Annex C. Capture and storage of CO₂ from large industrial

1. INTRODUCTION

   Power generation is the world's single largest source of anthropogenic CO₂¹ emissions. A characteristic of much power generation is that the flue gas streams are large and relatively few in number, a feature shared with other energy-intensive industries, such as cement production, oil refining, chemicals and metals production. This paper discusses the capture and subsequent storage of CO₂ from the flue gases of such large, stationary sources.

2. DESCRIPTION OF THE OVERALL PROCESS

   The main steps in the process of capture and storage or utilisation of CO₂ from flue gases are shown in the figure below.

After the fossil fuel has been burnt to produce power, the CO₂ is separated from the flue gas stream, and stored for a long time, if it cannot be put to some useful purpose.

2.1 Capture of CO₂

The technology of CO₂ capture is in use today to supply the food industry and for treatment of natural gas. CO₂ separation technologies include:

• Absorption (both chemical and physical solvent)
• Adsorption (pressure swing and temperature swing)
• Membranes
• Cryogenics

Techniques using solvent absorption techniques (for example, using a solvent such as monoethanolamine, MEA), have been commercially available for many years. These, and pressure swing adsorption are suited to low/medium concentrations of CO₂ as found in conventional power plant, and are already in use at a scale approaching that required for such plant.

Cryogenics are also an established technology, but are best suited to high concentrations of CO₂, which are not found in conventional power plant flue gas streams. Membranes are being actively investigated, and solvent assisted membranes have been identified as a technique with attractive potential.

The main obstacle to application of the available techniques is the cost of separation and solvent regeneration. Development of current techniques and search for novel alternatives are both warranted.

2.2 Novel Approaches for CO₂ Removal

The dilute concentration of CO₂ in the flue gas streams of conventional combustion plant makes separation equipment bulky and expensive, but size and cost could be reduced if the fuel is decarbonised before it is burnt. In such a system, the fossil fuel would be used to produce an intermediate, hydrogen-rich gas which would then be burnt to produce electricity. There are various ways in which the hydrogen could be produced, including solvent removal of CO₂ under pressure. Integration of hydrogen production, power generation and CO₂ removal would help to minimise energy consumption, and could offer savings in the cost of capture.

This precombustion decarbonisation concept² is still relatively novel and there seems substantial scope for further improvement. Some development, e.g. of gas turbines to burn hydrogen-rich mixtures, may also be required.

2.3 Storage of CO₂

To mitigate climate change, sequestration of CO₂ must be able to keep the gas out of the atmosphere for hundreds of years. Alternatively, captured CO₂ might be put to use but finding uses which also help mitigate climate change is more difficult than it might seem.

In view of the quantities of CO₂ produced, storage would need access to very large capacity reservoirs such as are available, for example, in disused oil or gas fields, deep saline reservoirs, or the deep ocean. Disused oil and gas fields have the attraction that the geology has been well studied and, in principle, a geological seal is known to exist, which will ensure long term storage. Deep saline reservoirs are found in many parts of the world; they are not used for any other purpose. There are many ideas for ocean storage of CO₂ but there are also substantial obstacles to it uses. Artificial stores for CO₂ are conceivable but would be very expensive.

The first facility for storage of CO₂ as a means of mitigating climate change, began operation in 1996 in the Norwegian sector of the North Sea. It is storing 1 million tonnes of CO₂/year in a deep saline reservoir under the North Sea. The CO₂ is extracted from a natural gas stream produced from the Sleipner West gas field (the gas contains about 10% CO₂, most of which must be removed before sale). The field's operator, Statoil, have installed an MEA plant to separate CO₂ from the natural gas. The CO₂ is then pressurised and injected into the Utsira formation, 800 m below the sea-bed. An international monitoring and research programme for this storage facility has been established.

Storage in the deep ocean would involve pumping CO₂ to a depth of 1500m or more (where it might be dispersed or induced to form a sinking plume) or injecting it as a liquid at 3000 m depth, where it would be deposited on the sea-bed. Research is needed to clarify likely performance and environmental impact, and the legal basis for such operations has yet to be established; these issues have been explored in a series of international expert workshops³ , which identified priority areas for research.

2.4 Utilisation of CO₂

Uses which have been proposed for CO₂ include:

• production of chemicals
• direct biofixation through growth of biomass/algae for fuel
• enhancing oil recovery (EOR)⁴
• enhancing the production of coal bed methane (ECBM)⁵ .

Production of chemicals is not attractive as a mitigation option because of the additional (energy related) CO₂ emissions arising from the production process itself, and because of the limited quantities of CO₂ required for production purposes. Direct biofixation of CO₂ is still very much in the research phase. Use of CO₂ for EOR or ECBM is more attractive. In EOR some of the CO₂ is left behind in the oil reservoir; in enhanced coal-bed methane production, much of the CO₂ should be sequestered in the coal-seam (as long as this is not subsequently mined). EOR, mainly using natural supplies of CO₂ is an established oil industry practice, and the first EOR project with a specific sequestration aim, i.e. using captured CO₂ is due to start operation in Canada in the year 2000. ECBM production has been demonstrated using natural CO₂ and further work is underway in Canada to demonstrate its potential for CO₂ sequestration.

3. INTERNATIONAL ACTIVITY

   Japan is the leading country in terms of research and development of CO₂ capture and storage/utilisation technology. There are also significant efforts in USA, Norway, Canada, and the Netherlands.

   3.1 Japan

   Japan has substantial amounts of work on CO₂ capture, on some forms of CO₂ storage and on chemical and biological utilisation technologies. This started as part of the Japanese government's New Earth 21 initiative, introduced in 1989, and involving industry, universities and research institutes. The electricity utilities mainly aim to gather information on longer-term options: Kansai Electric Power Company and Tokyo Electric Power Company were amongst the pioneers in this field in 1990; others joined them in collaborative work from 1994. The Central Research Institute of the Electric Power Industry and the Electric Power Development Company also have substantial programmes on this topic. Major engineering firms active in this field include Mitsubishi Heavy Industries (MHI), Chiyoda, JGC, Hitachi, and Ishikawajima-Harima Heavy Industry. MHI have installed an MEA plant at a Sumitomo factory for removing 150 tonne/day of CO₂.

   Current work at the Research Institute of Innovative Technology for the Earth (RITE) on CO₂ capture includes a pilot plant producing methanol from CO₂, development of a process for removal of CO₂ from flue gases by use of hollow fibre membranes, biological fixation and utilisation of CO₂, and ocean storage of CO₂ (part of the national programme on this subject). Other institutes working on this subject include the National Institute of Materials and Chemical Research, the National Institute for Resources and Environment, the Tokyo Institute of Technology, the University of Tokyo, and the Mechanical Engineering Laboratory of the Agency for Industrial Science and Technology, which is working on hydrogen energy systems and sequestration of CO₂ in the ocean, as well as other energy technology.

   3.2 USA

   Several US companies market proprietary CO₂ separation technology, such as ABB Lummus and Fluor Daniel. A number of full-scale plants with CO₂ separation are operating, mainly to provide CO₂ to the soft drinks industry, but a joint US/Canadian project was announced in 1997, which will sequester CO₂ from a coal gasification plant - this should be in operation in the year 2000. Until recently, research work was limited to small programmes at the Federal Energy Technology centre, MIT, Argonne National Lab., University of Hawaii and Los Alamos National Lab., and EPRI. In 1997 DOE challenged the technical community to develop breakthrough concepts for sequestering or recycling greenhouse gases. 12 projects were selected for initial funding of US$ 50 000 each to conduct technical and economic assessments; later funding could reach as much as $1.5 million each. An international project to investigate injection of CO₂ into the ocean is located in Hawaii and plans an initial, experimental injection in 2000.

   In the past year, there have been a number of reports produced for the Department of Energy to develop the research agenda on carbon sequestration. These are likely to result in substantially increased federal funding. Tenders have already been requested to support a centre on CO₂ technology costing tens of millions of $ per year, so it is likely that US activity will rise to a level similar to that of Japan in the foreseeable future.

   3.3 Norway

   The oil and gas industry in Norway, especially Statoil, has been the leader in application of this technology - Statoil commissioned the Sleipner storage project (see above) and is working on other developments of this technology. Norsk Hydro announced plans in 1998 to build a novel power generation system with 1400MW_e capacity onshore, with CO₂ being removed and piped offshore for sequestration as part of an EOR project. At present this project is on hold because of low oil prices. Kvaerner is developing solvent assisted membranes - a technology identified as having great promise for reducing costs of CO₂ separation. Kvaerner also operates a pilot plant test facility for CO₂ separation, located at Statoil's Karsto gas terminal. The national Klimatek programme supports development of novel technologies for reducing emissions from fossil fuels, including a number of capture and storage technologies. It has an annual budget of c. £2million. Leading experts in the field are in institutes associated with the universities of Trondheim and Bergen.

   3.4 Canada

   The Canadian government's energy technology centre (CANMET) has a number of major projects on CO₂ emission abatement, including a large-scale test rig for O₂/CO₂ combustion, which is potentially a method of improving the conditions for CO₂ separation. A proposal for a North American CO₂-capture test facility has just been announced in Saskatchewan. The process systems laboratory at the University of Regina has a major programme on characterisation and improvement of solvents for CO₂ separation. Alberta Research Council has leading experts on geological storage of CO₂, and is hosting the first international trial of ECBM/CO₂ sequestration. The Institute of Ocean Sciences and the University of Victoria in British Columbia have leading experts on ocean storage and ocean fertilisation. Provincial governments and utilities are also active in this field.

3.5 The Netherlands

There are a number of leading research groups in capture and storage in the Netherlands, including TNO, ECN, the University of Utrecht and the Technical University of Delft, with many years experience in these fields. Major engineering consultancies have also been working on these technologies for some years. In 1993-5, surveys of public opinion indicated a preference for future electricity supply from various sources, including some using capture and storage of CO₂. In 1997, a proposal was made for a major application of deep saline reservoir storage. There is continuing interest in production of hydrogen from natural gas with sequestration of CO₂. Power plant flue gases are being used as a source of CO₂ for greenhouse houses, in place of dedicated combustion of fossil fuels.

3.6 UK experience

The main areas of work and expertise in the UK are:

The University of Ulster at Coleraine has taken part in a number of studies on power generation options with capture and storage of CO₂; more recently universities such as Cambridge (Applied thermodynamics) and University College London (Chemical engineering) are beginning work in this area. Work on biological fixation of CO₂ has been carried out at Kings College, London for many years.

The British Geological Survey played a leading role in the European study on storage of CO₂ in aquifers⁶ . The Southampton Oceanographic Centre has, for some time, been promoting the need for work on ocean storage of CO₂.

UK has contributed to the IEA Greenhouse Gas Programme since its inception. The operating agency for this Programme, which was established in the UK in 1991, is one of the leading centre of expertise on this technology.

Industry has been involved as contractor on studies - for example, some years ago the then Department of Energy commissioned Air Products to study capture of CO₂ from Didcot power station; Mitsui Babcock and Air Products have participated in a European project on novel combustion systems with CO₂ removal.

Industry is also involved in learning about these options - for example National Power and Powergen have contributed part of the UK funding to the IEA Greenhouse Gas Programme since its inception, and have recently been joined in this by Eastern. BP Amoco is a sponsor of the IEA Greenhouse Gas Programme and has been actively assessing capture and storage options for use with existing and future projects; BP Amoco is expected to announce a major project using this technology later this year.

4. POTENTIAL SCALE FOR USE OF CAPTURE AND STORAGE

   As indicated above, capture technology is already in use in plant similar in size to power plant. Thus capture can be considered, potentially, to have wide applicability.

   4.1 Global capacity

   Estimates suggest that storage capacity sufficient for many years of emissions is also potentially available (Table 1). For comparison annual global emissions from fossil fuel combustion are currently about 6 Gt C/y.

   More recent estimates⁷ suggest the European capacity alone for storage in geological reservoirs could be as much as 220 GtC, which is equivalent to 200 years of emissions at the current European level. Most of this is in deep saline reservoirs, with only about 4% in oil and gas fields. The UK capacity is estimated at 66 GtC in deep saline reservoirs (equivalent to 400 times current annual UK emissions of CO₂), and 9 GtC in disused oil and gas fields.

   Global estimates for utilisation of CO₂ are given in Table 2. The extent to which these contribute to mitigation of climate change will depend on whether these displace other uses of fossil fuel, and the extent to which the CO₂ is sequestered.

4.2 UK capacity

It is likely that the opportunities for capture and storage in the UK will be of a similar type to those available to the Netherlands and Norway. The main fuel for power generation in the UK is natural gas, so application of natural-gas fired power plant technology, such as that proposed by Norsk Hydro (see above), would also be possible in the UK. Construction of new coal-fired power plant, especially IGCC, could be adapted to incorporate capture of CO₂. Storage of CO₂ in deep saline reservoirs would be likely to be the preferred option, although enhanced oil recovery would be considered and use of disused oil or gas reservoirs would also be possible. Capture of CO₂ from selected streams in oil refineries, chemical plant and other energy-intensive industrial users may be no more expensive than from power generation.

The UK has relatively unique opportunities for developing and demonstrating storage technology and, in view of the increasing international interest in this subject, there would be scope for a collaborative approach to such projects. UK-based expertise on power generation and chemical engineering would also be well placed to contribute to advancing the effectiveness of these technologies.

5. ENVIRONMENTAL SIDE-EFFECTS AND RISKS

   5.1 Capture

   Solvents gradually degrade in use and so there needs to be suitable procedures for destruction/disposal. There may also be some solvent carry-over in the flue gas stream. cost considerations mean that both solvent degradation and carry over would be likely to be minimised.

   5.2 Geological storage

   Geological storage of CO₂ should not have major environmental side effects and risks. Careful siting should minimise the risk of leaking from pipelines and underground reservoirs, particularly sudden large leaks resulting from seismic activity or fractures, which may be of public concern. Oil and gas fields have remained secure for millions of years so, as long as the extraction of oil or gas and the injection CO₂ does not fracture the reservoir cap, injected CO₂ should remain underground for a similar length of time. Deep saline reservoirs are not intrinsically secure stores and some of the CO₂ may slowly leak out to the atmosphere (on a timescale of the order 1000 years⁸ ), and monitoring to detect any such leaks will be necessary. Some of the CO₂ injected into underground reservoirs is expected to react with underground minerals, resulting in essentially permanent sequestration. The aquifers used for CO₂ storage are likely to contain saline water that is unsuitable for extraction and use, so aquifer contamination should not be a concern.

   5.3 Ocean storage

   CO₂ can be stored in the ocean by dispersing at mid-depths (1500m or deeper) or by forming a lake of liquid CO₂ on the seabed at depths of more than 3000m. For mid-depth dispersion, the increase in dissolved CO₂ in the sea water is unlikely to have a large effect on marine life, but the resultant changes in the pH could be large, and marine life may be sensitive to this. The impacts on marine life near the point of (mid-depth) injection can be minimised by design of the injection equipment and by moving the injection point, for example by using a moving ship with a vertical injection pipe.

   In the case of seabed storage, the environmental impacts will be concentrated on a very small fraction of the global seabed, but will be severe. More research is required to investigate the effects of increased oceanic CO₂ concentrations on marine life. In particular, this will need to consider the effects on deep ocean species, including those on and beneath the sea floor (benthic species), and the possible sub-lethal impacts that could occur over long periods of time.

   A series of meetings on ocean storage of CO₂, involving a wide range of stakeholders, including scientists, environmental non-governmental organisations, industry, government agencies and legal experts, are being organise, for example, by the IEA Greenhouse Gas Programme and should identify areas of environmental concern and encourage dialogue on the way forward for research.

6. OTHER BENEFITS

   One of the key benefits of capture and storage of CO₂ is that it would allow continued use of fossil fuels in a climate-friendly way. As a result, society would have more choice over the rate at which it wishes to switch to other sources of energy. This could be important for some major developing countries, such as India and China , which are heavily dependent on use of local fossil fuel reserves.

   A further environmental benefit of capture technologies is that emissions of other pollutants , such as SO_x, NO_x and particulates are also reduced.

7. ECONOMICS

   The cost estimates discussed below are drawn from the IEA Greenhouse Gas Programme which assessed all capture and storage options using a standard set of assumptions and conditions. They were based on a power plant supplying 500 MW of electricity to the grid and assume:

   • 85% of CO₂ is removed
   • CO₂, once captured, is dried and pressurised to 90 bar for transport to the storage site and the cost⁹ of this is incorporated in the total
   • fuel costs are £1.8/GJ for gas and £1.2/GJ for coal and Orimulsion^®
   • levelized costs¹⁰ are calculated at a 5% and 10% discount rate

   Results are presented in terms of the amount of emissions avoided (rather than the amount removed) in comparison with a similar type of plant but without capture; this is expressed in terms of tonnes of carbon-avoided. The cost of storage is addressed separately.

   7.1 Natural gas power plant

   Table 3 shows the cost of CO₂ capture by solvent absorption for a natural gas fired combined cycle (NGCC) power plant. The CO₂ concentration in the flue gas is low (3.4%) making removal of CO₂ quite expensive. The figures in Table 3 may overestimate costs, as the evaluation was conducted some years ago, and the efficiency of such plant has subsequently increased and the costs fallen.

Analysis of the pre-combustion decarbonisation options (where a hydrogen rich fuel is produced from natural gas), suggests a slightly lower cost of avoided emissions, of between £60 and £80/tC-avoided. Although the reanylsis of the costs of capture from the fuel gas has not been completed, it is likely that the revised costs will be much closer to those for pre-combustion decarbonisation.

7.2 Coal

Table 4 shows avoided costs of emissions for coal plants, conventional pulverised coal (PF), oxygen-blown integrated gasification combined cycle (IGCC) and air-blown gasification combined cycle (ABGCC), using MEA or Selexol^® solvent absorption for CO₂ capture. The cost of avoiding a tonne of C-emissions is lower for a conventional (PF) coal fired plant than for gas fired combined cycle plant as the higher concentration of CO₂ (about 13%) in the flue gas means that the size and cost of CO₂ capture equipment is reduced. However, twice as much CO₂ has to be removed compared with the gas fired plant.

Although the IGCC type of plant is only now at commercial demonstration stage, this would appear to offer advantages over other coal-fired plant in terms of minimising the cost of removing CO₂, if a shift reaction stage is incorporated to optimise the conditions for CO₂ removal. However, it should be noted that turbines to burn a hydrogen-rich (>70%) fuel gas in the combined cycle part of this plant still require some development.

7.3 Transport and storage

In all of the cases shown, the cost of transport and storage of CO₂ should be low (Table 5), certainly much less than the cost of capture. The cost of pipeline transport is estimated to be £1.8/tC for 100km distance.

8. PRACTICALITY

   8.1 Capture

   Power plants are in operation today where CO₂ is captured; these are commercial ventures supplying CO₂ to third parties (rather than aiming to reduce emissions of greenhouse gases). Thus separation of CO₂ in power generation and other industrial processes is a practicable option for mitigation of climate change.

   For example, ABB Lummus has built a plant that recovers CO₂ from flue gas produced by a coal-fired cogeneration facility - 200 t/day of food-grade CO₂ is recovered¹¹ . Conventional chemical process equipment is used in this - distillation columns, heat exchangers, pumps, etc. Such chemical processing may be less familiar to electricity utilities than the conventional generating plant but this should not be a major barrier as many utilities now routinely use flue gas desulphurisation processes, which are broadly similar (if smaller in scale).

   Improved processes for coal-based power generation are under development; especially relevant in this respect is the Integrated Gasification Combined Cycle plant (IGCC)¹² where the cost of removing CO₂ would be quite low (see table 4). Capture of CO₂ is by amine or other solvent or, if the pressure is high enough, a physical solvent.

   For natural gas, similar technology could be applied to gas turbines and NGCC; the alternative approach, precombustion decarbonisation¹³ , involves either steam reforming or partial oxidation of natural gas to generate a synthesis gas (i.e. H₂/CO mixture). Similar processes are widely used in industry to produce hydrogen and other chemicals; isolation of CO₂ is an integral part of such processes. Many researchers suggest this technology can be adapted as a means of reducing emissions of CO₂ to atmosphere but there are technical issues to be resolved. In 1998, Norsk Hydro proposed to use such a plant to produce power in conjunction with capture of CO₂ for EOR. This project is understood to be in abeyance because of the reduction in the price of oil but further research and demonstration of this option is under consideration.

   In general, CO₂ capture equipment would be likely to be fitted to new plant but retrofit to existing plant might be considered for relatively new, high efficiency plant with a long remaining life.

   8.2 Transport of CO₂

   CO₂ is largely inert and easily handled once isolated. It is already widely used as a refrigerant e.g. in solid form as 'dry ice', and is transported in bulk pipelines in the USA¹⁴ . Transport by ship, although not done at present, would be similar to transport of liquefied petroleum gas (LPG), and would be preferred to pipelines for longer distances at sea. For efficient transport, CO₂ has to be compressed to a pressure at which it is a dense phase fluid and this incurs a significant energy penalty. However, it is typically cheaper to pipe CO₂ than transmit the equivalent amount of electricity, so any such power plant would be sited to meet electricity demand, with CO₂ piped over distances up to several hundred kilometres to the storage site.

   8.3 Storage

   Effective storage of captured CO₂ must be able to handle large quantities for hundreds of years (at least) in order to mitigate climate change. Underground storage can do this more reliably than most other types of sequestration.

   Injection of CO₂ into sub-surface strata is established technology as a means of enhancing oil recovery (EOR); significant quantities of CO₂ are retained in the structure. Existing EOR projects, active over several decades, offer an extensive set of data about long-term CO₂ injection into hydrocarbon fields. Such projects provide valuable insights into the physical processes relating to CO₂ injection, production, processing, recycling, and (indirectly) sequestration in a variety of reservoir settings, with verified data.

   Since 1996, Statoil have been injecting about 1 million tonnes of CO₂/yr into a deep saline formation about 800m beneath the bed of the North Sea. This is the first time CO₂ storage has been undertaken purely for climate reasons¹⁵ .

   In the case of deep ocean storage, the engineering of injection at depth of at least 1500 metres can be handled using available technology although there may be practical problems to solve such as dispersion of the CO₂ and potential formation of hydrates that might block or jam equipment.

   8.4 Energy Carriers for Distributed Energy Users

   The above examples indicate various ways in which CO₂ emissions from large, stationary plant can be reduced substantially. However, a substantial amount of fossil fuels are used in smaller heating appliances and, especially, in motor vehicles. It is not practicable to capture, collect, and store CO₂ from such sources, nevertheless, there is still a potential way of reducing CO₂ emissions from these dispersed sources This would be through use of a carbon-free energy carrier, such as hydrogen. Traditionally, hydrogen is considered as an energy carrier for renewable energy sources, but it is also possible to think of it being produced from fossil fuels, using capture and storage technology to avoid release of CO₂.

   Various schemes have been suggested in which an 'energy carrier' is produced by decarbonisation of fossil fuel at a central point before being distributed to the users. By using CO₂ capture and storage technology, this could minimise emissions of greenhouse gases whilst delivering carbon free energy carrier to dispersed users¹⁶ . Table 6 shows the cost of producing hydrogen from natural gas. Even with CO₂ storage, this would be considerably cheaper than producing it from electricity generated by hydro-power, although still be a relatively expensive way of delivering energy. Nevertheless, production of hydrogen from fossil fuels with CO₂ storage could be an attractive transitional strategy to aid the introduction of hydrogen as an energy carrier¹⁷ .

Table 6 Cost of producing hydrogen
Fuel	Hydrogen production	£/GJ (10% dcf)	£/GJ (5% dcf)
Natural gas (at £1.8/GJ)	without CO2 capture	3.4	3.1
	with capture and storage of CO2	4.2	3.7
Coal (at £1.2/GJ)	without CO2 capture	6.2	5.0
	with capture and storage of CO2	7.9	6.4
Hydro-power (2.2 p/kWh)	electrolyis of water	12.1	11.3

9. TIMESCALE

   Most of the technology required for CO₂ capture is already proven and could be applied as soon as needed. Development work is underway to reduce costs and energy losses and improve operability. Demonstration of CO₂ capture and storage in commercial-size power stations has already been considered - for example the power plant which Norsk Hydro proposed to build in Norway using pre-combustion decarbonisation of natural gas. A number of companies and governments are now planning commercial-scale EOR projects for purposes of sequestration, involving capture of CO₂ from flue gas streams.

   CO₂ storage is already being applied commercially in the Sleipner project in the North Sea. CO₂ is also being used for commercial EOR schemes - although current EOR schemes aim to limit the amount of CO₂ left in the ground for commercial reasons, this does serve to demonstrate the storage technique. Further work will build confidence in the technique but, from the technical viewpoint, CO₂ storage underground can be considered to be available for use now.

   Ocean storage of CO₂ will take longer to develop than underground storage. Much of the necessary technology, for example undersea pipelines and ships for transport, is already proven in the oil and gas industry, but long term research will be needed to resolve the uncertainties regarding environmental impacts¹⁸ .

   9.1 Capital stock replacement

   CO₂ capture equipment, such as amine scrubbing, could be retrofitted on a large scale to existing power stations within a few years, in the same way that flue gas desulphurisation has been applied in some countries. However, this would be a relatively expensive way of capturing CO₂ except for newer and higher efficiency plant. It would be more energy efficient and less costly to include CO₂ capture as an integral part of a new plant design. The time-scale for introduction of new power stations with CO₂ capture would depend on the lifetime of the existing stock. Power stations normally have long lifetimes, typically 25-40 years, so replacement of the existing stock may take many years. However, given the right market incentives and regulatory framework, recent experience shows that the existing stock can be replaced relatively quickly¹⁹ . The types of power stations built in the past, i.e. coal and nuclear, were relatively capital intensive, incurring relatively large penalty for premature replacement. Current NGCCs have much lower capital costs, so premature retirement would be less of a barrier to introduction of CO₂ capture technologies, particularly if the replacements could make use of the newer, more efficient gas turbines now being developed.

10. VERIFICATION

    In CO₂ capture, gas flows will be measured as a normal part of the chemical engineering of the process. Technology already exists to do this, and modifications are continually being made to reduce the cost and increase efficiency, so the additional costs and effects from the introduction of verification requirements are likely to be small.

    In the case of transport of CO₂, large quantities of CO₂ being transported across the USA are already monitored in real time, accurately, using equipment which is available now at low cost. Similar measurements could be used to monitor CO₂ injected into geological reservoirs. The necessary equipment is already built into most oil and gas facilities so the ease of verification and cost is expected to be minimal (Table 7). Flows of CO₂ and other gases underground are routinely measured by 2-D, 3-D and 4-D seismic monitoring for EOR and deep saline reservoir storage. It is estimated that it would cost about £0.06/tC to verify the amount of CO₂ stored in a deep saline reservoir using seismic techniques. Over time, reaction with reservoir rock may be more difficult to follow using remote sensing techniques. Nevertheless, in the main it is clear that most verification requirements for geologically-stored CO₂ can be achieved with technology available today.

Table 7 Some views on the cost of verifying long-term CO2 storage in various reservoirs
CO2 storage method	Available technology?	Ease of verification	Cost of verification
Deep saline reservoir	Yes	Straightforward	Low
Depleted oil and gas fields	Yes	Established practice	Low
Enhanced oil recovery	Yes	Established practice	Low - medium
Unminable coal seams	Partly	Moderate	Medium

10. NEXT STEPS

    The technology for capture and storage of CO₂ is available - the main problems with it are the cost of capture, and proof of the reliability of storage. This indicates areas of immediate priority for research, development, and demonstration (R,D & D), and some specific topics are outlined below. Many of these would potentially cover more than one application²⁰ .

    There are significant advantages in many cases if R&D is undertaken by international co-operation. The UK is well positioned compared to many countries in terms of R&D costs and has the advantage that English is the international language of science and technology. These opportunities also apply to potential demonstration projects where the need to focus limited resources and the high costs make international co-operation highly desirable.

    CO₂ capture can be done now but it is relatively expensive and inefficient. The near-term priority is to reduce the penalty of using CO₂ capture in power plant. There is scope for the development of improved solvents, starting at the laboratory scale and leading to demonstration. Investigation would also be justified of improved separation processes, such as membranes, improved heat recovery to compensate for losses introduced by CO₂ capture, and novel concepts, such as precombustion decarbonisation or a combined reactor/membrane separator. Development of gas turbines able to handle hydrogen-rich gases, and methods of combustion in stoichiometric mixtures with oxygen are also important targets.

    CO₂ storage is relatively inexpensive and research to reduce costs is not a high priority; the main requirement for research is to establish storage as an environmentally acceptable solution, and to demonstrate the security of storage in various applications. The UK is well placed to play a leading part in such projects.

    Work under European and US programmes has identified and quantified potential underground stores but there is considerable need for more information on potential storage sites. Refinement of techniques to monitor CO₂ in underground strata will take place as part of the Sleipner project and other programmes. Research to assess the long-term interaction of CO₂ with potential host rocks will be done in the laboratory. The environmental concerns that have been expressed about underground storage of CO₂ are largely to do with safety i.e. the possibility of it leaking to the surface either slowly or as a sudden large-scale emission. The possibility of such events has not been effectively refuted. Before land-based schemes could be adopted (the only existing scheme is under the North Sea), their safety and public acceptability needs to be established.

    Storage in the ocean is a longer-term proposition than underground storage. There are many questions to be answered before its acceptability and effectiveness is assured. Environmental concerns with respect to the impact of CO₂ on ocean life need to be assuaged. The legality of the storage scheme has to be established. The effectiveness of ocean storage depends on a retention time in the ocean of hundreds of years and models are required that can predict retention with a high degree of confidence.

11. CONCLUSIONS

    Substantial reductions in CO₂ emissions could be achieved whilst continuing to use fossil fuels by application of technology for capture and storage of CO₂. This could be applied to power stations and many energy-intensive industrial processes.

    Capture of CO₂ can be done using available technology, although there is scope for reducing costs and energy consumption. Storage of CO₂ is feasible in natural underground reservoirs, which have sufficient capacity for many years' emissions, although the possibility of long term leakage if aquifers are used needs investigation. Utilisation of CO₂ has some potential to contribute to mitigating climate change, mainly by enhancing oil or gas production, where the additional revenue helps offset some of the cost.

    The cost of capture is about £60/tC-avoided for coal fired plant and £120/tC-avoided for gas fired plant. Many aspects of CO₂ capture and storage can be verified accurately and at low cost, with available technology.

    There is considerable scope for new ideas to accelerate the development and introduction of capture and storage technology. In the longer term these technologies could allow the production of hydrogen from natural gas with minimal CO₂ emissions.

1. In 1997, power generation and industry each produced 26% of UK CO₂ emissions
2. "CO₂ capture by precombustion decarbonisation of natural gas" Audus H., Kaarstad O., Skinner G., in "Greenhouse Gas Control Technologies"; Elsevier Science Ltd., 1999.
3. "Ocean storage of CO₂" IEA Greenhouse Gas R&D Programme; Cheltenham, UK, 1999, ISBN 1 898373 25 6
4. "Capture of carbon dioxide from coal combustion and its utilisation for enhanced oil recovery" by Hattenbach, R.P., Wilson, M., Brown, K., in "Greenhouse Gas Control Technologies", Elsevier Science, 1999.
5. "Injection of CO₂ for enhanced energy recovery: Coalbed methane versus oil recovery" by Wong, S., Foy, C., Gunter, W. D., Jack, T., in "Greenhouse Gas Control Technologies" Elsevier Science Ltd., 1999
6. "The underground disposal of carbon dioxide" by Holloway, S., Heederik, J.P., van der Meer, L.G.H., Czernichowski-Lauriol, I., Harrison, R., Lindeberg, E., Summerfield, I.R., Rochelle, C., Schwarzkopf, T., Kaarstad, O., Berger, B., British Geological Survey, Keyworth, Nottingham, U.K., 1996
7. ibid
8. "The underground disposal of carbon dioxide" by Holloway, S., Heederik, J.P., van der Meer, L.G.H., Czernichowski-Lauriol, I., Harrison, R., Lindeberg, E., Summerfield, I.R., Rochelle, C., Schwarzkopf, T., Kaarstad, O., Berger, B., British Geological Survey, Keyworth, Nottingham, U.K., 1996
9. All costs were originally calculated in US $, and have been converted at a rate of $1=£0.6.
10. Levelized costing involves charging capital throughout the life of the project, to the time when the CO₂ is sequestered. The calculation procedure is analogous to net present value calculations although the numerical results must only be compared with other results from use of the same procedure.
11. "The Kerr-McGee /ABB Lummus Crest technology for recovery of CO₂ from stack gases" by Barchas R. & Davis R., Energy Convers. Mgmt., Vol. 33, No. 5-8, pp 333-340, 1992
12. Such cycles can also be operated with heavy oil feed
13. "CO₂ capture by precombustion decarbonisation of natural gas" Audus H., Kaarstad O., Skinner G., in "Greenhouse Gas Control Technologies"; Elsevier Science Ltd., 1999.
14. The Cortez pipeline (built to supply CO₂ for use in EOR) is 800km long and can handle 12 million tonnes CO₂ /yr.
15. "Sleipner Vest CO₂ disposal, CO₂ injection into a shallow underground aquifer" by Baklid A. & Korbøl R. SPE 36600, Society of Petroleum Engineers, Richardson, Texas, USA, 1996.
16. "Decarbonisation of fossil fuels: hydrogen as an energy carrier" by Audus H., Kaarstad O., Kowal, M. in the proceedings of the 11th World Hydrogen Energy Conference: "Hydrogen Energy Progress XI", pages 525-534, International Association for Hydrogen Energy; 1996.
17. "Hydrogen - today and tomorrow" IEA Greenhouse Gas R&D Programme, Cheltenham, UK, 1999, ISBN 1 898373 24 8.
18. "Ocean Storage of CO₂ - workshop 2: Environmental Impact". IEA Greenhouse Gas R&D Programme, 1996, ISBN 1 898373 13 2.
19. In the UK, coal-fired power stations have been largely replaced by natural-gas-fired combined-cycle gas turbines within the last 10 years; a similarly rapid replacement of fossil-fuel-fired power stations by nuclear power stations took place earlier in France.
20. For example, membrane separation has a range of potential applications, and enhanced recovery of methane from unminable coal seams can also deliver storage of CO₂.