The Kyoto Protocol has first set a price on carbon dioxide emission (CO2).The energy sector is, due to its nature, particularly afflicted. The combustion of fossil fuels emits massive amounts of CO2 which need to be covered by means of limited emission permits.
Coal is the fossil fuel which on the one hand is provided with the largest reserves (thus assuring future fuel availability at comparably low costs) but is on the other hand emitting the largest amount of CO2 per MWhel. Therefore, technologies to capture and store that CO2 are under development. Those
technologies come with significantly higher capital cost for the plants and high energy losses in
generation. Consequently, high carbon prices are required to incentivize investment into that innovative technology.
But the adoption and diffusion of innovations is not only a question of financial incentives. As on other markets, the market for innovation is characterized by potential failures which may impede or prevent the successful diffusion of advanced technologies.
The following thesis first provides an overview about the innovative technologies to capture CO2 from large scale sources just reaching demonstration phase.
Second, innovation from an industrial organizational point of view is analyzed. The focus here is set on market failures for innovation, in particular with respect to market failures which interact with failures on the market for pollution control.
Third, a model is introduced which simulates the adoption and diffusion of Carbon Capture and Storage (CCS) in a two player Cournot game. The producers are subject to emission control and can choose among several technologies to comply with that constraint.
The analysis shows that producers prefer a significant reduction in output and profit instead of investing into the expensive technology. The situation changes as nuclear energy production is phased out and learning effects are introduced. This indicates that a switch to environmentally friendly
technologies needs strong policy support by stringent emission limits as well as by R&D support and public financed demonstration projects.
In extreme cases in which one player is initially equipped with a high share of coal while the other is nuclear based, no symmetric market shares develop. Then, despite being subject to a higher level of emission control, the fossil fuel based player dominates the market over a long time.
Table of Contents
Abstract
List of Figures
List of Tables
Abbreviations
1 Introduction
2 Carbon Capture and Storage
2.1 Technologies
2.1.1 The Post-Combustion Capture Process
2.1.2 The Pre-Combustion Capture Process
2.1.3 The Oxy-Fuel Process
2.1.4 Long-Term Technology Options
2.2 CO 2 Transport
2.2.1 CO2 Storage
2.2.2 Geologic Storage
2.2.2.1 Enhanced Oil Recovery
2.2.2.2 Enhanced Gas Recovery
2.2.2.3 Enhanced Coal-Bed Methane Recovery
2.2.3 Ocean Storage
2.2.4 Mineral Storage
2.2.5 Monitoring
2.2.6 Costs
3 Innovation Economics
3.1 A Definition of Innovation
3.2 Innovation Behavior and the Structure of Markets
3.3 Cournot meets Bertrand: Innovation and the Nature of Competition
3.4 Failures on the Market for Innovation
3.4.1 Knowledge Externalities, Technological Spillovers and Patent Protection
3.4.2 Patenting
3.4.3 The Impact of Knowledge Spillovers on Innovation
3.4.4 Adoption of Technologies
3.4.5 Adoption Externalities
3.5 Innovation under Pollution Control
3.5.1 The Basics of Weitzman
3.5.2 The Nature of Electricity and External Effects in Generation
3.5.3 Incomplete Information
3.6 Innovation and optimal pollution control
3.6.1 Investment Incentives under Emission Permits
3.6.2 Investment into Carbon Capture and Storage
3.6.3 Critical Discussion of the Results
3.7 Patent Race vs. Research Joint Venture under Emission Control 51
4 The Model
4.1 Model Description
4.2 Scenarios 65
4.2.1 Base Case Calibration
4.2.2 Scenario 1 – Changing Input Parameters
4.2.3 Scenario 2 – Permit Reduction
4.2.4 Scenario 3: Only Nuclear Capacity Replacement
4.2.5 Scenario 4 – Withdrawal from the Nuclear Energy Program
4.2.6 Scenario 5 – Learning Effects
4.2.7 Asymmetric Players
4.2.7.1 Scenario 6 – Asymmetric Players, no Learning
4.2.7.2 Scenario 7 – Asymmetric Players, Learning
4.3 Conclusion
5 References
Appendix A: GAMS Source Code, Base Case
Appendix B: Price - Quantity Calibration
Appendix C: An attempt to including Learning Rates into the Profit Maximization
List of Figures
Figure 1: Cumulative Power-Sector Investment in the IEA Reference Scenario 2005-2030
Figure 2: 2005 World Coal Reserves by Country
Figure 3: Maturity of CCS Technology
Figure 4: Post-Combustion Capture Plant with Optional Amine Solvent Storage Tank
Figure 5: O2/CO2 Recycle Combustion
Figure 6: CO2 Transport Cost Comparison: On/ Offshore Pipeline vs Ship Transport
Figure 7: Onshore/ Offshore CO2 Pipeline Transport Costs
Figure 8: Overview of Geological Storage Options
Figure 9: Original, Developed and Undeveloped US Oil Resources, Potentials for EOR
Figure 10: The Enhanced Gas Recovery Process
Figure 11: Sample Sorption Isotherms for CO2, CH4 and N2 on San Juan Basin Coal, USA
Figure 12: Potential Leakage Routes and Remediation Techniques for CO2 in Saline Aquifers
Figure 13: Public Energy R&D Investments as a Share of GDP
Figure 14: Trends in Private Sector Energy R&D
Figure 15: Leader's and Follower's Payoffs
Figure 16: Cost Comparison of Technologies Facing Learning Effects under Pollution Control
Figure 17: The Basics of Weitzman I: If Damage Curve is Steep
Figure 18: The Basics of Weitzman II: If Mitigation Curve is Steep
Figure 19: Uncertainty about Future Carbon Prices
Figure 20: Potential Gains from Emission Control under Marketable Permits
Figure 21: Potential Gains from CCS under Marketable Permits
Figure 22: Cournot Duopoly under Capacity Constraints and Emission Control
Figure 23: Possible Gains/Losses in Producer Rent from Innovation under Pollution Control
Figure 24: Technology related Producer Rents without Emission Pricing
Figure 25: Cost Efficient Electricity Production according to Emission Price
Figure 26: Technology related Producer Rents under Emission Pricing (35€/tCO2)
Figure 27: Technology Mix, Scenario
Figure 28: Technology Investment, Scenario
Figure 29: Electricity and Emission Permit Price, Scenario
Figure 30: Technology Mix, Scenario
Figure 31: Technology Investment, Scenario
Figure 32: Electricity and Emission Permit Price, Scenario
Figure 33: Technology Mix, Scenario
Figure 34: Technology Investment, Scenario
Figure 35: Electricity and Emission Permit Price, Scenario
Figure 36: Technology Mix, Scenario
Figure 37: Technology Investment, Scenario
Figure 38: Electricity and Emission Permit Price, Scenario
Figure 39: Decline in CCS Capital Cost with Respect to Cumulative Investment
Figure 40: Technology Mix, Scenario
Figure 41: Technology Investment, Scenario
Figure 42: Electricity and Emission Permit Price, Scenario
Figure 43: Market Output for all Scenarios
Figure 44: Players' Annual Profits
Figure 45: Technology Investment, Scenario
Figure 46: Scenario 7 – Market Shares, no Learning
Figure 47: Technology Investment, Scenario 7, Learning
Figure 48: Scenario 7 – Market Shares, Learning
Figure 49: Scenario 7 – Players' Annual Profits, Learning
Figure 50: Scenario 7 – Permits Used for Electricity Production, Learning
Figure 51: Scenario 7 – Market Shares, Learning
Figure 52: Scenario 7 – Profits, Learning
List of Tables
Table 1: Cost Estimation of CO2 Storage Options in €/tCO2
Table 2: Cost Estimation, Fossil plants without Carbon Capture in 2020
Table 3: Cost Estimation, Fossil plants with Capture in 2020
Table 4: Cost Estimation, Fossil plants with Capture in 2040
Table 5: RECCS Estimation about future CO2 Abatement Costs by means of CCS
Table 6: Scenario Description of the Analysis of Emission Control Policies
Table 7: Evaluation of Investment Incentives under Various Control Settings
Table 8: Evaluation of Regulatory Regimes to Foster Innovation
Table 9: RECCS Assumption on Future, Electricity related Costs
Table 10: Base Case Model Assumptions and Results
Table 11: Base Case Market Results
Table 12: Change in Fuel Prices
Table 13: Initial Market Shares, Scenario
Abbreviations
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Abstract
The Kyoto Protocol has first set a price on carbon dioxide emission (CO2). Participating economies are obliged to limit those emissions, with CO2 emitting firms now facing an additional constraint in their profit maximization. The energy sector is, due to its nature, particularly afflicted. The combustion of fossil fuels emits massive amounts of CO2 which need to be covered by means of limited emission permits. So in addition to the scarcity of fuel comes the scarcity of those allowances. Both increases pressure on electricity suppliers to switch to renewable or low carbon electricity production.
Coal is the fossil fuel which on the one hand is provided with the largest reserves (thus assuring future fuel availability at comparably low costs) but is on the other hand emitting the largest amount of CO2 per MWhel. Therefore, technologies to capture and store that CO2 are under development. Those technologies come with significantly higher capital cost for the plants and high energy losses in generation. Consequently, high carbon prices are required to incentivize investment into that innovative technology.
But the adoption and diffusion of innovations is not only a question of financial incentives. As on other markets, the market for innovation is characterized by potential failures which may impede or prevent the successful diffusion of advanced technologies.
The following thesis first provides an overview about the innovative technologies to capture CO2 from large scale sources just reaching demonstration phase. Second, innovation from an industrial organizational point of view is analyzed. The focus here is set on market failures for innovation, in particular with respect to market failures which interact with failures on the market for pollution control.
Third, a model is introduced which simulates the adoption and diffusion of Carbon Capture and Storage (CCS) in a two player Cournot game. The producers are subject to emission control and can choose among several technologies to comply with that constraint.
The analysis shows that producers prefer a significant reduction in output and profit instead of investing into the expensive technology. The situation changes as nuclear energy production is phased out and learning effects are introduced. This indicates that a switch to environmentally friendly technologies needs strong policy support by stringent emission limits as well as by R&D support and public financed demonstration projects. Those can help to overcome early technical difficulties and assure that all marketers have access to that knowledge.
In extreme cases in which one player is initially equipped with a high share of coal while the other is nuclear based, no symmetric market shares develop. Then, despite being subject to a higher level of emission control, the fossil fuel based player dominates the market over a long time.
1 Introduction
Economic growth and its affiliated increasing energy demand are calling for coal. The International Energy Agency (IEA, 2007a) predicts a growth in world's primary energy demand of 55% in its reference case till 2030. The Global demand will reach 17.7 billion tons of oil equivalents in absolute terms (11.4 btoe in 2007). This number could even become higher, if annual growth rates of the Chinese and Indian economy perform better than anticipated.
The share of electricity use in final energy consumption is expected to rise from 17% in 2005 to 22% in 2030, doubling in absolute terms.
Global investment in energy supply infrastructure of about 22 trillion US$ is required to meet the projected demand, with 56% of that expenditure expected in the power sector (Figure 1). But not only the increasing demand for electricity makes investment in new fossil fueled power plant capacity necessary. World's current power plant fleet is characterized by a rather high age, making capacity replacement indispensable (IEA/OECD, 2007).
Figure 1: Cumulative Power-Sector Investment in the IEA Reference Scenario 2005-2030
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Source: IEA 2006: p150
The opening gap between shutdowns and growing energy demand can not be compensated without fossil fuels within the next years. Yet, nuclear energy is subject to intense political discussion, making investment in new fission plants difficult or impossible in some countries. Renewable energy production is still in its infancy, not able to deliver large amounts of energy at reasonable costs and in a reliable manner. Therefore, fossil fueled power generation will, besides nuclear fission, remain the most important source for cheap base-load energy supply for the next decades (IEA, 2007). With coal not only being the fossil resource with the largest global reserves, but also the most even allocated (Figure 2), it can help to ensure reasonable fuel costs and political independence. In support of these reasons, coal will most likely keep and even experience increasing attractiveness for energy production.
Figure 2: 2005 World Coal Reserves by Country
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Source: IEA 2006: p129
The increasing use of fossil fuels will push global CO2 emissions from 27 Gt/yr in 2005 to 42 Gt/yr in 2030 (40 Gt/yr in the IEA 2006 estimation), with developing countries being responsible for more than 75% of the additional emissions (IEA, 2007c). According to the WETO-H2 (2006), these emissions will probably result in an atmospheric CO2 concentration between 900 and 1000 ppm in 2050, and average global temperature will rise by more than 3°C until 2100.
Therefore, the resulting challenge is to strive for a reasonable balance between energy security, economic growth through affordable electricity supply on the one hand and environmental protection leading to the best sustainable handling with the resources of our planet on the other hand.
Energy saving and efficiency improvement, both in production and consumption, extension of renewable and nuclear energy production and the fast introduction of even more stringent emission restrictions in developed countries are unlikely to outweigh the predicted demand increase in developing countries (WETO-H2, 2006).
For that reason, a technical solution, Carbon Capture and Storage (CCS), is gaining a rising attention. It is often cited as a powerful but also costly instrument to fight anthropogenic induced climate change. Applicable to coal, gas, oil and even biofuel power plants (it will than result in negative CO2 emission), a high share of the CO2 emissions can be captured and stored to mitigate its negative impact on climate. CCS depends on technologies and processes which have been tested extensively in different industries and applications, although they have never been applied to large scale CO2 sources like coal-fired power plants. Besides the technical barriers, even though those are not expected to represent insurmountable barriers, financial and market risks remain and could deter broad technology diffusion. Despite being in theory technically applicable to power plants, early demonstration projects are rare and most of them are induced by governmental initiative. CCS is associated with notable energy penalties, high installation costs and uncertain storage options for the CO2. In addition, there is uncertainty regarding to the actual net emission reduction that can be achieved by the relevant technologies.
With respect to the German electricity market, the withdrawal from the nuclear energy program, the emission trading obligation and the extension of renewable energy production will have significant impact on market shares, the merit order and producer rents as well as on electricity prices and demand.
The following thesis provides in its first chapter an overview about the innovative technologies to capture and store CO2. As those just reach demonstration phase, the core technical and economic barriers are identified which may impede the application of CCS.
The second chapter analyzes innovation from an industrial organizational point of view. Market failures for pollution control such as negative external effects in production interact with market failures for innovation. In face of an imperative system change, the energy sector is characterized by a rather low and still decreasing level of Research &Development (R&D) and innovative activity (Stern, 2006). First demonstration projects for CCS are rare and seldom induced by firms but by public founded projects (Valentine, 2007). The result is that advanced pollution controlling innovations need further support by regulation to overcome the so called valley of death.
The third chapter introduces a model to simulate the adoption and diffusion of Carbon Capture and Storage in a two player Cournot game. This model allows the simulation of scenarios, for instance the phase out of nuclear energy production or the impact of learning effects on the diffusion process.
The analysis shows that producers prefer a significant reduction in electricity output and profit instead of investing into the expensive technology. The situation changes as nuclear energy production is phased out or learning effects are introduced. This indicates that a switch to environmentally friendly technologies needs strong policy support by stringent emission limits as well as by R&D support and public financed demonstration projects. This could be one successful way to overcome initial technical difficulties and assure that all marketers have access to that knowledge.
2 Carbon Capture and Storage
Carbon Capture and Storage (also called Carbon Capture and Sequestration), defines a process in which CO2 from large point sources like fossil power plants is captured, compressed, transported, and stored underground or in the ocean in order to mitigate climate change (Amundsen, Bergman, 2007). Besides fossil fuel fired power plants, other mid-scale sources like cement manufacturing, ammonia production, iron and other metal smelters, industrial boilers, refineries, and natural gas wells1 are considered as potential CCS applications. Although these facilities produce CO2 in less quantity (<200 MtCO2/yr in total), they are especially qualified for the implementation of CCS (IEA/OECD, 2004) due to the high CO2 concentration in the flue gas specifically. The purity of the CO2 stream allows for cheaper capture and storage as often no sequestration is required. These industries can help to gain experience with the technology at comparatively low costs and help establishing the required pipeline network.
Despite being often called clean-coal or zero emission fossil fuel technology, CCS power plants are expected to reach plant-site CO2 capture rates between 80-90% for pre- and post-combustion capture and 99.5% for the oxy-fuel technology (RECCS, 2007). Under consideration of the total fuel-chain, the capture potential for a hard-coal pre- or post-combustion capture plant is expected to decline to a level of 70-80% and to 90% for the oxy-fuel process.
The driving force behind the research and development of CCS technologies is the need for mitigating anthropogenic induced climate change, although some economic incentives already exist as well, both for the capture and the storage of CO2. Many chemical and physical applications for CO2, e.g. urea production, foam blowing, carbonated beverages and dry ice production (Herzog et al., 2004) have created a market, however limited in demand. While the market for the industrial use of CO2 is saturated and does not hold a significant potential for additional demand, the storage of CO2 in oil, natural gas and coal-beds is considered to send strong additional market based signals for the capture and storage of CO2.
CCS increases the costs of electricity production. Most calculations claim that prices will almost double in the beginning of the diffusion process in 2020 (see Chapter 2.2.6). Therefore, strong environmental policy support is required to start demonstration projects, helping to lower costs.
The consequences for electricity production on coal markets as well as on gas markets are uncertain and depend on how carbon emission will be penalized in the future. With lignite being the fossil fuel in electricity generation emitting most CO2, it is likely to be the first technology to benefit from CCS. For hard-coal and natural gas, upfront investment - as well as capture and storage costs are likely to excel reasonable CO2 prices in the beginning of the diffusion process. Those plants are mostly used for middle and peak load demand, making it even harder to earn the high capital cost.
2.1 Technologies
All CCS technologies aim on creating a highly concentrated or pure stream of CO2, if possible at high pressure (supercritical > 75 bar), ready for transportation to a storage side (Vallentin, 2007). Applicable technologies depend on the type of fuel and whether the fuel is combusted in a liquid, gaseous or solid state. There currently exist 3 technologies on the market which, at least in small and mid-scale facilities or on components level, are technologically mature and ready for utilization.
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Source: WCI 2007: p18
Even though all CCS activities were implemented on a commercial scale, there should be distinguished between those applications and large scale facilities like a 1000 MW power plant. The later has not been realized yet and current demonstration projects are still in a planning or construction stage. Similar to e.g. aero plane production, it is not possible to simply scale up facilities. To apply CCS from a technical perspective, new materials are required and different proceedings need to be developed. The higher construction costs and significantly higher fuel consumption of all 3 processes presented below, result in higher generation costs and further environmental damage due to mining and transport as well as for the storage of the CO2. Those impacts need to be taken into account for assessing the suitability of the technologies for efficient global CO2 mitigation.
2.1.1 The Post-Combustion Capture Process
The post-combustion capture process aims on separating the CO2 from the flue gas, comparable to the flue gas desulphurization, which long has been instituted mandatory to filter SOx emission from industrial sources. CCS was first developed and applied in the 1960s to satisfy the growing industrial demand for carbon dioxide (Vallentin, 2007). Today's post-combustion capture plants are capable of capturing approximately 1000 tCO2/d., a capacity assumed extendable to 4500 t/d. This capture capacity would be sufficient for natural gas plants but needs further development to reach a level on which more than 11 ktCO2/d can be captured if applied to a 1000 MW coal-fired power plant (Chapel, Mariz, 1999).
Dependent on the carbon content of the fuel and the amount of excess air, the CO2 reaches concentrations in the flue gas between 3% for natural gas and up to 15% for pulverized coal (RECCS, 2007). The CO2 concentration determines which post combustion capture process can be applied. Two procedures have reached technical maturity. First, the physical absorption with pressure-induced CO2 recovery needs concentrations above 10%vol, as the capacity and CO2 selectivity of available adsorbents is low. Physical absorption takes place at high pressure on a solid absorbent (such as activated carbon or zeolites) and the CO2 is released under normal atmospheric conditions (Dong et al. 2001).
The second process, the chemical-absorption in combination with heat-induced CO2-recovery, is less sensitive to low concentration and partial pressure and is widely considered the technology most likely being used for capture retrofits (Vallentin, 2007).
For natural gas fired plants, the lower concentration of CO2 in the flue gas per MWhel leads to lower energy penalty and less decarbonisation costs. Furthermore, the consumption of toxic, environmental hazardous and highly corrosive chemicals is significantly lower than in coal fired plants (RECCS, 2007). The high construction costs of the scrubber and the lower load factor of gas turbines will probably limit post-combustion capture to coal fired plants.
The chemical scrubbing solution, mostly monoethanolamine (MEA), absorbs the CO2 under formation of a chemically stable compound. It is also sensitive to typical contaminants like SOx and NOx concentrations above 10 ppm and O2 concentrations above 1.5%vol. Those have to be filtered prior the flue gas decarbonisation (RECCS, 2007). In a next step, the MEA-solution is heated to 100-120°C in a stripper and releases the CO2, which is compressed and transported to the storage-site. The regenerated solution is cooled down to 40-60°C and recycled into the process. The MEA solution is subject to degeneration and therefore needs to be replaced constantly. The fundamental reaction for the MEA process is as follows:
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Figure 4: Post-Combustion Capture Plant with Optional Amine Solvent Storage Tank
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Source: Chalmers 2007: p2110
Due to the strong bonding between MEA and CO2 and the resulting high energy consumption for splitting the CO2, other solvents like sterically-hindered amines are under development (IEA/OECD, 2004). They need less energy in form of steam consumption to release the CO2 (0.9 MWhth/tCO2 for a 90% recovery rate) (Mimura et al., 2003).
Calculations state that the installation of an amine-scrubber for today’s pulverized-coal fired power plants will result in a decrease in net efficiency of 8-14%, an additional fuel consumption of 10-35% and additional investment costs between 30-150% above original (RECCS, 2007). Anderson et al. (2004) calculated an energy penalty of 15-30% for natural gas plants and 30-60% for coal fired plants. Therefore, electricity costs are supposed to double in the beginning and potentials for efficiency gains and cost reduction remain uncertain.
The post-combustion retrofitting of all kinds of fossil fueled power plants is technically feasible but incentives for the implementation do not only depend on high prices for carbon emission or potential prices for CO2. A sufficient remaining life span of the plant has to be given to allow the investment to pay off. The existing power plant stock differs in age; retrofit therefore needs to be split into future plants and existing plants. With an average life span of 40 years (lignite), it is unlikely that plants built over the next years are closed down even under high carbon penalties. New built power plants are characterized by a higher efficiency, retrofitting those will result in lower energy penalties and electricity production costs than retrofitting old, less efficient plants. Furthermore, the amine-scrubber needs additional ground (50-100% of the original ground) and the infrastructure for CO2 transportation to storage sites has to be given (Vallentin, 2007).
Because of high investment costs, the energy penalty and environmental concerns regarding the amine-solution, recent R&D focuses on two other sequestration processes. Both, the oxy-fuel and the pre-combustion capture process are expected to result in more efficient applications compared to post-combustion capture.
2.1.2 The Pre-Combustion Capture Process
Pre-combustion capture is usually considered to be installed in integrated coal gasification combined cycle plants (IGCC). The technology is based on the steam reformation of natural gas, which is deployed on large scale and has proven its reliability for hydrogen production (WETO-H2, 2006). Pre-combustion capture refers to the removal of the fuel embedded carbon in hydrocarbons to produce hydrogen which then combusts in a gas turbine, emitting a relatively pure stream of water vapor (NOx emission are also present). The efficiency of this process highly depends on the ratio of hydrogen to carbon in the fuel. Natural gas for instance contains 4 atoms of hydrogen per atom of carbon (CH4), oil contains 1-1.5 hydrogen atoms per carbon while the ratio for coal lies somewhere between 0.7-0.9 (Can Europe, 2003). The hydrogen feedstock is gasified in a high-pressure, high-temperature gasifier with either oxygen or air and water vapor. The fundamental reactions are:
1) The fuel reacts with oxygen to CO and H2
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2) The CO reacts with water to CO2 and H2
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The syntheses gas contains 35-40%vol CO2 (even more if pure oxygen is used instead of air) and both, the hydrogen and carbon dioxide are physically separated via pressure swing absorption (Can Europe, 2003). Modern gas turbines (General Electric H-class turbines) accept hydrogen concentrations up to 61%, to limit the flame temperature (and the efficiency which is determined by the Carnot factor) on a level on which materials work reliable (General Electric, 2008). Further research is needed to develop turbines which accept higher concentrations or pure hydrogen to increase the efficiency of the IGCC process.
The pre-combustion technology is estimated to increase construction costs by 20-25% compared to a pulverized coal plant at any given site (clean-energy.us 2008), excluding the costs for CO2 capture and transport. But changes in the general set-up, for instance higher carbon taxes or permit prices could make the application economically worthwhile. The European Union considers a CCS obligation beyond 2020 if the technology proves as reliable (EU MEMO/08/36). A case study published by Rutkowski and Schoff (2003) concludes that the investment costs of a capture-ready plant would be 59 US$/kW higher in the beginning but would lower capture investment from 438 US$/kW to 305 US$/kW if retrofitting becomes necessary.
For coal, the pre-combustion capture of CO2 is generally considered to be cost advantageous compared to post-combustion. 'Applied to natural gas, efficiency gains of pre-combustion separation systems are marginal' (Norwegian Petroleum Directorate, 2002).
2.1.3 The Oxy-Fuel Process
Another promising strategy to capture CO2 is the combustion of fossil fuels in a pure oxygen and carbon dioxide atmosphere instead of air (which contains 78% nitrogen contributing partly to the combustion by unwanted NOx emissions), resulting in a relatively pure CO2 stream. Shifting the CO2 separation from the flue gas to the intake air results in a highly concentrated stream of CO2 (up to 80%) after combustion (RECCS, 2007). The remaining gas contains primarily H2O. Oxy-fueling is applicable to both, steam-cycles and gas turbines. Part of the flue gas is recycled into the flame chamber in order to control the temperature onto a level of a conventional air fired plant2. The water vapor is condensed and the pure CO2 (>99%vol) stream compressed and transported to the storage site. The main cost driver of the oxy-fuel process is the energy intense separation of oxygen which alone consumes between 10-15% of the plants electricity production (Vallentin, 2007 and Herzog et al., 2004).
Figure 5: O 2 /CO 2 Recycle Combustion
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Source: IEA 2001: p13
The oxy-fuel process, besides pre-combustion capture, is regarded as a promising strategy to reach higher capture and efficiency rates. It is based on components from classic power plant technologies which have proven their reliability. Lower investment costs and less technological uncertainty could make that option electricity producers’ first choice.
2.1.4 Long-Term Technology Options
All previously introduced processes go hand in hand with significant efficiency losses. Innovative separation technologies in combination with new types of power plants can result in a lower energy input necessity and a better performance. Long-term options basically involve high temperature fuel cells or combustion processes which get the required oxygen from metal oxide reduction, so called chemical looping. But most of these technologies first have to prove feasibility and are speculative at the moment. One of the most promising technologies is a combination of a high temperature fuel cell and a natural gas turbine. Those could reach efficiencies up to 65% including CO2 separation (RECCS, 2007).
But both, technical realization and cost are uncertain today and depend on progress achieved in materials engineering and general market demand for low-carbon technologies.
2.2 CO 2 Transport
Following to the capture process, CO2 needs to be distributed to storage sites. Those can be some hundred, or even thousands of kilometers away. Transport can be conducted over a network of pipelines similar to natural gas and oil transport, by truck, train or ship. The transport in solid state (dry-ice) is not an option, despite its low transport volume. The amount of energy required to cool down the CO2 (375 kWh/t) is four times higher than for the transport in liquid form (96 kWh/t) (RECCS, 2007). Therefore, pipeline transport is commonly considered the only practicable onshore transport solution which is capable of quantities emitted by large point sources like power plants (a typical coal fired 1000 MW plant emits about 13.2 ktCO2/d (Vallentin, 2007). On-road or rail transport is merely considered as an option in the up-scaling phase of CCS where the required pipeline network is still under construction and for small scale (demonstration) projects. More than 2600 km of CO2 pipelines are existing worldwide (5 x USA, 1 x Canada and Turkey), capable of 50 Mt/yr (RECCS, 2007). The transport faces no significant technological barriers and is usually carried out at pressure above 7.4 MPa and density of 1100 kg/m3 to avoid two-phase flow regimes and to increase efficiency of the transport (IPCC, 2005). Pipeline transportation of gases and liquids relies on mature technologies and cost estimations can be considered credible. Costs are more comparable to oil transport than to natural gas or hydrogen, as CO2 is transported in liquid or supercritical state (IEA/OECD, 2004). Costs are estimated to rise 2-4 times if the pipeline goes through densely populated areas, mountains, rivers and other obstacles. Moreover, costs are sensitive to H2O and SOx contamination in the CO2. Those two form highly corrosive chemical compounds and require the application of expensive steels or sealing.
Shipping CO2 probably will be limited to some applications in the beginning as long as it is not going to be stored in the ocean. Japan for instance lacks of depleted oil or gas fields and therefore might have to ship it to the Middle East or Russia, where it can be stored in EOR or EGR operations. The dislocation of global CO2 sources and economic sinks requires cost-effective inter-regional transport solutions. Shipping LNG or oil to consumers and taking back CO2 could result in efficient intercontinental transport.
Transport costs in general depend on distance and volumes involved (Figure 6, Figure 7) but are considered to be responsible for about 10% of the overall CCS process costs.
Figure 6: CO 2 Transport Cost Comparison: On/ Offshore Pipeline vs Ship Transport
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Pipeline costs are given for a mass flow of 6 MtCO2/yr. Ship costs include intermediate storage facilities, harbor fees, fuel costs, loading/ unloading activities and additional costs for liquefaction compared to compression. Source: IPCC 2005: p28
Figure 7: Onshore/ Offshore CO 2 Pipeline Transport Costs
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Costs are shown per 250 km as a function of mass flow rate; high estimates (dotted lines) and low estimates (solid lines).
Source: IPCC 2005: p27
2.2.1 CO 2 Storage
Global storage potential for CO2 is limited. Recent studies about its range vary in their outcome. The IPCC (2005) estimates the global geologic storage potential to at least 2000 GtCO2, a number which, according to Dooley et al. (2004), can rise to 2876 GtCO2 if a larger share of saline formations is taken into account and proves as stable. Total capacity of depleted gas fields is estimated to 1000 GtCO2, which alone will hold enough storage potential for the next 50 years under current global CO2 emissions (IEA/OECD, 2004).
IPCC 2004: p5
2.2.2 Geologic Storage
A broad variety of storage solutions are summarized under geological storage and they are linked with a large spectrum of costs. Besides the storage in abandoned and active oil or gas fields already applied today, deep saline fields and aquifers are considered stable and secure. The critical point of all potential storage solutions is the long term safety of the embedded CO2. Storage in depleted oil fields and gas reservoirs (including those using enhanced oil recovery (EOR) and enhanced gas recovery (EGR)) is assumed to have a lower leakage risk than aquifers as their geology is often well known (IEA/OECD, 2004): But the latter are expected to hold the larger storage potential (4900-15300 GtCO2, IEA, 2001) Geologic formations that are suitable for CO2 storage always need to come with layers of porous rock (usually sandstone or carbonates) or cavities deep underground that are sealed upwards by a layer or multiple layers of non-porous rock (e.g. granite). The CO2 turns to liquid under high pressure and flows after injection through the formation where it will spread out until it reaches the upper sealing. This storage solution is currently studied in the Sleipner field, Norway (SEED, 2008). One MtCO2/yr is separated from natural gas production and stored in an aquifer below the field.
The risk of leakage falls into two categories. The first one, on a global scale, involves the contribution of leaking CO2 to climate change. The second category involves local risks for humans or the ecosystem close to the reservoir. Two leakage scenarios have to be taken into account: abrupt leakage and gradual leakage. The consequences for the ecosystem could include groundwater contamination and lethal effects on subsoil animals as well as on plants (IPCC, 2005). In Germany, high environmental and safety restrictions as well as economic and capacity considerations restrict the storage to depleted gas fields and deep saline aquifers (RECCS, 2007).
Saline formations are layers of porous rock that are filled with saline solution. They are much more common than coal seams or oil and gas reservoirs, representing an enormous potential for CO2 storage. Saline formations tend to have a lower permeability than hydrocarbon-bearing formations. More wells are needed to achieve a sufficient dispersion of the injected CO2. Besides the lower porosity, saline formations contain minerals that could react with injected CO2 under formation of solid carbonates. If the carbonate reactions occur over a long time, those reactions may increase permanence. But if the reaction happens fast and well in a close distance to the injection, it may plug up the formation (IPCC, 2004).
Research aims at developing prediction methods for formations storage potential before CO2 injection takes place. Early calculations suggested a storage potential of 2% of the aquifer volume, while recent estimations anticipate a capacity of 13-68% (Holt et al., 1995). The total quantity depends not only on the geologic structure, but also on the number of wells that are used to inject the CO2. Therefore, the development of CO2 injection techniques that achieve a broader dispersion of CO2 throughout the formation are required to keep overall costs low. Table 1 gives an early estimation on storage costs
Table 1: Cost Estimation of CO 2 Storage Options in €/tCO 2
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Source: Vallentin 2007: p37
2.2.2.1 Enhanced Oil Recovery
Enhanced oil recovery is a common and mature procedure to increase economic benefits from oil production. In EOR operations, more than 40 MtCO2/yr are currently injected into oil fields mostly in Texas/USA and Canada (IPCC, 2005). The pressurized CO2 expands in the field and thereby pushes additional oil to a production wellborn. Furthermore, the CO2 decreases viscosity of the oil which leads to a higher flow rate and can be pumped to the surface more easily (Melzer, 2007). The increase in total recovery can lead to additional monetary benefits of 50% for an average field (IEA/OECD, 2004). EOR is limited to oil fields which hold at least 20-30% of the original oil and can expand productivity up to the factor 2 (Vallentin, 2007). So far, most of the CO2 is taken from natural sources in the western of the USA (32 MtCO2/yr) or from industrial production (11 MtCO2/yr). In Canada, CO2 injection takes place in the Weyburn Oil field since September 2000. It is expected to result in an additional production of 130 million barrels over the 25 years life span of the project. Approximately 18 million tons of CO2 are injected and stored underground over the whole project life (Brown et al., 2001). If completely combusted, the additional oil produced would result in CO2 emission of 54 million tons. With ρOil = 0, 84 - 0,92 kg / l and a carbon content of 85%mas, on barrel oil holds the potential for:
One barrel (133 to 144 kg Oil) * 0.85 = 113 to 122 kg Carbon, combusting to 414 to 448 kgCO2.
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The US Department of Energy estimates the additional EOR production up to 210 million barrels (DOE, 2006), equivalent up to 94 GtCO2.
Figure 9: Original, Developed and Undeveloped US Oil Resources, Potentials for EOR
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*includes discovered and estimated undiscovered light oil, heavy oil, oil sands and residual oil in transition zones.
Source: US Department of Energy 2006: p3
In contrast to IEA/OECD (2004) estimations which state that one tCO2 increases oil productivity for 0.25-0.5 t, experience from the Weyburn field in Canada implicates a stored tCO2/tOil production ratio of 1:1, with approximately 3 tCO2 emissions per ton of oil. Furthermore, the CO2 is captured from large point sources which are or probably will be under emission control in the near term future. A high share of the additional oil is refined to petrol and light heating oil which is consumed by households. Because of the dispersed nature of the CO2 emissions in the private sector, capturing can hardly be achieved and direct CO2 restrictions to compensate the additional emissions in form of taxes are not going to be implemented everywhere. Therefore, capture from large point sources in combination with EOR can result in a multiplication and dislocation of emissions to a sector not subject to direct emission control.
2.2.2.2 Enhanced Gas Recovery
Similar to EOR, the CO2 is injected into natural gas reservoirs, sinks to the ground because of the higher density, and pushes the remaining natural gas upwards. Additionally it re-pressurizes the gas field which leads to a better depletion rate of the remaining natural gas. The critical point in this procedure is the amount of CO2 which mixes with the natural gas and therefore lowering its quality. This risk can be minimized by injecting the CO2 in the lower parts of the reservoir where it will remain on the ground due to the lower mobility of CO2 (higher viscosity and density) relative to CH4 (Oldenburg, 2003). Therefore, only gas fields which have been depleted to a level of 10-20% of the initial amount of gas are suitable for EGR (Vallentin, 2007). So far, EGR is still in the demonstration phase and a future large scale application is uncertain. Modeling done by Oldenburg et al. (2003) suggests that EGR might be economically feasible at CO2 delivery costs of 4-12 US$/t compared to 25-55 US$/t in EOR operations (IEA/OECD, 2004).
Figure 10: The Enhanced Gas Recovery Process
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Source: Oldenburg 2003: 3
2.2.2.3 Enhanced Coal-Bed Methane Recovery
The enhanced coal-bed methane recovery (ECBM) aims on deep coal-beds which cannot be exploited at reasonable cost. In contrast to oil or gas fields, coal beds are widespread and more evenly distributed around the world. Especially China shows a major interest in that technology. (Vallentine, 2007) The CO2 is injected into the field and is absorbed on the coal surface, displacing methane which was bounded by the coal. Most of the coal is under-saturated with gas and can hold twice the amount of CO2 than CH4. ECBM can result in significant storage potential and depletion rates > 90% (Pashin, 2000 and RECCS, 2007).
The IEA/OECD estimates an average additional production of 0.08-0.2 tCH4/tCO2 leading to economic benefits of 2-30 US$/tCO2. But the enlarged productivity decreases with the amount of CO2 stored underground as permeability reduces, making the process economically worthwhile in the beginning but less profitable after some time.
Experience from the Allision field in the USA indicates an injected CO2 to released CH4 ratio of 3:1 and an increase in depletion from 77% to now 95% (Reeves, 2003). Revenues from ECBR are supposed to lie between 2-33 USD/tCO2 (IEA/OECD, 2004). In contrast to gas or oil fields, the sufficient geological permeability of coal-beds is difficult to assess and ECBM is still in the demonstration phase (IPCC, 2005). The methane recovery from coal can also be obtained by injecting nitrogen which may results in lower costs and a better diffusion of the N2 in the coal-bed compared to CO2 (Reeves, 2003). First experimental injections of nitrogen result in an initial depletion of one unit methane per 0.4 units of nitrogen injected (Figure 11), increasing depletion rate by about 20% of the original gas in place (The Tiffany Unit, 2004).
Figure 11: Sample Sorption Isotherms for CO 2 , CH 4 and N 2 on San Juan Basin Coal, USA
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Source: The Tiffany Unit: 2
[...]
1 About 2800 t of carbon dioxide are separated daily from Sleipner West's gas production, Norway, and injected into the Utsira sandstone formation
2 Flame temperature of pulverized coal in pure oxygen > 1400°C (Günther, 1999)
- Citar trabajo
- Johannes Herold (Autor), 2008, Microeconomic analysis of investment incentives under emission control, Múnich, GRIN Verlag, https://www.grin.com/document/129016
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