under
construction in Berlin. It is 13 metres long, 5 metres in
diameter and weighs more than 440 tonnes. With
a capacity of 340 megawatts, it will be the largest
and best-performing gas turbine in the world and
will be 20 % more powerful than conventional plants.
Irsching in Bavaria is the envisaged site. If the test
phase proves successful, the gas turbine plant will be
extended to form a highly efficient gas and steam
(combined cycle – CC) power plant with a capacity of
about 530 megawatts (MW) (Figure 3).
1)
Integrated Cycle Solution
Challenges
In future, the demands made on gas combined cycle
power plants will become increasingly complex. On
the one hand, they must be able to adapt to the fluctuating electricity demand from the grid, i.e. alternating load. Peak demand is to be covered by “peakers”
(peak power plants), while operation close to base
load must also be efficient. Furthermore, such power
plants must display good partial load efficiency - for
example, for regulating short-term fluctuations from
energy generated by wind power or photovoltaics.
On the other hand, significance is also attached to
high availability at competitive capital costs, low
maintenance costs and high fuel flexibility with
the lowest possible fuel consumption – all these
factors define the technical and economic parameters.
The improved efficiency, shown in Figure 4 by
the example of a gas combined cycle power plant,
is of central significance for the overall success of
COORETEC. Any increase in efficiency is associated
with a reduction in specific CO2 emissions. Furthermore, lower CO2 emissions considerably reduce the
10
Gas Combined Cycle Power Plants
efficiency
combined cycle
spec. CO2-emissions
time
combined cycle
The core components of the combined cycle power
plant, i.e. the gas and steam turbines, account for
about one third of the production costs while the
development cost of these components amounts to
about 75 % of the development costs of a combined
cycle power plant as a whole. Particularly great R&D
efforts are therefore required for these two turbomachines
combined cycle with
CO2-capture
Figure 4: Relation between efficiency and CO2 emissions with
the example of a gas turbine power plant and a gas combined
cycle power plant
efforts required for CO2 separation, which will probably play an increasing role for gas-fired power plants.
condenser
heat recovery
system
instrumentation
and control
gas turbine
generator
Key technologies from gas combined cycle power
plants, such as gas or steam turbines, will continue to
be the main components of future power plants with
carbon capture technology. As an example, Figure 5
shows a design for a combined cycle plant with downstream CO2 separation, in this case CO2 absorption
with monoethanolamine (MEA).
CO2-lean
off-gas
CO2-absorption
with MEA
liquefied
CO2
steam turbine
boiler
fuel
air
combustion
chamber
compressor turbine
Figure 5: Example of downstream CO2 separation: gas combined
cycle power plant with amine scrubbing
steam turbine
compressor
turbine
combustion chamber
Figure 6: Perspective view of a combined cycle power plant
Research and development work in the field of
gas and steam turbines and also compressors in the
COORETEC programme is being coordinated by the
Turbomachines Working Group (WG Turbo). This
successful research collaboration has been active
for more than 20 years and currently consists of five
industrial enterprises, three research institutions and
17 universities. This working group performs R&D
activities in the field of turbomachines. The close
cooperation between the partners and the intensive
networking with the university sector has proved to
be a great benefit and has led to considerable savings
in costs and raw materials. The Turbomachines
Working Group cooperates closely with the other
COORETEC working groups (Figure 7).
Gas turbines – compression and expansion:
Step by step to 2020
Consideration must be given to a wide range of
components and individual systems in the further
development of gas combined cycle power plants.
The perspective view of a combined cycle power
plant in Figure 6 illustrates the components involved.
The compressors for the gas turbines used in gas combined cycle power plants must in future be even more
efficient, reliable and flexible.
This will be ensured by focusing research work on
the priorities listed below in the field of Compression
and Expansion".
11
CO2-reduction
by increased efficiency
Technical and economical
feasibility of
CO2-free power plants
steam turbines
increased of efficiency
WG Turbo
gas-fired combined
cycle power plant
coal-fired steam
power plant
CO2-free power generation
integrated
gasification
combined cycle
ioxyfuel
power plant
CO2storage
steam turbines
gas turbines
compressors
Figure 7: Cross-cutting function of the Turbomachines Working
Group (WG Turbo)
Aerothermodynamic optimization of compressors and turbines
raises the operating point of the compressor towards
higher efficiencies and leads to improved partial load
behaviour. Altogether, these measures decisively
improve the efficiency for applications in low-CO2
power plants. Furthermore, this also enlarges the
operating range of the compressor thus fulfilling the
demand for increased partial load stability.
Findings on compressor aerodynamics and
strength obtained in preliminary experiments must
be verified by practical trials on large compressor
test rigs. It is equally important that the high reliability of existing gas turbine compressors should be
transferred to new products. To this end, work will
be intensified on the evolutionary development of
the blade profile production and design of the gas
turbine compressors. Experimental studies on a
selected multistage segment in the compressor with
several rows of blades will then demonstrate the suit-
The aerodynamic losses, the efficiency and also the
stability of modern, highly stressed axial compressors
largely result from instationary flow in the peripheral
regions. A detailed understanding of the time-dependent processes taking place at the blades and cavities
represents an important basis for designs thus increasing efficiency, especially in highly stressed compressors, and consequently for improved process efficiency of the gas turbine. Another objective is the development of an improved casing structure for high-pressure compressors. Experiments will clarify whether
the surface and geometry in contact with the flow
medium can increase the efficiency or the stability of
the compressor.
Extending the operating range with increased
efficiency especially in partial load operation
(“partial load flexibility”)
An increase in efficiency and improvement of operational performance in the partial load range can be
achieved, amongst other approaches, by structural
means in the region of the blade tip or the stator gap.
This requires detailed studies of non-steady-state flow
phenomena in the region of the blade tips of the
rotors. It is also important to improve the surge line of
the compressor, which is a region in which operation
becomes unstable. This can be achieved by an
improved design of the compressor stators, which
Figure 8: Compressor and expansion stage of an Alstom GT8C2
gas turbine
ability of the improved component. Studies in the test
rig are indispensable, particularly for optimizing the
rear stages of the multistage segments. Conventional
measuring methods cannot fulfil this task. So-called
lattice measurements (2-D approach), for example,
are not sufficient since they do not cover the significant 3-D flow effects (boundary layers of the side
walls, blade clearing). The situation is made more
12
Gas Combined Cycle Power Plants
difficult by the fact that due to the limiting turbine
inlet temperature no specific load or overload of the
rear stages in an experimental gas turbine can be
determined by established measuring methods. The
measures discussed above will ultimately lead to an
impro-vement in gas turbines with respect to efficiency, reliability and flexibility.
Gas turbines – combustion:
Modern power plant processes have a great influence
on the combustion process in gas turbine combustion
chambers. Modified fuel and oxidator specifications,
higher flame temperature and pollutant minimization
– all these aspects must be kept under control by the
combustion technology. The provision of regulating
energy also requires optimal combustion in partial
load operation. Work in the field of “Combustion”
therefore focuses on the following topics:
partially or completely decarbonized fuel and fuel
mixtures of various compositions will be studied with
respect to their flexibility. Flexible burner designs of
this type display a very high potential for contributing to a significantly CO2-reduced energy supply.
In order to raise power plant efficiency, gas turbine
burners must be modified in such a way as to permit
even higher turbine inlet temperatures in the future.
To this end, burner performance data, thermodynamic data, design principles and operating parameters
must be determined and focused for the new concept
so that they can be adjusted more closely to each
other in the development of new burn chamber
designs. The following issues currently still require
clarification:
What fuel-air mixture should be selected in twist
burners with alternative fuels?
What influence do large fuel volume flows have
on burner aerodynamics?
What designs do burner systems need for flexible
fuel input (for example synthesis and natural
gas?).
Furthermore, combustion systems must be
developed for natural gas that has considerable proportions of higher hydrocarbons and they must be
qualified for temperatures of up to 1700 °C and high
pressures. Innovative designs are required for this
purpose in order to reduce both the NOx emissions
and also combustion instabilities, which increase
perceptibly at higher temperatures.
Thermoacoustics and stability at partial load
Figure 9: Illustration of a Siemens SGT5-4000F cooled gas
turbine annular combustion chamber protected thermal barrier
coatings
Innovative burner designs
The paramount aim of projects on the topic of
"Innovative Burner Designs" is to develop reliable
low-pollution gas turbine burners capable of utilizing
various fuels for a broad range of gaseous and liquid
fuels containing hydrocarbons. New ground-breaking burner designs, for example, making use of
Since heat release is not homogeneous during the
combustion process, local pressure changes arise in
the combustion chamber. At certain frequencies,
these pressure changes can increase and become pulsations with a devastating effect on the facility. The
general term for this subject area is thermoacoustics.
The undesirable thermoacoustically induced combustion vibrations lead to challenges regarding further developments, especially of combustion systems
operating at elevated pressures and temperatures.
Furthermore, they also restrict fuel flexibility. An
improvement in the thermoacoustic design procedures and test methods is therefore decisive for low-
13
CO2 gas turbine fuel chambers employing a range
of fuels. It is known that above all lean and low-pollution combustion systems tend to encounter problems
with combustion instabilities. Reliable findings on
thermoacoustic stability are indispensable for such
systems. Only in this way is it possible to achieve high
flame stability with future high-performance gas
turbines. This particularly applies to operation at
partial load. Amongst other aspects, investigations
must consider the thermoacoustic stability limits and
amplitudes of the acoustic pressure in high-temperature combustion systems over a wide pressure range.
From these studies, it will be possible to derive a
description of the dependence of acoustically triggered pressure amplitudes on operating pressure.
This is a necessary condition for transferring test
stand results to actual machine conditions. The
results lead to reliable correlations between test
stand and machine, which will considerably reduce
development efforts for future burner and combustion chamber development.
Figure 10: Turbine blade from one of Siemens’ state of the art gas
turbines
Gas turbines – cooling:
Air for cooling the hot gas components in gas turbines is generally drawn from the compressor or its
outlet. Cooling air accounts for about 20 % of the
volume of air drawn in by the compressor and is thus
not available for its primary purpose. Furthermore,
the cooling air must be subjected to elaborate pretreatment when taken from the main air mass flow.
Cooling air supplied externally can also adversely
affect the primary purpose. The objective must therefore be to reduce the volume of cooling air. This will
not only improve component efficiency but will also
have a positive influence on the overall efficiency of
energy conversion. Work in the field of “Cooling” will
focus on the following areas:
Coolant flow and internal blade cooling
There are various promising technical possibilities
for reducing coolant requirements and further
increasing the gas temperature in the turbine.
They include the development of improved hightemperature materials and thermal barrier coatings.
It is also hoped to make progress by innovative com-
ponent cooling and improved protection against
high surface temperatures with the aid of thin cooling films. These cooling films are insulating protective gas layers which separate the hot working medium from the gas turbine blade. Innovative concepts
are characterized by an increasing degree of design
detail. The combination of impingement cooling and
film cooling seems to be particularly suitable, and
apart from transpiration cooling, which is more
difficult to implement, seems to be the most efficient
method. These cooling methods are attracting
increasing attention for wall-integrated configurations in the combustion chamber, above all because
distinct progress has recently been made by fabrication technology in this field. The geometries are
characterized by the fact that they are in part able to
reconcile contradictory requirements – sufficient
structural strength of the component (greater wall
thicknesses) and the necessary cooling (low wall
thicknesses). Priority topics include work on the optimal coordination of the cooling methods, achieving
the lowest possible production and maintenance
costs, high reliability and increased functionality and
safety by means of particle separation systems.
14
Gas Combined Cycle Power Plants
Interaction of cooling, aerodynamics and
leakages
The overall efficiency of a plant does not only depend
on the quality of the individual components but it is
also decisively influenced by how well the individual
components and their interfaces are adjusted to each
other. One example is the interaction between the
strongly swirling combustion chamber flow and the
first row of guide vanes in the turbine. The swirling
motion has a considerable influence on the aerodynamic losses of this blade row and the propagation or
initiation of the cooling film on the surface of the
blade. If the complex flow at the combustion chamber outlet were considered in the design process then
it would be possible to achieve aerodynamic optimization of the first row of guide vanes and also
improved film cooling. This would directly increase
process efficiency and reduce the quantity of cooling
air.
Increased performance and demands on the
compactness of the facility will in the future lead to
high-pressure turbines which will display so-called
transonic flow conditions and which will be faster
than the speed of sound both in the stator and the
rotor. This does not only increase the aerodynamic
load on the turbine blades but also leads to a continuously increasing thermal load due to rising turbine
inlet temperatures. Intensive cooling of the trailing
edge of the blade, which is often the zone of the blade
that determines the lifetime, will thus be mandatory.
At the same time, the trailing edges must be as thin as
possible since the thickness of the trailing edge has a
great influence on profile loss due to the flow vortex.
This leads to an inherent conflict between structural
strength, manufacturability and induced aerodynamic losses of the turbine guide vane and rotor
blades. Optimization of the trailing edge is therefore
of great significance.
Roughly half of all the electricity generated
world-wide is produced by steam turbines driven by
coal, nuclear energy, oil or natural gas, and also by
biomass, solar energy or geothermal energy. An optimization of these key components will therefore lead
to great savings in energy carriers and thus considerably reduce CO2 emissions. Against this background,
the following development goals are recommended:
Raising the steam parameters to increase power
plant efficiency
Raising expansion effice
Increasing the flexibility of power plant operation
and improving partial load operation
Raising expansion efficiency
An important development goal in steam turbine
technology is that of increasing efficiency. This can
be achieved by increased performance with the same
fuel input. In other words: by increasing the thermal
efficiency it is possible to achieve a perceptible reduction in CO2 emissions at constant electric power.
R&D activities in this field are focused, amongst
other aspects, on the creation and further development of innovative sealing designs and the improvement of design procedures for large low-pressure
blades.
Steam turbine:
In a steam turbine, the flow medium of steam drives
a rotor, which in turn sets in motion a generator for
electricity production or a compressor. The steam
turbine is one of the most important components for
electricity generation.
Figure 11: Section through the steam turbine of a modern
combined cycle power plant
15
Another point is optimization of the exhaust steam
flow in order to reduce the exhaust losses behind the
final stage. Exhaust losses can be reduced by larger
outlet cross sections. This automatically increases the
efficiency. At the same time, larger outlet cross sections require larger final stage blades. However,
increasing the dimensions of the final stage blades
has previously come up against mechanical limits
and limits on fluid mechanics. Due to the size of the
final stages, the inflow Mach numbers towards the
rotor and the three-dimensional effects also increase.
Closely linked experiments and numerical studies are
therefore required in order to analyse the complex
flows in the low-pressure range (non-steady, transonic, moisture effects).
Increasing flexibility / improving partial load
behaviour
In the previous design philosophy for steam turbines,
priority was given to optimal efficiency. The deregulation of the electricity market and the increasing application of renewable energy sources for electricity generation now leads to new requirements. There is a
need for ever greater flexibility and optimal partial
load behaviour. The following demands can therefore
be formulated:
Rapid start-up and shut-down of the steam
turbines
Considerable rise in number of load cycles
Lowering of the stable minimum load point,
Higher efficiency and lower emissions at the
partial load point.
Central significance is attached to first describing
and plotting the maximum load states of multistage
steam turbines operated at very low partial load. This
will enable loss mechanisms to be identified in detail.
On the one hand, the findings will lead to an improved understanding of the flow phenomena and their
effect on turbine components. On the other hand,
these data will be of assistance in the development of
numerical optimization strategies for reliable predictions of turbine states. Another objective is optimization of the blade attachments of the low-pressure
final stages. Due to the increasing dynamic excitations, their damping behaviour must be improved.
Figure 12: Construction work at the power plant
Furthermore, stochastic lifetime analyses will
provide reliable information on fatigue of lowpressure blades under high- and low-cycle stresses.
An additional technical challenge is improving the
mounting of the low-pressure blades, which in
future will have to withstand increased dynamic
forces.
Turbomachines for air separation
and compression in CO 2 separation and
storage facilities
In a future low-emission power plant, apart from the
main components, i.e. the gas and steam turbines,
special turbomachines will also be of significance for
air separation and the compression of carbon dioxide
in CO2 separation and storage facilities. The reason is
that these turbomachines consist of compressors and
possibly their turbine drives. Attention is focused on
two aspects:
New, larger types of compressors and steam
turbine drives must be developed for the large
quantities of CO2 to be compressed in power
plants with CO2 separation.
16
Gas Combined Cycle Power Plants
Before CO2 separation can be introduced its high
energy demand must be significantly reduced.
Due to process requirements, turbomachines for
this application consume a major fraction of this
energy and must therefore be further developed
with respect to reducing their energy consumption.
Scaling of turbocomponents in air separation
plants
In air separation plants as required for combined
cycle power plants with integrated gasification or
oxyfuel power plants, use is made of industrial compressors, steam turbine drives and expanders.
However, much larger units are required for technical and economic reasons in typical large power
plants. Such units are not yet available on the commercial market. These larger units can only operate
economically if they can be constructed more compactly, with higher throughput, increased pressure
ratios and at the same time a greater range of performance characteristics. These requirements are
not yet met by compressors in stationary gas turbines
and air drives. However, efforts are being made to
optimize the units. Synergy effects can be exploited
by combining compressor know-how from industrial
compressor and gas turbine compressor development. Research and development is, however, made
more difficult by the wide range of applications.
Thus, for example, compressors of both axial and
radial design are used in compressor units for the
air separation plants. It is therefore important that
work should be intensified on the development of
both designs, and especially on their respective
blading.
Qualification of CO2 compressors for large delivery rates
Compressors of axial design, still to be developed, are
required for the initial compression of the large quantities of CO2 arising at power plants. Compressor units
of a radial type, as shown in Figure 13, can be considered for transporting CO2 from the power plant to the
storage facility. However, even larger units will be
required in the future to handle the growing volumes
of CO2. Their efficiency must, furthermore, be consid-
erably increased. Compressors of this type require
very high pressures. This can be achieved by several
radial stages arranged around a gearwheel. In this
way, each compressor can be operated in its optimal
working range. In an ongoing project, CO2 from a
power plant in North Dakota (USA) is piped to
Weyburn, Saskatchewan (Canada) where it is used
to improve the feed pressure in oil wells. Even facilities of this size will not be large enough for future
power plants and will have to be designed to be both
bigger and more efficient.
Figure 13: Multishaft 8-stage compressor facility for CO2
compression
This leads to new challenges arising for the development of the stages and the rotor dynamics of the
overall facility. Facilities of this type operated at the
power plant for the initial compression of CO2 will be
driven by steam turbines. In contrast, those compressors that are used in special pumping stations of the
transport pipeline to transport the CO2 will be driven
by industrial gas turbines. In accordance with the
flow rate, both types of turbine will have to be adjusted across a wide capacity range. Furthermore, the
units must be extremely reliable since the compressor
stations may be sited at remote locations. It would be
difficult and expensive for technicians to be employed
on the spot. For this reason, the compressors should
be characterized by long maintenance intervals.
17
1200 °C. The aim is to raise the operating parameters
towards higher temperatures. Improvements can be
achieved by modifications in the chemistry and structure and also by self-healing systems.
Figure 14: Special ceramic coatings for maximum thermal load
in gas turbines
Materials technology:
The increasing demands made by advanced gas
combined cycle power plants on their components
due to the higher process parameters of tem-perature
and pressure, with at the same time the requirements
for inexpensive manufacture and economic operation, must be satisfied by corresponding developments in materials technology. The crucial aspect is
to make the components so resistant to mechanical
and thermal load that they display increased lifetime
even with higher loads. To this end, sufficient knowledge must be available on the behaviour of the materials.
These demands on materials technology give rise
to the following R&D topics (see also the COORETEC
materials strategy paper).
High-temperature coating systems for gas
turbines
The life of thermally loaded components can be
extended in a particularly economical manner by
applying high-temperature coatings. Zirconia has
become established as a ceramic material for thermal
barrier coatings. The thickest possible ceramic layers
would be desirable for increased gas temperatures.
However, sintering of zirconia limits its application to
New ceramic thermal barrier coatings on the
basis of pyrochlore and garnet, some of which are
composed of several layers of different materials, are
also very promising. They can withstand higher gas
inlet temperatures. Coating parameters and service
life models must be adapted or redesigned in order to
develop extremely heat-resistant components. The
first laboratory findings are already available.
Another issue is the corrosion resistance of adhesive
layers when used with alternative fuels. Systems of
adhesive layer thermal barrier coatings must therefore be developed, which, in addition to high tem
perature resistance, are also able to cope with the
demands of corrosive conditions, and are moreover
able to withstand extreme cyclic operation on the
basis of their strain-tolerant behaviour.
Oxidation and corrosion in the hot gas path
due to altered working fluids
IGCC designs will be of great significance in the
future energy supply. However, the corrosion resistance of such plants must first be improved. IGCC
plants without gas quenching are operated with
synthesis gases that have a high particulate content.
This increases the content of alkalis and vanadium in
the flow medium – substances which intensify corrosion. By contrast, in the case of IGCC processes with
CO2 separation, almost pure hydrogen is burnt so that
high steam partial pressures are found in the flue gas
from combustion. Furthermore, fuels with a high content of sulphur, alkali and vanadium are increasingly
used for electricity generation and may attack base
materials with a low chromium content. There is an
urgent need for more research here. The aim is to
study the corrosion behaviour of materials systems
as well as the corrosion resistance of base materials
and coatings in IGCC plants with CO2 separation.
Particular interest is attached to the effect of fuel
gases contaminated with alkalis and vanadium
(heavy oil, low-caloric syngas) in the hot gas path
as well as the influence of steam on the long-term
corrosion resistance.
18
Gas Combined Cycle Power Plants
Numerical models must therefore be developed to
predict and verify corrosion behaviour. In this context, the influence of inhibitors must also be taken
into consideration.
developments, all the material properties and the
appropriate production methods must be identified
and qualified.
Rubbing and sealing system for rotor/stator:
Figure 15: View of a gas turbine
Modular components with optimized choice of
materials and joining technology
In order to optimize components, on the one hand
the potential of conventional materials should be
fully exploited by improving the base material and
the protective coatings. On the other hand, increased
corrosion and temperature resistance also requires
materials that are specifically tailored to the local
load profiles of the components. One possible
approach is to use modular components, for example
turbine blades whose feet are made of a different
material from that of the blades. Material technologies are already available that enable engineers to
design such modular components. The contribution
that materials technology can make is to be found, in
particular, in the development of joining and jointing
processes for materials of the same and different
compositions.
Rotor materials of greater strength, blade
materials of lower density
In future high-performance plants, the strain on the
rotors will also increase – for example, due to higher
circumferential speed. One solution is to use rotor
materials with greater strength or blade materials
that have lower density or greater strength. For such
The smaller the secondary losses between the rotating blades and the housing are, the lower are the efficiency losses of the compressor and turbine. It is possible to reduce the blade clearance with the aid of
suitable material structures. The optimal choice of a
materials system for the blade tip / housing inlet coating also has a direct impact on efficiency. The gaps
can only be kept small enough if the housing coating
is sufficiently porous to permit blade rubbing without
damage and, on the other hand, is hard enough so
that it does not corrode prematurely. A special focus
is the development of software tools for predicting
the behaviour of the rub coating during contact.
Furthermore, a comprehensive data basis is to be
made available for an optimal choice of materials
system.
Overall processes:
Process engineering aspects are of great significance
in order to transfer progress made on the component
level to suitable, improved overall plant concepts.
Maximum efficiency and reliability, availability and
cost effectiveness can only be achieved by new interconnections or specific, detailed optimization steps.
The preparation of combined cycle power plants for
the application of CO2 capture processes is also one of
the challenges in this field.
More effective CO2 separation by flue gas
recirculation in gas turbine processes
The idea of flue gas recirculation is based on the
development of a power plant design that permits
retrofitting so that the CO2 can be efficiently removed
from the flue gas flow. This is to be achieved by flue
gas recirculation by means of which, after leaving the
heat recovery steam generator, part of the flow is fed
back into the gas turbine (Figure 16). This leads to two
effects: the NOX pollutants are reduced and the rela-
19
tive CO2 concentration in the flue gas flow is
increased. This makes it easier to separate the CO2
from the flue gas and thus increases economic attractiveness. However, the modified operating conditions
in the combustion system, such as redu-ced oxygen
content, still require basic research on combustion
performance and flame stability. Gas turbines will
first be evaluated in a conceptual design study. A
comparison with boiler firing systems is, however,
studies on hybrid concepts are currently being performed with SOFCs and gas microturbines. The components will then later actually be coupled. By 2014,
a demonstration plant will be constructed on a megawatt scale. In parallel to process integration, upon
which attention is focused here, fuel cell development will be continued in a separate dedicated
programme.
Storing electricity by means of compressed air
energy storage plants
steam bleeding
fuel
steam turbine
fuel
heat recovery
steam generator
condenser
gas turbine
stack
cooler
air
CO2absorption
flue gas recycling
M
CO2
H2O
• MEA
• NH3
CO2 (liquefied)
Figure 16: Gas turbine combined process with flue gas recirculation and CO2 separation
also of interest. It will be possible to apply this technology in the near future by making use of components that can be retrofitted. This approach is consequently of special interest.
Hybrid processes based on coupling high-temperature fuel cells and gas turbines
Very high efficiencies can in principle be achieved
with hybrid processes. Hybrid power plants fired by
natural gas that generate electricity both via hightemperature fuel cells and also by gas and steam turbines can theoretically achieve peak efficiencies of up
to 70 % for plant outputs of more than 50 MWel. Such
hybrid power plants with lower efficiencies will first
be applied for decentralized energy production with
a few MWel, for example for the generation of electricity from biomass. A precondition for the later
application of solid oxide fuel cell (SOFC) technology
or other high-temperature fuel cells in large power
plants is, however, that they are further developed to
achieve higher operating pressures, increased unit
capacity and a dramatic cost reduction. Preliminary
The construction of ever increasing numbers of offshore wind farms means that in the future more and
more energy will be generated with fluctuating
power levels. There is thus a growing need for energy
to be stored so that generation and utilization can be
decoupled. In this case, compressed air energy storage plants (CAES) represent an alternative large-scale
commercial alternative to pumped storage power
plants. Experience has already been gained with socalled diabatic compressed air energy storage plants
combined with gas turbines. The first 290-MW plant
in Huntorf, Lower Saxony, has been in operation since
1978. Designs adapted to modern gas turbine technology are also available.
A further development of this concept is adiabatic compressed air energy storage. The goal is a local,
zero-emission, purely storage technique. By interim
storage and reintroduction of the compression heat,
adiabatic compressed air energy storage dispenses
with the use of fossil fuels. At the same time, high
storage efficiencies can be achieved. This technology
therefore makes it possible to generate peak load
electricity from renewable energies in a CO2-neutral
manner.
In order to make progress with this concept, suitable compressors, heat storage facilities and turbines
will be designed in the integrated research programme on “Renewable Energy Sources". However,
the obvious synergies of these components with
those in fossil-fired power plants mean that there
are close links to the topics of the COORETEC programme.
20
Gas Combined Cycle Power Plants
Where do we go after 2020?
Studies of visionary power plant technologies and
designs are already in progress in order to ensure that
electricity generation from fossil fuels remains competitive on an international level. Application-oriented basic research concentrates on products to be
introduced after 2020. In accordance with the major
focus of Working Group 1 (gas combined cycle power
plants), some promising ideas and technologies will
be presented in the following.
Isobaric, adiabatic compressed air energy storage
Going beyond adiabatic CAES technology, the thermodynamic process idea of isobaric, adiabatic gas
combined cycle compressed air storage has been
developed for the offshore sector. This process is
based on an isobaric volume storage system whose
volume and pressure are regulated by a water column. During the storage process, the compressed air
is cooled behind the compressor in a regenerative
heat exchanger and heat storage system before it is
displaced by water in the isobaric compressed air
storage unit. When the water flows back into the
storage unit during the expansion process, the compressed air is heated again in the regenerative heat
exchanger and storage system in the counterflow.
Depending on plant design, the air is either used
directly in a hot-air turbine or expanded in a gas turbine with additional heating provided by natural gas.
The exhaust gases contribute their heat to a steam
process attached.
Ceramic and fibre-reinforced materials
In the long term, the further development of alternative materials is of interest for hot-gas components in
gas turbines, such as the highly thermally stressed
blades or combustion chamber walls, where such
materials should display considerably higher temperature capacities in comparison to metallic materials.
The group of alternative materials includes ceramics,
ceramic fibre-reinforced materials and fibre-reinforced nickel aluminides. At present, experience is
largely restricted to the laboratory environment.
These materials still have to prove their technical
potential as well as their reliability and manufacturability at low cost. Apart from reliable manufacturing
and design methods, the application of alternative
materials also requires the development of suitable
new corrosion-resistant coatings. Suitably adapted
non-destructive test methods and quality-assurance
measures also need to be developed.
Thermally highly stressed, open-pored and
cooled multilayer systems for combined cycle
power plants
In order to achieve maximum efficiency in future
gas-fired combined cycle power plants, new design
principles for the highly stressed components must
be developed now for the period after 2020. This will
ensure that net efficiencies of 65 % and more can be
achieved. To this end, optimized process and flow
configurations must be designed for working and
cooling fluids and new materials need to be tested.
Only in this way will it be possible to control the
required high process temperatures and pressures.
The special collaborative research project 561
“Thermally highly stressed, open-pored and cooled
multilayer systems for combined cycle power plants”
at RWTH Aachen University has taken up this mission
and will provide the required technical and scientific
fundamentals. Attention is focused on research into
the interactions between complex flow and heat
transfer processes and open-pored multilayer materials with flow-through during effusion cooling.
Depending on the results of the development of fundamental principles, the collaborative research performed by industry and science can then pursue
promising approaches which can be turned intoproducts at the earliest possible date.
21
Overview of development needs
Gas turbine
Turbomachines for air separation and CO 2
compression
Compression and expansion
Aerothermodynamic optimization of compressors and turbines
Extending the operating range with increased
efficiencies especially in partial load operation
Ensuring the aerodynamic and aeromechanical
stability of the blades with sufficient service life
necessary for flexible power plant operation
Rig tests to determine the compressor load
limits
Materials technology
Combustion
Increasing fuel flexibility (fuel systems for a wide
range of fuels – natural gas / hydrogen-rich synthesis gases / alternative fuels, reaction kinetics
data and models)
Expanding the stability limits (humming, ignition and extinction behaviour, active and passive
damping, sensors, actuators)
Steam turbine
Increasing the steam parameters
Raising expansion efficiency
Making turbine operation and plant integration
more flexible
High-temperature coating systems for gas turbines
Oxidation and corrosion in the hot gas path due
to altered working fluids
Modular components with optimized choice of
materials and joining technology
Rotor materials of greater strength, blade materials of lower density
Rubbing and sealing systems for rotor/stator
Overall processes
Cooling
Optimization of coolant withdrawal and flow
Optimization of internal blade cooling
Multidisciplinary design of future blade profiles
(aerodynamics, cooling and leakage)
Improved and reliable sealing systems
Scaling of turbocomponents in air separation
plants
Qualification of CO2 compressors for maximum
flow rates
Optimization of plant integration with respect to
efficiency, availability, economic efficiency and
CO2 separation capacity
More effective CO2 capture by flue gas recirculation in gas turbine processes
Hybrid processes arising from coupling hightemperature fuel cells and gas turbines
Storing electricity by means of compressed air
energy storage plants
22
Steam Power Plants
Steam Power Plants
efficiency of the power plant process is beneficial
since this means that less resources are required
and thus the amount of CO2 to be separated is also
reduced. If possible, increasing efficiency and
subsequent CO2 separation should go hand in
hand.
What steam power plants can do
today
Steam power plants with maximum efficiency
Figure 1: Coal-fired power plant, Boxberg, Germany
Just over 40 % of electrical energy worldwide is
generated by conventional steam power plants. In
Germany, the proportion is about 50 %. Use is generally made of coal as the primary energy source,
since it is available throughout the world in sufficient
quantities and at a stable price. In order to conserve
resources and reduce fuel costs, the efficiencies of
steam power plants have been improved by continuous further development. In the past two decades,
increasing attention has been paid to improving
efficiency. The reason is the drive towards reducing
greenhouse gas emissions – in this case, carbon dioxide CO2. Appropriate efforts have improved power
plant efficiency by 15 to 20 % during this period. In
this way, fuel consumption has been reduced and
to the same extent also the amount of CO2 emissions
relative to the quantity of electricity generated.
Two complementary directions are being pursued in the development of steam power plants. On
the one hand, work is progressing on the above-mentioned increase in efficiency in order to achieve even
greater reductions in CO2 emissions. Moreover, concepts are also being examined for the subsequent
separation of CO2 from flue gases emitted by steam
power plants. The latter is termed post-combustion
capture. Even with subsequent separation of CO2 high
1)
Increased efficiency has been achieved in recent
years by rigorous optimization of the overall process.
The most important individual measures are increasing the steam temperature and steam pressure,
decreasing internal losses in the steam turbine and
the parasitic load and also raising steam generator
efficiency. Improving steam conditions was and is
closely associated with the development and testing
of different types of steel with the required thermal
stability.
In Germany, mainly large-capacity lignite-fired
power plants (a total of about 6000 megawatts (MW))
and hard-coal plants (a total of about 2000 MW) have
been constructed and put into operation in the last
two decades. In the past three years, work finally
began on the expected programme of power plant
refurbishment. Enquires have been received by
power plant manufacturers for coal-fired units with
a total power of more than 12,000 MW, and in some
cases orders have already been placed. In the short
term, orders are expected for units with a total capacity of another roughly 3000 MW. In accordance with
the present state of the art, these plants will reach live
steam temperatures of about 600 °C and reheated
steam temperatures of 605 to 620 °C and are thus
designed for maximum efficiency. The overall efficiency 1) will amount to 43 to 44 % for lignite-fired
units and 45 to 46 % for hard-coal plants. The maximum unit size was increased once again to 1100 MW.
The CO2 emissions of all conventional electricity generating plants in Germany will be considerably
reduced by this construction programme.
Net efficiency relative to the lower heating value, cooling via a natural convection cooling tower
23
Robust materials are indispensable for the
increased steam temperatures and pressures necessary for a further rise in efficiency. Before embarking
on this construction programme, the established
material concepts were therefore carefully scrutinized. In some cases the strength data and the corrosion and oxidation properties were reassessed. In
addition to Japanese manufacturers, European producers have also established themselves as suppliers
of semifinished products. Furthermore, the new steels
had to be tested to ensure that they comply with the
European regulation on pressure equipment. Weak
points were identified and eliminated by means of
appropriate investigation programmes.
With respect to developments in other countries,
particular consideration must be given to Japan and
China. In the 1990s, Japanese power plant and materials manufacturers were world leaders in the field of
high-temperature facilities and the associated materials. China has, however, caught up in the meantime.
In 2003 China launched a programme of power plant
construction of unprecedented dimensions. In order
to satisfy its enormous energy demand, China plans
to construct almost 100 new coal-fired power plants
per year up to 2012. These plants are at a high level of
technological development since all the projects
either make use of licensed technology or are undertaken together with foreign engineering partners.
The licensers or partners are Japanese, American and
European power plant manufacturers.
Numerous modern steam power plants have
been constructed in Japan in the past 20 years.
Especially in the 1990s, several units were put into
operation every year each with a capacity of 700
to 1000 MW. In the course of this expansion programme, the steam parameters were continuously
increased so that ultimately at the end of the 1990s
steam temperatures of 600 and 610 °C were achieved
at the live steam and reheated steam outlet, respectively. However, in ntrast to Germany, the live steam
pressures were not increased to more than 240 or 250
bar. The Japanese plants are almost exclusively fired
by Australian hard coal, which corresponds to the
quality of imported coal usual in Germany today.
As already mentioned, the progress described
can be attributed to various individual measures.
Further improvements in efficiency over and above
the present level can only be achieved by further
Figure 2: Steam lines
increasing the steam conditions. In the case of fuels
with high moisture content, such as domestic lignite,
external predrying of the coal will open up further
potential.
Post-combustion capture of CO 2 from flue
gases
The process of separating CO2 from flue gases consists
of an absorption step and a regeneration step. In the
absorption step, the CO2 is removed from the flue gas.
In the regeneration step, the CO2 is removed from the
solvent or the CO2 carrier. This produces a highly concentrated flow of CO2 which is then fed into the CO2
liquefaction unit.
Absorption can be performed with the aid of liquid solvents. A distinction is made between organic
solvents, usually amines, and inorganic solvents such
as alkaline or alkaline earth solutions or suspensions.
Furthermore, dry sorption can also be performed
with the aid of alkaline earths such as calcium oxide.
CO2 separation by amine scrubbing (organic
solvents) has already been introduced for certain
industrial applications. A number of plants with
24
Steam Power Plants
CO2 separation by amine scrubbing can already be
found around the world. These are, however, smallscale facilities producing CO2 for the food industry or
for enhanced oil or gas recovery – EOR/EGR. Moreefficient and larger CO2 separation units are required
for power plants, especially for coal-fired power
plants due to their specific gas compositions and gas
states as well as their very large volume flows. In this
field, there is still a considerable need for research
and development. Furthermore, the regeneration of
the solvent is very energy-intensive and leads to a
considerable loss of efficiency. According to the
present state of the art, these losses can amount to
as much as one third.
CO2
CO2-free off-gas
already used for gas treatment. They may also be of
benefit for CO2 separation from flue gases – on the
one hand because of the stability of the solvent and
on the other hand because there is little formation
of undesirable by-products.
Another option is dry CO2 absorption, which
resembles dry gas treatment in order to minimize
pollutants. Alkaline earths, preferentially calcium,
are well suited for this purpose. Under the appropriate reaction conditions, CO2 is separated from the
flue gas with the simultaneous formation of carbonate. In the case of flue gas scrubbing, the flue gas
interacts with solid matter. Gas and solids together
form a
gas-solid suspension.
Further details can be found below under the
headings of amine scrubbing, scrubbing with inorganic solvents and dry CO2 separation.
absorber
desorber
heat
exchanger
Challenges
for steam power plants with maximum
efficiency
flue gas
During CO2 separation with amines, the solvent
is sprayed into the flue gas flow. It absorbs the CO2 by
a chemical reaction. After this absorption, the amine
loaded with CO2 is thermally regenerated at 100 to
130 °C. To this end, low-pressure steam is extracted
from the water/steam circuit of the power plant. After
regeneration in the desorber, the solvent is once
again used for absorption. The above figure shows a
flow diagram of the process.
In the past, there have been numerous attempts to
develop steels capable of tolerating high steam temperatures of up to 650 °C, as yet without success.
Experts therefore do not expect that iron-based materials will be able to tolerate any further appreciable
temperature increases above the present state of the
art. However, a new material concept involving socalled nickel-base alloys opens up completely new
prospects. Nickel-base alloys are extremely resistant
even at high temperatures, which makes it possible to
dramatically increase steam temperatures to more
than 700 °C so that in future efficiencies of more than
50 % can be achieved.
As an alternative to amines, inorganic solutions
or suspensions can be used as solvents. However,
the basic process principle remains wet flue gas
scrubbing, in which the flue gas interacts with a liquid in the absorber. Detergent solutions of this type
have not yet been used for CO2 separation from flue
gases. In the chemical industry, such solvents are
Consideration should be given to the fact that,
due to the increasing amount of imported coal from
various sources, in future the fuel quality will vary to
a greater extent than is the case at present. The power
plant engineering must be particularly flexible in
order to nevertheless achieve maximum efficiencies.
Therefore, the prospects for conventional steam
heat supply
Figure 3: Process flow diagram of an amine scrubbing column
25
Fuel flexibility
The increasing use of imported coal from various
sources and of different qualities for power plant firing, the utilization of domestic coal with poor combustion properties and the co-firing of biomass and
substitute fuels make it necessary to adapt the firing
and steam generator technologies. However, the cofiring of biomass and substitute fuels with the associated biogenic fractions is of benefit since this further
reduces CO2 emissions. Furthermore, these fuels are
used with far greater efficiency than in the case of
monofiring. New monitoring methods for the firing
system and steam generator are required in order to
achieve optimum combustion.
Operational reliability
The design and operational monitoring of pressure
parts is undertaken by novel methods. Increased
process parameters and the expected flexibilization
of the load scheduling and start-up behaviour are
taken into consideration here.
Figure 4: Welding at a manifold
power plants based on coal firing can be summarized
as follows
Challenges
for CO 2 separation from flue gases
Amine scrubbing
Maximum efficiency
In the period under discussion, efficiencies of significantly more than 50 % can be achieved. It is thus possible to reduce CO2 emissions by about 30 % in com
parison to the existing plant stock in Germany and
by 15 % in comparison to that achievable with plants
being constructed at present. This is based on optimized process design and improved individual components with maximum component efficiency such
as steam generators and steam turbines. The extent
to which processes and components can be optimized
ultimately depends on the performance of the materials and developmental status of the materials technology. Fuels with a high moisture content, such as
domestic lignite, cannot yet achieve such efficiencies.
However, this will be possible in future by predrying
the coal in external drying facilities.
In amine scrubbing, aqueous solutions of various
amines and also mixtures of amines are used as solvents. The best known amine used for CO2 separation
is monoethanolamine (MEA). Since the amines have
to be thermally regenerated, a large quantity of energy is required for the regeneration process in the
form of steam. Thus, for example, an energy of about
4 MJ/kg of separated CO2 is required if MEA is used.
That is to say, the process consumes energy but on the
other hand releases a similar quantity of adsorption
energy. However, due to the low temperature level in
the absorber this energy cannot be used. The great
amount of regeneration heat required is ultimately
the reason for the above-mentioned reduction in
power plant efficiency.
The central challenge for amine scrubbing is thus
the identification of amines or amine mixtures that
26
Steam Power Plants
do not require such large amounts of regeneration
heat. To this end, new solvents or mixtures of solvents
are being developed and tested in research projects.
Activators (for example primary amines) are frequently added to tertiary amines. This step is necessary
because the absorption reaction of the tertiary
amines proceeds very slowly in comparison to the
reaction of the primary amines. Furthermore, in
developing new amine mixtures the corrosive action
of the solvent and its stability when in contact with
associated gases in the flue gas, such as SOx, NOx and
O2, must be investigated and taken into consideration.
Industrial experience has already been gathered
with dry processes for CO2 separation from flue gases,
at least in some process steps such as calcination.
Furthermore, the behaviour of sorbents also suitable
for CO2 separation is known from dry gas purification.
Whether alkaline earth metals are suitable as
CO2 carriers for a cyclic CO2 separation process and
whether they can be repeatedly used has not yet been
reliably established. There is still a need for basic
research here. This also applies to plant design. It is,
for instance, unclear whether two gas-solid reactors
can be operated effectively at very high solid
exchange rates.
Step by step to 2020
for steam power plants with maximum
efficiency.
Increased steam conditions
If the new nickel-base materials are applied for the
high-temperature sector instead of the previously
used iron-based material steam temperatures can
in the future be increased to values of more than
700 °C.
Figure 5: Scrubbing system with MEA
Moreover, the scrubbing systems must be adapted to the large volume flows present in power plants
and to associated components such as residual particulate matter.
Scrubbing with inorganic solvents and dry
sorption
As yet, processes with inorganic scrubbing liquids
have hardly been applied under conditions even
remotely resembling those of a steam power plant.
Basic development work is therefore still required in
order to explore the potential of this process for
power plant operation.
The idea of a power plant with a steam temperature of 700 °C was first put forward in the midineties.
These ideas were focused in the AD700 project that
was co-funded at that time by the 4th Framework
Programme for Research and Technological Development (RTD) of the European Community. One of the
most important findings of the project was that the
700 °C technology would be economically feasible. In
parallel to this – as a rule, coordinated with activities
in AD700 – other research projects were also implemented. This includes, amongst others, the MARCKO
DE2 und MARCKO 700 projects co-funded by the
German Federal Ministry of Economics. In the past,
the superheater test sections have been financed by
the participating industrial enterprises.
Under the name of COMTES700, a project has
been launched for testing key components for a 700
°C power plant under commercial conditions. This
27
component test facility was installed in the Scholven
power plant in Gelsenkirchen, Germany, and started
operation in summer 2005. Apart from the most
important steam generator and pipework components, the fittings and the turbine inlet valve were
also tested. The project was funded by the industrial
enterprises involved and the European Commission
as part of the “Research Fund for Coal and Steel“
(RFCS).
The COMTES700 project 2) is supported by the two
MARCKO projects. At the same time, experiments are
being performed in several power plants in order to
provide back-up data on high-temperature corrosion
behaviour in a real flue gas atmosphere and to study
the oxidation behaviour inside the piping.
On 25.09.2006, headed by VGB 3) with support
from the Federal State of North Rhine-Westphalia,
the NRWPP700 project was launched – a detailed
engineering study. Rising prices of raw materials,
such as nickel, and the experience gained in procuring semifinished materials and manufacturing
components for COMTES700 suggested that details
of the technical design for the PP700 project should
be re-examined.
New resistant materials are required since the
component temperatures at the transition to the 700
°C steam temperatures, both in the superheater and
also in the intermediate superheater, are increased by
about 100 K. Mainly novel austenites and nickel-base
materials can be considered for use in superheaters at
these elevated temperatures, but these materials still
need to be proven. Ferritic or martensitic steels are
particularly suitable for evaporators. Studies must,
furthermore, be made of the effect caused by ash
deposits from the flue gas. Special attention is also
paid to the way in which deposits arising under typical firing and boiler operating conditions in a 700 °C
power plant interact with the piping materials. As in
the case of 600 °C plants, programmes studying corrosion and scaling as well as materials research and
qualification programmes will focus on the 700 °C
power plant.
2)
3)
Sufficient knowledge has now been gathered
about the 700 °C power plant for a demonstration
plant to be built. However, the development potential
still has not been exhausted. In the meantime, it is
considered technically feasible for the steam conditions to be increased above 700 °C. This approach
will be intensively pursued. The aim of more extensive research is, amongst other aspects, to improve
the composition of the nickel-base materials to such
an extent that steam temperatures of up to 800 °C
are possible. The development of material models
to optimize the composition of the basic material
and a corresponding improvement of the weld
filler metals could then make an important contribution.
The 700 °C technology is to be further verified.
To this end, a demonstration plant with a capacity
of at least 500 MW will be planned and constructed.
Assuming that the current research projects and
those planned for the near future proceed successfully, such a plant could be realized by the year 2014. In
the pre-engineering study PP700, due to run until
mid 2008, the foundations are currently being laid
for detailed planning of the demo power plant.
Numerous research projects will have to be additionally performed in order to meet the requirements
for the construction and operation of the demonstration facility. The goal is to obtain optimized materials
and to verify the necessary processes for manufacturing the high-temperature components.
nickel-base
alloy
10% chromesteel
Figure 6: Nickel-base alloy in high-pressure steam turbines
The partners involved are the European utilities E.ON, RWE, EnBW, Vattenfall, EDF, Electrabel, Elsam, Energi E2 and PPC as well as
the four manufacturers ALSTOM Power Boiler, Hitachi Power Europe, Burmeister & Wain Energy, and Siemens
VGB Vereinigung der Großkraftwerksbetreiber e.V. (German Association of Large Power Plant Operators)
28
Steam Power Plants
Steam turbine
Higher temperatures cannot merely be controlled
by employing improved materials but also by cooling
certain components. State-of-the-art technologies
used for gas turbine blades can also be applied for
steam turbines. High priority is therefore assigned
to the development and introduction of blade cooling
for the first stages of the high-pressure/medium-pressure turbine sections. To this end, R&D activities must
be intensified in various fields. Interest is also focused
on investigating heat flows and transfer in high-temperature components, as well as work on the topics of
“component deformation” and “rotor stability and
bearings of high-temperature turbines”. The density
of the steam will increase in future due to the elevated steam pressures. At the same capacity, this leads to
a decrease in the blade compartments. The additional losses thus arising must be investigated and avoid-
Figure 7: Steam turbo group composed of high-, medium- and
low-pressure turbines and a generator
pling of the shaft and the blade, and also the flow
conditions.
External coal drying
If moist raw coal with a water content of more than
45 % is to be used for firing power plants, predrying
the raw coal enables the efficiency to be increased
by up to 10 %.
Two processes for external coal drying are
currently under development. On the one hand,
there is a thermomechanical dehydration process in
which the raw coal is mechanically dewatered after
being heated to approx. 140 to 200 °C. The second
process, steam fluidized bed drying, is already at an
advanced stage of development. In this process, the
raw coal is fluidized in a stationary fluidized bed in a
steam atmosphere while being heated. The process
can be applied under atmospheric and also elevated
pressure. In the variant under atmospheric pressure,
the steam released can be used in the process to heat
the dryer (fluidized bed drying with internal wasteheat utilization). A precommercial demonstration
plant is currently being constructed at an existing
power plant as the final step before the commercial
realization of a large-scale power plant fired by dry
coal.
IThe extent to which the process is suitable for
drying lignite must first be demonstrated in plants of
the corresponding size. Furthermore, issues of the
combustion and fouling characteristics of the dry lignite need to be investigated.
Design and monitoring
ed as far as possible. A developmental priority is the
further enlargement of the outlet area to reduce outlet losses. The introduction of titanium as a blade
material represents a leap forward in these developments.
With respect to a 700 °C demonstration plant,
the aim is to produce and verify the large components (shaft, casing). These activities must also pay
closer attention to the welded joint between the nickel-base material and the steel for the shaft, the cou-
National legislation or European directives govern
the design of components for the power plant sector.
In accordance with the relevant specifications (for
example the pressure equipment directive – PED)
“before placing pressure equipment on the market
and before putting such components into operation”
it must be demonstrated by a proven design method
that safe operation is possible under the specified
conditions. Modern methods, such as simulations, are
being increasingly used for this purpose.
29
With respect to strength-related aspects, power
plants are currently mainly designed according to
existing standards by analytical calculation steps
(design by formula - DBF). Important properties are
thus obtained from a data basis, validated by many
decades of experience, containing the characteristic
materials data and the know-how on relevant damage
mechanisms. In the course of the European harmonization of standards, however, approaches based on
continuum mechanics are being increasingly applied
(design by analysis – DBA). The validation of the computational approaches also requires basic experimental studies of the deformation and damage behaviour
of the new materials – especially with respect to the
complex load situation for applications at temperatures of over 700 °C.
Similar challenges arise in monitoring the plants.
To date, relatively little operating experience, or
indeed none at all, is available for components made
of the new materials. This then causes shorter inspection intervals than has previously been the case. In
order to minimize the resulting disadvantages for the
economic viability and the availability of the plants,
R&D work is specifically required for monitoring the
condition of the components made of the new materials.
For post-combustion capture of CO 2 from
flue gases
Amine scrubbing
The development of new solvents based on amines
is a key development goal. On the one hand, this
enables the demand for regeneration heat to be
reduced and, on the other hand, also improves the
energy efficiency. Furthermore, the solvents and
the related steps in the process engineering must
be adapted to conditions in power plant operation.
The technology for treating gas by amine-based
solvents comes from the chemical industry. In chemical plants, the solvents are as a rule merely marginally degraded, since apart from carbon dioxide and
hydrogen sulphide, the product gases generallyonly
contain very low quantities of oxygen. This is also the
case for the gas treatment process. However, amine
Figure 8: Steam generator being installed
scrubbers have to fulfil different demands under the
conditions prevailing in steam power plants. The
flue gas from a steam power plant contains approx.
3.5 to 7 % oxygen. This leads to a degradation of the
amines and various decomposition products also
arise (acetates, glycolates, nitrates). Inhibitors are
added to the solvents in order to prevent the degradation of the amine by oxygen.
The situation is aggravated by the fact that
amines form salts with SO2, SO3 and NO2, which are
unavoidable constituents of flue gas in power plant
operation. These salts are separated from the solution
during the treatment of the amine solution at high
temperatures in the so-called reclaiming process.
This means that amines are continuously lost from
the process. Additional amine consumption arises
from the oxidative and thermal degradation. The
level of this consumption is largely dependent on
the process parameters of oxygen and temperature.
The aim is to minimize amine consumption as far as
possible. This can be done, for example, by improved
flue gas cleaning and by a corresponding reduction
of the gas components SO2 und NO2, going beyond
the legal regulations. Amine loss can also be reduced
by further cooling of the flue gases. Furthermore,
modified regeneration processes are also conceivable.
30
Steam Power Plants
Plant systems familiar from the chemical industry are applied in flue gas scrubbing for CO2 separation using amines. These systems normally consist of
scrubbing columns with several scrubbing sections
which, in turn, are equipped with packing material or
structured packing to enlarge the reaction surface.
Distribution dishes are located between the individual scrubbing sections for optimal distribution of the
scrubbing solution. In order to avoid losses, evaporated solvent is condensed at the upper end of the scrubbing column using a scrubbing/cooling unit and
washed out of the flue gas. Complex structures of this
type are extremely large – not least because several
scrubbing columns are generally required. This leads
to pressure losses of about 100 millibars (mbar), which
must be compensated by the plant. Furthermore,
waste water arises through the scrubbing section at
the column outlet and has to be disposed of separately. In addition, during trial operation of an amine
scrubber in coal-fired power plants an accumulation
of fine fly ash was observed in the amine solution. The
extent to which this would lead to problems during
scrubbing column operation – for example, clogging
of the packing material – cannot currently be assessed due to the lack of operating experience. In this
respect, further experience must be gained under
conditions relevant for power plants.
Since the scrubbing columns currently applied
are based on those from the chemical industry they
are not entirely suitable for use in power plants. By
adapting the scrubbing columns it should be possible
to avoid problems such as column dimen-sions, pressure loss on the gas side, particle load, or laborious
removal of amine residues from the flue gas.
The use of amino salts is an alternative to aqueous amine solutions such as MEA. These salts have the
advantage that they are not sensitive to oxygen.
Furthermore, they need less energy for regeneration.
However, precipitation products are formed if amino
salts are used. Due to the danger of clogging, they
cannot be used in scrubbing columns equipped with
internal installations that intensify the gas-liquid
reactions. A basic requirement for the appli-cation of
this amino species as an alternative to the other
amines is that the scrubber does not need internal
installations of this type. The advantage of precipitation product formation is that the CO2 partial pres-
sure over the liquid remains constant. CO2 absorption
is ultimately promoted thus leading to a higher
loading of the solution, and the amount of energy
required for regeneration therefore drops.
A promising process variant is the application
of membranes. The membranes separate the gas
and liquid phases. Due to this phase separation it is
possible to control the gas and liquid throughput
separately. This results in more compact facilities
and lower pressure losses. However, the optimal combination of amine and membrane still remains difficult. On the one hand, the membrane must permit
the CO2 to be transported through the pores but, on
the other hand, the amine must not penetrate into
the pores. It furthermore remains unclear how the
fine fly ash in the flue gas influences the stability of
the membrane.
Another promising amine development is mixtures of tertiary (for instance, methyl diethanolamine
– MDEA) and primary amines. While the former are
characterized by lower regeneration heat requirements but a slow absorption rate, the primary amines
accelerate the CO2 uptake in the absorber by carbamate formation. However, these so-called activators
also have disadvantages. They increase the corrosiveness in the hot parts of the regenerator and these activators must be thermally regenerated in the detergent cycle. Compared with a pure MDEA solution, the
heat requirements for regenerating the detergent are
thus increased. One solution would be to selectively
retain the chemical activators in the absorber – to
immobilize them. This would mean that the substances would be available to increase the performance of the absorption process. On the other hand,
this would reduce requirements for regeneration
energy and also susceptibility to corrosion. It has
been shown that the same absorption rates can be
achieved with a mixture of immobilized amines (socalled fixed amines, ion exchangers or ion exchange
resins) and MDEA (tertiary amine) as with a mixture
of MEA (primary liquid amine as activator) and
MDEA.
The aim of further research and development
is to obtain amines with improved properties and
to integrate amine scrubbing into the power plant
process. Before it can be applied commercially, MEA
31
equilibrium reaction that increasingly proceeds in
the opposite direction with rising temperature. On
the other hand, the temperature increase can also be
used to regenerate the scrubbing liquid. The reaction
is naturally not determined by the temperature alone
but also by the concentration of the reactants. Apart
from the partial pressure of the carbon dioxide, the
concentrations of the carbonate and hydrogen carbonate also have a decisive influence on the reaction.
Figure 9: Steam turbine
scrubbing must be verified in a demonstration plant
downstream of a coal-fired plant.
Scrubbing with inorganic solvents
For existing coal-fired power plants, the separation
of carbon dioxide by basic inorganic sorption solutions represents an alternative to processes with solid
inorganic separation media and to absorption with
organic media (amines). If the chemical composition
of the absorption medium is specifically adjusted
then it is possible to optimize both the conditions for
separation and also for treatment and regeneration
by means of aqueous solutions. Basic alkaline and
alkaline earth solutions as well as suspensions of
the above-mentioned components can be used as
scrubbing liquids. Separation of the carbon dioxide
is essentially performed according to the ionic reaction
CO32- + H2O + CO2 2 HCO3- .
In the course of this reaction, one mol of CO2 per
mol of carbonate can be bound via the hydrogen carbonate. However, it should be noted that this is an
In spite of the great similarity between the chemical reactions of alkalis and those of alkaline earths,
considerable differences result for CO2 separation
from the process design. These differences are caused
above all by the different solubilities in water of alkali
and alkaline earth carbonates. The alkaline earth
carbonates are only poorly soluble whereas alkaline
earth carbonates dissolve comparatively readily.
Conversely, the alkali hydrogen carbonates are less
soluble than the corresponding carbonates. This
means that it is more appropriate to use alkaline
earth carbonates in suspensions whereas alkali carbonates can be used in a dissolved form.
paid to the influence of other acidic salt-formers
such as SOx and NO2 and of the hydrogen halides.
Even after flue gas desulphurization, SO2 concentrations of more than 100 m g/m3 may still be present in
the flue gas from coal-fired power plants This does
not only cause increased consumption of absorbents
during amine scrubbing but also directly influences
the reaction kinetics and equilibrium.
Additional emissions may be released both during the gas cleaning process and also in treating the
scrubbing media. Furthermore, substances may be
formed that could contaminate the groundwater.
However, in principle, all the processes mentioned
here are of the regenerative type in which the objective is to achieve the best possible regeneration of
the sorbents. Furthermore, the chemicals, sorbents
or reaction products released during the chemical
reactions are largely environmentally compatible
since they are mainly neutral or weakly alkaline substances, many of which also occur in natural minerals.
Flue gas scrubbing for CO2 separation with the
aid of inorganic solvents is currently still at a very
32
Steam Power Plants
early stage of development. It is not yet foreseeable
whether these solvents will be able to establish themselves as an efficient alternative to conventional CO2
scrubbing in the future. The feasibility of this process
must therefore first be demonstrated before suitable
solvents can be developed and tested.
Dry sorption
Dry sorption-based fluidized bed processes are an
alternative to conventional CO2 scrubbing. In these
processes, absorbent bed materials are used to transport the CO2 between two reactors thus enabling
very efficient CO2 separation processes. The drop in
efficiency can be significantly reduced.
Calcium oxide (CaO) is an appropriate choice
of CO2 carrier from the group of alkaline earth elements. Limestone is available almost everywhere at
low cost. It has long been used in dry gas cleaning for
removing pollutants from flue gases. In contrast to
the gas cleaning process, however, CaO has to be
Figure 10: Sketch of a coal-fired power plant with CO2 separation
regenerated for CO2 separation. This is done in an
additional process step – calcination.
In the calcination process, CO2 is separated and
channelled into CO2 liquefaction. The resulting
calcium oxide is recycled into the absorber. In the
absorber, the calcium oxide is carbonized by absorb-
flue gas
coal
absorption
(carbonizing)
CO2-free
flue gas
regeneration
(calcining)
Figure 11: CO2 separation on a calcium basis
ing CO2 from the flue gas thus forming calcium carbonate (CaCO3). The figure shows the basic principles
of the process.
Fluidized bed reactors coupled via the calcium
cycle are suitable for the absorption and regeneration
processes. Comparable processes, also based on calcium, for the gasification of biomass or very reactive
fuels are currently under development. On a laboratory scale, it has already been demonstrated that calcium is suitable as a bed material for fluidized bed
reactors. Moreover, it has been possible to obtain
important findings on the design and operation of
coupled fluidized bed systems.
The absorption process operates at a high temperature level. In contrast to the scrubbing processes,
the energy released during absorption can therefore
be used as heat. The heat requirements for calcination are covered by the combustion of coal. As in the
oxyfuel process, combustion must take place with
pure oxygen in order to obtain the desired high CO2
concentrations. However, compared to the oxyfuel
process, the oxygen requirements and thus the losses
during air separation are much lower. These losses
can be reduced even further if the heat required for
calcination is not supplied via the above-mentioned
combustion with oxygen but by means of a hightemperature heat exchanger.
hese processes will be performed with the chemicals already familiar in power plant operation such as
limestone. The first preliminary experiments have led
to good levels of CO2 separation. The next objectives
are a demonstration of feasibility and then the construction and operation of a pilot plant with an investigation of the sorbents.
33
Where do we go after 2020?
Steam power plants also display potential for development beyond the time horizon of 2020. With
respect to conventional steam power plants, work
will continue on raising the steam temperature to
more than 700 °C. In materials development, completely new approaches will be pursued for suitable
materials. In the same way, alternatives to steam as
a working medium must be investigated and also
multicomponent processes so that it may be possible
to exploit a potential efficiency of more than 60 %.
The objective of downstream CO2 separation is
mainly to decisively improve energy efficiency and
thus also economic viability. In the case of processes
based on the principle of CO2 absorption and CO2
regeneration, this can only be done by integrated
utilization of the absorption heat and integrated
supply of the regeneration heat. The need for additional energy is thus restricted to CO2 post-treatment
according to the present state of the art of CO2 liquefaction.
Permanent mineral binding of the CO2 as carbonates offers potential for further efficiency. On the one
hand, there is no need for CO2 liquefaction or the
additional energy it requires. On the other hand,
additional energy is released by carbonate formation
which can be usefully employed. This development
chain thus culminates in a vision of a steam power
plant that converts coal into electricity with an efficiency of more than 60 % and which permanently
stores the fossil carbon dioxide flow as carbonates.
34
Steam Power Plants
Overview of development needs
Steam power plant
Coal-fired power plant with steam temperatures of over 700 °C
Other efficiency-raising projects
Overall projectt
Construction and operation of a demonstration
plant for lignite drying
Enlarging the outlet area of the LP turbine to
reduce outlet losses
Construction of a demonstration plant with 50 %
efficiency and a capacity of at least 500 MW
Materials development
Post combustion capture
Amine scrubbing
Development and qualification of nickel-base
materials for even higher steam temperatures
(compare research in USA and Japan)
Further development of ferritic-martensitic
materials for use in the evaporator of the 700 °C
power plant (up to about 610 °C) and in the steam
turbine (up to 650 °C)
Development of improved coating systems to
reduce oxidation, corrosion and erosion of the
materials used in the high-temperature region
of the 700 °C power plant
Improvement of the sealing technology for the
700 °C power plant
Manufacture of large cast and forged parts
Welding of thick-walled components
Development and qualification of suitable
processes for manufacturing large-diameter
pipes
Development and testing of optimized aminebased solvents
Adaptation of the scrubbing columns and their
internal installations to the solvent and the
power-plant-specific flue gas constituents and
conditions
Investigation of alternative processes based on
amines (for example, use of fixed amines, amino
salts, and membranes to separate the gas and liquid phase)
Optimizing the incorporation of the process in
the heat cycle (both for retrofitting and for new
plants)
Demonstration of amine scrubbing with coal firing. This would be the next step on the road
to commercial plants.
Steam turbine
Scrubbing with inorganic solvents
Development and qualification of welded joints
between nickel-base materials and steel for
large-diameter shafts
Coupling of shaft and blade
Development of service life concepts and basic
principles for an assessment of the fracture
mechanics of high-temperature steam turbines
Development of long-term measurements of
static elongation of components and also of
sensor technology for measuring radial clearance
at 700 °C
Optimization of flow conditions incorporating
aspects of structure mechanics and rotor
dynamics (integral coupling of the calculation
approaches)
Performance of a feasibility study to identify
the potential
Development of scrubbing with alkaline
solvents
Testing a selected process in a pilot plant
Dry sorption
Performance of a feasibility study to identify
the potential
Construction and operation of a pilot plant to
investigate the sorbents with respect to stability,
consumption and subsequent utilization
35
36
Coal Combined Cycle Power Plants
Coal Combined Cycle Power Plants
Coal combined cycle power plants are a promising
option for future low-CO2 and zero-CO2 energy generation. By utilizing gas and steam turbine processes
they achieve high efficiencies of more than 50 %.
Special significance is attached to the combined
power plant with integrated gasification (IGCC) and
CO2 separation. Apart from efficient electricity generation, this technology also permits the generation of
synthesis gases for fuel, methanol, H2and SNG production. This optimizes the added value and enables
a flexible response to market developments such as
excessive prices for petroleum-based products. The
first challenge facing us is the development of a
robust, efficient and low-cost technology on a commercial scale. Furthermore, research for the generation-after-next of zero-CO2 IGCC power plants must
be initiated now.
Important building blocks in this endeavour are
the focusing of existing expertise, the experimental
and theoretical investigation of the basic principles
of gasification, as well as the continuing development
of subcomponents and adaptation to an overall
process that has been further optimized.
What coal combined cycle power
plants can do today
Combined cycle power plants generate electricity in a
combined gas and steam turbine process and thus
achieve considerably higher efficiency than conventional steam power plants.
Figure 1: IGCC power plant, Buggenum, Netherlands
The following technologies can be differentiated:
those in which hot flue gas from pressurized
combustion (pressurized fluidized bed or pressurized pulverized coal combustion) is fed into a gas
turbine
those in which the thermal energy is transferred
to a working gas via high-temperature heat
exchangers so that this gas in turn drives the gas
turbine
those in which coal is converted into a fuel gas
in a gasification process and this gas is then used
as a fuel for the gas turbine (IGCC: integrated
gasification combined cycle).
In all three processes, the hot waste gas from the
gas turbine is subsequently used to drive a water/
steam cycle with a steam turbine.
Of these three technical variants, essentially only
the IGCC is currently being pursued on a global scale
since the problems encountered in developing the
other technologies were too great or else the higher
costs involved outweighed the improvement in efficiency.
Apart from a high potential efficiency of more
than 50 %, coal-fired power plants based on IGCC
technology also have the advantage of being able to
effectively separate CO2. Even with CO2 separation,
comparatively high efficiencies of more than 40 % are
achieved as well as high fuel flexibility with very low
overall emissions. Power plant operation without CO2
separation is also possible (no-regret strategy).
IGCC technology has a decisive advantage over
all other power plant concepts. Apart from electricity,
it is also possible to generate synthetic energy carriers
such as hydrogen, SNG, methanol or liquid fuels as
well as raw materials for the chemical industry. On
the one hand, this ensures great product flexibility
enabling a short-term and rapid response to current
market developments. On the other hand, this places
the security of the supply of energy and raw materials
in Germany on a much broader basis (lignite, hard
coal, biomass, waste). Combined application of energy and material is characterized by the term polygeneration. The key is efficient coal gasification with subsequent gas treatment appropriately adapted to the
37
tion of hard-coal- and lignite-fired fixed-bed pressurized gasification plants for several decades now.
Plants of this type produce synthesis gas and SNG or
town gas. Such plants are found in South Africa,
China, the USA, the Czech Republic and also at the
Schwarze Pumpe site, southeast of Berlin. The RWE
utility company has developed the high-temperature
Winkler (HTW) process for the gasification of lignite. A
demonstration plant for the production of synthesis
gas for methanol synthesis was in commercial operation from 1986 to 1997.
Figure 2: IGCC power plant, Puertollano, Spain
process. This includes cleaning the gas from dust, S,
N, Cl and other compounds, as well as CO shift conversion, transformation of CO into CO2 with at the
same time the production of H2. The hydrogen or
hydrogen-rich gases can either be used in a gas turbine or for synthesis processes. A significant aspect of
post-treatment is, furthermore, CO2 separation.
It is now possible to implement a number of
different gasification processes, which according to
the gas/solid contacting can be subdivided into the
fixed bed, fluidized bed and entrained flow gasifiers.
Pressurized gasification processes are already
employed on an industrial scale for coal gasification.
To this end, technical oxygen or steam/oxygen mixtures are used as gasification agents. Depending on
the process temperature, a distinction is made
between processes with dry ash removal (classical
fixed bed and fluidized bed processes with temperatures below approx. 1300 °C) and processes with liquid slag removal (entrained flow and slag bath
processes with temperatures above approx. 1300 °C).
The actual temperature limit is ultimately defined by
the ash melting behaviour, which depends on the fuel
in question.
There are numerous plants throughout the
world that operate with entrained-flow gasification.
The vast majority of plants were constructed for the
gasification of refinery residues and for the production of hydrogen or synthesis gas for ammonia,
methanol or Fischer-Tropsch synthesis. Experience
has also been gathered with the commercial opera-
Since the mid 1990s, four IGCC power plants have
been operated commercially with integrated secondgeneration coal gasification according to the processes developed by Shell (Shell Coal Gasification Process
– SCGP), Uhde (Prenflo), GE (formerly Texaco) and
ConocoPhilips (E-Gas). The plants are located in
Buggenum (NL, SCGP), Puertollano (ES, Prenflo),
Tampa (USA, GE) and Wabash River (USA, E-Gas).
Without exception, they all operate according to the
entrained-flow process. As fuels they utilize hard coal,
petroleum coke and certain fractions of biomass and
sewage sludge. These fuels are fed into the gasifier
either in a dry form (SCGP, Prenflo) or as a slurry (GE,
E-Gas). Other IGCC plants are in operation in Vresova
(CZ) and Schwarze Pumpe (D). At both sites, town gas
is produced from lignite in fixed-bed pressurized
gasifiers of the “Lurgi dry ash” type. The plant in
Vresova was converted to IGCC operation in the mid
1990s and this will shortly be complemented by an
entrained-flow gasifier (SFG, formerly GSP). At
Schwarze Pumpe, the coal gasification was converted
to waste gasification for the production of methanol
in the 1990s. At the same time as methanol synthesis,
a combined cycle process is also operated. Since the
1980s the fixed bed pressurized gasifier has been
complemented by an entrained-flow gasifier and
since 2000 it has in part been replaced by a Lurgi slagging gasifier.
Very high gas temperatures arise, especially in
the entrained-flow process. The gas must therefore
first be cooled down considerably before it can be
subsequently treated in the gas cleaning steps. heat
recovery system in which steam is produced that can
be used for power generation. Another approach is to
inject water (quenching). Although the sensible heat
of the gasification gas is thus lost, the loss is, however,
38
Coal Combined Cycle Power Plants
partly compensated by clear benefits with respect to
investment costs and robustness.
Gas treatment is then performed via a chain of
separation processes. The raw gas is first freed from
dust particles in a candle filter. It subsequently passes
through a water scrubbing process to remove the
halogenides, the ammonia and the residual dust. In
a downstream hydrolysis step, COS and HCN are converted to H2S and NH3. Chemical scrubbing with
MDEA and physical washing with methanol (Rectisol)
has become established for H2S scrubbing. After gas
scrubbing, the gasification gas has a degree of purity
that is sufficient for synthesis or combustion in the
gas turbine, depending on specifications.
In the past, IGCC power plants have been unable
to achieve commercial success in competition with
steam power plants because the additional investments required for conventional IGCC operation are
higher than the profits obtained by the improved
efficiency. A further disadvantage was the previous
poor availability.
However, the significance of CO2 separation is
growing and thus the appeal of IGCC technology.
This technology is undoubtedly the most advanced
with respect to efficient CO2 separation. The separation of CO2 from raw gases is a well-known process on
a commercial scale in synthetic chemistry and is
widely operated. Treatment of the raw gas is individually adapted to the feedstock and the respective gasification process and configured as a function of the
gas quality (H2/CO ratio) required for the subsequent
process stages (methanol, ammonia, FT, oxosynthesis
etc.). CO shift conversion and CO2 scrubbing have
already been operated commercially at the HTW
demonstration plant in Berrenrath using lignite as
the feedstock. Altogether, 2 million t of CO2 has been
separated in the demonstration plant. At Schwarze
Pumpe, these processing steps are operated commercially for the gasification of a mixture of waste and
coal.
Challenges
With the aid of IGCC technology and CO2 separation,
a CO2-free, coal-fired power plant can become reality
before 2015. All the necessary process steps are available and have been tested in commercial operation.
In early 2006, RWE announced the construction of a
large CO2-free 450-MW power plant based on IGCC
technology. Results from the earlier COORETEC and
EU research projects, such as COORIVA und ENCAP, as
well as from future R&D projects will be incorporated
into the project.
The paramount objective is the development of a
robust, efficient and low-cost technology on a commercial scale. This primarily concerns the development of an optimal overall concept which does justice
to the different operational requirements with
respect to commercial operation. To this end, the
overall technology must in future be adapted to the
key boundary conditions – fuel availability, the level
of CO2 separation efficiency required and the opportunities for CO2 disposal. The various components
and techniques will first be brought together on a
large scale in the IGCC power plant with CO2 separation. All these components must be optimized in
accordance with the state of the art and adapted to
the new requirements. This particularly concerns the
gas turbines and the gasification sector. It is particularly important that the availability of the gasifiers
should be increased to such an extent that they operate as reliably as classical power plant boilers. In contrast, the gas turbines must be adapted above all to
hydrogen-rich fuel gases. These objectives can only
be realized by close cooperation between facility
operators, plant manufacturers and research institutions. An intensive exchange of information and
know-how is key. Only in this way it is possible to collate findings and to further pursue them in a targeted
and focused form.
It is not only the specific realization of a CO2-free
IGCC power plant in the RWE project that constitutes
the real challenge. The fundamental further development of the technology is also a demanding task. This
can only be done by finding new approaches for optimizing the individual processes in the IGCC power
plant and thus overcoming previous drawbacks. In
entrained-flow gasification, for example, considerable demands are made on raw gas cooling due to
the high inlet temperature of the gasification gas. In
pressurized fluidized bed gasification, ways must be
found of expanding the rather small range of possible
39
GT:
DT:
GT+DT:
air from gas turbine
air
electricity
N2 zur GT
ASU
GT + ST
450 MWel
O2
80 t/h
steam
steam
cooler,
dust removal
gasifier
steam
desulphurization
Staub
lignite
350 t/h
290 MW
160 MW
450 MW
CO-Shift
steam
H2-rich syn. gas
236.000 Nm3/h
CO2scrubber
CO 2
Pipeline
WTA
dryer
CO2compressor
300 t/h
> 100 bar
Figure 3: CO2-free IGCC-process
starting materials comprising highly reactive fuels,
such as lignite and biomass, to include other substances. In order to enhance the synthesis gas yield
(CO + H2), it is furthermore necessary to optimize the
carbon conversion, which is incomplete for processrelated reasons, and to reduce the methane content.
Fixed-bed processes, on the other hand, have the disadvantage that they lead to raw gas containing tar
and methane. More effort is thus required to clean
the gas thus also leading to a reduction of the synthesis gas yield. Another drawback is that the process
parameters restrict the thermal capacity of the gasifier to about 200 MW. The following specific challenges therefore arise for future IGCC power plants:
Optimization of the gasification technique with
the aim of using different energy carriers (lignite,
hard coal, biomass), increasing efficiency in converting the chemically bound energy of the coal
into that of the fuel gas (cold gas efficiency) and
also reducing the amount of gasification agent
required (especially oxygen requirements).
Further development of the raw gas cooling system by combining the advantages of a heat recovery system (efficient energy use) with those of a
raw gas quench (robustness), that is to say partial
quenching of the raw gas to a temperature level
that can be tolerated by the waste-heat boiler with
subsequent utilization of the residual waste heat
or by integrated conversion (quench conversion).
Improvement of the combustion system of the
gas turbine permitting the use of hydrogen on
the basis of the latest natural gas turbine technology with the aim of improving efficiency, increasing reliability and reducing nitrogen oxide emissions. Another objective is the optional application of natural gas, synthesis gas and, if possible,
methanol.
Further optimization of CO shift conversion and
the development of systems with isothermal
operation to minimize steam consumption.
Moreover, the overall system must be optimized
in such a way that a maximal CO2 separation rate is
achieved, especially with respect to the combination
of electricity generation and chemical synthesis in
one plant. Major priorities in current development
work are, furthermore, the variability of CO2 separation and integration of the air separation unit.
The CO2-free IGCC process outlined above has the
potential to make future power plants significantly
more efficient and economical than corresponding
conventional steam power plants. This potential must
be exploited now so that it can be applied in the
development of later generations of power plants.
This will thus also promote the base technology for
combined electricity generation and synthesis (polygeneration) both for the coal-to-gas (CtG) and also the
coal-to-liquid (CtL) synthesis routes. Both routes are
important elements of a future energy supply, which
will become increasingly independent of global
reserves of petroleum and natural gas.
40
Coal Combined Cycle Power Plants
Step by step to 2020
In order to enable IGCC technology for CO2 power
plants to establish a clear profile and to ultimately
achieve commercial success, the exchange of experience on the expert level, and also with respect to R&D
activities in plant engineering, must be intensified.
This process can be broken down into three areas.
Firstly, interdisciplinary workshops and IGCC conferences should be held thus providing an information
and discussion platform for knowledge bearers from
industry and research institutions.
Secondly, gasification represents one of the central components of the IGCC process and continues to
have a considerable development potential. This
process is characterized by the fact that extensive
know-how is already available. However, basic principles of gasification still need to be investigated both
experimentally and theoretically in order to develop
optimized gasifier generations.
Thirdly, there is a need for further development
and optimization of third-generation power plant
components in the process chain from gasification to
the gas turbine. Since experience shows that it takes a
long time to develop new solutions from the original
idea up to the commercial product, research should
already be initiated for the generation-after-next of
CO2-free IGCC power plants.
Workshops and IGCC conferences
The scientific and technical conditions for thirdgeneration gasification technology must be created
in the next five to ten years. This will require considerable efforts. It is essential that the expertise of the
individual COORETEC partners should be focused
and qualified, especially in the field of basic scientific
principles. Members of COORETEC Working Group
3 will be assisting in organizing workshops on various
specialist topics. At the workshops, the findings
obtained in the R&D projects will be presented,
analysed critically and discussed. On this basis, plans
can be made for more advanced development work
and the issues specified more closely. A technology
and information platform already in existence for
gasification technology is the Deutsche Zentrum für
Vergasungstechnik (DeZeV – German Centre for
Gasification Technology) in Freiberg, which organizes
an international IGCC conference every two years.
Basic principles of gasification
Basic research on this topic can be summarized under
five different headings. These research priorities can
then only be meaningfully implemented if they are
oriented to the requirements and needs of industrial
users. Furthermore, it is important to incorporate the
wide range of experience available from commercialscale projects that have already been realized.
Scientific understanding of material-related
sequences in gasification processes with the aim
of a better grasp of the process leading to optimization of gasification.
This includes above all the material relationships,
about which little is known at present. This concerns
pyrolysis behaviour, change in particle properties
during heating, precipitation and condensation
processes in the cooling flows, particle reactions in
reactive flows, thermochemical and kinetic studies of
the ash/slag reactions, and the rheological behaviour
of slags, solubility processes and phase separation in
slags. Furthermore, soot formation processes and the
reactions of trace substance formation and decomposition (gaseous N, S, Cl/F and P compounds) are still
not fully understood.
Modelling of reactive multiphase flows with the
aim of further developing the reaction compartments and reactor geometries.
The realistic modelling of reactive multiphase flows
still remains a great challenge for modelling and
numerical simulation. The reason for this is the large
number of parallel and sequential subprocesses proceeding in the pressurized gasifiers and their chemical and physical reactions. This includes torch flames,
fluidized bed and entrained flow regions as well as
superimposed homogeneous and heterogeneous
reactions. Major priorities in modelling are gasification flames, especially in the region close to the
41
heavy metals, alkalis, chlorides and other compounds.
Modelling the dynamic behaviour of gasifiers
with the aim of optimizing process control of the
individual plant components.
Figure 4: Conceptual design for an IGCC power plant with
CO2 separation
burner, ignition behaviour and gas/solid flows reacting endothermically. For the future, appropriate submodels must be developed describing, amongst other
aspects, particle burn-out, turbulence formation, and
cooling or condensation processes.
The three-dimensional visualization of reactive
flows represents one of the greatest scientific challenges that can only be realized by supercomputing
Establishing databases as a basis for material and
process modelling.
The modelling tasks will require material and process
databases to be established to record the parameters
for the relevant process conditions. Specifically, this
refers to material databases for ash/slag systems, for
trace substances and heavy metals, for carbonyls,
homogeneous elementary reactions and for particle
behaviour.
Studies of interactions between gas phase, slag,
deposits and materials during heating and
cooling processes with the aim of improving
temperature-dependent process control.
A special feature of modelling is the material interactions during heating and cooling. These interactions
can be recorded with the aid of thermochemical
process models (partial equilibria). The modelling
will deal with precipitation, condensation and postreaction processes as well as the behaviour of volatile
Knowledge of the dynamic behaviour of gasification
plants is indispensable for the operational and plant
engineering integration of the overall process. This
includes, for example, the start-up, shut-down and
load cycling behaviour and the dynamics of the ignition processes.
Work on these topics is of outstanding significance.
In order to verify the scientific findings under real
conditions so that they can be applied without delay
on an industrial scale, testing of new developments
should be performed in parallel on a laboratory and
pilot-plant scale. Considerable importance is also
attached to the development and application of special
measuring instruments for gasification compartments
capable of withstanding extreme process conditions,
high temperatures and pressures. Only robust measuring technology of this kind will permit the technical validation of theoretical findings in experimental
and industrial facilities. The techniques include pressure- and temperature-resistant optical and laser
optics measuring methods and radiotracer processes.
IGCC power plant concepts and components
The development of the 3rd generation of IGCC
power plant technology is characterized by clear
objectives such as further increases in efficiency,
improvement of plant operation, cutting costs, and
also increasing flexibility and reducing emissions.
These individual aspects will be discussed briefly in
the following.
Flexible and efficient gasification / raw gas cooling
General gasification issues
In order to make optimal use of the positive effects of
the economy of scale and to achieve the same power
42
Coal Combined Cycle Power Plants
range as that of present large power plants, it is
absolutely essential to use gasifier designs with a
thermal power of up to 2000 MWth and pressures
of more than 40 bar, as well as availabilities of more
than 90 %. A single-stage conversion of fuel into
gasifier gas is envisaged in order to reduce capital
expenditure (for example, dispensing with downstream oxidation of the gasification residues).
A value of more than 85 % is the target for cold
gas efficiency. In this case, the decisive methodo
logical approaches are quench conversion, partial
conversion and internal gasifier heat integration.
System integration of the gasification processes is
required for higher power plant efficiency and lower
internal energy consumption.
pressure steam generation in a waste heat boiler with
the sturdiness of a full water quench. This can be
achieved by partial cooling of the gas. In this process,
the gas is first only cooled to temperatures of 700 to
900 °C by water injection (partial quenching). The
previously liquid slag is present in a solidified form at
this temperature. In this way, the raw gas can be fed
into a waste heat system which utilizes the residual
heat for generating high-pressure steam so that it
should be possible to reduce the energy losses to a
large extent. Furthermore, the availability of the
plant thus approaches that of robust full quenching.
It is not only expected that there will be an increase in
efficiency but also a partial conversion of the CO fraction in order to increase the proportion of hydrogen
at the gasifier outlet (quench conversion).
Fluidized bed gasification
Very robust gasifiers are required in order to prevent malfunctions. It should be possible to operate
such gasifiers reliably even in view of fluctuating
quality of the feedstock. This is why a search is being
made for new approaches to avoid slagging, contamination and corrosion and to increase the creep strength
of thermally exposed plant parts and materials.
New, low-stress fuel feed systems, such as tamping
input or CO2 slurry input, can considerably reduce
internal energy consumption by IGCC plants. Such
IGCC plants enable fuels of different types and grades
to be utilized. Apart from lignite or hard coal, it
should also be possible to use biomass or substitute
fuels, at least in mixtures. Thanks to this fuel flexibility,
the utilities will in future be able to respond better to
fuel availability and price. On the other hand, it will
be possible to fulfil any demands made by national
energy policy with respect to increasing the proportion of renewable energy sources, for example in the
transport sector, and at the same time to improve the
CO2 energy emission balance.
Entrained-flow gasification
An important goal for the overall efficiency of entrainedflow gasification is utilizing the high-temperature
heat of the raw gas. This should, however, not significantly reduce the availability of the gasification plant.
For example, for its SFG entrained-flow gasifier
Siemens proposes to combine the advantages of high-
Considerable progress is also expected with fluidized
bed gasification. It is assumed that in future the
process will be able to use various fuels and will thus
be more flexible. Furthermore, the integration of
fixed-bed gasification for the post-oxidation of bottom products containing carbon will make it possible
to achieve complete gasification. This process will be
assisted by the complete recycling of dust in the fluidized bed. Interest is also focused on other developments such as expanding the range of fuels (from biomass to hard coal), complete gasification, and reduction of the CH4 and CO content in the raw gas (quench
conversion and reforming).
Low-emission combustion of hydrogen-rich gases
in high-efficiency gas turbines
The current EU-FP6 ENCAP project includes for the
first time work on a broad-based development of
qualified large stationary gas turbines for operation
with hydrogen-rich fuel. These studies are being
complemented by national activities on the flexible
application of gas turbines capable of using various
fuels, for example as part of the Turbo Working
Group. It can already been foreseen that even after a
successful conclusion of this project further research
work will be necessary in order to clarify other important outstanding issues. Gas turbines for standard
operation with natural gas are being continuously
43
further developed. In order to ensure that the progress thus achieved can also be applied in modern
IGCC power plants with CO2 separation, the development of combustion systems for hydrogen-rich fuels
must be based on the latest gas turbine technology
with premix burners.
In contrast to natural gas burners, the gas turbine
burners currently used for burning synthesis gas
operate in diffusion mode. Fuel and air are only
mixed in the combustion chamber. In order to comply with future NOx limits, nitrogen and water must
be added and the combustion temperature reduced.
In comparison to premix operation, in which the fuel
and air are mixed in a channel upstream of the actual
burner, this process leads to a significant reduction in
efficiency.
In the case of facilities with a premix burner, the
turbine inlet temperatures can be raised even further
in comparison to the machines with diffusion burners
currently in operation. In this way, it is possible to
achieve high efficiency and also high reliability. The
combustion system with premix burner, which still
remains to be developed, will generate low emissions
of less than 15 ppm of NOx with minimal dilution
even when operated with H2-rich fuel. H2O and surplus nitrogen from the air separation unit are available as dilution media. Even when operated with a
dry second fuel (natural gas) it will still be possible to
comply with the required low NOx values. Dilution of
the fuel with inert media will give rise to additional
capital expenditure and operating costs, which have
to be minimized. In order to achieve low emissions
and reliable operation with the smallest possible
addition of dilution media the gas/air mixture will
have to be optimized. Only in this way is it possible to
undiluted
hydrogen
60
H2 %vol
undiluted
syngas
40
20
0
0
10
20
30
natural
gas
40 50
lower heating value [MJ/kg]
Figure 5: Burner development for flexible fuel applications
allow for the increased volume flows and increased
reactivity in comparison to natural gas.
Optimization of the overall IGCC concept
If the aim is to realize IGCC processes with high
overall efficiency, low costs and good environmental
compatibility then all the subprocesses must be optimally incorporated into the process chain. Apart from
the components of gasification, gas cleaning and gas
turbines, this also concerns in particular
the air separation unit
CO shift conversion, and
CO2 separation.
The air separation unit is coupled to the IGCC
plant in a total of three different ways. Firstly, it supplies oxygen for the gasification process. Secondly,
it provides nitrogen as the diluent for the gas turbine
combustion chamber. Thirdly, the plant withdraws
an air flow from the air compressor of the gas turbine.
Optimal integration depends particularly on the gas
turbines and their further development, and must be
adapted to the specific application.
The effectiveness of CO shift conversion depends
decisively on temperature control and the catalysts
used for this purpose. Where this conversion takes
place is crucial. This may be done before or after the
separation of H2S from the gasification gas. The heat
flux for the necessary reheating of the gasification
gas must be further optimized in order to be integrated into the overall concept. The same is true for the
parameters of the steam required for CO shift conversion. Apart from the efficient integration of the heat
shift system, the required degree of CO2 separation
and thus the necessary level of CO conversion also
plays a central part. A further significant change is
the move from adiabatic operation, which is standard
at the moment, to the isothermal mode. In this way,
the process temperature can be predefined according
to the thermodynamic optimum. This is, however,
associated with higher capital costs.
The level of CO2 separation must be optimized
according to technical and economic considerations.
44
Coal Combined Cycle Power Plants
On the basis of the process parameters, the classical emissions (dust, sulphur oxides, nitrogen oxides,
halogens) can be very efficiently reduced in the raw
gas cleaning facility or, in the case of the nitrogen
oxides, downstream of the gas turbine. At present, the
challenge still remains of quantitatively separating
heavy metals. The aim must be to bind the heavy metals and other metal compounds in the ash so that they
are not water-soluble. This also affects the hot gas
path in gas turbines. This potential influence on the
gas turbines by certain pollutants is being investigated as part of work in Working Group 1 (materials technology).
Dynamic modelling of the overall process
For optimum process management, the different
control behaviour of the various components must
be coordinated precisely, according to their time
sequence in the overall process. This then leads to the
very complex task of describing and coordinating the
dynamic behaviour of the subcomponents in models.
Complex mathematical methods are required to
describe the process engineering relations.
In addition, modelling can be used to determine
whether the overall system is as a whole capable of
partial load operation. Furthermore, it thus becomes
possible to assess the impact on the process management and the overall efficiency. The mathematical
description can help to shorten the start-up and s
hut-down processes and thus to reduce downtimes,
increase the reliability of process control and permit
improved response to changes in the plant environment.
IGCC, CtG and CtL and combinations thereof
(polygeneration)
The goal of producing electricity and hydrogenrich energy carriers at the same time (coal-to-gas
(CtG) and coal-to-liquid (CtL) can only be achieved
if the various subprocesses and the entire IGCC plant
are tailored to this aim. Ultimately, it should be
possible to attain optimum environmental compatibility, economic efficiency, flexibility and reliability.
This is particularly true if the boundary conditions
should change (fuel availability, CO2 certificate
trading, market developments for energy and raw
materials).
Various applications can be realized using the
components of the IGCC already described, including
CO2 separation. However, gas cleaning, CO conversion and CO2 separation make special demands on
the overall system. As a rule, syntheses, such as the
Fischer-Tropsch synthesis for producing fuel or
methanol synthesis, require higher levels of purity.
This also affects the sulphur components, amongst
others. The ideal concentration of CO and hydrogen
required for each synthesis must be controlled by
adjusting the CO shift conversion. The most complete
possible conversion of CO and H2O into CO2 and H2 is
required for CO2 separation. If synthetic natural gas
(SNG) is to be produced then an additional methanation step must be integrated into the synthesis gas
path. The individual components have already been
tested in synthetic chemistry processes on a commercial scale.
A promising option is the production of hydrogen-rich energy carriers for decentralized applications and for coupled products (methanol, FischerTropsch fuel, oxo alcohol), hydrogen or reduction
gas. This optimizes the added value and enables a
more flexible response to market developments such
as excessive prices for petroleum-based products.
The development of optimal partial conversion and
partial separation concepts for CO2 will help to adapt
the gas quality of future polygeneration plants to the
respective gas application. At the same time, this
ensures a flexible response to the demands of CO2
trading. The production of hydrogen-rich, storable
energy carriers, furthermore, also contributes to
simplified load management during power plant
operation.
An important objective is therefore the combined
generation of electricity and chemical products. To
this end, the individual components must in future be
appropriately connected and their process control
integrated into the IGCC process in such a way that
the overall system can be operated efficiently, reliably
and with the greatest possible flexibility.
45
Where do we go after 2020?
The aim of electricity generation must be to optimize
the technical energy conversion processes insuch a
way that they come as close as possible to the theoretical maximum efficiency. Consideration must also
be given to the aspects of environmental compatibility and economic viability. The energy-losses in all
process steps should be kept as low as possible.
IGCC power plants in operation today achieve
electrical efficiencies of approx. 45 %. On the basis of
the current state of the art, it will be possible to operate
IGCC power plants without CO2 separation with an efficiency of about 50 % in roughly eight years’ time. If the
classical individual components and the overall IGCC
concept are further optimized then electrical efficiencies of 55 % can be reached in 15 years. The necessary
precondition for these improvements is a gasifier
adapted to the IGCC concept.
Looking beyond 2020, unconventional technologies will have to be applied in order to further
improve the level of conversion. These developments
should be initiated at the present time. These visions
will be presented in the following.
Vision: High-temperature IGCC processes
with CO 2 separation
In the IGCC plants to be constructed in the short and
medium term, gas cleaning will be applied using
methods that are already state of the art: particle separation, water scrubbing, COS hydrolysis and wet
desulphurization. Suitable gas is thus made available
for the gas turbines. Gas cleaning steps are necessary
in order to separate pollutants which could cause
damage to the facilities or to the environment. These
contaminants include volatile heavy metals, alkalis,
halogens, phosphorus, nitrogen and sulphur compounds. The potential influence of certain pollutants
on the gas turbines is being investigated as part of
work in Working Group 1 (materials technology).
With the aid of CO shift conversion and subsequent
CO2 separation by physical or chemical scrubbing,
CO2 can additionally be removed from the gasification gas before it enters the gas turbine. For wet gas
cleaning, the gasification gas must be cooled to
temperatures of 170 °C in the scrubber and subsequently heated again for CO shift conversion. If
methanol scrubbing is applied then the gasification
gas must be cooled to - 40 °C (Rectisol) and subsequently heated again. In the case of entrained flow
gasification, additional water or gas quenching
must be employed to prevent slagging problems.
The aim is the development of gas cleaning processes
that run at elevated temperatures and also, if possible, that operate in a dry mode. In the whole process
chain, the gas should not be cooled to a temperature
below that of the subsequent step. In this way, it
becomes possible to continuously extract useful
heat.
In order to ensure that the fuel gas has a high
H2 concentration of more than 80 % after CO2 separation, a strongly hyperstoichiometric ratio of steam
to CO is currently required for the shift reaction. To
this end, a large volume of medium-pressure steam
must be extracted from the process and is then no
longer available for electricity generation. An alternative would be the application of high-temperature
H2 membranes for the conversion reaction. These
membranes already work efficiently at a stoichiometric ratio of steam to CO. In this way it would, firstly,
be possible to greatly reduce the amount of steam
required. Secondly, cooling to the low temperatures
required for the conversion reaction would not be
necessary. Another solution to the problem of hightemperature CO2 separation is renewable chemical
sorption agents, for example on the basis of Li. The
long-term goal of developments for a CO2-free, highefficiency IGCC process (IGCC 4th generation) is
accordingly CO2 or H2 separation at the highest possible temperatures and also a H2 gas turbine with hot
fuel gas supply.
Vision: Hybrid power plant
(IGCC + fuel cell)
Another vision is the coupling of the IGCC process
to fuel cell technology to create so-called hybrid
power plants. It is assumed that this will lead to an
additional gain in efficiency of approx. 5 to 10 percentage points. This concept, however, reliesupon
fuel cell technology becoming mature enough for
application in large power plants.
46
Coal Combined Cycle Power Plants
Vision: SOFC combined cycle plant with
integrated CO 2 separation
Due to their high efficiency and their flexibility with
respect to fuel and applications, high-temperature
fuel cells have a great potential for fulfilling future
demands in the energy supply sector.
The combination of a solid oxide fuel cell (SOFC)
and an allothermic gasifier or reformer, in which the
heat is not produced directly in the gasifier by oxidation processes but is fed in from the outside, represents an innovative concept for the highly efficient
generation of electricity from gaseous, liquid and
solid fuels. Part of the waste heat from the SOFC is fed
into the gasifier. Furthermore, the SOFC supplies part
of the flow of anode off-gas into the gasifier as a gasification medium. This thus reduces the high steam
concentration in the gasifier. The synthesis gas arising in the gasifier is converted in the SOFC at a high
electrical efficiency of up to 50 %. By using the SOFC
waste heat (temperature level 800 to 1000 °C) in the
allothermic gasification process (principle of thechemical heat pump), electrical system efficiencies of
more than 60 % can be achieved depending on the
fuel used.
In order to implement the combined processes
described above there is still a need for considerable
research and development work, above all concerning the main components (SOFC and the gasification
reactor) and their connection.
Figure 6: SOFC combined cycle with allothermic gasification of
solid fuels and CO2 separation
47
Overview of development needs
Entrained-flow gasification
Harnessing high-temperature heat without
reducing availability (e.g. partial quenching)
Workshops and IGCC conferences
Focusing and qualification of expertise
Identification of follow-on work
Technology and information platform
IGCC conference
Fluidized bed gasificationg
Flexible operation with various fuels also
expanding the range of fuels
Complete gasification, e.g. by integrating
fixed-bed gasification into the post-oxidation
of carbon-containing bottom products
Reducing the CH4 and CO content in the raw
gas
Basic principles of gasification
Scientific understanding of material-related
sequences in gasification processes (material
models) with the aim of obtaining a better grasp
of the process leading to optimization of gasification
Modelling/simulation of reactive multiphase
flows (process models) with the aim of further
developing the reaction compartments and reactor geometries
Establishing databases as a basis for material and
process modelling/simulation
Studies of interactions between gas phase, slag,
deposits and materials during heating and cooling processes with the aim of improving temperature-dependent process control
Modelling/simulation of the dynamic behaviour
of gasifiers with the aim of optimum coordination and process control of the individual plant
components
IGCC power plant concepts and components
Developments in combined cycle power plants
after 2020
High-temperature IGCC processes with CO2 separation
Gas cleaning processes that run at elevated
temperatures and if possible operate in a dry
mode
High-temperature H2 membranes for the
conversion reaction
High-temperature CO2 separation with
renewable chemical sorbents, e.g. on a Li
basis
Hybrid power plants (IGCC + fuel cell)
SOFC plant with integrated CO2 separation.
Flexible and efficient gasification / raw gas cooling
General gasification issues
Reduction of capital expenditure by
economies of scale and single-stage conversion
Increasing the cold gas efficiency to more
than 85 % by quench conversion, partial conversion and internal gasifier heat extraction
Increasing robustness by preventing
slagging, contamination and corrosion
New low-stress fuel feed systems
Low-emission combustion of hydrogen-rich gases
in high-efficiency gas turbines
Optimization of the overall IGCC concept, i.e.
incorporation, in particular, of an air separation
unit, CO conversion and CO2 separation
Dynamic modelling of the overall process
Optimization of plant operation during start-up
and shut-down processes as well as during load
changes
Investigation of ability to operate under partial
load
IGCC, CtG and CtL and combinations thereof
(polygeneration)
48
Oxyfuel Power Plants
Oxyfuel Power Plants
The oxyfuel process is a method by means of which
the climate-damaging CO2 can largely be separated
out of the flue gases of coal-fired power plants. The
CO2 is subsequently transferred to suitable geological
formations for long-term storage. In order to efficiently separate the CO2 its concentration in the fluegas must be increased. This is done with the aid of
an air separation unit which withdraws the nitrogen
from the combustion air so that almost pure oxygen
is fed into the combustion process. In this way, mainly
CO2 is present in the flue gas after combustion. The
flue gas leaving the steam generator (Figure 1) is
completely dehumidified and then has a CO2 content
Flue Gas Recirculation
Air Separation
Unit
2/3
N2
Boiler
Cleaning & Drying
Air
89 % CO 2
11 % Ar, N 2,
O 2, …
1/3
O2
Ash
H2O
Coal
Exhausst Gas
47 % CO2
53 % Ar, N 2,
O 2, …
98 % CO 2
2 % O 2, NO X, SO 2,
N2, Ar, …
18 %
of coal. In the case of combustion with almost pure
oxygen, however, significantly higher combustion
temperatures would result since the nitrogen is not
present which would otherwise absorb the heat. As
such high temperatures cannot be controlled in
steam generators the temperature level will have to
be reduced. A promising solution is the recycling of
cooled flue gases back into the combustion chamber.
About two thirds of the flue gas flow would be
required to compensate the temperature-regulating
effect of the nitrogen. This, however, requires an
extensive system of ducts
The topic of the R&D programme “Oxyfuel Power
Plants” serves to extend scientific and technological
knowledge for assessing the feasibility and economic
viability of coal-fired power plants with CO2 separation
on the basis of the oxyfuel process. This work is based
on the present state of the art giving special consideration to realistic boundary conditions. Particular
attention is being paid to the level of purity which
can be achieved during separation for the CO2 that is
to be stored.
82 %
CO2 Liquefaction Unit
Figure 1: Simplified schematic of the oxyfuel process. All process
data in mol %.
of roughly 89 vol. %. This permits efficient CO2 capture. The remaining flue gas components largely
comprise excess oxygen, argon and small amounts
of nitrogen and also oxides of sulphur and nitrogen.
The volume of these residual gases is the crucial
factor for the oxyfuel process as it is considered that
these residual gases may have an adverse effect on
underground storage and will therefore have to be
separated from the CO2 before future storage in geological formations. This is currently being intensively
investigated in the COORETEC working group on
“CO2 Storage".
With conventional air-operated steam generators, temperatures in the region of the flames are
between 1300 and 1600 °C, depending on the type
What the oxyfuel process can do
today
General aspects
The oxyfuel process has been discussed since the
early 1980s. Since then numerous studies have been
performed worldwide. Nevertheless, there is still no
reliable information on the optimum design and
economic viability of this technology. Previous
studies have either been mainly theoretical or have
restricted themselves to experimental investigations
of combustion under oxyfuel conditions in experimental facilities. In most of these investigations no
attention was paid to important boundary conditions
especially those of significance for the combustion
of coal – for instance, the excess oxygen required.
Only recently have the first pilot plants for studying
the oxyfuel process for coal-fired power plants been
projected worldwide. Others are currently under
construction or at the planning stage. In Germany,
for example, Vattenfall Europe began construction
of a pilot plant with a thermal capacity of 30MWth
49
at the Schwarze Pumpe site southeast of Berlin in
2006.
CO2 separation
Apart from CO2 and steam, unavoidable quantities of
residual oxygen are found in the flue gas in concentrations of up to 4.5 vol. % (dry). Furthermore, the flue
gas contains residual quantities of argon and nitrogen which mainly enter the system together with the
undesirable air leakage. Moreover, pollutant gases
such as oxides of sulphur and nitrogen are formed
during the combustion of coal. All these residual
gases result in the fact that it is hardy possible to raise
the CO2 concentration in dry flue gas to more than 90
vol. %, according to the present state of the art. The
most economical and efficient solution for CO2 separation would be to compress the dried flue gas to
about 100 bar and then store it underground. In this
case, any contaminants such as oxygen, NOx and SOx
would be stored with the CO2, which might possibly
lead to undesirable processesin the geological storage
formations. For the moment, it must therefore be
assumed that the concentration of these contaminants will have to be reduced. One possibility of
doing so is to further concentrate the CO2 by cryogenic liquefaction. This liquefaction is not merely
performed by increasing the pressure but also by
reducing the temperature to values which may be as
low as - 50°C, resulting in condensation of CO2. It is
thus possible to separate the CO2 from the flue gas as
a liquid phase. In contrast, almost all of the abovementioned impurities remain gaseous, together with
about 10 % of the CO2 which cannot be liquefied, and
leave the power plant as off-gas. According to the
present state of the art, the liquefied CO2 can achieve
a purity of up to 99 mol. %. The purity achievable,
however, also depends on the CO2 separation rate as
high liquefaction rates basically result in lower purities
of the liquefied CO2 The residual impurities remaining
in the liquid CO2 consist of about equal parts of oxygen and oxides of nitrogen and sulphur. However,
previous findings still involve considerable uncertainties as they are based on calculations using equilibrium assumptions which are not applicable in real
cases since kinetic processes play a decisive role.
Furthermore, it is not yet clear what volumes of impurities are acceptable for transport and storage.
Overall process
Like all other power-plant technologies with CO2 separation, a power plant based on the oxyfuel process
will have a significantly lower net efficiency. The reason for this is the increased auxiliary power of the
process. The key power consumers of the oxyfuel
process are, above all, the facilities for air separation
and CO2 liquefaction. Using present state-of-the-art
technologies, the net efficiency (based on the lower
heating value) of a modern coal-fired power plant
will be reduced from 45 % to about 35 %. By introducing the well-known, but not yet fully established
three-column process the power consumption of the
air separation unit could be cut by about 20 %.
However, the achievable oxygen purity would then
drop from 99.5 vol. % to a maximum of 95 vol. %. The
remaining 5 vol. % consists of roughly equal parts of
nitrogen and argon. These ballast gases lead in turn
to an increase in power consumption for CO2 liquefaction. This is just one example of the various tradeoffs involved in an overall process analysis and which
have to be solved by appropriate optimization of the
overall process.
Steam generator and firing system
For modern coal-fired steam generators pulverized
coal firing has been established worldwide. In this
process the coal is supplied to the burners in the form
of fine dust, which has many advantages such as extremely low firing losses, high load flexibility and the
fact that the ash can be utilized for other purposes.
Therefore, this design is currently preferred for the
oxyfuel process. The oxyfuel process requires, however, an additional large-scale duct system to recycle
about two thirds of the flue gases back into the combustion chamber in order to reduce the combustion
temperature. Furthermore, the modified composition
of the flue gas will probably alter the heat transfer
behaviour significantly. This can be mainly attributed
to the modified radiative heat transfer, which in addition to the ash particles is influenced in particular by
the flue gas components CO2 and steam. Since due to
the lack of nitrogen these gas components are present in a more than fourfold higher concentration, an
increase in the radiative heat transfer is expected that
will have to be identified in future research projects.
50
Oxyfuel Power Plants
The firing system itself also still involves unanswered questions. In previous studies, especially in
older investigations, the excess oxygen required for
the combustion of coal was estimated to be 5 %, which
is much too low. In modern large steam generators it
is now at least 17 %, which is mainly due to the nonuniform distribution of the pulverized coal through the
burners into the furnace. This means that since the
fluctuating coal dust mass flow cannot be precisely
measured, the air or oxygen input cannot be accurately adjusted. Too low an excess of oxygen would
therefore lead to burnout problems and to corrosion
on the furnace walls. The excess of oxygen is, however, particularly important for the oxyfuel process
since an increase of this excess raises the residual oxygen content in the flue gas. This automatically
increases the energy required for capturing the CO2
from the flue gas and as a result also the proportion of
oxygen in the liquid CO2.
Slag tap firing, which is now no longer marketed
due to its high NOx emissions, could regain significance for the oxyfuel process. Firstly, since the combustion chamber temperature is about 300 °C higher
it requires less mass flow for flue gas circulation.
Secondly, it promises to have advantages with respect
to the excess oxygen required. Regarding the NOx
emissions, there is a reduction with respect to the
nitrogen oxide problems since no atmospheric nitrogen is present in the oxyfuel process – which is also
the case with pulverized coal firing. Fluidized bed firing could also be beneficial since this technology
largely dispenses with extensive flue gas recycling.
Figure 2: Vattenfall Europe’s oxyfuel pilot plant at the Schwarze
Pumpe site
Pilot plant
In order to better understand how the overall oxyfuel
process will have to be designed and to clarify outstanding technical issues, Vattenfall Europe has
decided to construct an oxyfuel pilot plant with a
thermal capacity of 30 MW at the Schwarze Pumpe
site. Figure 2 illustrates the layout of the pilot plant
which is currently under construction. In addition
to a steam generator, the plant will also include an
air separation unit, flue gas cleaning and CO2 separation facilities necessary for the process. The pilot
plant is intended to verify previous experimental
and theoretical findings and also to identify any
possible scaling effects. Above all operational issues
such as
optimal distribution of oxygen and recycled flue
gas,
fouling and corrosion behaviour,
performance of the electrostatic precipitator
with the altered gas composition,
separation behaviour of the flue gas cleaning
equipment and also
dynamic interaction of the key components such
as air separation unit, steam generator and CO2
treatment chain
can only be investigated properly in a pilot plant.
Challenges
The developments of the past decades have now led
to modern coal-fired power plants with net electric
efficiencies of more than 45 % (based on the fuel’s
lower calorific value). In order to achieve efficiencies
of more than 40 % with the oxyfuel process it is necessary to further increase the steam parameters and to
integrate the pre-drying of coal into lignite-fired
power plants and above all to optimize the integration
of the air separation unit and the CO2 capture unit
into the overall process. The greatest part of the auxiliary power in the oxyfuel process is accounted for by
the air separation facility arranged upstream of the
firing. Using the technology currently available on
the market, which provides an oxygen purity of
99.5 mol %, would reduce the plant’s net efficiency
51
by about 7 percentage points. By applying the threecolumn process it would be possible to cut the loss in
efficiency to less than 6 percentage points, while the
achievable oxygen purity would be limited to 95 mol %.
The auxiliary power for CO2 liquefaction would rise as
a consequence of the larger fraction of impurities in
the flue gas.
Another possibility for cutting auxiliary power
would be supplying oxygen by means of an ion transfer membrane which is to be applied in the oxycoal
process (see below). In this process, the energy-intensive cryogenic air separation would be replaced by a
high-temperature membrane integrated into the flue
gas recycling path with an operating temperature
of more than 700 °C. This system generates oxygen
with a considerable reduction in auxiliary power.
However, extensive research work is still required to
make this membrane technology ready for application
The auxiliary power for CO2 liquefaction reduces
the power plant’s efficiency by roughly another 4 percentage points. This is mainly determined by the CO2
concentration in the dry flue gas. Both in the case of
a zero-emission power plant with direct injection of
the flue gases into the geological underground and
also in the case of a power plant with cryogenic CO2
liquefaction, the ballast gases O2, Ar, N2, NOX and
SOX in the flue gas lead to higher auxiliary power.
These gases should therefore be reduced to a minimum. The greatest potential savings can be achieved
by reducing the leakage air which infiltrates into the
process in an uncontrolled manner.
However, minimizing the above-mentioned ballast gases is not only of significance for the efficiency.
These gases could also influence CO2 storage. Equilibrium calculations for simple mixtures lead us to
expect that significant quantities of ballast gases will
be dissolved in liquid CO2 during CO2 liquefaction.
This has already been confirmed for NO in CO2 by initial preliminary experiments. At the moment there is
little information on whether and how the acid and
oxidizing components affect the geological storage
formations. Studies must therefore be undertaken in
the near future to determine the extent to which storage formations and transport infrastructure could be
adversely affected. Furthermore, the chemical disso-
lution processes of the above-mentioned components
during CO2 liquefaction must be investigated in detail. For instance, there are as yet hardly any findings
on dissolution processes in a continuous process
where phase equilibrium cannot usually be attained.
There is still no knowledge on the quantity of impurities that actually remain in the liquefied CO2 under
realistic conditions. It is therefore of central significance to first clarify the level of tolerable impurities
in the storage formations and, secondly, to discover
which dissolution processes are in progress during
liquefaction. The impurities regarded as harmful
could, with the exception of residual oxygen, be
almost completely removed from the flue gas using
well-established flue gas cleaning systems. However,
classical flue gas cleaning has an adverse effect on
efficiency and economic viability. There is also a need
for further development in the power class under
consideration here for dehumidification of the flue
gas since almost complete dryness must be achieved.
Step by step to 2020
Fundamental investigations on combustion
In designing an oxyfuel steam generator with pulverized coal firing, it is first assumed that combustion in
the combustion chamber takes place at similar temperatures to the combustion of coal with air. This is
done by adjusting the adiabatic combustion temperature to a level similar to the air-operated case by
means of corresponding flue gas recycling. The recycled flue gas has a higher heat capacity in comparison to atmospheric nitrogen. Assuming that similar
temperatures prevail in the combustion chamber, a
lower gas mass flow of CO2 and steam is sufficient for
oxyfuel combustion compared to that required in the
case of combustion with air in the form of nitrogen.
Depending on the temperature of the recycled flue
gas and the excess oxygen selected, mean oxygen
concentrations result that are always significantly
higher than with air operation. Figure 3 shows the
required flue gas recycling rate as a function of the
temperature of recycling for selected hard coal and
lignite grades. Furthermore, Figure 3 also illustrates
the mean oxygen concentration resulting from the
oxygen mixing with the recycled flue gas. It can be
52
Oxyfuel Power Plants
Southafrican Hard Coal
Indonesian Hard Coal
Lusatian Lignite
%
70
Temperature of recycling
65
60
55
35
50
Vol%
25
20
100
200 300 400 500
Flue Gas Recycling Rate
600
°C
800
15
O2 concentration after mixing of recycled flue gas and oxygen
Lusatian Pre-Dried Lignite
80
Figure 3: Need for flue gas recycling and resulting oxygen concentration in the combustion atmosphere
seen from the figure that the oxygen concentration of
this mixture amounts to about 30 vol. % for South
African hard coal at a flue gas recycling temperature
of 300 °C. It is thus clearly higher than that of air,
which amounts to 21 vol. %. There are as yet no reliable findings on the effect of the high oxygen content
on the combustion behaviour and emission formation under the most realistic possible boundary conditions. Furthermore, in order to optimize the oxyfuel
process it must be clarified whether the oxygen
should be mixed completely with the recycled flue
gas before combustion. It may indeed be appropriate
to stagger the oxygen concentration. In this way, it
might be possible to reduce the oxygen demand and
to achieve a lower residual content in the flue gas
while maintaining good burn-out of the coal.
One further issue of the oxyfuel process is the
higher concentrations of the pollutant gases NOX und
SOX. These gases are formed during combustion from
the nitrogen and sulphur contained in the fuel. Since
the diluting nitrogen has previously been separated
by the air separation unit, their concentrations in the
flue gas are correspondingly high. Purely quantitatively, this enrichment would lead to a roughly fourfold concentration of pollutants. However, in experiments it has already become apparent that the NOX
formation reaction is itself inhibited by the enrich-
ment. According to the present state of knowledge,
the NOX concentration is actually only about 2.5
times higher than with comparable air operation.
Based on the firing rate, the NOx formation rate is
consequently smaller than in the case of air. However,
it is not yet known whether this effect also occurs
with sulphur oxides.
In order to answer these elementary questions,
test series are currently being performed for common
lignite and hard coal grades by Dresden University of
Technology and Hamburg University of Technology
in test plants for pulverized coal firing. These investigations are being accompanied by fluid dynamics
simulations of these plants in order to verify and
adapt the mathematical combustion models applied.
The findings obtained will form the basis for more
advanced studies under real conditions in the pilot
plant set up by Vattenfall Europe at Schwarze Pumpe.
Steam generator
The extent to which the heat transfer in the steam
generator is influenced by the modified flue gas
composition still remains largely unclear. About 40 %
of the total heat output from the firing system is
transferred almost exclusively by thermal radiation in
the furnace of a steam generator. In the downstream
convective heating surfaces, an appreciable fraction
of the heat transfer is still due to radiation. Since in
addition to the dust particles, in particular the gas
components of CO2 and H2O are involved in the radiative exchange, the radiant heat transfer will increase
considerably in the oxyfuel process due to the now
significantly higher concentrations of these gas components. It is, however, difficult to make quantitative
forecasts since the most extensive empirical basis for
the radiation behaviour of flue gases has only been
examined for air operation. It is already becoming
apparent that these relations cannot simply be transferred to the oxyfuel process.
In order to be able to control the high combustion
chamber temperatures in the oxyfuel process, a
major fraction of the fuel gas must be recycled. This
makes it necessary to have an extensive system of
ducts. The aim must be to keep the temperatures of
the recycled flue gas as low as possible in order to
53
Alternative approaches are also conceivable for
utilizing low-temperature flue gas heat. For instance,
this heat could be used in an absorption refrigeration
plant for CO2 liquefaction or for preheating the oxygen. Apart from the investment costs, the efficiency
of the overall process is decisive and is influenced by
the type of low-temperature flue gas utilization. From
the energy perspective, it may thus be more beneficial
to choose a relatively high temperature of the flue gas
to be recycled and to position the low-temperature
heat utilization system in the flue gas that is dissipated from the boiler island. Higher recirculation temperatures would also be advantageous with respect to
combined drying and pulverizing of the coal.
All steam generators operated at atmospheric
pressure have in common that the entire flue gas
pathway from the outlet of the burners to the induceddraught fan is operated under slight subatmospheric
pressure. This prevents dust or flue gas escaping into
the environment. For this reason, a certain quantity
of air always penetrates into the system in an uncontrolled manner. With the power plants currently
under construction the proportion of air leakage
amounts to about 4 % of the total flue gas volume.
However, in the course of the operating life this may
rise to about 10 %. This air leakage particularly leads to
a considerable contamination of the flue gas – especially with nitrogen. With an air leakage of 4 % it
would not be possible to achieve a CO2 concentration
of more than 82 vol. % (dry), as shown in Figure 4.
With an oxygen excess of 15 % and an oxygen purity of
99.5 %, which can be achieved with existing technology, the air leakage would have to be reduced to less
than 1 % in order to achieve a CO2 concentration of at
least 90 vol. % in the dry flue gas, where the value of 1
% refers to the total flue gas flow in the boiler. Since
many potential leakage points are present along the
flue gas pathway, such as burner tip sealings, ash discharges, manholes, viewing or measuring ports, care-
O 2−purity 99.5 %, O2−excess 10 %
O 2−purity 99.5 %, O2−excess 15 %
O −purity 98.0 %, O −excess 15 %
2
2
O −purity 95.0 %, O −excess 15 %
2
2
100
CO2 −Concentration in the dry flue gas as % vol
reduce the volume flow and thus the auxiliary power
of the recirculation fan. In this way, it is moreover also
possible to dispense with expensive high-temperature
materials. One possible approach to this cooling is,
for example, to transfer the flue gas heat to the feed
water preheating section by an economizer. This
would represent an optimization since at the same
time the cost of flue gas recycling is also cut.
95
90
85
80
75
70
0
1
2
3
4
5
Air leakage as % of the total flue gas flow
6
Figure 4: Achievable CO2 concentrations
ful consideration should be given as to which
improvements are necessary and at the same time
economical.
Although pulverized coal firing with dry ash
removal is most widespread for conventional coal
combustion with air, other firing technologies could
be suitable for the oxyfuel process such as circulating
fluidized bed combustion and slag-tap firing with
liquid ash discharge. The advantage: both systems
require less recycled gas to regulate the temperature
in the combustion chamber due to the nature of the
system.
The fluidized bed technology uses a circulation
of ash and sand solids in order to regulate the combustion chamber temperature. In this technology,
heating surfaces for heat removal are arranged in
the circulating solids. In addition to the flue gases,
the circulating solids therefore also serve as a further
heat transfer medium. In the oxyfuel process, this
flow of solid matter would transfer the major proportion of the generated heat to the heating surfaces and
thus remove it from the combustion chamber. This
heat removal in the circulating solids means that the
volume of flue gas recycling can be kept much lower
than in the case of an oxyfuel steam generator with
pulverized coal firing. Thanks to the considerably
smaller volume flow of the flue gas, the overall
54
Oxyfuel Power Plants
dimensions can be greatly reduced in comparison
to conventional fluidized bed steam generators. In
contrast, with slag tap firing, higher combustion t
emperatures are in general possible and also desirable so that a lower degree of flue gas recycling than
with pulverized coal firing is sufficient in this case as
well. In principle, very high NOx emissions occur with
slag tap firing and are formed from the atmospheric
nitrogen. Due to the lack of atmospheric nitrogen,
these emissions are significantly reduced in the oxyfuel process. In addition to the lower level of flue gas
recycling in the case of slag tap firing, the process can
also be operated with lower amounts of excess oxygen. This is particularly beneficial with respect to the
oxygen content in the flue gas and thus also in the
liquid CO2.
CO2 treatment chain
Various methods are available for separating CO2.
They are based on the five basic operations of adsorption, absorption, condensation, rectification and
membrane separation. The condensation method is
particularly beneficial for a low-CO2-emission power
plant based on the oxyfuel process if a direct transfer
of the CO2 together with its impurities is not possible.
It is, however, still unclear how the required separation equipment should be designed. A necessary condition for the appropriate design is, first of all, a
detailed investigation of the phase equilibria of the
multicomponent mixtures present in the flue gases.
This requires phase equilibrium studies of the flue
gases. These studies will show the extent to which the
components contained in the flue gas will make the
separation of the CO2 more difficult and to what
degree these components are recovered in the separated liquid CO2.
dissolved in the liquefied CO2. This would then alleviate the problem of impurities in underground storage.
An essential process step is the greatest possible
dehumidification of the flue gas upstream of CO2 liquefaction. Otherwise, solid hydrates could be formed
during CO2 separation and CO2 storage. However,
flue gas cannot be completely dehumidified by
means of condensation. A certain residual humidity
still remains. More extensive residual drying can
only be achieved by adsorption with silica gel. It is,
however, still unclear to what extent the comparatively high concentrations of nitrogen and sulphur
oxides impair the long-term stability of the adsorption materials. Another interesting question is what
amount of these pollutant gases is precipitated
together with the water during dehumidification
and residual drying
In order to implement the CO2 treatment chain
it is therefore indispensable that the factors decisively
influencing CO2 purity should be identified in order
to draw conclusions about the level of CO2 purity
that can actually be achieved and about the fate
of the pollutant gases. To this end, an experimental
facility is currently being constructed at Hamburg
University of Technology containing all the com
ponents necessary for CO2 liquefaction on a pilot
scale (Figure 5). In combination with the test rig for
pulverized coal combustion the entire flue gas train
Flugstrom reaktor
Compressor
Demister
Drier
Drier
Water
Above all the residual oxygen and the acid components NOx and SOx can adversely affect the quality
of the separated CO2 and could impair storage in
geological formations. Investigations of the phase
equilibria are particularly important for the energyrelated and economical design of the separation
equipment. The kinetics of these processes is also
of great interest since in real plants it may not be
possible to achieve equilibrium. This could mean that
the above-mentioned impurities are less strongly
Water
Gas
CO 2condenser
Adsorption
drier
Demister
Liquid
Figure 5: Schematic showing the pilot plant for CO2 liquefaction
currently under construction at Hamburg University of
Technology
55
is reproduced. In this way both the phase equilibria
and also the kinetics of the processes, some of which
are quite complex, can be investigated under the
most varied boundary conditions.
Flue gas cleaning
If the oxidizing and acid pollutant gases dissolved in
the CO2 can be shown not to cause any damage to the
geological storage formations and, at the same time,
the infrastructure for CO2 transport is designed in a
sufficiently robust manner then the CO2 could be
stored directly in the formations without any previous NOx removal or desulphurization measures
(Figure 6). This option is, however, relatively unlikely
since the concentrations of oxygen, SOx and NOx are
comparatively high. Altogether the concentrations of
these impurities may amount to more than 5 vol. %.
The separation of CO2 described above by means of
condensation, on the other hand, considerably
reduces the concentrations of these impurities because
only a certain proportion of them can be dissolved in
liquid CO2. Depending on how much of these impurities can be retained in the liquid CO2 and in the
dehumidification connected upstream, the nonliquefied residual gas may be vented into the environment
without further treatment.
According to the present state of the art, residual
oxygen represents the major fraction of the impurities dissolved in the CO2 accounting for approx. 0.5
mol %. Apart from this, certain quantities of the pollutant gases NOx and SOx are also dissolved in the liquid CO2. Whether these impurities adversely affect
storage in geological formations has to be investigated
in present and future research. Relevant findings and
information are therefore only to be expected in the
medium term. If it should ultimately prove necessary
to require very high CO2 purity then flue gas cleaning
steps will also have to be placed upstream even in the
case of CO2 separation by means of condensation. It
would then only be possible to retain the residual
oxygen by distilling the CO2, which would further
deteriorate the overall efficiency. The economic viability of the oxyfuel process therefore crucially
depends on the level of purity required for the CO2 to
be stored.
NOx removal
The NOx concentration could be reduced by as much
as 90 % by applying technology already available
today. For hard-coal firing, NOx removal by means of
selective catalytic reduction (SCR reactors) with the
addition of ammonia could be applied, where the SCR
facility is positioned upstream of the flue gas dryer
(Figure 7). The NOx concentration in the liquefied CO2
would thus be reduced to 43 ppm according to current calculations. A further reduction to about 20 ppm
could be achieved by positioning the SCR reactor
upstream of the point where the flue gas recycling
branches off (Figure 8) and also by increasing the precipitation performance of the NOx removal facilities.
However, these forecasts do not consider either the
kinetics or the expected separation of part of the
impurities during drying. At the moment, there is a
need for more research here. Furthermore, the
impacts which different set-ups in the flue gas section
Exhaust gas
O2
Coal
NO X SO X
Ash
H2O
CO 2
Figure 6: Arrangement of the flue gas NOx removal and
desulphurization plants if no special demands are made on the
purity of the liquid CO2
Exhaust gas
O2
Coal
Ash
NO X
SO X
H2O
CO 2
Figure 7: Arrangement of the flue gas NOx removal and
desulphurization plants if high demands are made on the purity
of the liquid CO2
Exhaust gas
O2
Coal
Ash
NO X
SO X
H2O
CO 2
Figure 8: Arrangement of the flue gas NOx removal and
desulphurization plants for the maximum purity of liquid CO2
achievable with conventional technology
56
Oxyfuel Power Plants
may have on the overall efficiency still remain to be
investigated. Corrosion problems are also to be
expected in downstream plant components due to
the ammonia leakage that is always present.
Desulphurization
The flue gas desulphurization plants available today
can achieve SO2 removal efficiencies of 99 %. If the
flue gas desulphurization were placed upstream of
CO2 liquefaction then SO2 concentrations of about
57 ppm would result in the liquid CO2, according to
present calculations. It does not seem possible that a
further reduction could be achieved with the wet
desulphurization procedures currently applied. Due
to the low operating temperature of wet desulphurization it is not possible to position the unit upstream
of the point at which the flue gas recycling branches
off. With respect to the separation forecasts, the same
restrictions apply for desulphurization as for NOx
removal, since as yet neither the kinetics nor the additional separation during flue gas drying has been
taken into consideration.
Other components
The concentrations of the NOx and SO2 gases can
be significantly reduced by the flue gas cleaning
processes currently available. Problems could arise
above all due to the residual oxygen present in the
flue gas since a certain amount of this oxygen is also
dissolved in the liquid CO2 and will thus also enter
the storage formations. Even carbon monoxide,
which does not normally lead to any difficulties,
could cause problems during transport and storage
as a pollutant dissolved in CO2. Further research
work is necessary in order to explore the interactions
of these pollutant gases with the geological storage
formations. If it should become apparent that the
residual content of impurities present in the liquid
CO2 was not acceptable then this could be removed
by a rectification process. However, this would
probably lead to considerable additional losses
of efficiency. Studies on this issue are currently
being performed at Dresden University of Technology using the experimental facility shown in
Figure 9.
Figure 9: Experimental facility for flue gas cleaning by
rectification at Dresden University of Technology
Overall process
One of the greatest challenges in optimizing the
oxyfuel process is avoiding impurities. Minimizing
auxiliary power is of equal importance. Due to these
mutual dependences, the optimization of individual
plant components often leads to conflicting goals.
One example is the air separation unit, which
requires significantly less electric power with the
three-column process. Oxygen purity is then restricted to 95 mol %.
The central aspect of all optimization efforts is
and remains the optimal CO2 separation rate. The
more CO2 that is separated, the lower is the CO2 purity which can be achieved by cryogenic liquefaction.
Raising the separation rate moreover also increases
the auxiliary power, which is why more fuel has to be
used for the same net electric power. This inevitably
leads to higher specific CO2 emissions. A high CO2
57
separation rate is therefore not necessarily synonymous with a high CO2 emission reduction rate.
An oxyfuel power plant is characterized by a high
level of integration of the air separation unit and the
CO2 separation facilities, and also flue gas treatment,
in the overall process. For this reason, an oxyfuel
plant may be less flexible than conventional plants
with respect to frequent load changes. There is still a
need for further research in this area. The experimental programmes at Vattenfall Europe's pilot plant will
also make a major contribution.
Second-generation oxyfuel process
While great efforts are currently being devoted to
developing the first oxyfuel process, research work
has already begun at RWTH Aachen University on the
so-called oxycoal process – the second-generation
oxyfuel process. In the oxycoal process, the atmospheric nitrogen is not separated by energy-intensive
cryogenic air decomposition but by a ceramic membrane module. These ion transfer membranes only
permit oxygen to pass through them at a temperature of more than about 700 °C. As long as there is a
gradient in the oxygen concentration the transport
of oxygen takes place in these membranes at correspondingly high temperatures. In this way, atmospheric oxygen can be selectively fed into the process
and nitrogen retained. In a future oxycoal power
plant, air compressed to about 20 bar will be fed into
the membrane module and this air will release the
major proportion of its oxygen to the recycled flue
gas. The high temperatures required will be reached
by recycling the flue gas at about 850 °C. When the
oxygen-depleted and heated air leaves the membrane
reactor it is expanded in a gas turbine. In this way,
part of the power used for compressing the air can
be recovered.
A research priority is the development of suitable
membrane modules for commercial applications.
Apart from the development of membrane materials
with long-term stability and sufficiently high oxygen
transport rates, some design problems also have to be
solved. Only in this way is it possible to ensure leakage-free operation even with temperature fluctuations. Investigations on this topic are currently in
progress at RWTH Aachen University. Studies are also
being made as to whether flue gas recycling can be
achieved at the high temperatures required and also
whether hot gas cleaning is possible upstream of the
membrane module.
Oxyfuel process for gas-fired power plants
In principle, the oxyfuel process can also be used for
gas-fired steam generators and for combined cycle
power plants. For the latter, however, the CO2 reduction potential is smaller due to the lower specific CO2
emissions. A potential concept for retrofitting existing gas-fired steam power plants has been proposed
by MAN Turbo AG and basically corresponds to the
coal-fired process. A special feature is, however, the
possibility of bivalent operation. In this way, the
power plant can be run in the air-operation mode as
usual. In oxyfuel operation, however, the losses in efficiency can be further reduced by applying an organic
Rankine cycle to utilize the waste heat arising from
the air compression required for the air separation
unit.
Where do we go after 2020?
Chemical-looping combustion (CLC) with CO 2
separation
Apart from cryogenic air separation and air separation by means of membranes, the chemical looping
process is another method for keeping nitrogen out
of the coal combustion process and thus of increasing
the CO2 concentration in the flue gas. The chemical
looping process is thus similar to the oxyfuel process,
but in the same way as the oxycoal process it should
rather be regarded as a second-generation oxyfuel
process.
In contrast to conventional combustion with air,
in chemical looping combustion (CLC) a metal oxide
(for example, Ni, Fe, Mn, Co or Cu oxides) is used as
the oxygen carrier. This metal oxide is fed into the
combustion reactor. There the oxygen is separated
from the metal in an endothermic reduction and consumed during oxidation of the fuel, which involves a
58
Oxyfuel Power Plants
release of heat. The metal that remains along with the
combustion products is subsequently fed back into
the oxidation reactor operating in parallel. By adding
air, the metal particles are oxidized there at about
1200 °C thus also releasing heat. They are then once
again available as oxygen carriers for the combustion
process (Figure 10).
Oxygen depleted air / off gas
both under atmospheric pressure conditions in a
steam power plant process and also at an elevated
pressure level with a potential for higher efficiency in
a combined gas and steam turbine process. The reactors could operate with a fluidized bed system.
Combustion products
CO 2
+ Other
H2O
gases
Oxygen carrier (metal oxide)
Fuel reactor
Air reactor
Used oxygen carrier (metal)
N2
O2
Air
Fuel
Figure 10: Basic principles of chemical looping combustion
Since a metal oxide is used as the oxygen source
for the combustion, a combustion flue gas is formed
that in the ideal case only consists of CO2 and steam.
This yields the same favourable conditions for CO2
separation as with combustion under an oxyfuel
atmosphere. The great advantage of chemical looping combustion (CLC) is that the oxygen required for
combustion can be obtained directly without a more
or less energy-intensive air separation unit connected
upstream by means of a cryogenic or membrane
process.
Previous research activities have concentrated
on the use of (natural) gas as a fuel for the CLC
process. There are, however, indications that solid
fuels might also be suitable. Two variant processes
have been proposed: on the one hand, upstream gasification with subsequent combustion of the synthesis
gas generated in the CLC process, and, on the other
hand, the direct combustion of the fuel in a combustion reactor.
A CLC power plant process for low-CO2-emission
power generation using fossil fuels would function
Figure 11: Experimental pulverized coal firing facility at Dresden
University of Technology
The heat released from the fuel separates into
two heat flows – the off-gas from the oxidation reactor and the gaseous combustion products from the
combustion reactor. Considerable structural modifications will have to be made to the plants in order to
be able to use both heat flows for power generation.
Particular attention must be paid to ensure that the
two flows do not intermix. Only in this way is it possible to retain the high CO2 concentration in the flue
gas of the combustion reactor that is essential for CO2
separation. There is currently a need for considerable
research to find a metal oxide carrier material with
sufficient mechanical and thermal stability since only
in this way will the process become economically
viable. Research should be devoted to identifying the
level of particle discharge from the system and also
the impact of the particles on the components as well
as the dynamic behaviour of the process.
59
Overview of development needs
Oxyfuel
Combustion technology
Determination of optimal values of oxygen
excess and oxygen concentration during combustion
Burn-out behaviour of different types of coal in
atmospheres of CO2, H2O and O2 with oxygen
excess rates and concentrations of practical relevance
Formation mechanisms of the pollutant gases
NOX, SOX and CO
Staggering of oxygen to improve the burn-out
and to reduce the formation of pollutant gases
Pilot plant
Steam generator
Impact of the altered flue gas composition on the
heat transfer, especially on radiative heat transfer
Reliable mixing of oxygen with the recycled flue
gas
Possibilities of utilizing the low-temperature flue
gas heat at the steam generator outlet
Optimal temperature of flue gas recycling
Alternative steam generator designs (fluidized
bed, slag tap firing)
Determining the phase equilibria of the flue gas
mixtures as a basis for designing the liquefaction
plants
Influence of the kinetics on the concentrations in
the liquid CO2
Fate of the pollutant gases (SOX, NOX, CO) during
dehumidification
Pumps for transporting the liquefied CO2
Minimizing auxiliary power
Long-term stability of the materials for flue gas
dehumidification
Increasing efficiency by integrating the key
components CO2 separation and air separation
into the overall process
Development of suitable membrane materials
with sufficient long-term stability
Development of membrane modules with as
little leakage as possible
Technological and energy-related restrictions
with respect to the location of the membrane
module in the flue gas path
Development of hot gas cleaning for the power
class required
Configuration of the overall process
Chemical looping
Overall process
Optimal distribution of oxygen and recycled flue gas
Fouling and corrosion behaviour under oxyfuel
conditions
Separation behaviour of the flue gas cleaning
facilities
Heat transfer in the furnace and in the area of the
convective heating surfaces
Start-up behaviour
Dynamic interaction of the individual
components
Oxycoal
CO2 separation
Behaviour with and suitability for partial-load
operation
Possibility of implementing air separation units
for the power class required
(> 400 MWel gross power plant capacity)
Arrangement of any NOx removal and
desulphurization plants that may be required
Configuration of the overall process
Suitable substrate materials with sufficient longterm stability
Reactor system
Control and dynamics of the reactor system
Separation methods for ash and particles of substrate material
60
CO 2 Storage
CO 2 Storage
The R&D programme on the topic of “CO2 storage“ is
intended to develop scientific and technical guidelines for COORETEC in order to optimize the reliability of transporting, injecting and storing carbon dioxide (CO2) in geological formations. Furthermore, injection and propagation processes are to be monitored,
and the risks assessed and minimized. Research work
is focused on the potential of saline aquifers and
exhausted natural gas fields for the injection and
long-time storage of CO2.
What geological CO 2 storage
can do today
In order to protect the global climate, emissions of
carbon dioxide from sources such as coal- and gasfired power plants, steel mills, cement and fertilizer
factories are to be reduced worldwide. This can be
achieved by increasing the efficiency of energy conversion and by separating the CO2 before or after
combustion of fossil fuels. After separation, the CO2
will be removed from the separation unit and transported as safely as possible and with the least expenditure of energy and cost to a suitable storage location. Special facilities may also be used to pump the
CO2 back into geological structures where it arises
naturally. In Germany, sandstone formations in the
deep strata have the greatest storage potential. These
strata largely comprise salt-water-bearing layers
(aquifers) with an estimated storage capacity of
approx. 20 billion tonnes (with an uncertainty of 8 billion tonnes in both directions) and exhausted natural
gas deposits with a capacity of approx. 3 billion
tonnes. In these formations, the CO2 can mix with the
subterranean water or displace the liquid. For comparison: a large lignite power plant emits about
8.5 million tonnes of CO2 per year.
ery rate. Furthermore, in recent years CO2 arising
from natural gas extraction has in some cases been
fed back into underground formations instead of
being released into the atmosphere. For instance,
about I million tonnes of CO2 per annum is pumped
into the deeper strata both in Statoil’s Sleipner field in
the North Sea and BP’s In-Salah natural gas field in
the Algerian desert.
In Germany, underground storage systems have
been used for decades for the interim storage of natural gas. About 20 % of Germany’s annual gas consumption is currently stored underground. Although
extensive experience has already been gained with
natural gas storage underground, this cannot be simply transferred to geological CO2 storage. The essential differences relate to the duration, purpose, nature
and quantity of the gas to be stored. Furthermore,
CO2 and natural gas differ with respect to their
physicochemical behaviour. In addition, different
mining regulations apply since, for example, natural
gas is gaseous whereas CO2 is stored in the liquid,
supercritical phase.
CO2 transport and storage location
The geological structures in Germany contain a wide
range of high-porosity sedimentary structures. If suitable cap rock is present to prevent the carbon dioxide
from escaping then these structures offer good conditions for the underground storage of CO2. Numerous
deep drilling operations and seismic exploration
projects from earlier prospectingcampaigns for natural gas and crude oil provide information on the strata and structures of the various deep geological formations. The data are stored in the archives of the
regional geological agencies. The gas and oil companies also have a vast amount of information on storage.
Underground gas storage
The technology for storing CO2 in underground
formations has already been applied on a large scale
around the world. Producers of crude oil in the USA
and Canada have been using CO2 for decades in order
to increase the production from their reservoirs. In
this so called enhanced oil/gas recovery, CO2 is injected into the reservoirs to achieve an enhanced recov-
In order to keep time and expense for transport
to a minimum, efforts will be made in future to locate
underground stores close to power stations with CO2
separation. Nevertheless, in some cases it may be necessary to transport the CO2 over several hundred kilometres. There is still a great need for research in this
area. This refers to both general and also site-specific
aspects. It is, however, certain that millions of tonnes
61
of CO2 will have to be transported in a liquid state in
pipelines or in a cold liquid state in ships in an economically and environmentally acceptable manner.
Compression or liquefaction of CO2 will give rise to
additional costs.
CO2 injection technology
A CO2 injection well (Figure 1) normally consists of a
protective tube and an inner tube. The protective
tube surrounds the free borehole and is sealed off
from the surrounding rock by a special deep-well
cement which must be compression-resistant, gastight and corrosion-resistant. The inner tube serves
as an injection tube and separates the CO2 from the
protective tube. The hydrostatic pressure compensation
in the annular space between the two tubes is produced by a corrosion protection liquid. A so-called
annular space packer with rubber elements seals the
annular space tight above the storage layers. At the
head of the well, the annular space is sealed at the top.
The geological and hydrological properties of a
reservoir determine the pressure and the temperature
of the CO2 injection. They limit the maximum permis-
CO2
Earth’s surface
annular gap
cementing
injection tube
drilling fluid
CO2
sible injection pressure and define a suitable temperature interval for the injection. For example, the
injection pressure must never be so high that it causes
the cap rock to crack. The temperature should be close
to that of the natural rock to keep thermal stresses
low. The CO2 storage facility must therefore be
equipped with pressure and temperature sensors to
record, monitor and optimize the gas properties after
CO2 conditioning and along the path to the reservoir.
Geoprocesses in the CO2 reservoir
Carbon dioxide may be stored underground as a free
gas, a liquid or a supercritical phase. Its physical state
depends on the pressure and temperature, which
both rise with increasing depth. Liquid or supercritical
CO2 is up to 500 times as dense at great depths than in
the gaseous state close to the Earth's surface. In CO2
storage facilities a hydrostatic pressure of more than
74 bar should be maintained, which corresponds to
the critical pressure of CO2 and is reached at depths of
more than 700 m. The advantage: due to the high
density of the supercritical CO2, the pore space of the
storage layer can be optimally exploited.
The storage of CO2 in geological formations proceeds according to chemical and physical processes.
Chemically, CO2 can in the long term be bound by the
formation of minerals in the reservoir rocks – for
instance in the form of carbonates. Physically, it can be
stored in deep strata in geological capture structures
or by capillary forces in the fine pores of salt-waterbearing layers (aquifers). Impermeable cap rock
above the reservoir rock have a hydrodynamic effect
and function as semipermeable beds (aquitards). They
may consist of clay, mudstone, gypsum or salt rock
and prevent the stored CO2 from rising into the overlying rock strata and thus escaping into the atmosphere. The various storage mechanisms have different impacts on the effectiveness of CO2 storage and
the time sequence, but they all contribute to the longterm storage of the CO2 in the reservoir rock.
perforation
CO2reservoir rock
Figure 1: Basic principles of a CO2 injection well
Pilot and demonstration projects
Work has already begun all over the world on individual
pilot and demonstration projects concerning the
62
CO 2 Storage
geological storage of CO2. The Greenhouse Gas Research and Development Programme of the International Energy Agency (IEA) maintains a database of
the most important CO2 separation and storage projects (www.ieaghg.org).
CO2 as major fields of activity. The resolution of licensing and acceptance issues is, moreover, absolutely
indispensable for future storage facilities. Research and
development can contribute important insights here.
The first EU-funded research project - CO2SINK –
on the storage of CO2 in an onshore saline aquifer
started in spring 2004 near the town of Ketzin, west
of Berlin, (www.co2sink.org). Coordinated by the
National Research Centre for Geosciences (GFZ) in
Potsdam, up to 60,000 tonnes of pure CO2 will be
pumped to a depth of about 700 m via an injection
well starting in 2008 or 2009. The underground propagation will be monitored from two adjacent observation wells.
Objectives
In the next step, demonstration projects will be
developed in Germany with an annual storage capacity of more than 1 million tonnes of CO2. These projects will be complemented by research work and will
thus help to develop reliable storage strategies as
quickly as possible.
Challenges
The geological storage of CO2 in deep sedimentary
strata can considerably reduce the release of greenhouse gases into the atmosphere in the short to medium term. It will thus become possible to continue using
fossil energy carriers to generate electricity and heat
in Germany for many decades to come and at the
same time to achieve the Federal Government’s climate protection goals.
Before the geological storage of CO2 can become
established, the high cost of separation in power
plants must first be reduced. Furthermore, the necessary transport capacities – optimized with respect to
energy and cost – must be created. Moreover, efficient
injection technologies must be developed and evidence provided that storage facilities of the required
size are safe for the considerable periods of time
envisaged. Research and development must provide
support for energy research by focusing on storage
potential, geochemical reactions, long-term geological stability and cost of the underground storage of
The research priority of “CO2 Storage” is intended
to develop scientific and technical guidelines for
optimizing the safety of the transport, injection technology and storage of carbon dioxide in geological
formations. Furthermore, injection and migration
processes are to be monitored, and the risks assessed
and minimized. Research activities will concentrate
on saline aquifers and exhausted natural gas fields for
the injection and long-term storage of CO2.
An indispensable prerequisite for operation of
a geological storage facility is the leak tightness of the
reservoir. Only in this way is it possible to preventthe
stored CO2 from escaping into the atmosphere. Before
starting storage operations it must therefore be
demonstrated that the cap rock remains undamaged
and leak tight even under the physico-chemical
impact of CO2. This will require geological, mineralogical and structural studies. Furthermore, an
exten-sive geophysical and geo-chemical monitoring
programme is required in order to observe the storage facilities before, during and after injection.
Development of methods
Efficient storage technology also includes efficient
and robust injection and monitoring methods. With
appropriate modifications, these methods can be
applied to other processes which also concern fluids
in porous rocks. They include, for instance, enhanced
oil and gas recovery (EOR and EGR), the monitoring of
pollutant propagation in the soil or the underground
storage of natural gas
In order to assess and ensure the long-term safety
of geological CO2 stores, qualitative and quantitative
studies must be made of fluid migration pathways
and physicochemical processes in the reservoir and
cap rock. This requires specific geophysical and
geochemical methods with a high resolution above
63
ground and in the boreholes. An unresolved question
is in particular how studies on small specimens in the
laboratory can be transferred to the extremely large
dimensions found in nature. Extrapolation of the
parameters and processes studied in the laboratory
still requires a collaborative research rffort. These
data are to be included in models on a reservoir scale
which can be used to demonstrate the suitability of
the reservoirs and assess the risks.
Acceptance
A critical point for CO2 storage in geological formations is the permissible leak rate at which CO2 may
escape into the cap rock and the biosphere. The rates
that are acceptable for a long-term storage of CO2
still remain to be decided. It must also be taken into
consideration that the leak rates vary from reservoir
to reservoir. Ultimately, the question is not only a
technological issue but also, and above all, the extent
to which the public is prepared to accept the possible,
but rather low, risks involved in CO2 storage in
comparison to further emissions of CO2 or the higher
risks and costs involved in energy generation
A sustainable scientific basis is decisive for
the success of the development of low-CO2 power
plants in Germany and their acceptance in the coming years and decades. In order to create this basis,
there is a need for technical studies, cost-benefit
analyses and the further development of technologies for the transport and geological storage of CO2.
Step by step to 2020
CO 2 transport and storage technology
A necessary condition for the safe storage of CO2 from
combustion processes is the corrosion-resistance of
the transport and storage components. This applies,
in particular, to pipelines, the injection facilities with
compressors or pumping stations and also to the
storage wells with head, injection tube, packer and
protective tube.
The corrosion of metals in a CO2 environment
is accelerated by liquid fractions in the gas, by the
pressure of the CO2 and high temperatures. Corrosion
occurs above all during contact between the CO2 and
water in the geological formations. Gas-tight connectors must therefore be used for the tubing, special
cable protectors, corrosion-resistant sensors and CO2resistant steels such as chromium steel. The injection
section must be additionally protected by a CO2resistant internal coating.
The cemented annular space between the protective tube and the rock is particularly critical for the
long-term leak tightness of a borehole. It is possible
that this space could be attacked by reaction processes with CO2 and thus losing strength and becoming
permeable to CO2. The formation of calcium hydrogen bicarbonate causes special problems for the
tightness of the reservoirs since this substance is
water-soluble and can thus be eroded (karst effect).
Penetration of CO2-saturated water into the cement
structure can moreover lead to the formation of dissociated carbonic acid which may react with calcium
hydroxide and also calcium silicate hydrate phases.
This leads to the formation of calcite which could clog
the injection point. Other conversion processes also
take place in the presence of free CO2 as a function of
pH and temperature. The changes arising from shifts
in the calcium/silicon ratio in the cement can be reliably determined analytically. At the end of the project, the boreholes must be backfilled and sealed gastight, not least in order to comply with the legal regulations on maintaining public safety. The closure
must be so gas-tight that leakage of CO2 out of the
well and an emission of CO2 into the biosphere must
be ruled out for a considerable period of time (Figure
2). Abandonment technology for various storage scenarios must also be tested and optimized in field tests.
The same is true of the long-term safety of the boreholes together with their tubing and sensors.
Purity, transport and conditioning of CO2 for
storage
Basically, three methods can be taken into consideration for the separation of CO2 from the power plant
process: post-combustion capture, pre-combustion
capture and oxyfuel combustion. The first two methods achieve separation rates of between 85 and 95 %
whereas the oxyfuel process can reach separation
64
CO 2 Storage
well head
seal
Earth’s surface
cement seal
annular gap
cementing
possible
additional
caprock
non-corrosive
drilling fluid
cement seal
mechanical
bridge plug
perforation
impermeable
caprock
CO2reservoir rock
respect to the chemical and thermodynamic processes. An analysis must also be made of the effect certain
concentrations of impurities have on the transportation of gases in pipelines, on injection via deep
drilling and on the propagation of these gases in the
storage rock. Apart from studies on corrosion, it is
necessary to investigate the phase behaviour of the
CO2 mixture during transport and injection.
The CO2 storage facilities must be equipped with
pressure and temperature sensors with the aid of
which the gas properties after conditioning and on
the way to the storage facility can be recorded, monitored and optimized. A numerical simulation program must also be developed to accompany these
studies making use of these data and at the same time
paying attention to the design of the tubing and the
cementing, the injection and reservoir temperatures
as well as the flow rate and changes in the phase
properties.
Figure 2: Schematic of a CO2 injection well sealed against leaks
after storage has been completed
Exploration of sites for geological CO2 storage
rates of more than 98 %. The higher the required purity of the CO2 the more expensive and complicated is
the separation process. The economic viability of a
future coal-fired power plant with CO2 capture and
storage therefore decisively depends on the required
purity of the CO2 and the degree to which secondary
constituents such as NOx and SOx can be tolerated.
Ultimately, it must be ensured that any impurities do
not damage either the transport and injection technology or the storage facility.
The CO2 quality is determined during separation
from the process gas. This will be optimized for geological storage by technically and economically
appropriate process control. Before injecting mixtures of CO2 off-gas mixtures into geological formations corrosion protection measures must be taken to
fulfil the safety requirements for transport and borehole equipment.
Whereas extensive studies have already been
made of pure CO2/water systems, hardly any scientific
findings are yet available for CO2/process gas systems.
In order to make the technologies more reliable and
to optimize them, further research is needed with
The separation of carbon dioxide at coal-fired
power plants is only really meaningful if it is
ensured that the CO2 can be retained in geological
formations away from the atmosphere for considerable periods of time. Since the first pilot plant with
CO2 separation will be ready for operation in 2008
research into long-time storage must be speeded
up and intensified.
A selection of possible sites is necessary for
the geological storage of CO2. In Germany, it has
been decided to use saline aquifers and exhausted
natural gas deposits, which represent the greatest
storage capacities on the mainland of Europe.
Suitable aquifers will be explored both in closed
structures as well as in open, shallow bedded rock
formations. An important consideration is the vicinity to the CO2 producer and the possibility of safe,
energy-saving and environmentally acceptable
transportation. Even a less suitable formation may
be economically viable due to its vicinity to the
CO2 source, but in any case the same demands must
be made on all the storage facilities with respect
to capacity, safety and environmental compatibility.
65
On site, the spatial distribution of suitable storage
layers and cap rock can be determined by geophysical
methods and exploratory drilling. In doing so,
parameters are recorded such as depth, thickness,
faults and facies (from the Latin, meaning the characteristics of a rock or series of rocks reflecting their
appearance arising from conditions during sedimentation). Selected data are extrapolated to the entire
reservoir taking the lithogenesis into consideration.
The data of previous exploration and production
activities relating to crude oil and natural gas and
also geothermal power archived by the geological
industry and government agencies need to be examined, revised, digitized and visualized. Finally, these
data must be adapted to the special requirements
of CO2 storage. In order to comply with the ambitious
time schedule of the COORETEC beacon project, the
geological and geophysical exploration of possible
storage sites must start right away.
The risks for the planned reservoirs must be
assessed as proof of suitability. This is the only way to
ensure that CO2 injection can be performed safely.
The measures also include extensive analyses of
rock samples, fluids and microorganisms from the
underground formations, as well as measurements
and experiments in boreholes and also theoretical
forecasting models. Furthermore, information is
required on fissure and fault patterns, the hydrogeological and geomechanical conditions, pressure and
temperature as well as on the stress field in situ. The
data will ultimately be incorporated into an integrated geological model which will form the basis for
selective precautionary planning for storage monitoring.
rocks that are of relevance for specific CO2 storage
sites.
Geochemical interactions between CO2 fluids
and brines with reservoir and cap rocks can lead to
the dissolution and conversion of primary minerals
(for example, dewatering of clay minerals) and the
formation of secondary minerals. The cap rock of the
reservoir may thus become less impermeable. It is
therefore conceivable that the injected CO2 could
force the brines into drinking water horizons.
Furthermore, the geochemical changes of the stratal
water are of significance since they could lead to a
mobilization of contaminants from the rock. In this
context, consideration should not merely be given to
CO2 but also to the secondary constituents dissolved
in the CO2.
CO2 injection can cause short-term chemical
imbalances and thus a wide range of chemical and
physical reactions. Depending on the pressure, temperature, fluid chemistry and rock type, this may lead
to beneficial or adverse changes in the geometry of
the pore space and thus of the storage capacity and
permeability. Such reactions in the underground for-
Geomechanical behaviour and fluid/rock
interaction
For forecasting geomechanical processes and also
for evaluating storage issues and assessing risks it
is important to gain an understanding of the constitutive equations and their parameters. This will
require laboratory experiments on mineralogically
well-defined rocks with various degrees of CO2 saturation and additional gases under simulated in situ
pressure and temperature conditions (Figure 3).
Attention should be focused on investigating those
Figure 3: Sandstone sample with sensors for a triaxial highpressure test with CO2 through-flow under simulated rock
pressure and temperature conditions
66
CO 2 Storage
mations can be recognized by changes in the geophysical values measured – for example, the seismic
wave velocities or the electrical conductivity of the
rock strata. Geochemical laboratory experiments are
useful for investigating the reaction kinetics of fast
geotechnically relevant reactions under in situ conditions.
events of the surrounding rocks. The rise in pressure
during an injection of gas must not under any
circumstances lead to an endangerment of the
cap rock. Technical measures must be taken to ensure
this. Furthermore, the displacement and ascent of
brine into strata bearing drinking water must be
prevented (Figure 4).
The reaction rates generally determined in
such experiments for pure mineral phases often
differ from those occurring in natural deposits by
several orders of magnitude. This is particularly
true of complex minerals such as silicates or alum
inosilicates which are chemically and structurally
variable. The reactions and propagation processes
that proceed slowly in geological formations can be
readily studied in natural CO2 deposits.
For example, deposit models of hydrocarbon
reserves will be continuously compared with the production data and adapted empirically. This opportunity does not present itself for the case of the injection
of CO2 into aquifers since practically no experience is
yet available. Forecasting of storage capacities and
injection rates with hydrodynamic simulations is currently still uncertain. There is thus room for improvement in the mapping of structural heterogeneities in
fluid dynamic transport simulations which can often
only be described statistically.
The effect supercritical CO2 has on organic material is as yet unclear. This material may accumulate in
coal intercalations in reservoir rock and clay cap rock.
Chemical reactions may mobilize soluble organic compounds or poorly soluble residues may be formed.
Modelling and monitoring CO2 reservoirs
Simulation models are required for modelling the
processes in CO2 reservoirs. These models will numerically quantify the influence of CO2 storage on different reservoir and cap rocks under the conditions to be
expected in situ. Since hydraulic, geomechanical and
geochemical effects are closely coupled in underground reservoirs, models must be applied or developed that are capable of covering the complexity of
the various processes and calculating the effects of
long-term storage of CO2. Appropriate models are
thus necessary for selecting a storage site. Furthermore, with the aid of the models it will be possible to
perform parameter studies and risk assessments for
planning and assessing the risks of the injection
process.
In forecasting the long-term behaviour of the
reservoirs, attention should also be paid to recent
movements of the underground formations. Mass
displacements due to the injection of gas can result
in mechanical reactions such as rearrangement of
stresses, deformation, fractures or even macroseismic
For the geological long-term storage of CO2
it is therefore important that the propagation of
CO2 in the supercritical liquid and / or gaseous state
should be monitored and measured. In this way,
the operational cycle of the storage process can be
monitored and it can also be demonstrated that the
regulations for safe operation of the reservoir are
being observed. Furthermore, this monitoring can
identify leaks in the cap rock at an early stage.
Recommended monitoring methods include
hydraulic tests, pressure measurements, chemical
sampling, seismic and geoelectrical tomography
caprock
aquifer (groundwater)
saline aquifer
Figure 4: Possible leak paths for CO2 from aquifer storage in a
geological anticlinal structure:
I injection borehole, O observation borehole, A earlier borehole,
B well borehole, 1 leak via permeable boreholes, 2 capillary
penetration of CO2 into the cap rock, 3 ascent of CO2 from the
reservoir via a fault V into an upper aquifer, 4 lateral escape of
CO2 by flowing under the spill point S of the reservoir, 5 acidification of the groundwater, 6 outgassing of dissolved CO2 into
the biosphere
67
(Figure 5) as well as geomechanical sounding and
measuring methods.
The spatial resolution of the available measur-ing
methods must be increased by further developments
and new discoveries. Only in this way can leaks in the
cap rock be recognized in detail and instabilities in
the dynamic propagation front of the liquid and the
preferred flow paths be identified. Ultimately, it must
be possible to precisely determine how the CO2 flows
and where to. Furthermore, strategies must be developed for initiating effective countermeasures in the
case of major leaks.
4D-surface seismics
4D seismic
crosshole
and
vertical
seismic
profiling
caprock
CO2-injection
Monitoring methods for tracking a CO2 injection
must be adapted to the special features of the deep
wells with respect to pressure, temperature and corrosion. The sensors should be installed in theborehole
tubing or in the cemented annular space between the
protective tube and the rock for as long as possible.
The borehole measurements must be planned in such
a way that they can be routinely monitored with a satisfactory repetition rate over lengthy periods of time.
The application of an integrated data recording
system (borehole and reservoir information system)
will make it possible to automate the long-term
observation of the CO2 reservoir. In this way, data
obtained by various measuring methods (such as seismic velocities or electrical resistance) can be evaluated together. Long-term monitoring provides important information on the hydraulic properties of the
reservoir and fluid/rock interactions. The results can,
moreover, also help to validate and calibrate the numerical simulation models. This thus enables a reliable
forecast of the long-term security of the CO2 reservoir.
There is also one more thing that the data measurements should provide: a reliable prediction as to
whether the storage system will in the long term
behave as calculated after closure and backfilling of
the borehole. This would significantly reduce monitoring efforts for subsequent generations.
Risk management and legal framework
For the planning and operation of a CO2 reservoir it is
important to recognize the risks in good time so that
reservoir rock
1 Injection well with non-explosive inhole seismic
sources and 3D geophones
2 Observation wells with 3D geophones
and hydrophones
Figure 5: Seismic surface measurement and borehole
connections in a CO2 reservoir
they can be dealt with. This requires, for example, a
standardized catalogue of requirements listing and
assessing the potential risks. This catalogue should
include the following priorities: nature and extent of
the preliminary geological exploration, requirements
for forecasting models (parameters, time frame, reliability), technical demands on borehole design and
dismantling, design of the installations above ground
and also the type and extent of the monitoring technologies
To this end, the major risk sources in constructing CO2
reservoirs must be identified and their risk potential
assessed both qualitatively and quantitatively. These
risks will then be identified by modelling the underground formations with the probability of occurrence
and hazard potential. Such hazard scenarios form the
basis for reviewing the design concepts.
As yet there is no comprehensive and specific
design code for CO2 storage in Germany. The existing
regulations were not developed for injecting CO2 into
geological formations and only cover certain aspects
of CO2 storage. In general, the legal boundary condi-
68
CO 2 Storage
tions result from the national and international specifications of mining law, law relating to water, immission control legislation, waste legislation and other
branches of the law. Appropriate parameters are currently being examined by the geologicalagencies of
the individual federal states and the federal government. Federal mining legislation will have to be formulated more precisely according to an expected EC
directive which has already been proposed
Experience with licensing procedures and
acceptance on the part of the general public is just as
valuable for COORETEC as the actual scientific and
technical research findings. COORETEC therefore
aims to establish a dialogue with the public – for
example in the form of consultations. This is intended
to address the reservations and resistance of the public with respect to the safety of operations above and
below ground. Great significance is also attached to
the question of how the risks of geological storage
can be dealt with in international CO2 certificate trading.
I.
Influence of the CO2 flue gas quality on transport,
injection and storage
The purity of the captured CO2 and the level of impurities depend on the method applied and the technical efforts invested in CO2 separation. The cost of separation rises with increasing purity of the CO2 gas. On
the power plant side, it would be more economical to
keep efforts for purifying the separated CO2 as low as
possible. On the storage side, in contrast, it must be
ensured that the flue gas contains so little trace gas
that there is no damage to the technical components
or the reservoir.
For the design and planning of separation facilities it is therefore necessary to determine the tolerance of technical components with respect to contaminated CO2 and also to establish limits for the
mechanical and geochemical load capacity of the
reservoir and cap rock. The physicochemical properties of the underground rock formations could therefore be a decisive factor for the demands to be made
on the purity of CO2 during separation and storage.
Lighthouse project „CO2 storage technologies“
Major R&D topics
As part of the federal government’s high-tech initiative, the “COORETEC Ligthouse Concept” will develop
options for a long-term reliable, sustainable and environmentally acceptable energy supply in Germany.
The capture and storage of carbon dioxide arising from the combustion of fossil energy carriers is
regarded as a promising climate-protection measure
in the medium term. This method known as CCS
(carbon capture and storage) is still at the research
and trial stage. It promises to provide an opportunity
for the nearly climate-neutral utilization of fossil raw
materials.
II. Information system for CO2 storage and cap rock
The separated CO2 will be stored in deep aquifers
bearing salt water or exhausted natural gas fields.
Some issues remain to be clarified such as the size of
the available storage volume, how pure the flue gas
CO2 needs to be, how long-term storage security can
be ensured and whether there are possible impacts
on the ecosystem. The following development tasks
represent the cornerstones of the “COORETEC
Lighthouse Concept”:
Corrosion of means of transport and storage
facilities by CO2 off-gas mixtures
Geochemical reactions of CO2 gas mixtures with
reservoir rock and cap rock
It is only meaningful to separate CO2 arising at power
plants with the aim of preventing CO2 emissions if it
can be demonstrated that sufficient underground
storage capacity is available in the long term.
Sufficient capacity for storing very large volumes of
CO2 (several hundred megatonnes) is not available in
the vicinity of every power plant. For this reason, a
geographical survey map will be compiled locating
reservoirs in Germany and also including a general
characterization of the regional cap rock.
A detailed geological and geophysical characterization of selected potential reservoirs will also be
undertaken with the aid of 3-D seismic and geoelectrical mapping methods. These locations must then be
correlated with geological observations. If the first
69
storage facilities for the “COORETEC Lighthouse
Concept“ are to be set up by 2020 then preliminary
investigations must begin in the immediate future.
The basic geoscientific data thus obtained will be
incorporated into reservoir models permitting the
first reliable estimates to be made of the storage
capacity, suitability as a reservoir and safety of the
storage facility.
fresh state, this cement must be easy to work and
inject. The basic prerequisite for CO2 storage capable
of being certified is that the cementing can be reliably controlled. This applies equally to the tubing and
the closure of the borehole.
Major R&D topics
Major R&D topics
Information system for geological reservoirs
Modelling and characterization of types of reservoir structure
III. Development of methods for increasing the efficiency and safety of reservoirs
To date there is no experience with the injection of
CO2 into deep saline aquifers on the mainland of
Europe. An important prerequisite for safe storage of
CO2 in underground formations is an injection technology which injects CO2 at depths where the formation pressure is significantly above the critical pressure of CO2. This corresponds to a depth of about 1000
m. Previous research approaches in Europe have concentrated on the scientifically and technically particularly interesting area in the vicinity of the critical
point.
Further development of reliable CO2 injection
technology
Long-term behaviour of borehole seals exposed
to CO2
Overview of development needs
The R&D programme on “CO2 storage” will demonstrate that CO2 can be stored safely and stably in geological formations in the long term. Important fields
for scientific and technological investigation are the
capacity and sealing behaviour of the storage formations, the geochemical reactions of the carbon dioxide with the rock and the fluids in the underground
formations, and also the encouragement of public
acceptance of underground CO2 storage as an option
for climate protection.
This programme topic rests on three pillars:
There are many indications that an ecologically
and economically effective approach for storing large
volumes of CO2 is to inject it into deep geological formations. On the basis of experience gathered with
existing research boreholes on the mainland of Europe,
the storage of CO2 should be undertaken in the short
term at depths of more than 1000 m in field experiments
with redesigned sensor and monitoring technology
in order to further develop the technology and adapt
it to greater depths, to revise the approaches and to
extend the lead over possible competitors.
For the safe, long-term confinement of CO2
stored underground, it is necessary to develop new
types of borehole cement and cement paste suspensions, which after hardening possess a high degree of
stability and resistance to carbonic acid under the
environmental conditions and conditions of chemical
attack expected in CO2 storage formations. In the
Influence of the CO2 off-gas gas quality on transport, injection and storage
Information system for CO2 storage and cap rock
Development of methods for assessing the efficiency and safety of reservoirs
To this end, the overall chain will be investigated
starting from planning and operation up to and
including the conclusion of pilot and demonstration
projects. This chain comprises the choice and characterization of the site, basis monitoring and surveillance of the storage facility, reservoir modelling and
risk analysis as well as technologies for safe closure of
the reservoir.
In this work, attention is focused on safety-related issues. For example, the leak tightness of the cap
rock and the boreholes must be demonstrated before
70
CO 2 Storage
injection activities begin and must also be regularly
monitored during and after injection. Subsequently,
existing methods and techniques can be further
developed and optimized with respect to cost and
benefit
Development of methods for increasing the efficiency
and safety of reservoirs
Project-specific studies will focus on geologically
different sites that can be considered as storage locations. Expertise already available and methods still to
be developed will be applied in large-scale pilot and
demonstration projects in close cooperation with
industry in order to achieve COORETEC's ambitious
goal in the given time frame.
Influence of CO2 off-gas quality on transport, injection
and storage
Thermodynamic and technical behaviour of CO2
and CO2-gas mixtures
Demands made on the quality of CO2 for transport and injection
Experimental studies of corrosion rates of borehole steels as a function of the concentration of
various components in the CO2 mixture
Increasing the long-term corrosion resistance of
the borehole tubing
Experimental and analytical studies of the petrophysical and geochemical properties of rock
exposed to CO2 and CO2-gas mixtures
Influence of impurities in the CO2 on the reservoir and cap rock
Information system for CO2 reservoir and cap rock
CO2 storage atlas: systematic recording, classification and quantification of reservoir sites in
Germany
Specific exploration technologies for geological
storage facilities
Characterization of selected storage and cap rock
geology, lithology, hydrology, capacity, injectivity, reactivity, stability
Permeability of reservoir and cap rock for supercritical CO2
Leak and reaction behaviour of natural CO2
deposits
Creation of a database of parameters and models
for assessing suitability as a reservoir
Numerical simulations of geoprocesses in the
reservoir and cap rock during CO2 injection
Optimization of the thermodynamic regime for
CO2 and CO2 mixtures during the injection
process
Improvement of the geoscientific monitoring
technologies for CO2 storage with respect to spatial and temporal resolution, penetration depth
and sensitivity as well as reliability and cost
Development of technologies for a safe closure of
CO2 storage boreholes (abandonment tech-nologies) at the conclusion of the project and demonstration of long-term leak tightness of the reservoir
Monitoring of the CO2 in geological storage and
verification of the propagation of CO2 according
to plan in the geological formations during the
operational and post-operational phase
Development of methods for the qualitative and
quantitative assessment of risks
71
Note
72
Note
Concept:
Projektträger Jülich
Forschungszentrum Jülich GmbH
Dr. Jochen Seier, Dr. Horst Markus
www.fz-juelich.de/ptj
Editorial team:
Dr. Thomas Rüggeberg, Bundesministerium für Wirtschaft und Technologie
Dr. Jochen Seier, Forschungszentrum Jülich GmbH, PTJ
Armin Schimkat, Alstom Power Generation
Prof. Manfred Aigner, Deutsches Zentrum für Luft- und Raumfahrt e.V.
Prof. Dr. Günter Scheffknecht, IVD-Universität Stuttgart
Dr. Jörg Kruhl, E.ON Energie AG
Dr. Johannes Ewers, RWE Power AG
Prof. Bernd Meyer, TU Freiberg
Dr. Frank Schwendig, RWE Power AG
Dr. Karl-Josef Wolf, RWE Power AG
Hubertus Altmann, Vattenfall Europe Generation AG & Co. KG
Prof. Alfons Kather, TU Hamburg-Harburg
Christian Hermsdorf, TU Hamburg-Harburg
Prof. Günter Borm, GFZ Potsdam
Tim Schröder, freier Journalist
Editorial team:
Translation: Language Services Forschungszentrum Jülich GmbH
Photo credits:
Siemens Power Generation, Alstom Power, Hitachi Power Europe GmbH, MAN Turbomaschinen, RWE Power AG, E.ON Energie AG,
TU Dresden, Vattenfall Europe Generation AG & Co. KG, TU Hamburg-Harburg, GFZ Potsdam, N.V. Nuon, Universität Stuttgart
Printed by:
Grafische Betriebe
Forschungszentrum Jülich GmbH
Published by:
Federal Ministry of Economics and Technology (BMWi)
Public Relations /IA8
11019 Berlin
www.bmwi.de
As of:
April 2008
Research Report
No 566
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COORETEC Lighthouse Concept
The path to fossil-fired power plants for the future
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