CO 2 capture and storage from fossil fuels

Transcription

1 9.3 CO 2 capture and storage from fossil fuels Introduction One of the greenhouse gases arising from human activity is CO 2, which mainly comes from the combustion of fossil fuels. The rate of emission of CO 2 could be reduced in various ways, one of which would be to capture the CO 2 and store it away from the atmosphere for a very long period of time. This technique, CO 2 Capture and Storage (CCS), is a new application of an established technology. It has only been recognized in the past few years for its potential to address the global problem of climate change. This chapter describes the technology and key features of its potential role in reducing greenhouse gas emissions. Climate change There is now widespread acceptance of the changes taking place in the Earth s climate, which are believed to be due to emissions of greenhouse gases arising from human activities. The largest contributor among these gases is carbon dioxide, which is released by burning fossil fuels and biomass. Another factor is deforestation. The eventual consequences of climate change are not certain, although many mathematical models have been constructed to examine this very complex problem. Recognizing the potentially damaging consequences of unfettered climate change, the countries that signed the UN Framework Convention on Climate Change agreed its objective should be «stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system». However, there is no agreement on what level should be aimed at for stabilization, nor how much action is needed to reach this state. In many of the models, stabilization at a level of 550 ppmv of CO 2 -equivalent is often considered, which represents a doubling of CO 2 concentrations compared with pre-industrial times. It is estimated that achieving stabilization at this level would require a reduction in global emissions of 75-85%, compared with current rates, by the year Lower concentrations would require even greater reductions. Achieving such reductions cost-effectively will require the application of a wide range of measures. The technological options available for stabilizing CO 2 levels in the atmosphere include: a) reducing energy consumption by increasing the efficiency of energy conversion and/or utilization; b) switching to less carbon intensive fuels, for example natural gas instead of coal; c) increasing the use of renewable energy sources or nuclear energy, each of which emits little or no net CO 2 ; d) sequestering CO 2 by enhancing biological absorption capacity in forests and soils, or by capturing and storing CO 2, which is the subject of this section. Role of fossil fuels in energy supply At the start of the Twenty-first century, global energy consumption is continuing to rise as it did in the last decades of the Twentieth century. Fossil fuels currently provide 86% of the energy used worldwide (BP, 2003), accounting for about 75% of anthropogenic CO 2 emissions, with the remainder coming from non-energy sources such as deforestation. Current emissions of CO 2 from fossil fuel consumption are around 25 Gt CO 2 /yr. Among the fossil fuels, 45% of the energy produced globally comes from oil, 27% from natural gas, and 28% from coal. Average global carbon dioxide emissions grew at a rate of 1.4% per year between 1995 and 2001, a little above the rate VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 811

2 SUSTAINABILITY of growth in primary energy use (Watson et al., 2001). The 30 member countries of the Organisation for Economic Co-operation and Development (OECD) were responsible for 47% of energy-related CO 2 emissions in 2001, transition economies accounted for 14%, and developing countries 39% (EIA, 2003). Given the importance of fossil fuels in current energy supplies and the expectation that this will continue for the foreseeable future, and in view of the threats of climate change, methods of using fossil fuels without necessitating much emission of CO 2 are very pertinent to the continued, reliable delivery of energy. This control of emissions could be achieved by capturing and storing CO 2 from fossil fuel combustion. Capture and storage of CO 2 The main components of a CCS system for a power plant are shown in Fig. 1. In this case the source of CO 2 is the flue gas stream. A separation stage is used to capture CO 2, which is then compressed for transport to a storage site. In order to make a significant reduction to global emissions, the amount of CO 2 to be captured and stored would need to amount to several Gt CO 2 /yr worldwide. Each of the stages of the process is examined separately below; after that some of the broader issues are discussed Sources of CO 2 General Anthropogenic emissions of CO 2 come from various sectors of the global economy, as shown in Table 1. From this it can be seen that power generation is the single largest source of emissions. The emissions from this sector arise from large point sources, an aspect which is highly relevant to capturing CO 2 economically. All parts of the CCS system show distinct economies of scale: capture of fuel gas fossil fuel combustion N 2, H 2 O to atmosphere CO 2 separation CO 2 compression power generation Fig. 1. Principal components of a CO 2 capture and storage system. storage Table 1. Global CO 2 emissions in 2001 from fossil fuel combustion by sector (IEA, 2003) Sector CO 2 emissions (Mt/yr) Public electricity and heat production 8,236 Other producers of electricity 963 Other energy industries 1,228 Manufacturing industries and construction 4,294 Transport (of which: road) 5,656 (4,208) Other sectors (of which: residential) 3,307 (1,902) TOTAL 23,684 CO 2 costs less per tonne of CO 2 for a large plant (capturing millions of tonnes per year) than for a small one (capturing thousands of tonnes per year); large pipelines, transmitting several million tonnes per year, transmit each tonne of CO 2 for much less cost than smaller ones; the cost of storage is similarly affected by scale. CO 2 is also emitted by large point sources in the other energy industries sector (including oil refineries, manufacture of solid fuels, coal mining, oil and gas extraction, and other energy-producing industries) and in parts of the manufacturing and construction sector. However, the sector with the fastest growing emissions is transport. In contrast to power generation and heavy industry, transport emissions come from a multiplicity of small, distributed sources which would be uneconomic to capture. Another factor which is highly relevant is the concentration of the CO 2 in the gas stream. High concentrations of CO 2 are much easier to capture and purify than low concentrations. How this is done is discussed later, but the distinction between the concentrations available in different industrial sectors is important in understanding how capture could be employed. Some examples of the concentration of CO 2 in different types of plant are shown in Table 2. Power generation Fossil fuels provide the main source of energy for electricity generation in most countries, with a few notable exceptions where nuclear energy (e.g. 812 ENCYCLOPAEDIA OF HYDROCARBONS

3 CO 2 CAPTURE AND STORAGE FROM FOSSIL FUELS France) or hydro-power (e.g. Norway) is used. The fossil fuels may be coal, pulverized to facilitate combustion, or natural gas. Other fuels which may be used include residual oil, heavy oil, and waste materials. In a typical plant, combustion of the fuel raises steam, which is then expanded through turbines connected to a generator. In a modern gas-fired plant, combustion takes place in a gas turbine coupled to a generator and heat is recovered from the waste gases to drive a steam turbine which supplements the electricity generation. Emissions from such plants are about 750 g CO 2 /kwh for a coal plant and 380 g CO 2 /kwh for a natural gas plant. Although the CO 2 concentration in power plant exhaust gases is low, the importance of this sector, in terms of global emissions, puts it high on the list of sources to consider for CCS. Industry Industrial use of energy is as diverse as the industries involved. Energy-intensive industries, such as cement, iron and steel manufacture, and oil refining, may release as much CO 2 from a single site as a power plant releases. In these cases, the concentration of emissions can be Table 2. Indicative CO 2 concentrations in gas streams from particular units in various fossil fuel-using plants (Metz and Davidson, 2005) CO 2 concentration in exhaust gas stream (vol %) Electricity and heat production Pulverized coal fired power generation Coal fuelled IGCC 8-9 Natural gas combined cycle 3-4 Other energy industries Oil refinery/fired heater 8 Hydrogen production Manufacturing Ammonia 100 Iron and steel manufacture Cement kiln off-gas higher than that of a power plant, which would make capture easier. Thus, some energy-intensive industries could provide opportunities for easier capture of CO 2. Indeed, processes for producing hydrogen and ammonia already release CO 2 in concentrated streams, making these processes potentially attractive as early opportunities for capture of CO 2. Other industrial sources are smaller, which makes them less interesting; however, it is worth noting that natural gas processing (a current application of CO 2 separation equipment) already releases concentrated CO 2, so it may offer an early opportunity to supply CO 2 for storage. Other sources The other main sectors responsible for emissions of CO 2 are buildings and transport. The energy used in buildings is partially supplied as electricity, so opportunities for capture of CO 2 at the power plant are relevant to reducing emissions from this sector. However, much of the energy used in buildings is supplied by local combustion of fossil fuels, which produces relatively small quantities of CO 2 (e.g. on the order of 1 tonne CO 2 /yr from a house), which would be far too small to be captured economically. Transport is the most rapidly growing source of emissions globally. Each vehicle emits only 1 or 2 tonnes of CO 2 per year, which would be a very small amount to capture. In addition there is the problem of dealing with a moving source; on-board storage has been suggested as a way of dealing with this, but the volumes involved and the handling requirements make this infeasible. A possible future scenario: carbon-free energy carriers An alternative approach for both buildings and transport sources is to supply a carbon-free energy carrier, thereby avoiding the need to capture small quantities of CO 2. Such an energy carrier could be electricity or hydrogen. There may be problems with both of these concerning ease of use and cost of handling, as well as on-board storage. The vehicle drive train could be electric, and this might be true also for hydrogen vehicles if suitable fuel cells are developed as the source of motive power. Several manufacturers are also planning to offer internal combustion engine vehicles running on hydrogen, which have fewer technical hurdles to overcome. Whether electricity of hydrogen will be used as an energy carrier is not known at present; but, in either case, CCS could make an important contribution in their manufacture. VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 813

4 SUSTAINABILITY Methods of capturing CO 2 The combustion of fossil fuels in air produces a gas containing CO 2, N 2, water vapour, and small amounts of O 2 and other components. Table 3 shows examples for a power plant. The components other than CO 2 are not greenhouse gases, and so do not need to be kept out of the atmosphere. Some components, principally oxides of sulphur and nitrogen, and particulates, are already subject to control. The N 2 component represents a large proportion of the volume of the gas stream, which makes it uneconomic to store the whole gas stream as a way of protecting the climate. Thus, to capture CO 2 it is necessary to separate it from N 2. There are three broad types of system in which CO 2 could be removed from the process, and these are described below. Depending on the system used, capture may be in an oxidizing or a reducing atmosphere, which has a bearing on the separation process used. Separation can be done using processes developed for other applications. Separation processes will be described later, after the introduction to the three main types of capture system. By convention, in process evaluation, compression is considered with capture. Examples given here are based on applications to a fossil fuel fired power plant, although a similar approach could be used with fired heaters in refineries or with blast furnaces, etc. Three types of system The most easily recognized method of capturing CO 2 is to separate it post-combustion from a flue gas stream (see Fig. 1). Otherwise the problem of Table 3. Typical components of the exhaust gas streams from combustion of fossil fuels in modern power plants (expressed in molar percent). Small amounts of NO x, Hg and particulates may also be present Component Coal Natural Gas Ar 0.86% 0.89% O 2 3.2% 12.3% N % 74.5% H 2 O 10.1% 8.2% CO % 4.1% SO 2 0.1% 0% N 2 can avoided by preparing the fuel in a N 2 -free environment and separating the CO 2 at that stage: this is called pre-combustion capture. A third option is to avoid introducing nitrogen into the combustion system by using oxygen instead of air for combustion: this is sometimes called de-nitrogenation, but more frequently oxy-fuel combustion. Post-combustion capture Separating the CO 2 from the flue gas stream has been applied in (a few) power stations and other processes for several decades. A variety of separation techniques are available; the main one in use today for separating CO 2 from flue gases or other gas streams is scrubbing the gas stream using an amine solution. In many respects, post-combustion capture of CO 2 is analogous to Flue Gas Desulphurization (FGD), which is widely used in coal- and oil-fired power stations to reduce emissions of SO 2. In principle, post-combustion capture could be retro-fitted to existing plants, but in practice, the extra energy requirements of the process would render the plant uncompetitive unless it already was of high efficiency, so the main application foreseen is in purpose-designed power plants. The low concentration of CO 2 in flue gases (3-14%) means that a large volume of gas has to be handled, resulting in large and expensive equipment. A further disadvantage of the low CO 2 concentration is that powerful solvents have to be used to capture CO 2, and regeneration of these solvents, to release the CO 2, requires a large amount of energy. Pre-combustion capture An alternative way of increasing the CO 2 concentration is to prepare the fuel so that the carbon-containing component can be removed before combustion. This is, in fact, the original application for which CO 2 capture was developed more than 60 years ago, for use in production of town gas. Fuel gas can be prepared by reacting the fuel with oxygen and/or steam to make a synthesis gas consisting of mainly carbon monoxide and hydrogen. The carbon monoxide would then be reacted with steam in a catalytic shift converter to give CO 2 and more hydrogen. The CO 2 can then be separated and the hydrogen used as fuel for a gas turbine combined cycle power plant (or perhaps, in the future, for a fuel cell). The fuel gas is at elevated pressure (e.g. 15 to 40 bar) with a medium level of CO 2 content (15-40%); both of these features make 814 ENCYCLOPAEDIA OF HYDROCARBONS

5 CO 2 CAPTURE AND STORAGE FROM FOSSIL FUELS for easier CO 2 capture than in the post-combustion case. The process is, in principle, the same for coal, oil or natural gas; but in the case of coal and oil, gasification is used to prepare the fuel, whereas in the case of natural gas, reforming or partial oxidation is used. The extent of gas cleaning prior to capture differs between the three fuels. Fig. 2 is a simplified diagram of a coal-fired power plant with pre-combustion capture of CO 2. This is very similar to an Integrated Gasification Combined Cycle (IGCC) with the addition of a shift conversion stage (to convert CO to CO 2 ) followed by CO 2 separation and compression. Although pre-combustion capture involves a more radical change to the power station design, most of the technology is already proven in ammonia production and other industrial processes. One of the novel aspects is that the fuel gas would be essentially hydrogen. It is expected that it will eventually be possible to burn pure hydrogen in a gas turbine with little modification, but this is not commercially proven technology, although gas turbine manufacturers have developed turbines able to combust hydrogen-rich fuels of various compositions. Oxy-fuel combustion The concentration of CO 2 in the gas stream is a key factor in determining the cost of capture. The higher the concentration, the easier (and hence cheaper) it is to remove the CO 2. The concentration can be increased greatly by using oxygen instead of air for combustion, either in a boiler or gas turbine. If a fossil fuel is burned in pure oxygen, the flame coal oxygen slag gasifier air sulphur removal shift conversion H 2 rich fuel gas CO 2 capture gas turbine N 2, O 2, H 2 O to atmosphere Fig. 2. Schematic diagram of a coal-fuelled power plant with pre-combustion capture of CO 2 (IEA GHG, 2001). CO 2 to storage steam generator steam turbine temperature is very high, but if some flue gas is recycled to the combustor, the flame temperature can be brought down to a level similar to that in a conventional combustor. As the flue gas stream consists of mainly CO 2 and water (steam), the recycled gas can be either CO 2 -rich or H 2 O-rich. Both methods have been shown to limit the combustion temperature effectively. Only simple CO 2 purification is required after combustion. The disadvantage of this approach is that production of oxygen is expensive, both in terms of capital cost and energy consumption. The extent of interest in this process varies with the type of fuel and type of plant. Because much of the energy released in combustion of natural gas comes from oxidation of hydrogen, as distinct from carbon, much of the pure oxygen provided for combustion would achieve no advantage in terms of producing pure CO 2, making oxy-fuel combustion a relatively expensive way of separating CO 2 when using natural gas fuel. On the other hand, the use of oxy-fuel with coal (with its relatively low hydrogen content) means that much more of the oxygen is being used for CO 2 production and is therefore contributing to the purpose of separating CO 2. However, combustion of coal is typically done in boilers with relatively low thermal efficiency, so the advantages of oxy-fuel processes over established systems tend to be small, making it hard to justify the necessary research and development. Because the more efficient combined cycle plant (whether using gas or coal) is based on turbines, which are not as easily adapted to oxy-fuel firing because of the change in composition of the gas stream, there has been less progress in this respect. Nevertheless, one project is now testing the use of turbines with an H 2 O-rich recycle stream. A variant of the oxy-fuel process makes use of oxygen supplied as a metal oxide rather than as pure oxygen gas. In Chemical Looping Combustion (CLC), the fuel is reacted with metal oxide, typically in a fluidized bed reactor, thereby oxidizing the fuel and reducing the metal oxide. The metal must then be re-oxidized by exposure to air at high temperature. This process takes place in a pair of reactors which are alternately used to oxidize the fuel and to re-oxidize the metal. The model has been demonstrated at laboratory scale. One of the potential limiting factors for this approach is the durability of the solid particles, but recent work (Lyngfelt et al., 2005) has indicated that thousands of cycles may be possible with new materials, suggesting this may have potential for future application. If it can be developed successfully, this technique would, like other oxy-fuel processes, VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 815

6 SUSTAINABILITY allow the production of a high concentration CO 2 stream without further separation while avoiding the need for conventional air separation techniques. Separation techniques In broad terms there are four types of separation method which have been or are being developed for separating CO 2 from a gas stream: solvent absorption, solid adsorption, membranes and cryogenics. Solvent absorption Solvents can be separated into two classes, chemical and physical, although in practice there is some mixture between these characteristics. Chemical solvents, such mono-ethanolamine (MEA), di-ethanolamine (DEA) and proprietary mixtures, were developed for the oil and chemical industries for use in removing hydrogen sulphide and CO 2 from gas streams. The CO 2 -containing gas stream (i.e. the flue gas stream in post-combustion applications) is passed through a scrubber where the solvent dissolves much of the CO 2. The remaining gas stream passes out of the scrubber to the atmosphere. The CO 2 -rich solvent is then heated, releasing high purity CO 2, and the CO 2 -free solvent is then reused. Removal of up to 98% of the CO 2 with purity in excess of 99% can be achieved using MEA. Fig. 3 is a simplified diagram of a natural gas combined cycle power station with post-combustion capture of CO 2. Similar separation methods can also be applied in coal fired power stations with some additional preliminary cleaning of the flue gases. The energy required for regenerating the solvent is one of the main issues with this approach, since it can have a substantial impact on the overall system efficiency. Amine solvents were originally developed for operation in a reducing environment; application in power station flue gases (i.e. an oxidizing environment) can lead to degradation unless suitable inhibitors are added, which increases the cost. Even then, some degradation of the solvent will occur and the disposal of waste solvent may be a significant problem. Several plants use amine solvents to capture CO 2 from flue gas streams, one example being the Warrior Run coal fired power station in the United States, where 50,000 t/yr of CO 2 is captured for use in the food industry. Improved solvents and improved design of the scrubber and the regenerator could reduce energy requirements by as much as 40% compared to current practice (Roberts et al., 2005). There is considerable interest in the use of sterically-hindered amines, which are claimed to have good absorption and desorption characteristics. The second class of solvent, physical solvents, relies on physical absorption of CO 2 to capture the gas; regeneration is achieved by reducing the pressure, thereby avoiding the large heat consumption of amine scrubbing processes. This makes physical solvents, such as Selexol, the preferred technique in plants where there is elevated pressure, such as the syngas stream from a gasifier with shift (see Fig. 2), where the CO 2 concentration would be about 35-40% at a pressure of 20 bar or more. However, while the energy penalty of physical solvent separation is not as great as with chemical solvents, depressurization of the solvent still results in a significant energy penalty. Physical solvent scrubbing of CO 2 is well established in the industry. Solid adsorption Separation of gases by adsorption onto a solid, such as a zeolite or activated carbon, is another well established technique. Indeed, it is used commercially for purifying hydrogen and natural gas by removal of CO 2. The gas mixture flows through a packed bed of adsorbent until the product gas approaches equilibrium concentration, when the bed has adsorbed as much CO 2 as possible. The solid adsorbent is then regenerated either by pressure reduction (Pressure Swing Adsorption, or PSA) or by increasing the temperature (Temperature Swing air natural gas gas turbine N 2, O 2, H 2 O to atmosphere CO 2 capture steam generator steam turbine CO 2 to storage Fig. 3. Schematic diagram of a gas turbine combined cycle power station with post-combustion capture of CO 2 (IEA GHG, 2001). 816 ENCYCLOPAEDIA OF HYDROCARBONS

7 CO 2 CAPTURE AND STORAGE FROM FOSSIL FUELS Adsorption, or TSA). The PSA process could be used in applications that use physical solvents. However, in power plant applications, the TSA processes are cost-effective compared with PSA. TSA is of limited attractiveness for this type of duty because the extent of CO 2 removal that it can achieve is considerably less than for chemical solvents at similar overall cost. Solid adsorption is not sufficiently attractive for large-scale separation of CO 2 from flue gases because the capacity and CO 2 selectivity of available adsorbents are low. However, there may be some role for it in combination with another separation technology. Membranes Gas separation membranes allow one component of a gas stream to pass through the membrane faster than the other components. There are many different types of gas separation membrane, including porous ceramic membranes, palladium membranes, polymeric membranes and zeolites. Membranes are already in use for separating CO 2 from natural gas streams. Polymeric membranes would be used for low temperature applications such as removing CO 2 from flue gas streams. Ceramic or palladium membranes may be most useful in process application at high temperature and/or high pressure, which may be of most interest for separation of H 2 (for example, as part of a pre-combustion decarbonization process). Some novel processes are experimenting with ceramic membranes which would allow conduction of oxygen ions at high temperature (as well as heat transfer) with the aim of achieving an oxy-fuel combustion process (Sundkvist et al., 2005). Membranes cannot usually achieve high degrees of separation, so multiple stages are typically needed or one of the product streams must be recycled. This leads to increased complexity, energy consumption and cost. Several membranes with different characteristics may be required to produce high-purity CO 2. An adaptation of this approach is the solvent-assisted membrane which has been developed to combine the best features of membranes and solvent scrubbing. Further development work is required before membranes could be used on a large scale for CO 2 capture in power stations. Cryogenics Another established technique, the use of low temperatures to cool and condense CO 2, can be an effective way of separating CO 2. Cryogenic separation is widely used commercially for streams that already have high CO 2 concentrations (typically greater than 90%) but not for more dilute CO 2 streams. A major disadvantage of cryogenic separation of CO 2 is the amount of energy required to provide the refrigeration, which makes it inappropriate for gas streams with low CO 2 concentrations. Other gas components, such as water, have to be removed before the gas stream is cooled, to avoid blockages. Cryogenic separation has the advantage that it enables direct production of liquid CO 2, which is needed for certain transport options, such as transport by ship. The best application of cryogenic processes would be with high concentration, high pressure gases, such as in pre-combustion capture processes or oxy-fuel combustion. Other methods of separation Several other concepts have been proposed for separation of CO 2 from gas streams, and several of these are under development: An alternative method of regenerating adsorbents makes use of an electric field. Electric swing adsorption was developed for nuclear fuel preparation and has recently been investigated for capturing CO 2. An alternative to separating CO 2 aims instead to separate carbon as a solid. This process is technically feasible, but suffers from an intrinsic energy penalty compared with combustion processes that generate CO 2 because the energy potentially available from oxidation of carbon is not exploited. It was thought that, in compensation, the availability of solid carbon might provide a saleable product, or at least one which could be easily disposed of. In practice, this advantage does not turn out to have any commercial value. Novel reactors for the reforming or gasification process incorporate membranes for removal of H 2 to enhance the reaction; the method has been under development for several years but is not yet fully proven. Capture from plant using biomass fuel Since it was first considered as an option for mitigating climate change, CO 2 capture and storage has been associated with the use of fossil fuels. In principle, it would also be possible to capture CO 2 from power plants that use biofuels for production of electricity. Use of CO 2 capture and storage in this way could potentially achieve net removal of CO 2 from the atmosphere, when considered over the whole life cycle of growth of biomass, utilization, and capture and storage of CO 2. The most efficient VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 817

8 SUSTAINABILITY way of using biomass for electricity generation would be in a Biomass Integrated Gasification Combined Cycle plant (BIGCC). This technology is still in development but offers the prospect of higher efficiency than straightforward combustion. Capture of CO 2 could be incorporated into this plant in the same way as with IGCC, especially if the BIGCC plant uses oxygen for gasification (Audus and Freund, 2005). The overall impact of using a plant of this type is discussed later (see Section 9.3.6). A more effective way of using biomass may be to blend the biofuel with the fossil fuel used by a large, conventional power plant equipped with CO 2 capture and storage. This would be especially attractive for coal-based power plants due to their large size and existing solid fuel handling systems. Energy requirements Capturing CO 2 uses energy, as does compression to 110 bar for transportation. This energy is supplied, for example, by low pressure steam for regenerating the solvent or by electricity to run the compressor. As a consequence, less electricity can be dispatched by the power plant. Further compression of the CO 2 in transportation and for injection into storage can add a significant, if smaller, amount to the emissions of the process (with a corresponding small reduction in system efficiency). In order to understand the effect this has on the economics of the plant, it is necessary to normalize to a standard output so that the costs and emissions associated with making up the difference in electricity production or emissions are properly accounted for. The convention is that nominal output (e.g. MW electricity) should be the same for the plants being compared, both with and without capture. Unless this is done, it can give an advantage to schemes with reduced output (due to capture) because it is difficult to allow for the lost output. This convention is followed in the discussion below. The result is that the plant with capture will be significantly larger and more expensive than the plant without capture. The thermal efficiencies (expressed as percent of LHV, Low Heating Value) and emissions of power plants (normalized to 500 MW output), both with and without CO 2 capture, are shown in Table 4. With current capture technology, reducing emissions by 80-85% would decrease the efficiency of the plant by 6-10 percentage points compared to a similar plant without capture. The reduction in efficiency is less in a Natural Gas Combined Cycle plant (NGCC) than in a supercritical, pulverized Table 4. Thermal efficiencies and CO 2 emissions of power stations with and without CO 2 capture (Davison et al., 2005; Roberts et al., 2005) Efficiency (% LHV) Coal-fuelled plant coal plant (PF, Pulverized Fuel) with flue gas desulphurization (PF FGD), mainly because less CO 2 has to be captured per unit of electricity produced. The efficiency penalty for CO 2 capture is lower in the IGCC plan than in the pulverized coal plant because the gas for separation is at higher pressure, the concentration of CO 2 in the gas stream is greater, and less energy is needed for regeneration of the solvent. The size of the energy penalty for capture is one of the main reasons for the interest in developing new approaches to capturing CO 2. It should be noted that comparing similar types of plant with and without capture, as above, is a useful way of understanding the effects of capture on a particular type of plant design. When considering different methods of reducing greenhouse gas emissions in a system (as opposed to optimizing the design of an individual plant), it is less useful to make comparison with a similar type of plant. This will be discussed further in Section Transportation of CO 2 CO 2 emissions (g/kwh) PF+FGD with capture IGCC dry feed with capture IGCC slurry feed with capture Gas-fuelled plant NGCC with capture (A) with capture (B) The storage site may be hundreds of kilometres away from where the CO 2 is captured, so pipelines may be used to carry large quantities of CO 2. By compressing the CO 2 to a pressure of more than 818 ENCYCLOPAEDIA OF HYDROCARBONS

9 CO 2 CAPTURE AND STORAGE FROM FOSSIL FUELS 70 bar, it changes into a state called the dense phase, where its volume is reduced to about 0.2% of the volume of the gas at normal temperature and pressure. In this way, high pressure pipelines can transport large quantities of CO 2 using well understood, established technology. Currently there are 2,500 km of CO 2 pipeline in use (mainly in the United States) with total capacity of 50 million t/yr of CO 2 (Gale and Davison, 2003). The diameter of these pipelines is typically mm. The longest, the Cortez line, is 808 km long. These pipelines are constructed of mild steel. Because CO 2 in the presence of water can form a weak acid, it is necessary to dry the CO 2 before it enters the pipeline. This is not difficult to do and, as a result, the risk of corrosion is slight. In some cases it may not be possible to dry the gas, in particular when CO 2 is used for enhanced oil recovery, in which case short lines may be constructed from stainless steel. The cost of moving CO 2 by pipeline is a simple function of the distance: it can be expressed approximately as dollars/t for a specific distance. The cost will also depend on the type of terrain to be crossed and, particularly, on the amount of CO 2 to be moved. Fig. 4 shows how the cost of transporting CO 2 by pipeline varies depending on the quantities involved (the cost is shown for different pipeline sizes, each of which is taken to be full.) In early projects there will be a single pipeline which links the capture plant with the storage reservoir, as is done today between Beulah, North Dakota, United States and Weyburn, Saskatchewan, Canada. However, if CCS becomes widely used, pipeline grids will probably be built linking multiple sources and storage sites. These grids would improve operational flexibility and reduce cost through the economies of scale. An alternative approach offshore would be to use ships. This would be most appropriate for long distance transport of CO 2 (distances greater than 1,000-2,000 km). Small quantities of CO 2 (several thousand tonnes) are transported by ship at present. Larger tankers, similar to those currently used for Liquefied Petroleum Gas (LPG), could also be built for CO 2. Ships may also be used to move CO 2 before a pipeline grid is established, but the cost/tonne would necessarily be higher than that of the corresponding pipeline. The location of CO 2 facilities will need to take account of the potential hazards of CO 2. Although it is not dangerous at low concentrations (the atmospheric concentration is 360 ppm), at high concentrations CO 2 is an asphyxiant. Because it is heavier than air, it tends to collect in depressions. To minimize risks from leakage, CO 2 pipelines would be routed away from large centres of population, and precautionary features would be adopted in the design, including automatic block valves at separation distances sufficient to constrain the amount of CO 2 released in the event of a rupture. The experience of existing pipelines is that they have a similar number of accidents as natural gas pipelines, but without the dangerous consequences of releasing an explosive gas (Gale and Davison, 2003). Some intermediate storage of CO 2 may be needed to cope with variability in supply. By adopting approaches similar to those used for natural gas, ethylene, and LPG, there should be few problems. Other options for transporting CO 2 have been suggested, for example making a solid from it such as CO 2 -hydrate (a compound of CO 2 and water). Although feasible, such an approach does not seem to be competitive with pipelines for large scale shipment. Piping the whole flue gas stream (i.e. without any separation) is also impracticable because of the energy costs of pumping such a large amount of material over any distance, not to mention the amount of storage space that would be needed (Macdonald et al., 2005) Storage of CO 2 In order for capturing CO 2 to make a difference to global emissions, the storage reservoirs must have sufficient capacity to hold a significant fraction of global CO 2 emissions (currently about 25 Gt/yr). Analysis of many options indicates that only certain natural reservoirs have sufficient capacity to do this. These natural reservoirs fall into two categories: underground geological formations and cost (dollars/t) diameter (m) Fig. 4. The cost of transporting CO 2 by pipeline over a distance of 250 km as a function of the diameter of the pipeline (assumes fully-utilized onshore pipeline 140 bar pressure). VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 819

10 SUSTAINABILITY the deep ocean. The main options for storing CO 2 in natural reservoirs are illustrated in Fig. 5. For CO 2 storage to be an effective way of avoiding climate change, the CO 2 must be stored for several hundreds or thousands of years. Thus a key requirement for any storage facility is that there must be some means, such as a physical barrier, for keeping the CO 2 in store. CO 2 storage also needs to have low environmental impact, low cost, and to conform to national and international laws. Other ideas for storage of CO 2 have been proposed including making carbonates, which have the attraction of being highly stable, or storage as dry ice in artificial repositories. These are discussed briefly below. Geological storage in depleted oil and gas reservoirs Oil and gas reservoirs consist of porous rocks covered by impermeable cap rocks, which are often dome shaped. Following more than a century of intensive petroleum exploitation, many oil and gas fields are approaching the ends of their economically productive lives. Some of these depleted fields could act as effective storage sites for CO 2. These have a number of attractive features as CO 2 storage reservoirs: a) exploration costs would be small; b) the reservoirs are proven traps, known to have held liquids and gases for millions of years; c) the reservoirs have well known geology; d) there is potential to re-use some parts of the hydrocarbon production equipment to transport and inject the CO 2. However, in the course of using reservoirs for producing oil or gas, the cap rock may have been damaged by the injection of fluids (including the subsequent injection of CO 2 ) or by drilling through the cap for production purposes. Until the security of storage has been investigated, the history of the field may raise concerns about whether the integrity of the reservoir has been compromised. Underground storage in natural reservoirs has been an integral part of the natural gas industry for many decades (using depleted oil or gas fields or aquifers). Natural gas is routinely injected into, stored in, and withdrawn from hundreds of underground storage fields. Some depleted gas fields could be adapted easily for storage of CO 2. CO 2 -enhanced oil and gas production In most oil fields only a portion of the original oil is recovered using standard petroleum extraction methods. Injecting CO 2 into suitable, depleted oil reservoirs can enhance oil recovery by typically 10-15% of the original oil in place. This is an established technique, called CO 2 -EOR (Enhanced Oil Recovery), which is illustrated in Fig. 6. If used in conjunction with CO 2 storage, the additional oil production could offset some of the costs of CO 2 capture and injection. About 33 million t/yr of CO 2 is already used at more than 74 EOR projects in the United States. Fig. 5. Main options for storing CO 2 in natural reservoirs (IEA GHG, 2001). power station with CO 2 capture pipeline pipeline ocean unminable coal beds depleted oil or gas reservoirs deep saline aquifer 820 ENCYCLOPAEDIA OF HYDROCARBONS

11 CO 2 CAPTURE AND STORAGE FROM FOSSIL FUELS Most of this CO 2 is extracted from natural reservoirs, but some is captured from natural gas processing and from ammonia production. A further 6 million t/yr of CO 2 has been injected as part of a large CO 2 -EOR project in Turkey. Use of this technique started in the 1980s, but more recently a major CO 2 -EOR scheme was begun at the Weyburn oil field in Saskatchewan, Canada, using captured CO 2. The CO 2 for this project is captured in a large coal gasification project in North Dakota, United States, and is transported 300 km by pipeline before being injected into the Weyburn field. 5,000 t/d of CO 2 is being injected, but there is capacity to use more. An intensive monitoring programme is following the injected CO 2, which will provide much information about this method of storing CO 2 (Wilson and Monea, 2004). Enhanced gas production cannot be achieved in the same way late in the life of a depleted gas field because of the danger of contaminating the gas with CO 2. However, early in a gas field s life, CO 2 can be injected to maintain production pressure, thereby improving the rate of recovery of the gas. Eventually there will be break-through of CO 2 into the produced gas, which will increase the requirement for separation. The first field designed for this to be done is the In Salah complex in Algeria (Bishop et al., 2005). Here, the separated CO 2 is being re-injected into a part of the field well away from the producing well. A similar but smaller example is the K-12B field offshore from The Netherlands (van der Meer et al., 2005); for some time CO 2 has been separated from the produced gas stream before shipping the gas to market. In 2004, re-injection was started as part of a project to establish knowledge about the behaviour of CO 2 underground and methods of monitoring it. In order to make use of depleted oil and gas reservoirs for CO 2 storage, there will need to be some changes in current operational practices. For example, if the focus changes from oil production to CO 2 storage, the amount of CO 2 to be injected and the operation of the field will be quite different from what would be done for EOR. For example, in EOR the operator is concerned to import as little CO 2 as possible; whereas, if enhanced recovery is an adjunct to CO 2 storage, the operator may wish to inject as much CO 2 as possible. Another difference may be in terms of the ownership of the field; transfer of ownership from the licensed operator to a storage operator is, as yet, an untried procedure. Abandoned fields still contain oil and gas, which could potentially have economic value if oil prices were to rise enough or if EOR technologies were to be improved, so it would be necessary to assign responsibility for the stored CO 2 to ensure it would Fig. 6. Schematic diagram of CO 2 -enhanced oil recovery (IEA GHG, 2001). any produced CO 2 is separated and reinjected CO 2 injection well production well CO 2 oil bank miscible zone additional oil recovery VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 821

12 SUSTAINABILITY not be released into the atmosphere at a later date. All of these aspects will need to be addressed if depleted oil and gas fields are to be used for CO 2 storage. A related technique, CO 2 -enhanced coal bed methane production, is described later. Geological storage in deep saline reservoirs There are many underground, water-filled strata (aquifers) that could potentially be used to store CO 2. The aquifers that would be used for CO 2 storage are deep underground, contain saline water and are unsuitable for supplying drinking water. Injection of CO 2 into deep saline reservoirs would use techniques similar to those used for disused oil and gas fields. In order for these aquifers to store CO 2, there has to be an impermeable cap rock above the reservoir to trap the CO 2. As time passes, some of the CO 2 will dissolve in the water in the aquifer. Depending on the nature of the formation rock, the CO 2 might then react slowly with the minerals present to form carbonates, which in essence would permanently lock up the CO 2. Nearly a million tonnes of CO 2 per year is already being injected into a deep saline reservoir, the Utsira formation, under the Norwegian sector of the North Sea (Fig. 7). This is a sand formation extending under a large area of the North Sea at a depth of about 800 m. At such depths, the CO 2 is in its dense phase, but is still less dense than the formation water, so it floats above the water in the formation underneath the cap rock. In this case, the CO 2 comes from a plant which is processing a natural gas stream before shipment to market. Normal industry practice would be to discharge the CO 2 into the atmosphere, but instead it is being stored underground. When this injection began in 1996, it marked the first instance of CO 2 being stored in a geological formation in order to avoid greenhouse gas emissions and it subsequently became the first large-scale, monitored instance of storage of CO 2 underground (Baklid et al., 1996). Other gas fields where this is being done or planned include Snøvhit (Norway) and Gorgon (Australia). Geological storage in unminable coal beds CO 2 can be injected into suitable coal beds where it will be adsorbed onto the coal, locking it up permanently, provided the coal is never mined. There are vast reserves of coal worldwide, but only a fraction of these can be considered for CO 2 storage, i.e. those which will never be mined. CO 2 is believed to displace the methane that exists in the coal, which can then be captured for use; this is referred to as CO 2 -enhanced coal bed methane production (Fig. 8). Coal can adsorb about twice as much CO 2 by volume as methane, although this ratio varies depending on the type of coal and its location. This technique is in its infancy and a reliable understanding of the amount of methane which could be recovered is not yet available. The ease with which CO 2 can be injected into the coal will be determined by, among other things, the permeability of the coal. Although the problem of relatively impermeable coals might be helped by hydraulic fracturing of the coal, the cost would likely mean that only limited improvement in permeability could be justified by the economics of CO 2 storage. It might be thought that this approach would lead to an increase in greenhouse gas emissions, but if the recovered methane were burned and the resulting CO 2 were reinjected, the coal bed could still provide net storage of CO 2. A substantial amount of coal bed methane is already produced in the United States and elsewhere, but so far there has been only one production-scale trial of CO 2 -enhanced coal bed methane production, which took place at the Allison Unit in New Mexico, United States. Over 100,000 tonnes of CO 2 were injected at this site over a three-year period. A field test using various CO 2 and nitrogen mixtures has been carried out in Canada by the Alberta Research Council for several years; an experimental injection has been undertaken in Japan; and an injection trial began in Poland in 2004 in a project supported by the European Commission. Ocean storage The largest natural reservoir for carbon is the ocean, which holds about 50 times as much carbon as is in the atmosphere at present. This is primarily in solid form as carbonates including the skeletons and shells of marine creatures. Atmospheric CO 2 is continuously being exchanged with the CO 2 in the ocean as part of the natural cycle. With the increasing concentration of CO 2 in the atmosphere, due to anthropogenic emissions, a greater flow of carbon is taking place into the ocean (leading to acidification); the oceans are taking up about 7 Gt/yr of CO 2 from the atmosphere. Eventually, some of this carbon is carried into the deep ocean through the mechanism known as the biological pump where some of it will be retained. Thus the oceans play a major part in limiting the rate of increase of atmospheric CO 2 levels, by moving carbon into the deep ocean, although the rate at which this process takes place is not fast enough to protect the atmosphere fully against rising CO 2 levels. 822 ENCYCLOPAEDIA OF HYDROCARBONS

13 CO 2 CAPTURE AND STORAGE FROM FOSSIL FUELS Fig. 7. CO 2 injection into the Utsira deep saline reservoir. The CO 2 is extracted from the natural gas from the Sleipner West field before this is sent to market (courtesy of Statoil). Sleipner T gas from Sleipner west Utsira formation Sleipner A CO 2 injection well CO 2 Sleipner east production and injection wells Sleipner east field Direct injection of CO 2 into the deep ocean has been suggested as a way of increasing the speed with which anthropogenic CO 2 reaches the deep ocean. However, injected CO 2 would be in a different state from that produced by the biological pump, so the carbon would not be stored as securely. Nevertheless, this approach could help to keep CO 2 out of the atmosphere for centuries, although the retention time would depend on depth and location. A key factor influencing the design of such concepts is the likely environmental impact of the injected CO 2. In particular, dissolving CO 2 in the oceans would make the seawater more acidic. This would be a potential danger to marine life and possibly to the life-cycle of marine organisms. In recognition of this, a scheme has been proposed that would disperse CO 2 at mid-depth (1,000-1,500 m) possibly from a moving vessel. This would limit the acidification so that it would not present dangers to marine life except, possibly, close to the injection point. However, there would be no obvious way of directly detecting the CO 2 retained in the ocean, which might present problems for verifying the amount stored. An alternative scheme involves injection onto the sea-bed at great depth (greater than about 3,000 m) where its density would be greater than that of the surrounding water. At the surface of the CO 2, a layer of CO 2 -hydrate would be formed which would dissolve in the surrounding seawater. The rate of dissolution would depend on, among other things, whether the CO 2 was sheltered in a depression or exposed to ocean currents. Thus, the deep lake concept would not store the CO 2 forever, but might be able to retain it for sufficient time to contribute usefully to mitigation of climate change. A key aspect of ocean storage is the environmental impact; this and the related issue of its legal status are discussed below. This is still very much at the concept phase and very little field research has been done, so there is unlikely to be significant application of this technique in the foreseeable future. Other storage options Various other options have been proposed for storing captured CO 2. One proposal is to react CO 2 coal/ gas rock coal seam power plant captured CO 2 CO 2 CO 2 purification CH 4 Fig. 8. CO 2 enhanced coal bed methane production (IEA GHG, 2001). methane product VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 823