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Abstract: Alstom is developing a portfolio of solutions to address CO2 emission reductions. Among them is CO2 Capture and Storage (CCS) for which Alstom is developing several CO2 capture systems based on post-combustion and oxycombustion processes. This paper will be oriented to utility and industrial companies that would like to be prepared to CCS challenges and understand the key features of the CO2 capture technologies, in this article focus will be on oxy-combustion. This paper is also oriented to “oxy-experts” community for an update coming from pilots operation. It will describe key features of the different pilot projects with Alstom’s involvement and will describe the work performed in there. The development of CO2 capture technologies are being pursued by European and US suppliers in collaboration with utility companies, academia, the US DOE, the European Union, and universities. The first part of this article will address the work of Alstom and corresponding results in three major oxy pilots: • Vattenfall Schwarze Pumpe Oxy-combustion pilot plant (30 MWth, coal)) and corresponding results (pilot is in operation since September 2008, a full PC oxy-combustion chain has been under evaluation there). • An oxy tangentially fired boiler development project (coal) with co-funding from the US DOE and other organizations, which includes pilot testing at the 15 MWth scale, conducted in Windsor CT (US). This pilot has started operation in September 2009. • The TOTAL Lacq Oxy-combustion pilot plant (30 MWth, natural gas) where Alstom did the retrofit of a conventional boiler for its conversion into oxy-combustion. Considerable knowledge has been gained with these pilots through different considerations, both on boiler components but also on the integrated oxy chain. All these positive outcomes confirm the expectations of the community in oxy-development and open the door to the next development step of ∼250 MWel large scale oxy-fired carbon capture and storage (CCS) demonstration plants. This paper provides an update about the CO2 capture pilot plant operation and also present the technical challenges expected to be demonstrated during large scale demonstration plants. [Copyright &y& Elsevier]

Abstract: This paper summarizes recent numerical modeling activities investigating geological CO2 sequestration project at the Cranfield field, Mississippi, USA, performed with the commercial compositional flow simulator CMG-GEM. The oilfield was produced from the 1940’s to the 1960’s but has been the recent recipient of an enhanced oil recovery (EOR) CO2 flood. The subset of actual site operations of interest to the BEG consists of (1) an early phase, object of this paper, in which CO2 is injected into the oil-bearing reservoir (the so-called Phase II) and (2) a second phase (started on December 1, 2009) in which CO2 is injected at a high rate (>100 kt/yr for several years) in the saline aquifer down dip of the reservoir (Phase III). We present the modeling efforts related to the early phase of injection (Phase II, started in July 2008) in which CO2 is injected into the oil-bearing reservoir. The objectives of the modeling effort are to (i) to gain insights on how to approach CO2 injection modeling at the site, (ii) to match recent pressure measurements at several wells including a dedicated observation well, and (iii) to vindicate the necessity of monitoring of reservoir pressure. Its intent is not necessarily to do a full-fledged history match of the historical production period (1940’s–1960’s). We conducted numerous repeat simulation runs to modify boundary conditions, fluid properties, and reservoir properties to match observed fluid responses to production and to injection. A good understanding of subsurface heterogeneities, and composition of the oil and gas components, and boundary conditions of the reservoir is the key to successful history matching. However, allocating the correct distribution of rock properties based on historical geophysical logs remained an area of uncertainty even as additional new data were obtained during characterization because of the complex interplay between depositional environment and strong overprint of diagenetic events. Parameters of utmost importance for a correct description of a flow field, in particular the relationship between porosity and permeability and the nature of permeability spatial variations remain uncertain as well as boundary conditions. The uncertainty was dealt with through sensitivity analyses. Ultimately, the constructed model shows a reasonable match with the data. [Copyright &y& Elsevier]

Abstract: The IEA 2007 World Energy Outlook forecasts that fossil fuels will continue to dominate the energy mix until 2030, including large economies such as the EU, Japan, US and China. A growing concern among many countries is the design o f mechanism s that will finance clean coal technologies and in particular carbon capture and storage projects. To illustrate, it is estimated that the United States will require 170 GW of new coal -fired capacity prior to 2030 with 90% of that being post 2015. Therefore substantial government and private investment into carbon capture and storage (CCS ) projects will be required and m echanisms designed to facilitate that investment. Many organizations are examining this issue including the IEA Clean Coal Centre, IEA Greenhouse Gas R&D Programme, Clean Coal Power Initiative and the Carbon Sequestration Leadership Forum (CSLF). In 2007 and 2008 two expert meetings on financing post-demonstration CCS projects were organised in London and New York by the IEA Greenhouse Gas R&D Programme and the IEA Clean Coal Centre, with the support of the World Coal Institute and sponsorship from Chevr on and Rio Tinto. This paper reports back the results of those meetings in regard to identifying the key drivers for financing post-demonstration CCS projects in Europe and North America. This is of particular interest with the restructuring of the USA Fut ureGen Programme as well as the proposed inclusion of CCS within the European Union Emissions Trading Scheme (EU-ETS) in the future. Different options for financing such projects are explored and compared with a focus on how they could assist in the realisation of commercial CCS projects. In addition, this paper examines the response by the insurance, banking and other financial sectors to the potential investment opportunities CCS projects could provide in dealing with issues such as liability and project investment. Lastly, the paper analyses the knowledge and awareness of CCS technology within the financial community in general. [Copyright &y& Elsevier]

Abstract: Over the past few years, several pieces of legislation have been introduced in Congress aimed at reducing US greenhouse (GHG) emissions by setting emission targets by specified years. One of the latest bills, America’s Climate Security Act of 2007 (S.2191) was introduced in October 2007 and sets a US GHG emissions target for 2050 that is 85% below the governments business-as-usual forecast. DOE/NETL has employed a multi-sector emissions accounting tool, CarBen, that identifies emission abatement options and their contribution, via a wedge analysis, to the total GHG emissions reduction needed to meet the 2050 emissions target laid out in S.2191. This paper begins with a review of expected greenhouse (GHG) emissions in the United States through 2050. Historical and projected trends in U.S. energy use per GDP and GHG emission per unit of energy delivered are assessed. The paper then explores “technical possibilities” that exist for the U.S. to mitigate its GHG emissions in line with S.2191. Within the power sector, these options include nuclear power, renewable power generation, refurbishing existing coal power plants, retrofitting existing coal power plants with carbon capture and storage (CCS) and deploying new coal and natural gas power plants with CCS Outside of the power sector abatement options cover non-CO2 GHG emissions abatement, terrestrial offsets, international credits, improved vehicle efficiency and electrification of the transportation sector through hybrid electric vehicles. The methodology for calculating the wedges and allocating emissions reduction among the different options is described. [Copyright &y& Elsevier]

Abstract: The United States and China are the two largest emitters of greenhouse gases in the world and their projected continued growth and reliance on fossil fuels–especially coal–make them strong candidates for the large-scale deployment of carbon dioxide capture and storage (CCS) systems in a greenhouse gas constrained world. Previous work has revealed that both nations have over 1600 large electric utility and other industrial point CO2 sources as well as very large CO2 storage resources on the order of 2000 billion metric tons (Gt) of onshore storage capacity. In each case, the vast majority of this capacity is found in deep saline formations. In both the USA and China, candidate storage reservoirs are likely to be widely accessible with over 80% of these large industrial CO2 sources having a CO2 storage option within just 80 km. This suggests a strong potential for CCS to help bring about meaningful, sustained CO2 emissions reductions for these large, vibrant economies. However, while the USA and China possess many similarities with regards to the potential value that CCS might provide, including the range of costs at which CCS may be available to most large CO2 sources in each nation, there are a number of more subtle differences that may help us to understand the ways in which CCS deployment may differ as the the two nations work together–and in step with the rest of the world–to most efficiently reduce greenhouse gas emissions. This paper details the first ever analysis of CCS deployment costs in these two countries based on methodologically comparable CO2 source and sink inventories, economic analysis, geospatial source-sink matching and cost curve modeling. This type of analysis provides valuable insight into the degree to which early and sustained opportunities for climate change mitigation via commercial-scale CCS are available to the two countries, and could facilitate greater collaboration in areas where those opportunities overlap. [Copyright &y& Elsevier]

Abstract: The use of carbon dioxide (CO2) for enhanced oil recovery (EOR) is being tested for oil fields in the Illinois Basin, USA. While this technology has shown promise for improving oil production, it has raised some issues about the safety of CO2 injection and storage. The Midwest Geological Sequestration Consortium (MGSC) organized a Monitoring, Verification, and Accounting (MVA) team to develop and deploy monitoring programs at three EOR sites in Illinois, Indiana, and Kentucky, USA. MVA goals include establishing baseline conditions to evaluate potential impacts from CO2 injection, demonstrating that project activities are protective of human health and the environment, and providing an accurate accounting of stored CO2. This paper focuses on the use of MVA techniques in monitoring a small CO2 leak from a supply line at an EOR facility under real-world conditions. The ability of shallow monitoring techniques to detect and quantify a CO2 leak under real-world conditions has been largely unproven. In July of 2009, a leak in the pipe supplying pressurized CO2 to an injection well was observed at an MGSC EOR site located in west-central Kentucky. Carbon dioxide was escaping from the supply pipe located approximately 1 m underground. The leak was discovered visually by site personnel and injection was halted immediately. At its largest extent, the hole created by the leak was approximately 1.9 m long by 1.7 m wide and 0.7 m deep in the land surface. This circumstance provided an excellent opportunity to evaluate the performance of several monitoring techniques including soil CO2 flux measurements, portable infrared gas analysis, thermal infrared imagery, and aerial hyperspectral imagery. Valuable experience was gained during this effort. Lessons learned included determining (1) hyperspectral imagery was not effective in detecting this relatively small, short-term CO2 leak, (2) even though injection was halted, the leak remained dynamic and presented a safety risk concern during monitoring activities and, (3) the atmospheric and soil monitoring techniques used were relatively cost-effective, easily and rapidly deployable, and required minimal manpower to set up and maintain for short-term assessments. However, characterization of CO2 distribution near the land surface resulting from a dynamic leak with widely variable concentrations and fluxes was challenging. [Copyright &y& Elsevier]

Abstract: This paper presents results from a survey on stakeholder attitudes towards Carbon Capture and Storage (CCS). The survey is the first to make a global comparison across three major regions; USA, Japan, and Europe. The 30-question survey targeted individuals working at stakeholder organizations that seek to shape, and will need to respond to, policy on CCS, including electric utilities, oil & gas companies, CO2-intensive industries and non-governmental organizations (NGOs). The results show generally small differences across the regions and between the different groups of stakeholders. All believed that the challenge of significant reductions in emissions using only current technologies was severe. There is a widespread belief both that renewable technologies such as solar power and CCS will achieve major market entry into the electricity sector within the next 10 to 20 years, whereas there is more skepticism about the role of hydrogen and especially nuclear fusion in the next 50 years. All groups were generally positive towards renewable energy. Yet, there were some notable areas of disagreement in the responses, for example, as expected, NGOs considered the threat of climate change to be more serious than the other groups. North Americans respondents were more likely to downplay the threat compared to those of the other regions. The Japanese were more concerned about the burden that would be placed on industry in the coming decade as a result of emissions constraints and NGOs were more likely to believe that the burden would be light or very light. NGOs believed CCS to be far more attractive than nuclear fusion power but much less than renewables. As expected, the risk for leakage from reservoirs was ranked number one of the risk options given. [Copyright &y& Elsevier]

Abstract: Three of the U.S. Department of Energy’s (DOE’s) Regional Carbon Sequestration Partnerships analyzed community perspectives on carbon capture and storage (CCS) through focus groups and interviews in five communities. These perspectives were analyzed in the context of each community’s history and its social and economic characteristics. The results were considered for their insights into specific concerns within each region, as well as to assess inter-region commonalities. In all cases, factors such as past experience with government, existing low socioeconomic status, desire for compensation, and/or perceived benefit to the community were of greater concern than the concern about the risks of the technology itself. This paper discusses the findings from the joint review of the focus groups and the potential lessons for application to CCS deployment. [Copyright &y& Elsevier]

Abstract: This paper explores the mismatch between the widely held public policy view of the long-term risk profile for carbon dioxide (CO2) storage with the emerging science and engineering of CO2 storage. We review the key issues of fit, interplay, and scalability associated with a trust fund funded by a hypothetical $ 1/ton CO2 tipping fee for each ton of CO2 stored in the United States under WRE450 and WRE550 climate policies. Left to grow unchecked, this hypothetical tipping fee fund would accumulate hundreds of billions to trillions of dollars before it would be expected to pay out claims caused by potential damage arising from CO2 storage. The authors conclude there is no intrinsic value in creating a trust fund predicated solely on collecting a tipping fee. Rather than mitigating the financial consequences of long-term CCS risks, this analysis suggests a blanket $ 1/ton CO2 tipping fee may increase the probability and frequency of long-term risk by eliminating financial incentives for sound operating behavior and site selection criteria–contribute to moral hazard. At a minimum, effective use of a trust fund requires: (1) strong oversight regarding site selection and fund management, and (2) a clear process by which the fund is periodically valued and funds collected are mapped to the risk profile of the pool of covered CCS sites. Without appropriate checks and balances, there is no a priori reason to believe that the amount of funds held in trust will map to the actual amount of funds needed to address long-term care expenses and delimited compensatory damages. [Copyright &y& Elsevier]

Abstract: As the private sector and government begin to spend billions of dollars to research and deploy carbon capture and storage (CCS) technology, the question of legal liability for managing short-term and long-term environmental, health and safety risks must be addressed. We examine potential CCS liability within a U.S. context and survey the existing environmental and tort law liability regimes that may affect CCS. We conclude that while existing liability regimes are insufficient on their own to govern the CCS industry, they could provide important risk management tools and serve as safeguards to private parties and governments in the event of harm. We also propose a model for long term stewardship, blending including bonding, insurance, and pooled federal funding into commercial CCS project management to better provide financial security to investors without destroying existing liability protections for those who may suffer harm from CCS. This proposal offers a starting point to develop a model to integrate liability for the nascent CCS industry. A longer version of this paper can be found in the Emory Law Review, Fall 2008. [Copyright &y& Elsevier]

Abstract: As a technology that may involve new risks, large-scale infrastructure, and significant government involvement, carbon capture and storage (CCS) faces a wide variety of deployment challenges. Because energy policy in the U.S. is negotiated at the state level, it is important to evaluate what might influence CCS related decisions in the U.S. at that level. This paper presents a detailed analysis of how deployment discussions and decisions regarding CCS are negotiated within Texas, Minnesota, and Massachusetts. These states were chosen based upon their current involvement in CCS research (high, medium, low), potential for deploying CCS (direct, indirect, or absent), and regulation (restructured, regulated). We explore nuances within the policy debates and public discourse surrounding CCS in these three states through the use of legislative and policy analysis, interviews with stakeholders, and media analysis. Using information generated from legislative dockets and state-level newspaper coverage we construct a template of CCS discussions, framing, and policy creation within each study state. [Copyright &y& Elsevier]

Abstract: This paper provides a financial analysis for new supercritical pulverized coal plants with carbon capture and sequestration (CCS) that compares the effects of two relevant climate policies. First, an updated cost estimate is presented for new supercritical pulverized coal plants, both with and without CCS. The capital cost escalation of recent years can be attributed to rising materials, plant supply, and plant contractor constraints. This estimate is then compared with recent estimates from public sources. Second, several current and proposed public policies relevant to CCS are presented. Finally, a financial analysis is performed to evaluate the effectiveness of two likely US carbon regulations on deploying Nth-plant CCS technology. The major conclusion is that the leading US carbon cap-and-trade bills will likely not be sufficient to deploy CCS technology in a manner consistent with a 550 ppm CO2 stabilization scenario. A more aggressive carbon policy including CCS research, development, and demonstration must be considered to achieve this goal with significant CCS deployment. [Copyright &y& Elsevier]

Abstract: Plug-in hybrid electric vehicles (PHEVs) have the potential to be an economic means of reducing direct (or tailpipe) carbon dioxide (CO2) emissions from the transportation sector. However, without a climate policy that places a limit on CO2 emissions from the electric generation sector, the net impact of widespread deployment of PHEVs on overall US CO2 emissions is not as clear. A comprehensive analysis must consider jointly the transportation and electricity sectors, along with feedbacks to the rest of the energy system. In this paper, we use the Pacific Northwest National Laboratory MiniCAM model to perform an integrated economic analysis of the penetration of PHEVs and the resulting impact on total US CO2 emissions. Under the assumptions used in this analysis where PHEVs obtain 50–60% of the market for passenger and light-duty trucks, the ability to deploy PHEVs under the two climate policies modeled here results in 6000–7300 Mt CO2 of additional cost -effective emissions reductions from the US economy over the period 2005–2050. The additional demand for geologic CO2 storage created by the introduction of the PHEVs is approximately equal to the cumulative geologic CO2 storage demanded by two to three large 1000 MW IGCC+CCS power plants over a 50 -year period. The introduction of PHEVs into the US transportation sector, coupled with climate policies such as those examined here, can also reduce US demand for oil by 20–30% by 2050 compared to today’s levels. [Copyright &y& Elsevier]

Abstract: Interest is growing regarding the potential size of a future U.S.-dedicated carbon dioxide (CO2) pipeline infrastructure if carbon dioxide capture and storage (CCS) technologies are commercially deployed on a large scale within the United States. This paper assesses the potential scale of the CO2 pipeline system needed under two hypothetical climate policies (WRE450 and WRE550 stabilization scenarios); a comparison is then made to the extant U.S. pipeline infrastructures used to deliver CO2 for enhanced oil recovery and to move natural gas and liquid hydrocarbons from areas of production and importation to markets. The analysis reveals that between 11,000 and 23,000 additional miles of dedicated CO2 pipeline might be needed in the United States before 2050 across these two cases. While either case represents a significant increase over the 3900 miles that comprise the existing national CO2 pipeline infrastructure, it is important to realize that the demand for additional CO2 pipeline capacity will unfold relatively slowly and in a geographically dispersed manner as new dedicated CCS-enabled power plants and industrial facilities are brought online. During the period 2010–2030, this analysis indicates growth in the CO2 pipeline system on the order of a few hundred to less than 1000 miles per year. By comparison, during the period 1950–2000, the U.S. natural gas pipeline distribution system grew at rates that far exceed these growth projections for a future CO2 pipeline network in the U.S. This analysis indicates that the need to increase the size of the existing dedicated CO2 pipeline system should not be seen as a major obstacle for the commercial deployment of CCS technologies in the United States. While there could be issues associated with siting specific segments of a larger national CO2 pipeline infrastructure, the sheer scale of the required infrastructure should not be seen as representing a significant impediment to U.S. deployment of CCS technologies. [Copyright &y& Elsevier]

Abstract: A core mission of the U.S. Department of Energy’s (DOE) Carbon Sequestration Program is to foster the development of commercially-ready technologies for CO2 capture and sequestration. An R&D program goal of 90% carbon capture, at an increase in the cost of electricity (COE) no greater than 10% above current state-of-the-art designs without capture, has been established for electric power generation from next-generation Integrated-Gasification Combined-Cycle (IGCC) plants. Advanced gas separation membranes for separating H2 from CO2 are one possible technology for achieving these goals. For IGCC CO2-capture applications, membranes will need to out-perform existing chemical and physical absorption processes. Gas separation membranes, however, can be integrated into a number of different locations in the IGCC process in addition to post water-gas-shift (WGS), the preferred location for current absorption technologies. Due to the many integration options possible, membranes could potentially be required to operate over a wide range of conditions. It is preferred that the membrane operate at pressures and temperatures normally encountered at that point in the IGCC flowsheet where it is being placed. And, clearly it is beneficial that the membrane be placed in a location with relatively high pressure in order to maximize separation. If this is possible, the feed and product gases need not be compressed/expanded or heated/cooled. In addition, membrane materials being considered, whether ceramic, metallic or polymeric, have physical and chemical limitations in regards to operating temperature and tolerance to various compounds that might be present in synthesis gas. It is therefore unlikely that one type of membrane will be able to perform over the entire range of conditions possible. In this paper, we identify preferred membrane locations and quantify performance requirements for a wide range of membrane materials currently under consideration for H2/CO2 separation. [Copyright &y& Elsevier]