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                                                                                        CSLF-T-2006-12
                                                                                         November 2006


                             Final Report from the Task Force for
                        Identifying Gaps in CO2 Capture and Transport


Background

At the meeting of the Technical Group in Melbourne, Australia on September 15, 2004, a Task
Force was created to identify gaps in CO2 capture and transport. This Task Force consists of the
European Commission (lead), China, France, Germany, Italy, and Norway. It was instructed to
produce a discussion paper that would then undergo review and be presented at a Technical Group
meeting. A first version of this discussion paper was presented at the meeting of the Technical
Group in Oviedo, Spain, on April 30, 2005 and a revised version was presented at the meeting of the
Technical Group in Berlin, Germany, on September 28, 2005. This final report represents the
conclusion of the Task Force's activities.
                                  Final Report:
             Gaps Existing in Knowledge of CO2 Capture and Transport

                     Developed by a Task Force under the Technical Group
                     of the Carbon Sequestration Leadership Forum (CSLF)

General

The CO2 capture and storage technology, its basics, costs and areas of knowledge improvements
necessary are discussed in the CSLF Technology Roadmap. This Roadmap is to be updated
regularly. The present version was adopted at the meeting of the Technical Group on the 13th of
September 2004.

This Gap Analysis shall be seen as additional input to further update and improve this roadmap.

Appointment of the Task Force

It was decided at the September meeting of the Technical Group of the CSLF that an analysis of the
gaps in the knowledge of CO2 capture and transport should be made by a Task Force. Delegates to
this Task Force were selected in January 2005, and initially consisted of:

Lars Strömberg, Vattenfall AB Sweden, representing the European Commission (appointed
Chairman in January 2005)
Chen Wenying, Tsinghua University, representing China
Claudio Zeppi, ENEL S.p.A., representing Italy
Hubert Höwener, Forschungszentrum Jülich GmbH, representing Germany
Lars Ingolf Eide, Norsk Hydro ASA, representing Norway
Jean-Xavier Morin, Alstom, representing France

Subsequently, Germany notified that Jürgen-Friederich Hake from Forschungszentrum Jülich was
also a Task Force delegate. Also, in 2006, Volker Breme from Forschungszentrum Jülich replaced
Hubert Höwener as one of Germany's Task Force delegates.

Overview of the Paper

This analysis, according to the instructions of the CSLF Technical Group, handles only the Capture
and the Transportation steps in the full chain of capture and storage of CO2. The paper describes
gaps to be covered in future R&D work to establish a technology knowledge good enough to fulfill
the goals set up by several countries, to avoid CO2 emissions from large scale power plants and other
sources, at a cost of 10-20  per ton of CO2. This is within a time frame up to 2020.

The paper begins with a brief description of the main technology candidates fulfilling the above-
mentioned requirements. This means that R&D in processes, principles and technology that might
be very important and promising but probably will not give results enabling large-scale applications
within this timeframe is not discussed. In addition, only technical ways to capture CO2 are
considered, i.e. reforestation and other system-related ways are not included. Technical options shall


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also be interpreted as referring to energy production or in energy-related industrial processes. There
are also numerous existing industrial processes not discussed here, such as where CO2 can be
captured in chemical, petrochemical, food, and in the paper and pulp industry.

Capture Technology Overview

The technology can be described several ways. Here, three categories of capture technology are
considered.

    1. Technologies possible to realize within 15 years, based on existing production technology
       and reasonably well-established technologies.

            a. Postcombustion capture
            b. Precombustion capture
            c. Oxyfuel processes

        Further, one must distinguish between the fuels used, such as different kinds of coal as
        opposed to natural gas.

    2. Technologies tested in technical scale and possible to realize after the three first generation
       technologies, such as chemical looping.

    3. New technologies not yet available that will be based on next-generation physical, chemical
       or thermodynamic processes, such as processes based on membrane technology, solid
       adsorbers, or new thermal power processes.

The three technologies in the first category are described in the CSLF Technology Roadmap. All
three are also well described in the European Power Generators Association's state of the art report
from 20041 which also describes the technologies in the second and third categories. Another recent
overview can be found in the IEA report, "Prospects for CO2 Capture and Storage from 20042". The
"IPCC Special Report on Carbon Dioxide Capture and Storage3" also describes the technologies
extensively.

1-a)    Postcombustion Capture

Postcombustion capture, or capturing CO2 from flue gases, is an established technology that exists
today. It can be delivered from commercial vendors but needs scaled-up engineering by a factor of
about 10 and optimization to be able to be applied to a 500 MW power plant. Postcombustion
capture separates CO2 from flue gas by a liquid absorber in a conventional absorption column at
ambient pressure. Regeneration of the absorber is done at a relatively low temperature, where the
CO2 separates from the absorber in another column. The separated CO2 is then cleaned and

1
   CO2 Capture and Storage. VGB Report on the State of the Art. VGB Power Tech, Essen, Germany 2004.
http://www.vgb.org
2
   Prospects for CO2 Capture and Storage. OECD/IEA 2004. IEA Publications, Paris, France. ISBN 92-64-108-831;
2004
3
  Available at www.ipcc.ch


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processed further, to be compressed into a liquid or supercritical state. The amount of compression
required depends on how the CO2 will be transported. The criteria for the process are that the flue
gas must be cleaned down to a very low level of trace contaminants, such as particulates and sulfur.
Furthermore, the regeneration step uses energy taken from the power process.

The cost for the process is related to the extra investment in equipment and the energy use for the
desorption and further compression. For coal, the process requirements for cleaning of flue gases
before absorption are stringent, which increases investments. For gas combustion, the CO2
concentration is low, which increases requirements for the absorption tower.

1-b)    Precombustion Capture

Precombustion capture can be adopted both for gas and for coal or any other feedstock that can be
converted to syngas (i.e., CO and H2). For coal and other solid fuels, a gasifier is needed to produce
a syngas. For natural gas, syngas is usually made by a catalytic reforming step. After that, the
processes are similar in principle, though syngas clean-up is a necessary first step after a coal
gasifier, as there are impurities in coal that are not found in natural gas. Using a water shift reaction,
the CO contained in the syngas is converted into additional H2 plus CO2. This gas is then separated
in an absorption process, with similar principles as the postcombustion capture. The product gas
before combustion has higher CO2 concentrations and higher CO2 pressure, and stripping of CO2
from the sorbent can partly be done by pressure reductions; these differences simplify the separation.
In principle, the following power process is a combined cycle or an advanced gas turbine process.
The product stream after separation of CO2 is a hydrogen-rich gas which is burned in a gas turbine
that has been optimized for this fuel. There currently exist turbines capable of burning hydrogen,
although they are not optimized for this. The development of an optimized gas turbine for hydrogen
is considered a major development task.

Most of the process equipment is well established in industry, e.g. in ammonia plants and refineries.
The separation technology is not based on liquid chemical absorbers, but on a physical adsorption
mechanism. With natural gas as a feedstock, this technology can be considered commercial.
However, when using coal, a gasifier system is needed. The chemical industry has been employing
gasifiers for many years that run on many different solid and liquid feedstocks. Several large-scale
gasifiers with a combined cycle as a power generation process have also been built. However,
without CO2 capture, this technology is approximately 10-20% more expensive than current
technology. Nevertheless, studies suggest that precombustion technology may be the most
favourable and technically appropriate for cases where CO2 capture is required4.

The inherent ability to produce hydrogen as an intermediate product might give precombustion
technologies a boost. Today's hydrogen market is restricted to the internal hydrogen consumption in
the chemical and refinery industry and does not play any role as an energy carrier. However, much
effort is being put into the development of hydrogen-based energy technology. The least costly
option at present to produce hydrogen without CO2 emissions is a natural gas or coal-based process
with carbon capture and storage. Further, electricity can be combined with other products such as


4
 for example, COORETEC Report, Research and Development Concept for Zero-Emission Fossil-Fuelled Power Plants,
Federal Ministry of Economics and Labour, Germany


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syngas for methanol or synthetic liquid fuel production. This might form a market adjusted
polygeneration technology, improving profitability when mid-merit types of plants are also needed.

The cost for the pre-combustion technologies relates to the cost for equipment, energy consumption
for the CO2 removal step, CO2 compression and some energy losses other parts of the process, such
as the water-gas shift.

1-c)   CO2/O2 Recirculation or Oxyfuel Combustion Technology

The principle for oxyfuel combustion is to use pure oxygen or a mix of oxygen and carbon dioxide
for combustion instead of air. The flue gases will then mainly consist of only CO2 and H2O plus
impurities related to the fuel. If the flue gas is cleaned of particulates, sulfur, and other undesirable
substances, and the water vapour is condensed, the remainder is relatively pure CO2. Further
separation is then needed to remove non-condensable gases. To keep temperature control in the
flame, CO2 is recycled. In the case of coal-fired power facilities, the generation process is a
conventional steam cycle. Thus, a first-generation boiler will be designed in a similar fashion to a
conventional boiler, but instead of air, CO2 and O2 will be used for combustion in a proportion
giving similar properties of the flame as a flame with air i.e., 27% oxygen with the remainder CO2.
The boiler must also be built air-tight to avoid nitrogen in-leakage. The boiler can utilize modern
standards with supercritical data and a conventional steam turbine process.

This process does not need any energy to recover any absorbent, but does need energy for air
separation. The amount of oxygen needed is about seven times higher than what is required for a
gasifier. In addition, energy is needed for CO2 compression, just as in the two processes described in
1-a and 1-b above.

All equipment for this process is also commercially available, except that the boiler must be
optimized for CO2/O2 combustion instead of air. Also the desulfurization equipment must be
adjusted, since the gas flows are much smaller and the partial pressure of SO2 and CO2 are higher.
As in the cases above, several of the components are not available in the sizes needed for a very
large power plant, and existing equipment is not optimized for this use.

For coal, the combustion process can also be a fluidized bed or any other type of boiler. For
circulating fluidized bed (CFB), the technology might become more attractive as the bed material
can be used for cooling, thus reducing the need for CO2 recirculation.

The oxyfuel process can also be adapted to gas firing. However, in this case a new gas turbine
process design is needed. As for coal, the air separation is energy-intensive. The cost for the coal-
fired oxyfuel process depends on the cost for the CO2 cleaning equipment and air separation, the
energy used for air separation, and for CO2 compression as described in 1-a and 1-b above.

2)     Technologies Tested On a Technical Scale

Chemical Looping
Another promising alternative, which might be able to become almost commercial within the time
frame considered here, is Chemical Looping Combustion (CLC), a special variant of oxyfuel, in



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which the flue gas is CO2 and H2O, plus impurities. The principle is that a solid-state oxygen carrier
brings the oxygen for combustion to the combustion zone. This can be a metal oxide or similarly
designed material. The oxygen is attached to the solid in an air blown reactor where the material is
oxidized and the metal oxide is subsequently reduced in the combustion reactor.

This process has recently been demonstrated as working well in a laboratory scale, burning natural
gas. Due to its impurities, coal cannot be similarly burned in as simple a way as gas because the
oxygen carrier becomes mixed with unburned char, degraded by trace elements and difficult to
separate from the ash.

The solution is either to use a cheap carrier or find another more delicate way of gasifying the coal
that does not produce gas stream impurities. No such process has been demonstrated even on a
laboratory scale.

The process is mechanically very similar to a conventional fluidized-bed boiler, although with two
reactors instead of one. The power process can be a conventional steam turbine process. This
implies that the cost for equipment will be higher than for a conventional fluidized-bed boiler, but
there is no longer a cost for energy to separate oxygen from air. However, costs for the oxygen
carrier, for CO2 clean up, and for energy for compression must be added.

3)     New Technologies

"New technologies", as used in this paper, means "not based on conventional power generation
processes" as described above. The aim of these new technologies is generally to make gas
separation easier, cheaper and more efficient. Numerous variants are possible.

New Gas Separation Technologies
Initially, two gas separation principles can be distinguished. First, for membrane technologies, there
exist a family of materials which can be made in the form of a membrane capable of letting some
molecules through while others are hindered. Thus, O2, H2 and CO2 separation membranes have
been designed. Most of these operate at elevated temperatures, typically about 1,000°C. The
driving force is differences in partial pressure, which can be obtained either by adjusting the
concentration of the gas and/or total pressure. Most technologies also need a flushing gas stream to
remove the separated molecules from the surface of the membrane. One main challenge facing these
technologies is integration with a technically feasible combustion system. However, there exist
rather large membranes, which are being operated in laboratory surroundings that have these
specified requirements established both for O2 and CO2 separation. There is ongoing R&D work for
hydrogen membranes.

The second principle is to adsorb a gas on a specific material, and cycle this material in alternating
surroundings. Therefore, the gas is separated from one gas stream to another. These technologies
also require high temperatures and differential partial pressures, as the membranes do, as well as a
flushing stream. Again, the principle works in the laboratory, but no complete power process close
to realization has yet been demonstrated.




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In addition, numerous new thermodynamic processes have been promoted. They all have in
common a need for either a breakthrough in membrane or separation technology. All proposed
processes are at the study level and cannot be realized before the others mentioned above. Thus,
they are not further described here, and cannot be evaluated at the same level of certainty as the ones
described above.

The driving force for all attempts with new processes is to reduce energy consumption for CO2
separation, or reduce equipment and operating costs. They all claim better properties in some of
these aspects, but most give little or no information on the cost of capture.

Transport of CO2

Transport of CO2 is a well-known technology. It is utilized extensively in industry, and also for
enhanced oil recovery (EOR) purposes. This means that technologies exist for all types of
transports, for small or large volumes, for long and short distances, onshore and offshore. These
include:

   ·   Truck transport with standard containers or tanks
   ·   Railroad transport, also with tanks or containers
   ·   Ships (1,000-1,500 ton capacity at present; Statoil has performed a study for ships of about
       20,000 ton capacity)
   ·   Pipelines

The transport means are established for different purposes, i.e. for the food industry. The
requirement there is different than for a power plant, where CO2 must be disposed as inexpensively
as possible. This also indicates a need for adaptation to new requirements. Also, the operational
properties of the transport system place requirements on the properties of the CO2 to be transported.
One example is that it is more favourable if the CO2 is in supercritical form for pipeline transport.
Pipelines are the most favourable alternative for large, continuous volumes and long distances. On a
ship, also suitable for large volumes, CO2 should be stored as close to its triple point as possible; the
larger the vessel, the lower the pressure and temperature. Truck or tank rail transport can only be
adapted to small volumes and short distances. Neither of the latter two are probable for any power
plant situation.

What does not exist, and will not, until a market is formed, are larger integrated systems with trunk
pipelines, distributed pipelines, ships and trucks forming a system serving several emitters of CO2
and supplying a system of storage. Several studies have established a cost level for each alternative.
These studies have also clearly shown that the system cost per transported ton is much lower for an
integrated system than for a line from source to storage.

The Cost Structure

The driving force for all development is to reduce cost. In the process from capture to storage,
capture represents the highest costs. Transport cost, as discussed below, depends very much on
distance but also on volume, since large volumes allow the use of less expensive large-scale



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solutions. Again, the storage cost depends on the storage structure, location and depth. However, it
is considered that the capture accounts for some two-thirds of the total cost.

The introduction of carbon capture and storage technologies depend entirely on what extra cost is
incurred in comparison to other ways of reducing CO2 emissions. In Europe, a trading system for
CO2 emission rights has been introduced. Beginning in February 2005, the market cost was about 7
 per ton CO2. In July 2005 it was about 22  per ton. If new technologies can meet future CO2
costs, they will be introduced. If not, other cheaper ways of reducing emissions will be used.

It must be stressed that the technology choice for new investments is governed by the energy
generation costs for the technology in question, including any CO2 penalty. This implies that a
technology with lower generation costs will be preferred over a more expensive technology, even if
the calculated CO2 capture cost is higher. Secondary parameter for the choice is the cost for
capture/avoidance.

The cost for capture is calculated in several different ways. The most important issue is to what the
comparison is made: a plant of the same kind without carbon capture, or to some other plant. It is
common that the calculations shall include:

   ·   Incremental investment costs
   ·   Incremental operational and maintenance costs (O&M)
   ·   Incremental fuel costs
   ·   Energy penalties, i.e. the reduced output or the energy imported to maintain output shall be
       accounted for

This results in an increased energy production cost, when comparing the same type of plant without
and with carbon capture and storage. Dividing the energy production cost by the reduction of CO2
emitted to the atmosphere yields the unit cost of CO2 avoided to the atmosphere (not only captured)
expressed in  per ton of CO2. To make comparison between different results possible, the
calculation must take into account energy penalties, fuel prices, cost estimation basis, expected
lifetime, interest rates, load factor, and if taxes etc. are included.

This implies that reducing cost does not only include reduction of the capital cost, but also energy
consumption and unavailability. Present postcombustion and precombustion technologies have
energy penalties in the range of 15-25% of the output, depending on fuel. This means that the
capture cost will be sensitive to reduction in energy loss, but also sensitive to fuel price. With
present European fuel prices, it is easier to achieve lower costs for coal than for gas per captured ton
of CO2. In fact, the capture cost for coal is about half that of gas. At the same time, it must be
remembered that the present commercial total electricity generation cost for a gas-fired combined
cycle power plant is about equal to a modern coal-fired supercritical plant in Europe.

Primary Development Goals

The primary objective is to achieve the avoidance cost goals adopted by the United States (