Energia

Michael Weber

 

 

Figure 1 – Schematic diagram of possible CCS systems showing the sources for which CCS might be relevant, transport of CO2 and storage options p4

Introduction

Carbon capture and storage (CSS) is a technique for trapping carbon dioxide (CO2) as it is emitted from large point sources, compressing it, and transporting it to a suitable storage site. CCS has over the past few years increasingly become regarded as a serious option for reducing atmospheric emissions of CO2 from human actions. The 2008 European Commission proposals, for example, also known as the EU Energy and Climate Package, envision greater use of CCS technologies in Europe but also internationally. However, CCS should not only be seen as a European Initiative. The United States and even countries in the Arab-Persian Golf region have been in support of this mitigation technique for climate change. Amongst other initiatives, Saudi Arabia, Kuwait, Qatar and the United Arab Emirates announced at the OPEC summit in November 2007 that they would pledge US$ 750 million to a new fund that would support and promote cleaner and more efficient petroleum technologies such as CCS. Partially, CCS has found support amongst these countries because it would allow for the continued utilization of fossil fuel energy sources while at the same time it could secure substantial reductions in carbon emissions.

CCS, however, is in a relatively early phase of development. Uncertainties remain about its technologies, its attractiveness versus other low carbon opportunities, its environmental effects, its timing and especially about its costs. This report aims to analyse the prospects for CCS. For this purpose, we will assess CSS technologies and especially the costs for CO2 capture, transport and storage. While costs are likely to be initially very high, they can be expected to fall over time through a learning-by-doing process and technological improvement. Nonetheless, the range of potential costs is large and depends on various factors such as future energy prices which are hard to predict. It will be argued that CCS is technically feasible and under certain circumstances economically attractive.

The rest of this paper will be structured as follows. The next section will look at the different existing CCS technologies. After that, we will in greater detail look at the costs of CCS. The last section will conclude.

 

CCS Technology

CO2 is emitted into the atmosphere whenever fossil fuel is burnt, if in large combustion units such as used in power generation or in smaller sources such as vehicle engines. Resource extraction or certain industrial processes especially steel and cement production or oil refining also lead to great quantities of emissions. A scientific consensus has been established that higher CO2 concentrations in the atmosphere combined with incoming solar radiation trap heat and influence earth's temperature. Under the United Nations Framework Convention on Climate Change, governments have agreed to stabilize 'greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system'. Since then, an amount around 500 ppm has become the target. However, even this benchmark requires a 50% reduction from the business-as-usual emissions within about half a century.

CCS aims to prevent the CO2 generated by large stationary sources to enter the atmosphere. Current technology is believed to be able to capture around 90 percent of CO2 emissions from these sources. The basic process of CCS consists of three stages: capturing the CO2 emitted from these sources, transporting it to a suitable storage location, and storing it there permanently. Figure 1 on the cover illustrates these three components. While technologies used in each stage can be found in industrial operation today, CCS as an overall integrated system is by far not as mature as some of its components. Capturing CO2 requires separating it from other gaseous products. Existing separation technologies exist that can either be used to capture carbon after combustion or to decarbonize the fuel before it. Before CO2 is transported to a storage site, usually through pipelines, it usually needs to be compressed to a high density. Storage methods include injection into underground geological formations, into the Deep Ocean or industrial fixation in inorganic carbonates. The first large scale CCS project to be initiated has been the coal fired power plant Schwarze Pumpe in Germany in September 2008.

 

Capture Technology

During fossil fuel combustion, the fuel consisting of a mixture of hydrocarbons with some impurities is oxidized with the help of an oxidant, usually air or O2, to release a large amount of energy, the heat of the combustion, and a mixture of combustion reaction products, the flue gas. The composition of the flue gas depends on the fuel and oxidant used and the reaction conditions. CO2, however, is an unavoidable product of the reaction as a result of the large amount carbon in all fossil fuels.

Carbon capture is the most complex and as we will see the most costly component of CCS. The purpose of CO2 capture is to produce a concentrated stream of CO2 at high pressure that can readily be transported. The choice of a suitable technology for the separation and capture of CO2 depends on the characteristics of the gas stream from which the carbon needs to be separated, which mainly depends on the power plant technology. Three main approaches to capturing the carbon generated from a primary fossil fuel (coal, natural gas or oil) or biomass exist: post-combustion, pre-combustion and oxyfuel combustion. Each has its own advantages and disadvantages and neither should be seen as superior to another. A common problem is that they are all very energy intensive and relatively expensive. Which of the technologies is chosen, often depends on local circumstances and the fuel used. Figure 2 shows a schematic diagram of the main technologies.

 

Figure 2 – Schematic representation of capture systems

 

 

Post-combustion

Post-combustion systems separate CO2 from the flue gases produced by the combustion of fossil fuels or biomass in air, for centuries the most economic technology to extract and use the energy contained in the fuel. After the combustion of the primary fuel, the flue is not discharged into the atmosphere but instead passed through equipment which separates most of the CO2. While the separated CO2 can be fed to a storage site, the remaining flue gas is discharged into the atmosphere. The combustion of fossil fuels in air leads to a flue gas that is a dilute stream of CO2 mixed together with a large amount of N2 and some other gases. The CO2 can be captured through a process referred to as flue gas scrubbing. It is based on chemical absorption of CO2, using a monoethanolamine-based (MEA) solvent. Generally, 75%-95% of CO2 is captured using this technology.

The separation of the CO2 from the other components of the flue gas usually takes place through a continuous scrubbing system. The two main elements of such a system are firstly an absorber in which CO2 is absorbed into a solvent, and secondly a regenerator in which CO2 is released in concentrated form and the original solvent is recovered. Once the CO2-rich solution leaves the absorber, it is passed through a heat exchanger and then further heated in a reboiler, using low-pressure steam in order to break down the CO2 solvent compound and then to regenerate the solvent and to produce a concentrated CO2 stream. While the hot solvent can be returned to the heat exchanger, where it is cooled and then sent back to the absorber, the CO2 can be transported to a storage site.

The post-combustion technology is well understood and is used for example by Statoil to store CO2 from the Sleipner West gas field. Also, several commercial CO2 capture plants were constructed in the United States in the 1970s, largely in order to use the CO2 produced for other industrial applications such as the carbonation of brine or the production of dry ice. Although these applications are still in operation today, they are significantly smaller than a typical power plant application.

 

Pre-combustion

As is nicely shown in figure 1, pre-combustion systems process the primary fuel in a reactor with steam and air or oxygen. This produces a mixture consisting mainly of carbon monoxide and hydrogen, that is 'synthetic gas'. Gasification technology that converts cheap and dirty fuel such as coal into synthetic gas has been around for more than hundred years and is frequently used in the chemical and fertilizer industries. The gasifier is a high-pressure vessel into which the fossil fuel is fed along with a controlled quantity of O2 (or air) and steam (or water). Chemical reactions at high pressure lead to the partial oxidation and dissociation of the fuel to form the syngas. The hot syngas is then cooled and filtered in order to remove particulate matter. The result is a clean fuel gas that is then taken to a second reactor, called the 'shift reactor'. In this high temperature reactor, the CO in the fuel gas is converted to CO2 with the help of steam and a catalyst to create shifted syngas. The resulting mixture of hydrogen and CO2 can then be separated into two streams: one CO2 gas stream and one consisting of hydrogen. The CO2 can then be transported to a storage site and the hydrogen is a carbon-free energy carrier that can be combusted to generate power. Pre-combustion systems would generally be used at power plants that employ integrated gasification combined cycle (IGCC) technology.

 

Oxyfuel Combustion

Using oxyfuel combustion is a more recent procedure compared to the previous two. As can be seen from figure 2, in comparison to the post-combustion system oxyfuel combustion uses oxygen instead of air for combustion of the primary fuel. The resulting flue gas stream consists mainly of water vapour and CO2. After heat is extracted from the flue gas, it is sent to a precipitator, a cyclone, or a bag filter for particulate removal. A portion of the flue gas is recycled back into the boiler so that excessively high temperatures in the boiler are prevented by diluting the O2. The rest of the flue gas is sent to a compression and refining unit where the moisture, inerts and other impurities such as SOx and NOx are removed. The high pressured CO2 stream that is left over is ready to be transported.

Although oxyfuel combustion is a promising option for CO2 capture from power plants, it is in its earlier stages of development compared to post- and pre-combustion systems. While parts of the system are commercially available, only laboratory studies using this technology have been conducted so far.

 

Emerging technologies

One of the most promising emerging technologies is the application of membranes. Membranes are believed to be able to be used to separate CO2 from other components or gases. It is argued to have large potential in offering energy savings and a low-cost solution to CO2 separation and capture in each of the systems explained above. However, at this stage, membrane-based processes are still at an early stage of development.

A wide range of further techniques is being developed. However, an explanation of all of these is beyond the scope of this paper. Such technologies include chemical looping combustion, the Clean Energy System, Biomass gasification with CO2 capture, the development of better solid adsorbents and absorbents, and electrochemical processes for the separation of CO2 from flue gas or for the concentration of CO2 from syngas.

 

Transport

Unless plants are directly at or above geological storage sites, the captured CO2 must be transported to a storage site. Transport is likely to be the least problematic of the three stages of CCS. Pipelines are usually the primary option although shipping is also possible. For transport in pipelines, gaseous CO2 is usually compressed to 8 MPa to avoid two-phase flow regimes and to increase the density of the CO2. This makes transport easier and cheaper. Pipeline transport of CO2 is already successfully being done. In the US, for example, over 2,500 km of pipelines transport more than 40 MtCO2 per year. For transport in ships, CO2 is carried in insulated tanks at a temperature well below ambient and at lower pressures. Transport by ships might be more economically when the CO2 has to be moved over a long distance or to the middle of the ocean. Shipment of CO2 would resemble that of liquefied petroleum gases such as propane and butane.

 

Storage

CO2 can either be stored in deep, onshore or offshore geological formations or in the Ocean. For both, various options are possible. Public opinion has generally been more in favour of geological storage as ocean storage is perceived as riskier.

 

Geological storage

The primary options for geological storage are depleted oil and gas fields, deep saline aquifers, i.e. natural underground formations containing salty water, and unminable coal beds. All options require CO2 to be injected in dense form into a rock formation below the earth's surface. Figure 3 offers a nice overview of geological storage options. As can be seen, storage can occur in onshore as well as offshore sedimentary basins, meaning natural large-scale depressions in the earth's crust that are filled with sediments. Enhanced oil and gas recovery and enhanced coal bed methane recovery refers to techniques for increasing the amount of oil, gas and methane respectively that can be extracted from oil and gas fields or coal beds through the injection of CO2.

Geological storage might not be technologically as advanced as CO2 transport but it is ongoing in smaller industrial-scale projects in the Sleipner project in the North Sea, the Weyburn project in Canada and the In Salah project in Algeria. EOR techniques are applied in Texas, USA. The injection of CO2 in geological formations is based on many technologies that are used in the oil and gas exploration and production industry. What is of real concern is that it is guaranteed that the injected CO2 remains locked underground and does not leak over time.

 

Figure 3 – Overview of geological storage options

 

CO2 storage is generally injected at depths below 800m where it has a liquid-like density due to prevalent pressure and temperature in those depths. Storage space in geological formations can thus be optimized. The injected CO2 is believed to fill space by partially displacing present fluids. In order for the CO2 to remain trapped, rock of very low permeability needs to lie over it to serve as an upper seal. Because totally closed off sites rarely exists, some migration of CO2 is often unavoidable. Geochemical trapping, i.e. the reaction of CO2 with in situ fluids and the host rock, limits these movements. Amongst other things, CO2 dissolves in the in situ water, thereby becoming denser and sinking down in the formation over time. What is more, chemical reactions between the CO2 and rock minerals form ionic species and convert to solid carbonate minerals. This process, however, takes millions of years. Coal bed storage can take place at shallower depths. CO2 is hereby absorbed on the coal.

CO2 usage for EOR involves the injection of captured CO2 into an oil reservoir so that it literally pushes oil out of the pores of the rock. Injected CO2 expands underground and thereby pushes oil towards a production well (Figure 4). At the same time, CO2 can also thin oil by dissolving in it and thereby lowering its viscosity. The result is an improved flow rate of the oil. EOR depends on reservoir temperature, pressure and crude oil composition and thereby resulting behaviour of CO2 with crude oil mixtures. Some of the injected CO2 returns with the produced oil but could be captured again and re-injected.

 

Figure 4 - EOR

 

Similarly, enhanced coal bed methane recovery (ECBM) is a method that produces additional coalbed methane from a source rock by injecting CO2 into a bituminous coal bed where the CO2 then displaces methane. The great advantage of EOR and ECBM is obviously the additional revenue from the extra recovery of oil in EOR and methane in ECBM. Both therefore present potentially a viable option especially for oil producing states.

Risks due to leakage from storage of CO2 exist for humans, ecosystems and groundwater. The IPCC has estimated that the fraction of CO2 retained underground will exceed 99% over 100 years with a probability of 90 to 99%. Over 1000 years, it is still very likely that more than 99% of the injected CO2 is kept enclosed.

 

Ocean Storage

Ocean storage could be done by injecting and dissolving CO2 into the deep ocean at depths greater than 1000m where most of the CO2 is argued to be isolated from the atmosphere for centuries. This can be done via a fixed pipeline or a moving ship. Additionally, CO2 can be deposited onto the sea floor at depths below 3000m where the CO2 is denser than water and is expected to form a 'lake'. This way dissolution of the CO2 into the surrounding environment is delayed. The deeper the CO2 is injected, the more it is believed will be retained. Ocean storage and the environmental impacts are still in the research phase. One of the downsides of this storage option is the likely increase in water acidity. This could have severe impacts on the marine ecosystems. Dissolving alkaline minerals such as limestone have been proposed in order to neutralize the acidic CO2. This, however, would require large amounts of energy.

 

As we have seen, components of CCS are in various stages of development. But an entire CSS system could be built from existing technologies that are used in the production of fossil fuels or electricity. The state of development of the overall system, however, is less than most of its components. As yet, little experience exists about combining CO2 capture, transport and storage into a fully integrated system. The economic feasibility of such efforts is often questioned. For this reason, we will now assess the costs of CCS.

 

CCS Cost Analysis

In comparison to the costs for normal large installations emitting CO2 such as power plants or cement and steel producing factories, CCS adds four additional costs:

• Capture equipment needs to be installed.
  
• The capture process needs to be powered which requires additional energy and therefore further fuel costs.
  
• A transport system has to be built.
  
• And, the CO2 has to be stored and necessitates monitoring afterwards.
  

Cost estimations for CCS are difficult tasks given the many uncertainties that bedevil the technologies explained above. Site-specific sectors such as the design, operating and financing characteristics of power plants or industrial facilities are an extremely crucial factor that accounts for the great range of costs for CCS that is given in the literature. What is more, the type and cost of the fuel used, the distances and terrains of transport and the type and characteristic of storage are all factors that influence the overall cost of CCS. Given all these cost influencing factors, cost-analysis is preferable done for specific projects rather than for the overall system. Nonetheless, in order to compare the economic feasibility of CCS to competing technologies such as for alternative energies, it seems useful to establish a price range for CCS. Each of the three components of an integrated CCS system - that is capture, transport and storage - all incur costs. From these, CO2 capture accounts by far for the greatest part which is why we will focus on it here. However, scientists maintain that the cost of CCS, especially the capture component, will decline over time as a result of a learning-by-doing process and further R&D.

Table 1 summarizes the costs for capture from different power plants and industrial sources, for transport and for storage (also including monitoring).

 

Table 1 – 2002 cost ranges for the components of a CCS system for a large-scale, new installations

The table clearly shows the great cost range especially for CO2 capture. Capture for industrial sources has a wider range as a result of R&D focus largely only on the power sector. Additionally, industrial sources greatly vary in size. The smaller the plant is the greater the cost of US$/tCO2 captured because of economies of scale. Table 2 combines the component costs to offer some range of what total costs of CCS are likely to be for three different power plant systems with transport and geological storage options.

    Pulverized coal plants (PC) and natural gas combined cycle power plants (NGCC) both use post-combustion systems. The cost of CCS ranges from 0.019 to 0.047 US$/kWh for PC and from 0.012 to 0.029 US$/kWh for NGCC plants. Integrated coal gasification combined cycle power plants (IGCC) use pre-combustion capture. The CCS cost range is 0.01 to 0.032 US$/kWh. Using EOR can reduce the cost of CCS because EOR revenues can partly compensate for the CCS costs. For IGCC plants, CCS costs can in some circumstances turn negative, representing a profit. But it must be mentioned that although IGCC plants are projected to have the lowest CO2 mitigation cost, initial capital expenditure is greater. NGCC plants on the other hand have typically been found to have lower electricity costs. Therefore, there is no winner amongst any of the technologies regarding CCS costs. Also, as already mentioned a lot depends on local factors and the fossil fuel type that is being explored. One technique might be more practical than another for a certain coal type for example.

    Retrofitting existing plants is an option. However, research has not yet looked in great details at the costs involved. Generally, it is believed that CCS costs will be greater in this case and only worthwhile for younger plants.

    Research up to this date is lacking an in-depth study for non-power applications. The cost range for these plants is likely to be larger given the diversity of these sources in terms of CO2 concentrations and gas stream pressure. The higher the concentration of CO2 is the cheaper to separate and capture larger amounts. The lowest costs can be found for processes that already separate CO2 as part of their production.

 

Table 2 – Range of total costs for CO2 capture, transport and geological storage based on current technology for new power plants using bituminous coal or natural gas

It is important to notice that we have to accept these cost estimates with some hesitance as they make assumptions for example about fossil fuel prices that can greatly distort the reality. Fossil fuel prices in 2002 have been lower than in 2008. This is likely to increase the cost premium associated with emission mitigation for power installations with CCS as the capture and separation technologies require great amounts of energy. However, natural resource exporting countries such as most countries in the Arab-Persian Gulf region might not be hurt as much by higher fuel prices. CCS costs for these countries might therefore be lower.

    Economic potential for CCS systems exist to the extent that policies are in place whose aim it is to substantially limit GHG emissions. Given that the supply of primary energy will continue to be dominated by fossil fuels until at least the middle of the century and that the magnitude of emission reductions needed to stabilize CO2 concentrations in the atmosphere are so substantial, CCS must be an option as it is the only technology that allows continued business-as-usual use of fossil fuels but that at the same time can reduce the amount of CO2 emitted into the atmosphere. The IPCC as well as the consultancy McKinsey & Company agree that with greenhouse gas emission limits imposed and with substantial R&D investment, a large scale deployment of CCS systems can be viable. However, for this to happen either a tough cap on CO2 emissions must be mandated or CO2 must be priced effectively. Otherwise, only niche opportunities for CCS will be deployed such as CO2 captured from high-purity, low-cost sources coupled with CO2 storage in a value-added application such as EOR. The IPCC argues that a price of CO2 would have to exceed 25-30 US$/tCO2. McKinsey & Company believe a price of €30-45 per tonne might be necessary. Above everything, it seems necessary that a binding global environmental agreement with stringent commitments will be negotiated at the UN climate change conference in Copenhagen in 2009. So far, a price for carbon has only been effectively established in the EU through the EU emission trading scheme (EU ETS). The price per tone CO2 emitted in its first trading period varied from a peak of €30 per tonne CO2 in April 2006 to almost approaching zero from August to December 2007. While the price in late 2007 dropped because of an overallocation of allowances in the first trading period, futures for the second trading period price of CO2 remained roughly stable between €20 to €25. As of October 21 2008, the price of carbon is €21.22. Although this price is just below the estimated price needed, recently analysists from Deutsche Bank forecasted the carbon price per tonne in the EU ETS to range from €30 to 48 in the second trading period but also beyond it up to 2030. Without going into too much detail, it should be noted that such estimates are far from certain. The EU are currently discussing Commission proposals to implement necessary reforms of the EU ETS that would put the EU on the right path to an ambitious climate change policy that could guarantee an efficient internalization of the cost of carbon. However, member states' governments including Germany's Angela Merkel have recently increasingly taken side with industry demanding exemptions to EU climate rules. Unless the reform proposals pass through the EU's codecision procedure without major amendments, it is very likely that CO2 prices will not be sufficient for CCS systems to be installed at least in Europe. What is more, threats of a global recession will most likely also influence the price of carbon negatively and delay any further investment in R&D. At the same time, however, a decline or slower growth in production will decrease CO2 emissions. In sum, we can be certain that there is uncertainty. And uncertainty is not conducive to business investment. However, if governments agree on CO2 emission limits, it is argued that CCS systems are competitive with other large-scale mitigation options such as nuclear power and renewable energy technology. Including CCS in a mitigation portfolio could reduce the cost of stabilizing CO2 concentrations by 30% or more.

 

 

Conclusion

The only certain thing we can say about Carbon Capture and Storage is that it is naturally plagued by uncertainty. This goes as much for almost all of its technological components as for its costs. Although most of its technologies are somehow commercially used, the integration of the entire system is problematic and requires further research. Capturing and separating CO2 appears to be the biggest and most expensive component of CCS. However, new technologies such as membrane-based processes are likely to be able to improve the system and to reduce costs. Generally, cost projections vary greatly and are dependent on a variety of factors, many of them inherent to local circumstances. What is more, we believe that costs of CCS will decline over time through a learning-by-doing process.

    Overall, it was argued that CCS has economic potential but only when governments either mandate stringent emission limits of CO2 or when an efficient price for carbon is established that internalizes the true cost of CO2 to society. Great potential exists for the use of CCS, especially since it is cost competitive to nuclear power or alternative energy and because it offers a compromise between energy importing countries that have increasingly become concerned with climate change and oil exporting countries that want to guarantee a future income stream for their country through the continued use of fossil fuels. One of the biggest disadvantages of CCS is its low acceptance amongst a majority of the public. Safety and environmental concerns will have to be addressed further before it can become a viable option for the mitigation of climate change