Select Committee on Science and Technology Written Evidence


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 activity—these 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.


Current state of R&D and deployment of CCS technologies

  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 volume—in 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 oil—it 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 Sea—this began operation in 1996. Other commercial projects announced include Sønvhit (Norway) and Gorgon (Australia); aquifers are good locations for research on storage—current 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 fuel—the 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 underground—these may form the basis for monitoring such reservoirs, perhaps identifying whether any leakage is occurring. Monitoring for leakage is important for two separate reasons—to 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 proposed—for 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 technologies

  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 Programme—these 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 1—Efficiency of plant with capture as assessed for the IEA Greenhouse Gas R&D Programme at various dates plus one study looking forward to 2020—trend 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 components—the 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 2—CO2 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 3—The 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 4—This 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 CO2—it 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 5—Reduction 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 itself—it 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 change.

Geophysical feasibility

  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 permeability—hydraulic 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 storage—a 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 convention—there 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.


  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 technologies—some 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 be offered.

  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 project—there 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 worthwhile—a 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.

September 2005

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