Memorandum from Dr Paul Freund
1. Carbon capture and storage (CCS) technology
could make an important contribution to reducing greenhouse gas
emissions, in the UK and worldwide.
2. The key feature of CCS, which has led
to the recent increase in interest, is that it is based on established
technology. However, there is limited experience of applying this
technology to the purpose of protecting the climate and little
experience of monitoring and, especially, verification of CO2
storage. This level of maturity of the technology is different
from the situation of other, novel energy technologies, which
leads to different recommendations for R&D activitythese
mainly concern demonstration of full scale systems and proving
of monitoring and verification techniques.
3. Cost reduction will arise more from gaining
experience with CCS technology by wider deployment than from basic
research. This will build on relevant developments in other technologies,
such as gasifiers and gas turbines.
OF CCS AS
Current state of R&D and deployment of CCS
4. Capturing CO2 typically involves
separating it from a gas stream. Suitable techniques were developed
60 years ago in connection with the production of town gas; these
involve scrubbing the gas stream with a chemical solvent. The
process has since been improved so as to inhibit the oxidation
of the solvent in a flue gas stream. Other types of solvent and
other methods of separation have been developed more recently.
The total number of such installations worldwide is probably several
thousand today. Application of this type of technology to mitigation
of climate change was first discussed in the 1980s with initial
focus on electricity generation. CO2 removal is already
used in the production of hydrogen from fossil fuels; application
of capture and storage in this process as a climate protection
measure has been examined by several authors and is proposed for
a new plant which may be built in Scotland.
5. Projects aimed at developing improved
capture technology include several which are European funded (eg
AZEP, CASTOR and ENCAP) as well as industrial projects carried
out by the manufacturers (eg Mitsubishi have developed several
improved solvents; Fluor-Daniel have described the benefits of
improvements in heat integration; the CO2 Capture Project,
largely industrially funded, examined many capture options and
instigated some work on novel methods).
6. In order to transport CO2
to possible storage sites, it is compressed to reduce its volumein
its so-called dense phase, CO2 occupies around 0.2%
of the volume of the gas at standard temperature and pressure.
Several million tonnes/year of CO2 are transported
today by pipeline, by ship and by road tanker.
7. For storage of CO2, many options
are, in principle, available. As the amount of CO2
that would need to be stored would be comparable in magnitude
to the amount of CO2 emissions, potential storage options
have to have capacity for Gt/y of CO2; the only feasible
options are natural reservoirs, such as geological formations.
Potentially attractive formations are those which have held oil
or gas (or natural CO2), because of their demonstrated
ability to retain these fluids, plus the fact that they will have
already been investigated and surveyed, especially if the oil
or gas has been extracted. Providing that subsequent penetrations
of the sealing layer have not compromised its ability to retain
CO2, such formations should make good storage reservoirs.
Injection into a depleted oil field has not yet been attempted
on a commercial scale but the West Pearl Queen project in the
USA has used such a reservoir for a research project; the ORC
project (offshore the Netherlands) is the first to do this in
a depleted gas field.
8. A well established use of CO2
is for enhanced oil recovery (EOR)in this CO2
is injected into depleted oil fields to recover an extra few per
cent of the oil in place, as is being done at the Weyburn oil
field in Canada (the first EOR project with monitoring of the
CO2 stored in the reservoir). Some of the CO2
injected for EOR will be produced with the oilit is normal
practice to separate this and reinject it. The CO2
remaining in the reservoir at the end of injection can be regarded
as being stored providing the field is not re-entered. This is
analogous to the use of a depleted oil field for storage of CO2
except that the extra oil produced can help to offset some of
the cost of supply an injection. The same cannot be done to enhance
production from gas fields but CO2 injected into a
gas field can help maintain the pressure in the reservoir and
hence the production rate; this is being done at the In Salah
gas field in Algeria.
9. An extension of this idea involves injection
into deep saline formations, which may have much larger worldwide
capacity. The world's first commercial scale CO2 storage
facility, the Sleipner project, makes use of a deep saline formation
under the North Seathis began operation in 1996. Other
commercial projects announced include Sønvhit (Norway)
and Gorgon (Australia); aquifers are good locations for research
on storagecurrent projects include Nagaoka (Japan) and
Frio (USA). Another storage option is unminable coal beds, where
CO2 injection may sometimes result in displacement
of methane which could be used as a fuelthe first pilot
was carried out in the USA in a highly permeable coal; initial
results from this project have since been questioned. A research
project in Poland experienced difficulties with injecting CO2
into coal. This approach would be of most value to countries with
relatively permeable coals, unlike the UK.
10. Monitoring will be needed both for management
of the storage site and to verify the amount of CO2
stored. Techniques such as seismic surveys have been demonstrated
to observe CO2 undergroundthese may form the
basis for monitoring such reservoirs, perhaps identifying whether
any leakage is occurring. Monitoring for leakage is important
for two separate reasonsto ensure that there is no threat
to health or the environment around the storage site, and to ensure
that CO2 does not leak to the atmosphere and thereby
negate the purpose of the injection. This latter objective seems,
potentially, to be a very demanding task, requiring sensitivity
of detection well below natural background levels (onshore).
11. Many alternative storage methods have
been proposedfor example, using the CO2 to make
chemicals or other products, fixing it in mineral carbonates for
storage in a solid form, storing it as solid CO2 ("dry
ice"), as CO2 hydrate, or as solid carbon. None
of these are competitive with storage in geological formations
if this can be done safely and securely.
Timescales for producing market-ready, scalable
12. Even without radical technical breakthroughs
it can be anticipated with some confidence that the efficiency
of power plant with capture will improve over time, as a consequence
of improvements in all of the components, such as turbines and
gasifiers. A view on this can be gained from looking at the progression
in results of a number of studies undertaken by the IEA Greenhouse
Gas R&D Programmethese are shown in Figure 1; trend
lines have been added to make it easier to distinguish the different
types of plant. The most recent of these studies looks forward
to the year 2020. Figure 1 shows the efficiencies of power plant
with capture for the three main types considered: coal-fired pulverised
fuel (PF) with flue gas desulphurisation (FGD), coal-using integrated
gasification combined cycle (IGCC) and natural gas combined cycle
(NGCC). It can be seen that there is expectation of ongoing improvement
in the efficiency of power plant with capture. Such improvements
will lead to cost reductions as will be discussed below.
Figure 1Efficiency of plant with capture
as assessed for the IEA Greenhouse Gas R&D Programme at various
dates plus one study looking forward to 2020trend lines
have been added to make this easier to read; they do not necessarily
imply progression with time.
13. Given that CCS is based on available
technologies, a good indication of the time needed for producing
market-ready technologies is provided by current commercial activities,
for example BP and Scottish & Southern Electric's recent announcement
that they are evaluating a joint project which would involve CO2
capture with a new combined cycle power plant. They are expected
to make a decision on whether to proceed with this project in
2006. From this it is inferred that the timescale for producing
power plant with CO2 capture is in the range 0 to five
years. It may be noted that Norway gave serious consideration
to building such a power plant in 1998. The timescale for finding
and evaluating suitable CO2 storage facilities may
be somewhat longer than this depending on the geological formation.
In the BP/SSE case, storage would be in an existing oil/gas field
so this may also be available in 0 to five year timescale. Storage
in deep saline formations would probably require longer time for
development because of the need for more onsite investigations
but, even so, would probably be in the five to 10 year timeframe,
as has been the case with recent Norwegian projects.
14. Non-technical factors, such as how the
project is to be paid for, will likely be an important influence
on the timeframe to application for this technology.
The Cost of CCS as a mitigation option
15. As with most mitigation technologies,
use of CCS will impose a cost on operators of the plant so a prime
motivation for R&D is to reduce the cost.
16. The cost of CCS is typically built up
from three separate componentsthe cost of capture (including
compression), the cost of transportation and the cost of storage
(including cost of monitoring and, if necessary, remediation of
any leakage). Any income from EOR (if applicable) would help to
offset part of the extra cost of CCS. The cost of CCS is typically
expressed as a "levelized cost" in keeping with the
approach used in the electricity industry for evaluating the cost
of new plant. Alternative methods are found in the literature
on mitigation options and care should be taken in making comparisons
between cost figures from different sources unless it is clear
that similar assumptions and similar methods have been used in
all cases. Capture (and compression) is typically the major component
of system cost.
17. It is important to establish a convention
for expressing cost since this is something which frequently causes
confusion. This will be done below followed by an overview of
some recent studies on the cost of CCS. Finally some remarks are
made about comparison with the cost of other mitigation options.
Convention for expressing cost
18. The cost data must take account of the
additional energy (and emissions) resulting from capturing the
CO2. The emissions from such a plant are illustrated
in Figure 2 which shows how the emissions from a plant with capture
are less than those of the plant without capture but not by as
much as the amount of CO2 captured. This is because
extra energy is used for capturing and compressing the CO2,
which generates extra CO2 (assuming both plants are
sized to deliver the same amount of electricity to the grid).
The amount of CO2 emissions avoided is a key measure
of the effectiveness of the plant.
Figure 2CO2 generated in
power plant with and without capture (having similar electricity
output). Red bars show the emissions from the plant; the yellow
bar shows the CO2 captured which is more than the amount
of CO2 avoided as indicated.
19. This can be taken into account in expressing
the cost of the plant by using as a measure of levelized cost
the cost per tonne of CO2-avoided. For completeness
this will take account of the costs and energy use of the transportation
and storage parts of the system as well as the capture part.
20. However, as a means of comparing mitigation
options, £/tCO2-avoided can be confusing since
the answer depends on the basecase chosen for the comparison (ie
what is being avoided). An easy convention to adopt for calculations
is to compare the plant with capture against the same type of
plant without capture. However this can have the effect of making
some options look unjustifiably favourable. A better approach,
one which provides a more accurate comparison with other ways
of supplying a similar service (eg electricity), is to present
costs in terms of a unit of product, eg £/MWh, coupled with
the CO2 emissions per unit of electricity generated
(eg in tCO2/MWh). The principles of this are illustrated
in Figure 3 which shows costs and emissions for PF (with FGD),
IGCC and NGCC plant with and without capture. The cost per tCO2-avoided
is represented by the gradient of the line linking any two points.
For comparison, Figure 4 shows what happens if IGCC is compared
not with a similar plant but with the least cost coal-basecase
(in this case a PF plant), with quite different result (54 v 37
$/t in this case). This method of presentation provides a warning
about how confusion can occur about the lowest cost method of
avoiding emissions. This should be borne in mind when reading
the literature on this technology. However, the following information
on cost of capture is presented on the basis of comparison with
similar basecase plant for ease of calculation and presentation.
Figure 3The cost per tonne of CO2
avoided is represented by the gradient of the line linking any
2 points on a graph of electricity cost versus CO2
emissions. In this case, each plant with capture is compared with
a similar plant without capture.
Figure 4This is similar to Figure 3 but
in this case the IGCC with capture is compared with the least
cost coal-fired plant without capture, which in this example is
a PF plant. This shows the cost per tonne of CO2
avoided is significantly higher than if the IGCC had been compared
with an IGCC without capture as in Figure 3.
Danger of confusing two measures of cost because
they use similar units
21. Expressing the cost of mitigation in
terms of £/tCO2-avoided is also the approach used
by energy modellers when considering mitigation options for, say,
a national electricity system. This is typically found in integrated
assessment modelling done for policy-related purposes. The costs
calculated in this way should not be compared with the cost of
CO2-avoided calculated for a particular design of CCS
power plant as described above because the base-case will not
be the same. However, because the term "avoided" is
used in both cases, there can be misunderstanding by the reader,
if a clear distinction is not made.
Potential for reduction in cost
22. Most of the published studies of specific
projects consider particular CO2 sources and particular
storage reservoirs. Necessarily these use costs appropriate to
particular plant, so currently the quantities of CO2
involved are typically only a few million tonnes per year. Although
these are realistic quantities for the first such projects, they
fail to reflect the potential economies of scale which are likely
to be found if/when this technology is widely used for mitigation
of climate change. Under those circumstances, much greater quantities
of CO2 would have to be captured, transported and stored,
with commensurate reduction in cost.
23. It can be expected that, over a period
of several decades, there would be reductions in costs as a result
of both economies of scale and increased experience in the manufacture
and operation of most stages of the CCS system. Using the studies
referred to in Figure 1 (converted to £ at $1.5/£) the
trend in additional cost due to capture is shown in Figure 5.
These extra costs are calculated by comparing similar types of
plant with and without capture. It should be noted that these
costs do not include the cost of transmitting or storing CO2it
is anticipated that the cost of transporting CO2 over
250km in quantities of 10 Mt/y would be about £2/t offshore.
The cost of injection for storage is estimated up to about £5/t
CO2 although this is site specific. In large quantities,
monitoring storage should cost less than £1/t CO2
stored over the life of a project.
Figure 5Reduction in additional cost of
capturing CO2 in studies carried out by the IEA
Greenhouse Gas R&D Programme over a number of years. IGCC
is omitted for sake of clarity, because the data points are very
close to the PF+FGD points.
Comparison with other mitigation options
24. Given what has been said above, it will
not be surprising that caution is recommended in comparing the
cost of CCS with that of other mitigation options. The safest
comparison to make would be with other supply-side measures, such
as alternative energy schemes. A general conclusion from doing
this is that CCS offers potential for deep reductions in emissions
from individual plant (ie 70% emission reduction or better) at
a cost which is comparable with other mitigation options which
can be deployed on a large scale.
25. CCS cannot "solve" the problem
of greenhouse gas emissions by itselfit must be expected
that a variety of measures will be used together. However, if
as seems likely, CCS is cost competitive with other measures then
it can be expected to have a part to play in mitigation of climate
26. The UK is fortunate in having access
to a variety of geological formations which should be suitable
as CO2 stores. The most appropriate are probably the
depleted gas fields in the Southern North Sea, especially those
which have not flooded after extraction of the gas (these would
be similar to the Dutch ORC project). Use of one of more of these
(providing it were allowed under OSPAR) would be a useful learning
and demonstration exercise for UK activity in this field. Depleted
oil fields would also be of interest but, more likely, the commercial
interest in respect of these fields will be in using CO2
for enhanced oil recovery. The UK also has deep saline formations
around the coast but further work will be necessary to explore
these and properly map them before storage could be undertaken.
The UK is also fortunate in having a number of small onshore depleted
oil fields which might be appropriate sites for small scale test
injections. Although the UK has a great deal of coal, much of
which can now be regarded as unminable, this is unlikely to be
useful for CO2 storage since it is of low permeabilityhydraulic
fracturing is unlikely to change this conclusion.
27. It is likely that at least some of these
formations will be viable for use in CO2 storagea
more serious question arises about the need for and means of verification
of the stored CO2. Will it be sufficient just to monitor
the injection of the CO2 or will it be necessary to
verify the amount in store at some later time? The injection of
CO2 into a deep saline formation will initially produce
(as shown at Sleipner) a distinct CO2 bubble which
can be observed using seismic analysis, especially if observation
wells are sunk into the formation. These results can be compared
with models which would provide the basic means of verifying the
ongoing presence of CO2 underground. Something similar
should be possible with depleted gas fields although the Dutch
decided that, with ORC, a small injection would be needed first
as a test of the concept before full-scale injection takes place,
because the behaviour of the reservoir could not be predicted
on the basis of theory alone. In the case of oil fields where
some of the CO2 may dissolve in the oil, especially
carbonate formations in which there may be geochemical interactions,
the situation is more complex and it is not clear whether the
presence of CO2 can be verified in these formations
with sufficient accuracy over the long term. This is particularly
likely to be the case with enhanced oil recovery where the verification
of CO2 in the produced and re-injected fluids, and
the CO2 dissolved in oil and water in the formation
and in the form of free gas makes monitoring very complicated
and verification difficult. Trying to do this onshore is difficult
enough (as shown in the West Pearl Queen and Weyburn cases), so
attempting it offshore seems likely to be especially difficult.
Other obstacles or constraints
28. Other significant obstacles are encapsulated
in the questions: is it legal, and how can it be paid for? The
legality of offshore CO2 storage will be determined
by the OSPAR conventionthere are moves underway in this
convention to consider what should be done in respect of CCS.
On the commercial side, there are questions about who will own
the storage facility and whether the European Trading System can
become a means of paying for the investment in such plant.
THE UK GOVERNMENT'S
FUNDING CCS R&D AND
INDUSTRIAL R&D IN
29. In respect of funding for CCS R&D,
the following proposals arise from identification of current gaps.
Other topics may be promoted by those with vested interest in
them but, if they are peripheral to development of CCS, they will
not contribute to successful development of CCS technologiessome
of these are noted below.
30. The most important gap is adequate demonstration
of the safety and security of large scale storage in order to
build confidence in storage of CO2 (given there are
very few large scale monitored storage projects anywhere in the
world and none in the UK at present). This means that R&D
should be directed at effective monitoring and verification tools,
especially for complex reservoirs such as those involving EOR.
The Government should support the development of legal and trading
regimes conducive to CCS, which also speaks to a need for more
work on monitoring and verification.
31. If there were a possibility of radical
reduction in cost and/or improvement in efficiency of CCS systems,
there would be a case for funding appropriate R&D but, given
what has been said above and in view of the maturity of this technology,
finding worthwhile opportunities will be very challenging. Evidence
should be demanded of the feasibility of attaining radical reduction
in cost before any government funding for such R&D should
32. As noted above, there are also areas
which it is not worth supporting with government funds, especially
incremental work in support of existing capture technologies which
should be undertaken by the manufacturers and/or users. It may
be suggested that improvement in power plant efficiency per
se would be worthwhile as an aid to CCS technology but this
should not be accepted as sufficient reason for funding this as
a CCS projectthere are several examples available which
show that improving energy efficiency by itself can be a dead-end
when it comes to developing the most competitive plant incorporating
CO2 capture. (This may seem illogical but arises from
the fact that the plant we build today is optimised for cost and
emissions under current regulations; if we were to build a plant
with CO2 capture, the optimum plant may well have different
features (aside from the capture aspects) from the optimum plant
built without capture).
33. Another area not appropriate for government
funding is storage in unminable coal since UK coal tends to be
too impermeable. Also, use of CO2 to make things (eg
building materials) is not clearly worthwhilea full systems
analysis typically shows that as much CO2 is released
by using CO2 as a feedstock as is stored in the product;
in that case, funding of R&D would not be justified.
34. Finally, a point about possible incentives.
Bearing in mind the large scale that would be necessary for significant
application of this technology (eg the first commercial scale
project was 1Mt/y) a key component of CCS systems is the transport
infrastructure. The cost of pipelines for single capture/storage
projects will tend to distort the cost (this was a major obstacle
against a project proceeding in Norway some years ago). To avoid
this it will probably be necessary to transport 10Mt/y or more
(depending on distance), which may be more than one individual
project could justify. There is an important role here for government
in providing incentives for establishing a CO2 infrastructure
(cf national transmission systems for electricity and gas). The
common good makes a commanding logic to establishing such infrastructure
by use of government support, more so than subsidising an individual
plant or storage project.