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The Midwest Regional Carbon Sequestration Partnership (MRCSP) is implementing a commercial-scale carbon capture and storage (CCS) project in multiple Silurian carbonate pinnacle reefs in northern Michigan that are in various phases of enhanced oil recovery. This paper presents analyses of five pressure fall-off tests performed sequentially during the injection of 166,000 tonnes of CO 2 into a Type-1 (depleted) reef which has undergone primary and secondary production. Bottom-hole pressures were monitored in the injection well and in two observation wells to record progressively increasing reservoir pressure during the injection period, which also included five fall-off tests. Pressure data were analyzed using combined history-matching and pressure derivative matching techniques implemented with a commercial well-test interpretation program, FAST WellTest™. The paper illustrates the challenges of consistently interpreting CO 2 injection fall-off tests under multi-phase flow with varying pressure conditions using a single-phase analytical model. This work is relevant to CO 2 sequestration in depleted oil reservoirs because regular fall-off testing is required under the U.S. Environmental Protection Agency's Underground Injection Control (UIC) Program for CO 2 geologic sequestration (75 FR 77230). [ABSTRACT FROM AUTHOR]

Abstract: In 2007, the Norwegian prime minister made the promise that a ‘lunar landing’ was due at Mongstad Refining in 2014, involving full-scale cleaning of CO2. This was the prelude to a long and heated debate on Carbon Capture and Storage (CCS) in Norwegian media. Through a discourse analysis we have identified two main media discourses related to the announced lunar landing; including important participants and arguments, as well as the positions taken by the actors of the discourses. The paper outlines the underlying structures of the public debate about CCS, and argues that the discourse is not really about CCS but politics in the form of narratives on promises, alliances and emotions caused by political actions. The paper shows the importance of media discourses for the legitimacy and willingness to finance CCS R&D. [Copyright &y& Elsevier]

Abstract: This paper describes an operability analysis and control structure design for handling membrane leakage in a hydrogen membrane reactor (HMR) as used in an integrated reforming combined power cycle (IRCC) based on natural gas as fuel. For this type of reforming to be competitive to power generation with carbon capture, low costs and emission of CO2 and NOx is required. Further, high operability and robustness is also required. This is achieved through an understanding of the system dynamics and robust control structure design. The overall aim of the work is to improve the operability of such gas power plants under membrane leakage, which may cause detrimental hot areas in the reactor. Good operability means essentially that a plant can be operated easily, i.e. it can cope with disturbances, offsets and other uncertainties with the smallest possible profit loss and without frequent shutdowns. This is obtained both through design of the process itself and design of the control system. An important ingredient is the use of a dynamic, control relevant simulation model. The paper presents an analysis of how the control objective affects the choice of control structure for the HMR process and the control performance under membrane leakage. Also, the effect on CO2 capture is shown. [Copyright &y& Elsevier]

Abstract: The increasing atmospheric carbon dioxide concentration has lead to concerns about global warming. One of the options that can contribute to the reduction of carbon dioxide emissions is CO2 sequestration by mineral carbonation. In this paper we will present a model of an oxyfuel combustion process integrated into a carbonation process using Mg(OH)2 produced from magnesium silicate mineral. Therefore, the objective of this work is to develop integrated carbon dioxide capture and storage methods for an oxyfuel combustion process where CO2 will be captured directly from the flue gas in a carbonation reactor. There it reacts with injected magnesium hydroxide Mg(OH)2 solid, with thermodynamically stable MgCO3 as the final product. In this paper we will present a process model that illustrates how the carbonation process integrated into oxyfuel combustion could be an alternative process for oxyfuel combustion followed by geological storage of CO2. We will also present a simulation model for this process by using Aspen Plus® simulation software. [Copyright &y& Elsevier]

Abstract: Carbon capture and storage (CCS) has been identified as a critical enabling technology to mitigate the large quantities of carbon dioxide (CO2) emitted from coal-fired power plants and subsequently discharged to the atmosphere. While large-scale CO2 injection in geologic formations associated with enhanced oil recovery operations have been ongoing for over 30 years, different technical challenges face the injection of CO2 into saline reservoirs sourced from utility boilers. Beyond the high costs of capture, operational reliability related to the integration of capture with pipeline transport and injections are components of CCS with very little operational experience. Some issues unique to utility boiler capture include planned and forced outages, generation loading, and changes in CO2 purity. These operational issues can only be resolved through the integration of capture, transportation, and injection operations in demonstration-scale projects. Parametric testing provides an opportunity to evaluate how the integration of transportation and injection for storage respond to changes in plant operations. This paper will introduce a CCS demonstration-scale research program that involves a carbon capture unit designed to supply up to 500 metric tons (tonnes) per day (182,500 tonnes per year), a 19-kilometer pipeline and injection into a subsurface saline reservoir located at 3,060 meters below ground surface. The project will provide a test bed to begin to understand and resolve the challenges of integrating the key components of CCS with utility boilers. The paper will provide an update on the status of the project, covering the permits required to get the demonstration in motion, the geologic assessment of the proposed injection target reservoirs, and the engineering design for the injection and monitoring program. [Copyright &y& Elsevier]

Abstract: With the increasing concern about climate change, the public, industry and government are showing increased interest towards reduction of CO2 emissions. Geological storage of CO2 is perceived to be one of the most promising methods that could allow significant reduction in CO2 emissions over the short and medium term. One major concern against geological storage of CO2 is the possibility of its leakage. Carbon dioxide under the pressure and temperature conditions encountered in typical deep aquifers remains more buoyant than water. One process that could lead to permanent trapping of CO2 is one that includes geochemical reactions leading to the formation of solid minerals. However, the time-scale of such reactions is perceived to be centuries to millennia. In contrast, the kinetics of CO2-hydrate formation–that leads to trapping of CO2 in the solid form–is quite fast, providing the opportunity for secure storage of CO2. In this paper and its companion, two different geological settings that are suitable for formation of CO2 hydrate are investigated. In this paper storage of CO2 beneath the ocean floor is studied, while storage in depleted gas reservoirs is studied in the companion paper. It has been suggested that CO2 may be accumulated in the depressions on the ocean floor, where pressure and temperature conditions are such that either liquid CO2 would accumulate or CO2 hydrates would form. However, there have been significant concerns about the accompanying change in pH and its adverse effect on the ocean ecosystem. In this paper, permanent trapping of CO2 at a depth of a few hundred meters beneath the ocean floor, where the CO2 is thought to be of little or no harm to the ocean ecosystem, is studied. Based on density calculations, Schrag and his co-workers have shown that for oceans that are deeper than approximately, CO2 density at the ocean floor is more than the surrounding water. With increased depth below the ocean floor and as a result of increased temperature, the density of CO2 reduces faster than that of water such that at some depth below the ocean floor, CO2 will be lighter than the surrounding water. Injection of CO2 at such depths or deeper intervals will lead to rise of the CO2 until it arrives at a depth where its density becomes heavier than water. The zone above this depth, where CO2 becomes heavier than water is called the negative buoyancy zone. Beneath the negative buoyancy zone, the CO2 is naturally trapped by a gravity barrier. Furthermore, as CO2 is rising towards this depth, it could pass through conditions where CO2 hydrates form. Formation of CO2 hydrate will further reduce formation permeability and introduce a second barrier against CO2 rise, even before it arrives at the boundary of the negative buoyancy zone. Under dynamic conditions of injection and hydrate formation, the initial state of pressure and temperature is perturbed, affecting the negative buoyancy zone. Simulation studies are presented to investigate (i) the changes in pressure as a result of injection that could push CO2 upwards into the negative buoyancy zone, and (ii) the increase in temperature as a result of formation of hydrates. Through a case study, we report numerical simulation studies that indicate that injection of CO2 at a depth of approximately 800 m below the ocean floor leads to the rise of CO2 until a depth of approximately 360 m below the ocean floor, where hydrates will form reducing the formation permeability. Any CO2 that might migrate further upwards could do so for another 135 m before it arrives at the negative buoyancy zone. These simulation studies suggest that total CO2 emissions of large power plants may be stored at such a site. [Copyright &y& Elsevier]

Abstract: The significant CO2 pipeline and CO2 injection well infrastructure developed in the United States over four decades of underground injections of CO2 for Enhanced Oil Recovery (“EOR”) operations was accompanied by development of a legal and regulatory framework for the incidental geologic storage of CO2 during EOR operations. That framework currently forbids incremental injections of anthropogenic CO2 beyond those required for oil recovery but that could be injected for the sole purpose of reducing atmospheric emissions of CO2. This paper summarizes some key aspects of the current legal and regulatory framework applicable to the transportation and underground injection of CO2 in connection with EOR operations and identifies those elements that are adequate to support CO2 transport and injection for carbon capture and storage (“CCS”) purposes. The paper next discuses regulatory changes underway that are intended to fill the regulatory gaps to allow for incremental injections of CO2 in the CCS context. Particular attention is paid to the current rulemaking proceedings before the USA Environmental Protection Agency governing permitting of CO2 injection wells for CCS purposes as well as some approaches to addressing potential regulation of CO2 pipelines and related matters. In concluding, the paper seeks briefly review the status of transposition of the European Union’s CCS Directive into binding national norms and points out some contrasts with the USA experience due to the absence of an EOR industry in Europe. [Copyright &y& Elsevier]

Abstract: Climate change mitigation is a dynamic area that, as it is addressed, brings new challenges to other environmental aspects. Carbon capture and storage (CCS) plants are the latest development in a series of environmental controls and have some distinctive features that could potentially lead to other wider environmental problems. Whilst CCS represents a significant step towards cutting greenhouse gas emissions, consideration needs to be given to the potential wider environmental consequences especially in terms of pollutant emissions and local air quality impacts. Challenges remain for existing plants which will need to consider the most cost-effective strategies for installation of CCS plant balanced against managing air quality impacts as dispersion characteristics change. In the case of post-combustion carbon dioxide (CO2) capture technology, which is the focus of this paper, removal of CO2 from the main flue gas stream requires diversion of the flue gas through the CCS process, before it arrives at the exhaust stack. This flue gas stream may be all or part of the total plant flow or for multi-unit plants may be diverted from specific power generation units into the CCS plant before exhausting to atmosphere, either through returning back to the existing stack or through a new dedicated stack. This diversion and subsequent emission in itself poses an engineering challenge. In particular, the integration of the CCS process with the existing plant must also ensure that the diverted flue gas still achieves adequate dispersion as it contains residual levels of pollutants such as nitrogen oxides (NOx) and sulphur dioxide (SO2), despite the fact that the CCS process itself may reduce some of these pollutant levels further as a process by-product. Power plants which incorporate CCS will still be required to adhere to the appropriate pollutant emission limits and ensure effective dispersion to minimise the risk of breaching local air quality standards. This paper draws on experience gained through post-combustion CCS projects and addresses the potential effects of CCS on air quality, in the case of carbon capture retrofits. The findings of this paper are relevant to project developers, power generators and policymakers globally who have an interest in the potential for CCS to provide an emissions abatement option for existing thermal assets in the short and long term. [Copyright &y& Elsevier]

Abstract: With the growing concern about climate change, interest towards reducing CO2 emissions has increased. Geological storage of CO2 is perceived to be one of the most promising methods that could provide significant reduction in CO2 emissions over the short and medium term. Since a major concern regarding geological storage is the possibility of leakage, trapping CO2 in the solid form is quite attractive. Unlike mineral trapping, the kinetics of CO2-hydrate formation is quite fast, providing the opportunity for long-term storage of CO2. In this paper, we study storage of CO2 at conditions similar to those at depleted gas pools of Northern Alberta. Thermodynamic calculations suggest that CO2 hydrate is stable at temperatures that occur in a number of formations in Northern Alberta, in an area where significant CO2 emissions are associated with production of oil sands and bitumen. Numerical simulation results presented in this paper suggest that, upon CO2 injection into such depleted gas reservoirs, pressure would initially rise until conditions are appropriate for hydrate formation, enabling storage of large volumes of CO2 in solid form. These results show that, because of tight packing of CO2 molecules in the solid (hydrate), the CO2 storage capacity of these pools is many times greater than their original gas-in-place. This provides a local option for storage of a portion of the CO2 emissions there. [Copyright &y& Elsevier]

Abstract: As CO2 is injected into a deep saline aquifer, three regions develop: A “drying” region next to the well in which CO2 injectate occupies 100% of the pore space, a brine region away from the injection well in which 100% of the pores are saturated with brine, and a two-phase region in which water and CO2 coexist. Several papers describe the speeds at which those two fronts progress outward using the Buckley-Leverett fractional flow (BLFF) theory. Next to a CO2 injection well and at early times, compositional flow theory must be implemented. It is also understood that far from the injection site, where only slight pressure elevation is felt, a single phase flow approach is sufficient because all the complexities of compositional flow could be neglected. However regulators may be wary of complex models and of the associated black box syndrome and rather may favor the simpler single-phase flow approach. This paper investigates using single-phase flow numerical models to describe compositional flow processes. Previous work already showed that results from the CMG-GEM and MODFLOW numerical codes are very similar away from the injection zone given some minor modifications in the input file of the single-phase flow code. We present a more thorough scoping analysis aiming at establishing the proposition that single-phase flow models (CMG-IMEX), given some simple treatment, can predict pressure increase as well as more complex compositional flow models (CMG-GEM). [Copyright &y& Elsevier]

Abstract: Integrated Gasification Combined Cycle (IGCC) is a technology for power generation in which the feedstock is partially oxidized with oxygen and steam to produce syngas. In a conventional IGCC design without carbon capture, the syngas is purified for dust and hydrogen sulphide removal and then sent to a Combined Cycle Gas Turbine (CCGT) for power production. The hot GT flue gases are sent to Heat Recovery Steam Generator (HRSG) for steam generation. Additional power is produces by expanding the steam generated in a steam turbine. Carbon capture and storage (CCS) technologies are expected to play a significant role in the coming decades for reducing the greenhouse gas emissions. Integrated Gasification Combined Cycle is one of the power generation technologies having the highest potential to capture carbon dioxide with the low penalties in term of plant energy efficiency and cost. The modification of the IGCC design for carbon capture can be done in various plant concepts considering the carbon capture method to be used (e.g. pre- and post-combustion capture, syngas chemical looping etc.). This paper investigates various carbon capture methods suitable to be applied for an IGCC plant for power generation. The coal blended with biomass (sawdust) based IGCC case study investigated in the paper produces around 400–500 MW net electricity with more than 90% carbon capture rate. An important focus of the paper is concentrated on overall energy efficiency optimization of the IGCC plant concepts with various carbon capture options by better heat and power integration of the main plant sub-systems (e.g. steam integration between gasification island, syngas conditioning line and the steam cycle, influence of heat and power demand for Acid Gas Removal unit etc.). A particular attention of the paper is focused on the quality specification for the captured carbon dioxide stream considering various capture options but also the storage options (enhanced oil recovery, storage in depleted oil and gas fields, saline aquifers etc.). [Copyright &y& Elsevier]

Abstract: In this paper, the possibilities and conditions for CCS applications in Finland are assessed. The study includes an overview of Finland’s current climate and energy policy framework, mapping of large CO2 emission point sources and identification of possible CO2 transportation and storage alternatives. The future role of CCS in the Finnish energy system is further assessed with energy and emission scenarios created with a comprehensive model called TIMES-Nordic. There are several large CO2 emission sources in Finland that could be potential candidates for CCS, including steel works, power and heat generating plants, as well as oil refineries. In 2008, the 12 largest facilities in the Finnish emission trading registry accounted for 30% of the total CO2 emissions in Finland. Since the Finnish bedrock is not suitable for large-scale geological storage of CO2, captured CO2 would most likely have to be transported to the North Sea or Barents Sea for long-term storage. Most of the largest CO2 emitting facilities are located on the coast line of Finland, which facilitates transportation of CO2 by ship. The current Finnish climate and energy policy largely focuses on increasing the share of renewable energy and nuclear power in energy conversion, which leaves less room for CCS. The preliminary results from the scenario calculations indicate that the share of CO2 mitigation by CCS in Finland would be less than 10 Mt/a CO2 by 2050. However, Finland has also large, stationary CO2 emissions originating from biomass combustion in the pulp and paper industry. When assuming that biogenic CO2 emissions would be included into the emission trading system, the CCS potential rises up to 18 Mt/a CO2 by 2050. [Copyright &y& Elsevier]

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: The storage of CO2 in deep saline aquifers is due to the large available capacities and the common occurrence of these formations one of the major options for carbon dioxide sequestration. Besides the multiphase flow aspects geochemical, thermal and mechanical processes may alter the conditions within the reservoir as well as in the cap rock. Whereas single aspects of these processes can be investigated with experiments a multi-process simulator allows evaluating their combined consequences for the storage system over short and long time scales. In this paper the newly coupled software ECLIPSE-OpenGeoSys is presented that allows a combined simulation of multiphase flow, transport and geochemical reactions. ECLIPSE provides a fast and efficient solution for the multiphase flow whereas the open-source scientific software OpenGeoSys is used for calculating transport and geochemical reactions. This paper presents the code structure of the interface. Furthermore the coupled software is successfully applied to benchmarks [Copyright &y& Elsevier]

Abstract: Most projected climate change mitigation strategies will require a significant expansion of CO2 Capture and Sequestration (CCS) in the next two decades. Four major categories of challenges are being actively researched: CO2 capture cost, geological sequestration safety, legal and regulatory barriers, and public acceptance. Herein we propose an additional major challenge category across all CCS operations: Water management. For example a coal-fired power plant retrofitted for CCS requires twice as much cooling water as the original plant. This increased demand may be accommodated by brine extraction and treatment, which would concurrently function as large-scale pressure management and a potential source of freshwater. At present the interactions among freshwater extraction, CO2 injection, and brine management are being considered too narrowly -in the case of freshwater almost completely overlooked- in the technical and regulatory CCS community. This paper presents an overview of each of these challenges and potential integration opportunities. Active management of CCS operations through an integrated approach -including brine production, treatment, use for cooling, and partial reinjection- can address challenges simultaneously with several synergistic advantages. The paper also considers the related potential impacts of pore space competition (with future groundwater use, gas storage and shale gas) on CCS expansion. Freshwater and brine must become key decision making inputs throughout CCS operations, building on existing successful industrial-scale integrations. [Copyright &y& Elsevier]

Abstract: The European CCS Demonstration Project Network was initiated by the European Commission in 2009. The main objective of the network is to accelerate development of CCS technologies by creating a forum for exchange and dissemination of new knowledge generated by the first large scale CCS plants in Europe. This paper provides an overview and understanding of the activities of the network and the political and theoretical context of their development. The paper focuses on how the Network has been structured to add value to demonstration projects and create vital new channels of information for enabling CCS demonstration and deployment to be advanced worldwide. [Copyright &y& Elsevier]

Abstract: The Netherlands is both heavily dependent on the success of carbon capture and storage (CCS) and renewable electricity for its decarbonisation policy. The same holds for the EU and some of its Member States like the United Kingdom. This paper discusses several scenarios for the Netherlands within the context of a liberalised and a more and more connected energy market in Northwest-Europe. The research reported here shows that CCS on new coal fired power plants does not pose a threat to the increase in the electricity production by large quantities of wind energy in the electricity system, and vice versa. For renewable energy, several additional policies are in place mainly in the form of financial support as long as these renewable options are not yet profitable. For CCS, financial support is only granted now for a selection of the first demonstration projects now planned in the EU. It is not yet clear if large scale CCS and high shares of wind energy can be incorporated in a balanced way in the electricity system. This paper shows that from a technical and economic point of view, there is room for both, and under which conditions such a two fold growth will be feasible. [Copyright &y& Elsevier]

Abstract: CO2 avoidance cost economics are an essential tool for analysis of the potential for future CO2 capture and storage (CCS) utilization. The CO2 avoidance cost is the CO2 tax at which the product cost is the same for either a fossil fuel plant without CO2 mitigation (but paying the CO2 tax) or the same fossil fuel plant that includes the added capital and efficiency losses of adding CCS (but avoiding most of the CO2 tax). The CO2 tax must be higher than this CO2 avoidance cost to justify the higher risks, capital, and lower efficiency of utilizing CCS. Understanding which issues impact CO2 avoidance costs the most is fundamental to economically encouraging the massive CO2 reductions enabled with CCS. SFA Pacific recently completed two similar economic analyses of coal-based power plant CO2 mitigation costs. Both analyses included the options of converting to lower CO2 emissions with natural gas (with and without CCS) and continued coal use with and without CCS. One analysis was for an existing coal-based power plant baseline as part of a Massachusetts Institute of Technology (MIT) Workshop and Report entitled Retrofitting of Coal-Fired Power Plants for CO2 Emissions Reductions . The second analysis was for a new coal-based power plant baseline as part of an analysis of CO2 mitigation options by the U.S. Business Roundtable entitled The Balancing Act: Climate Change, Energy Security and the U.S. Economy . However, the resulting CO2 avoidance costs for these two analyses were very different. Specifically, the CO2 avoidance cost was about twice as high for the existing coal power plant than for the new coal power plant baseline. There are basic technical and economic reasons for this big difference in CO2 avoidance costs. They are best explained by simply showing the costs and performance of each baseline without and then with CCS in simple, transparent, and consistent one-page models. This enables easy, insightful side-by-side direct comparisons. Since first developing a cost and performance economic screening model of CCS for our GHGT-4 paper in 1998 , SFA Pacific has continued to improve the model which focuses on objectivity by stressing transparency and consistency with easy to compare cases. SFA Pacific has clearly shown identical inputs for key items such as fuel costs, non-fuel operating costs, unit capital costs, contingencies, site location factors, cost indexes, and especially capital charges. This makes it easy to see that power costs for the existing coal power plant baseline can be very low when the power plant is old and most of the existing capital is already paid-off. This GHGT-10 paper presents the most updated SFA Pacific analysis of CCS retrofit for existing coal power plant CO2 mitigation. The paper focuses on showing and explaining why the CO2 avoidance costs can be much higher for the existing plants versus new fossil fuel power plants. CO2 taxes which are high enough to discourage new coal power plants with high CO2 emissions would likely have little or no impact on existing coal power plants. Until the over 1,200 GW of existing old coal power plants begin reducing their high CO2 emissions, there can be little net reduction in worldwide CO2 growth. Converting or replacing this large capacity of existing coal power plants is essential to obtaining large CO2 reductions . [Copyright &y& Elsevier]

Abstract: This paper presents an overview of the wellbore integrity research component of the IEA GHG Weyburn-Midale CO2 Monitoring and Storage Project. The Weyburn and Midale fields are located adjacent to one another in southeast Saskatchewan, Canada, and have been undergoing full-scale CO2 flooding starting in 2000 and 2005, respectively. Given that there are over four thousand wellbore penetrations in these fields, combined, effective implementation of CO2 storage requires an understanding of the hydraulic properties of these wellbores, their response to CO2 exposure, appropriate tools for monitoring their performance, and knowledge of appropriate remediation options. The objectives of the wellbore integrity research program in this project are all oriented towards developing an understanding of these issues, and towards documenting this information in the Project’s Best Practices Manual. Research activities summarized in this paper include an overview of a downhole testing program which is planned for October 2010, a review of literature and regulatory policies on current practices in oil and gas production and injection which are relevant to wellbore integrity in CO2 storage projects, and the development of a wellbore database and its use in support of a ranking system to classify wells based on their potential for leakage and a ‘life of well’ numerical modelling project. [Copyright &y& Elsevier]

Abstract: After 3 years and over one thousand person-months of effort, the FP6 CACHET project was successfully concluded in the first half of 2009. CACHET focussed on pre-combustion capture of carbon dioxide (CO2) from natural gas fuelled power generation and hydrogen (H2) production. Through a combination of experimental and paper studies, CACHET developed, optimised and evaluated four promising capture technologies: Advanced steam methane reforming (HyGenSys), Redox technologies (chemical looping), Metal membranes and Sorption enhanced water gas shift (SEWGS). This paper reports the technical and economic conclusions of the project and provides a look ahead to the future for each of the technologies and the challenges for full scale deployment. All technologies showed the potential to reduce CO2 emissions by more than 90% and the opportunity to improve the energy efficiency compared to the state-of-the-art technology. [Copyright &y& Elsevier]

Abstract: This paper evaluated the economic effects of introducing flexibility to state-of-the-art integrated gasification co-generation (IG-CG) facilities equipped with CO2 capture. In a previous paper the technical and energetic performances of these flexible IG-CG facilities were evaluated. This paper investigated how market conditions affect the economics of flexible IG-CG facilities by analyzing several case studies. The IG-CG facilities used Eucalyptus wood pellets, torrefied wood pellets and Illinois #6 coal as feedstock and produced electricity, FT-liquids, methanol and urea. Results indicated that currently biomass is, compared to coal, too expansive. Therefore, feedstock flexibility is not attractive. Production flexibility between chemical and electricity production under current economic conditions reduces the profitability of the IG-CG facility. Therefore, with state-of-the-art technology and the current economic climate, introducing flexibility to IG-CG facilities is not economically profitable. [Copyright &y& Elsevier]

Abstract: This paper discusses the current status of CCS in China, providing an update of current projects and past activities in research and development, and a brief overview of prospects for CCS deployment in China. CCS related research in China has been building from a focus on research and development and exploration of the technical considerations o f CCS potential in China in coordination with international partners. While large scale demonstration of integrated CCS projects is still at an early stage, there is significant knowledge and technical expertise that can be derived from ongoing pilot projects. These projects employ various mature technologies that may be integrated and scaled to facilitate demonstration and deployment of CCS in the future. In addition, China is increasingly exploring opportunities in CO2 utilization to drive and support deployment of CCS–this is also known as CO2 capture, utilization and storage (CCUS). This paper provides information on some of these key activities, including details of specific projects and a background of the regulatory and policy frameworks and international cooperation on CCS and CCUS in China. [Copyright &y& Elsevier]

Abstract: A significant proportion of the research into CCS in the literature assumes ‘complete capture’ of the CO2, that is at least 85 to 90 percent of the CO2 from the flue gas is captured for the entire operating year (7,000 to 8,000 hours). Only a few papers have examined a model involving ‘flexible’ operation of the capture facility in which the CO2 is captured at variable or reduced rates for all or part of a day, week, season or year. This paper presents an assessment of the operational opportunities for deploying flexible CO2 capture at black coal fired power plants located in the state of New South Wales (NSW), Australia. Different models of flexible capture including part-time operation, partial CO2 capture rates and a combination of both operating modes are examined. The results show that it may be possible to reduce the current CO2 emissions from NSW coal-fired power plants by up to 50% during summer while still meeting the state electricity demand. The estimated cost of CO2 avoided ranges from A$120 to A$190 per tonne avoided for flexible capture. [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 CCS Roadmap highlighted the significance that CCS will need to play in achieving an atmospheric CO2 concentration stabilization of 450 ppm. In the scenario it is based on, CCS will provide approximately 20% of the total CO2 emissions reductions out to 2050. Achieving this contribution of emissions reductions will require an ambitious CCS growth-path, with 100 projects needed globally by 2020 and over 3000 by 2050. In both 2020 and 2050 the major developing countries, including South Africa will need to contribute to CCS deployment. South Africa has a heavily coal-dependent economy with 94 % of electricity production coming from coal. In addition to this, South Africa also meets approximately 30% of its domestic fuel -oil demand through the conversion o f coal and gas to transportation fuels. The combination of these two factors means that South Africa is as dependant on coal as any country in the world, placing the country as the 13th largest CO2 emitter in the world. Currently South Africa is experiencing electricity shortages where the reserve margin is below desired levels on a daily basis. Consequently, deployment of electricity generation capacity is seen as a priority. With the slow development of renewable energy and the deployment of nuclear energy currently under review, the required short term increase in electricity production is likely to come from new, coal plant that will be expected to be in operation for 50–60 years, thus continuing the country’s dependence on coal for some time to come. At the climate change negotiations in Copenhagen, South Africa announced that it would take nationally appropriate mitigation actions to enable a reduction in national GHG emissions equating to a deviation of 34% below the “Business as Usual” emissions growth trajectory by 2020 and a 42% deviation below the below “Business as Usual” emissions growth trajectory by 2025, pended upon the provision of sufficient funding and technology support. Given all these factors, CCS could be a crucial technology for South Africa in the near future. This paper looks to discuss the current status of CCS in South Africa. This includes looking at the key outcomes of the recently released South African CCS Research and Development Roadmap and the milestones it outlines, such as the development of a geological storage atlas by 2010, a CO2 test injection by 2016, and a demonstration project operating by 2020. It also looks at how the South African government is positioned toward CCS, including how CCS fits with the countries priorities of poverty alleviation, economic growth, sustainable development, job creation and ensuring the most efficient use of domestic resources. In addition the paper looks at the manner in which the South African government could go about regulating the operation of CCS projects. The paper will discuss the options available to South Africa to fund CCS demonstration and deployment domestically including via the clean development mechanism (in the event that the question of using this mechanism in the CCS context is dealt with at the international level), development banks and other, appropriate, development finance institutions. Public awareness and engagement on CCS will also be covered, given the crucial role the public play in the smooth progress of projects. Finally the paper will look at international collaboration on CCS including the role South Africa can play internationally and what more the international CCS community can offer. [Copyright &y& Elsevier]

Abstract: Surface deformation monitoring provides unique data for observing and measuring the performance of producing hydrocarbon reservoirs, for Enhanced Oil Recovery (EOR) and for Carbon Capture and Storage (CCS). To this end, radar interferometry (InSAR), particularly multi-interferogram Persistent Scatterer (PS) techniques, such as PSInSAR™, are innovative, valuable and cost-effective tools. Depending on reservoir characteristics and depth, oil or gas production can induce surface subsidence or, in the cases of EOR and CCS, ground heave, potentially triggering fault reactivation and in some cases threatening well integrity. Mapping the surface effects of fault reactivation, due to either fluid extraction or injection, usually requires the availability of hundreds of measurement points per square km with millimeter-level precision, which is time consuming and expensive to obtain using traditional monitoring techniques, but can be readily obtained with InSAR data. Moreover, advanced InSAR techniques developed in the last decade are capable of providing millimeter precision, comparable to optical leveling, and a high spatial density of displacement measurements over long periods of time, without the need for installing equipment or otherwise accessing the study area. Until recently, a limitation to the application of InSAR was the relatively long revisiting time (24 or 35 days) of the previous generation of C-band satellites (ERS1-2, Envisat, Radarsat). However, a new generation of X-band radar satellites (TerraSAR-X and the COSMO-SkyMed constellation), which have been operational since 2008, are providing significant improvements. TerraSAR-X has a repeat cycle of 11 days, while the joint use of two sensors of the COSMO-SkyMed constellation have an effective repeat cycle of just 8 days. With the launch of the fourth satellite of the constellation, in 2010, COSMO-SkyMed will have an effective revisiting time of just 4 days, allowing “near real-time” applications. Indeed, by combining two acquisition geometries (e.g. data acquired along ascending and descending orbits), it will be possible, on average, to have a new scene over the area of interest every other day. Additional advantages of the new X-band satellites are: A higher sensitivity to target displacement and a higher spatial resolution (the density of measurement points can be increased by an order of magnitude, possibly exceeding 2,500 PS/km2). In this paper, we present some examples of the application of X-band SAR data to reservoir monitoring. Special attention will be given to CCS projects where InSAR data could become a “standard” monitoring tool. The paper will highlight the technical features of the new sensors, the possible synergy between TerraSAR-X and COSMOSkyMed data, as well as the importance of a careful analysis of atmospheric disturbances affecting SAR data covering the area of interest, in order to retrieve high quality displacement data. Finally, some conclusions will be drawn supporting recommendations about future CCS monitoring programs. [Copyright &y& Elsevier]

Abstract: In recent years debates about public involvement in the decision making process regarding science and technology have been the focus of much debate. This paper uses the deployment of carbon capture and storage technology as a case study to explore both the theoretical and practical reasons why the public need to be consulted on such issues. It concludes that a social contract approach is far more effective than the traditional technocratic approaches as it ensues the lay public are fully informed and understands the rational behind the decisions. Furthermore, if deliberative approaches are employed it provides people with the opportunity to enter in to debate with experts, decide whether they are trustworthy and take ownership of the decisions. As this paper demonstrates when the issues are highly complex and controversial, as they are with CCS, such approaches offer an effective way of communicating information and can significantly reduce opposition aiding implementation. [Copyright &y& Elsevier]

Abstract: This paper develops an interdisciplinary framework to assess the different dimensions of uncertainties which surround the development of carbon capture and storage (CCS). It includes technical, economic, financial, political and societal uncertainties about CCS and develops methods for assessing these uncertainties. It also identifies important linkages between uncertainties. This generic framework aims to help decision making on CCS by private and public actors. The paper is based on a systematic review of the social science literature on CCS and on broader insights from innovation studies. [Copyright &y& Elsevier]

Abstract: Various methodologies are proposed to reduce CO2 emissions that are believed to be the main drivers of the climate change. CO2 capture and storage in deep underground formations is one of the promising methods that allow reducing the emissions while continuing the use of fossil fuels. Injection of immense quantities of CO2 is required to make a reasonable cut of the emissions. Deep saline aquifers can provide the capacity to accommodate the storage of such huge amounts of CO2. However, one of main challenges in deployment of CO2 storage is the risk of CO2 leakage through pathways in the cap-rock overlying the target aquifer. The sealing capacity of the cap-rock must be evaluated to ensure the safety of the storage. Therefore, characterization of the cap-rock is required to find the potential leakage pathways even before the CO2 storage begins. Methods to characterize the leakage pathways are proposed at two different scales: 1- By point sampling of the cap-rock and testing the potential pathways such as abandoned wells, 2- by analysing geophysical (e.g. 3-D seismic) data to estimate paths of upward migration of the injected CO2. Flow based methods have the potential for bridging the large gap that exists between the length scale of these two approaches. The aquifer could be tested for the leakage pathways before CO2 storage. This will allow finding proper storage aquifers and locations for the injection wells. In this work we present an analytical model to evaluate the pressure variation in the overlying aquifers due to leakage from the storage aquifer. In a companion paper, this model will be used along with an inverse modelling approach to locate and characterize the leakage pathways based on pressure data. This paper introduces two new analytical solutions: 1- Exact solutions for the pressure variation in an overlying aquifer due to leakage (obtained in Laplace-transformation domain), 2- time-domain approximations for the exact solutions to make the inversion possible. In deriving the analytical solutions two aquifers are considered: Storage and monitoring. The aquifers are separated by an aquitard and are in communication through a leakage pathway. In departure from previous works the leakage pathways are not required to be line source/sink. Such consideration allows incorporation of large pathways such as stratigraphic and structural heterogeneities in the cap-rock. We consider a single-phase 1-D radial flow system in the storage and monitoring aquifers. Both of the aquifers are considered as homogeneous, isotropic, and infinite-acting with constant thickness. The injection (or production) rate is taken as constant. The analytical solution are applied to a base case and corroborated versus numerical solution. [Copyright &y& Elsevier]

Abstract: Power generation processes with CCS that are capable of operating at variable load will be needed to achieve deep reductions in emissions of CO2 to the atmosphere. This paper assesses the effects of operating load factor on costs of coal and gas fired power generation processes with CCS and analyses the emissions and costs of fossil fuel fired plants in an electricity system that includes 35% wind and 25% nuclear generation. The paper shows how the costs of generation increase at an increasing rate as the emissions are reduced using power plants with integrated CCS such as post combustion capture, because many of the CCS plants have to operate at low load factors. This could be avoided by using coal gasification plants with CCS which feed hydrogen to underground buffer storage and then to flexible combined and open cycle gas turbines. The gasification, CO2 capture and storage equipment would operate at base load which would avoid potential practical difficulties of flexible operation and reduce costs. Emissions from the fossil fuel plants in the system with wind and nuclear generation could be reduced to 16 g/kWh at electricity costs competitive with coal-based post combustion capture with emissions of 140 g/kWh. Emissions from the overall electricity system including the wind and nuclear would be 6 g/kWh. [Copyright &y& Elsevier]

Abstract: CCS technology is particularly important to China due to its large and rapidly rising emissions and high dependence on fossil fuel. There is a huge basin scale theoretical CO2 storage capacity in China; however the CCS deployments will consider firstly those matched source-sink pairs with early opportunities at present. This paper presents the key results of evaluation of early opportunities for the deployment of CCS technologies within China. The proximity analysis suggests that there also are many early opportunities for CCS deployment, such as the promising EOR/EGR opportunities from using high concentration CO2 sources. The combined benefits of short distance between sources and sinks, the potential hydrocarbon revenues and low CO2 capture cost make these pairs as promising near-term CCS candidates. These near-term CCS candidates can be deployed at very low cost or even with some revenue. In this paper, several sources-sink pairs in China are analyzed in details, such as, the pairs of high purity CO2 emission sources and aquifer, co-storage of waste gas stream and depleted gas fields, IGCC and aquifer. These early opportunities will provide China the chance to develop and spread CCS technologies steadily from early stage to commercial stage. [Copyright &y& Elsevier]

Abstract: One of the most critical problems when considering the geologic storage of CO2 is the risk of leakage which can lead to seepage from the storage area. The model described in this paper examines the injection of CO2 into faulted reservoirs with some degree of compartmentalization. Presented here are analytical solutions to relate the transmissivity of a fault to the pressure responses in the compartments. The solutions also show the different groups of parameters influencing the migration of injected CO2 in faulted areas that contain saline aquifers. The amount of cross-fault leakage that can occur is evaluated with respect to basic reservoir parameters that can be easily obtained prior to injection. The model is intended for a type of formation likely to be used for storage in Trinidad. We use the average reservoir pressure and an estimated fault transmissivity from the Mahogany field offshore Trinidad to illustrate the practical application of these analytical solutions. Fluid and rock properties influence the pressure response, and two possible cases are studied for their effects on the reservoir pressure and cross-fault flow. One case that is applicable is at early injection times, when on either side of the fault the water compressibility is dominant. The other case presents a more realistic case that treats the supercritical CO2 as slightly compressible. A sensitivity analysis shows the effects of fault transmissivity, pore volume and fluid compressibilities. This paper presents a few of the base case scenarios of the pressure response versus cumulative CO2 injected and also estimates the percent leakage that can occur with time. [Copyright &y& Elsevier]

Abstract: The purpose of this paper is to describe a methodology for assessing the impact of different risks and uncertainties on the financial output of a carbon capture and storage (CCS) project. The Value Chain Assessment (VCA) methodology is developed by DNV as a decision making tool for project developers to assess the financial feasibility of the investment and for alternative concepts. The methodology can be applied to optimize the financial result and the performance of a CCS project for a given level of risk. In this paper the VCA methodology is described and applied on a case study with a CCS project developer selecting between different capture technologies. [Copyright &y& Elsevier]

Abstract: This paper provides an overview of the current status of CCS in Indonesia and includes a review of the recently released Indonesia CCS Study Working Group report on the potential for CCS in Indonesia, collaboration between LEMIGAS, KLH, PT PLN, WEC, Shell and the British Embassy. The report found that there is significant potential for CCS in Indonesia, but also a number of barriers to overcome. This paper also considers regulations and legal aspects for the Indonesian government to consider for operation and long-term stewardship of CCS projects. It also includes a discussion of the options available to Indonesia to fund CCS demonstration and deployment domestically, with consideration towards the clean development mechanism (CDM) or other financing mechanisms, development banks, etc. Other opportunities including EOR and utilization of CO2 are discussed as nearer term opportunities to deploy pilot projects. The paper concludes with a discussion of the overall current status, awareness and support for CCS in Indonesia and international collaboration on CCS including the role for Indonesia. [Copyright &y& Elsevier]

Abstract: Evidence from experimental investigations, natural analogue studies and demonstration projects support the assertion that significant quantities of CO2 will not leak from a properly selected and managed CO2 storage complex. However, site operators must nevertheless justify the expectation of secure CO2 containment to regulators and other stakeholders. Secure containment will depend upon well seal stability inter alia. This paper presents fully-coupled geochemical models of well seal stability, focusing on cement degradation. The models have been developed with the ambition of reducing the simulated chemical system to the simplest possible configuration that is able to reproduce key features from experimental and field observations. Simplifying the models in this way makes them suitable for inclusion in larger scale system-level models of the storage system, where the use of highly-detailed chemical models can be impractical. Two sets of models were constructed in order to simulate: (1) a cement carbonation experiment (9 days in duration); and (2) field observations of cement degradation from the ‘SACROC’ site (30 years of reaction time). Although some model input parameters are uncertain, the experimental system was successfully simulated and the model was subsequently ‘up-scaled’ and applied to the SACROC core data. Over longer time-scales (102–103 years), the effects of parameter and thermodynamic data uncertainties on model output are more significant than at shorter time-scales. Although further work is required to bound the effects of these uncertainties, this paper illustrates the practicality of constructing simplified fully-coupled models to explore the significance of uncertainties by carrying out sensitivity calculations. [Copyright &y& Elsevier]

Abstract: This study is focused on the pertinence of the seismic reprocessing done in the North-East of Paris Basin in order to define the geometry of the Dogger and Trias reservoirs. The goal of this work was to evaluate the possibilities of storage of CO2 in the deep saline aquifers of the Paris Basin. This paper presents a new updated vision of the structural map and geology of North-East of Paris Basin. The preliminary phase involved reprocessing of 343 oil seismic lines recorded between 1981 and 1988, adding up to 303 kilometres coming from 10 different surveys. The quality of the existing data was not always good and work was performed to digitize original bands. Data consistency at the different scale was also analysed and checked. Particular attention was applied to the faults of the Dogger and Trias reservoirs and all shallower structure and aquifers up to the surface. The whole set of available data was harmonized through the establishment of a model of static multi-layer correction of the tertiary cover and by the use of adapted deconvolution. The crossings are thus homogeneous knowing that in-depth quality and definition remain dependent on the parameters of recording on the ground and in particular the length of the maximum offset and the distance between traces. Interpretation made it possible to identify the reflectors from the establishment of synthetic seismograms on 3 representative wells. The tops of the following layers were picked: Cenomanian, Gault, Oxfordian, Dogger, Aalenian, medio liassic sandstones, Triassic sandstones, and the metamorphic basement. The structure issued by this interpretation is notably different from that presented by the public sources because of the different density of the profiles taken into account. Explanations of the different interpretations are discussed in the paper. The isochrone maps were converted in-depth on the basis of 38 calibrations per well to illustrate the interpretation. The different layers show smooth deformations but also some faults where continuity and density increases with the depth because of the character inherited from the fault in the basement. Accidents visible are not continuous from the top of Cenomanian and to the top of the Gault, rather they correspond to the fault of Pays de Bray oriented N130 ° and to a meridian accident located in the western part of the study. From the top of Oxfordian, the continuity increases for these accidents. In addition, some oriented North-South faults appear. All the major faults are visible from the Sandstones in Medio Liasic. In addition to antithetic faults in relation with the accidents previously described, other meridian faults appear in the North of the fault of Pays de Bray. It should be indicated uncertainties in the picking of reflectors between the Trias and the basement, many multiples resistant to the processing programs interfering with these events. This project is based on an appropriated density of existing seismic 2D lines. The unequal quality of these acquisitions makes it possible to define structural aspects of the deep layers but does not allow to image possible lateral variations of rock types of the reservoir. [Copyright &y& Elsevier]

Abstract: The cement industry is coming under increased scrutiny for its CO2 emissions. The industry has reduced its CO2 footprint through energy efficiency measures, reduction of clinker factor, and the use of alternative fuels. However in a carbon-constrained world, more significant reductions are anticipated and thus CEMEX has been investigating the deployment of CO2 capture and sequestration (CCS) technologies for its own cement plants. The goal of this paper is to present the groundwork for the development and demonstration of a commercial-scale CCS project at one of CEMEX Inc.’s U.S. cement plants. The first part of this paper presents the criteria to determine the most suitable CO2 capture technology in an integrated CCS system for a cement plant. The second part of this paper summarizes how CO2 sequestration potential in proximity to one of CEMEX’s cement plants was a critical factor in determining the suitability to host a commercial CCS demonstration. Findings of this work showed that the development and demonstration of a commercial-scale CCS in the cement industry is still far from deployment. Retrofitting a very compatible CO2 capture technology for the cement industry is a limiting factor for early implementation of CCS. A pilot phase under actual cement plant flue gas conditions is a must to develop this technology to a commercial level. Uncertainties regarding the level of CO2 purity for transportation, geological sequestration, and enhanced oil recovery (EOR) warrant further investigation. [Copyright &y& Elsevier]

Abstract: Power generation is one of the biggest sources of man-made carbon dioxide (CO2) emissions, the main anthropologic greenhouse gas. As the combustion of fossil fuels generates CO2 emissions, new technologies are required to enable the power sector to continue to meet the global demand for electric power, while controlling the CO2 emissions that contribute to global warming. To achieve meaningful reductions, it will be necessary to develop technologies that can be applied to both greenfield projects and to the existing fleet through cost effective retrofits. Among those technologies under development, Post-Combustion Carbon Capture and Storage (CCS) using the Chilled Ammonia Process (CAP) technology is one of the more promising solutions. Testing and technology development for CAP has been completed at the We Energies Field Pilot and is underway at the E.ON Karlshamn and AEP Mountaineer facilities. This paper will report on the progress being made at those three facilities and describe how the data being generated is contributing to the commercial scale-up of the technology. The current status of these facilities is as follows: [•] The We Energies Field Pilot, designed to capture over 15,000 metric tonnes/year of CO2, commenced operations in June 2008 and was operated through October 2009. This first of a kind Proof of Concept unit demonstrated that CAP could be applied to coal fired applications. [•] The E.ON Karlshamn Field Pilot, designed to capture over 15,000 metric tonnes/year of CO2, was commissioned in April of 2009 and captures CO2 emissions from a boiler combusting a high sulfur fuel oil. [•] The Product Validation Facility (PVF) at American Electric Power (AEP)’s coal-fired Mountaineer Power Plant, inaugurated in September 2009, is designed to capture and store 100,000 metric tonnes/year of CO2. The Chilled Ammonia Product Validation Facility treats a flue gas slipstream taken from a location downstream of Mountaineer’s existing selective catalytic reduction (SCR), electrostatic precipitator (ESP), and wet flue gas desulfurization (WFGD) systems. Deployment of a CAP facility in this configuration represents a significant step in the technology scale-up process. This project scope includes CO2 capture, compression, and storage in two geologic reservoirs with injection wellheads located on the plant property. AEP worked with Battelle to develop the geologic storage system. This paper describes the Chilled Ammonia Process Development Program and provides an update on the CO2 capture pilot plants status including the AEP Mountaineer Product Validation Facility. [Copyright &y& Elsevier]

Abstract: A significant number of efforts are underway to develop and assess technologies that will lead to technically and economically viable routes to reduce the CO2 emissions of fossil energy systems, particularly coal-fired power plants. Developing technologies to reduce emissions from these sources is essential for controlling atmospheric levels of CO2 because of the widespread reliance on coal as an inexpensive and abundant energy source. Two major systems-level design challenges exist. The first is how to design new plants that incorporate CCS technology. The second is how to retrofit existing plants to capture CO2. Both design challenges can benefit from an optimization approach, which considers the application of multiple potential technologies and analyzes ways in which the whole plant-wide system can be integrated to increase overall efficiency. This paper will present a modular framework for the analysis and optimization of power generation systems with CCS that helps to meet these design challenges. In order to more completely understand the economic and operational tradeoffs associated with the various potential carbon capture technologies, and how they can be applied to new and existing plants, a unified, systemic framework has been developed to provide a common basis for evaluation. Given the complexity of the design problem and the fact that new technologies are continually being developed, this framework is modular in nature and incorporates algorithms for the selection, integration and optimization of carbon capture technologies for both new and existing plants. In addition to the framework itself, this paper discusses simulation modules representing various capture technologies and power plant components. The framework provides the means to link the various modules together in order to provide a holistic, systems perspective of plant wide operations. Results of analyses and optimization scenarios performed with the framework are also presented. [Copyright &y& Elsevier]

Abstract: The Kansai Electric Power Co., Inc. (KEPCO) has developed energy efficient chemical absorbents and economical processes which aim to reduce the cost of CO2 capture, in collaboration with Mitsubishi Heavy Industries, Ltd. (MHI). Together the companies have been developing and critically testing high efficiency, economical absorbents according to the latest absorbent development procedures and process simulation for CO2 capture processes. This work has been ongoing since 1991, using several Japan based R&D facilities and a pilot plant, used to verify improvements, located at Nanko Power Station in Osaka, Japan. Following significant testing of a range of absorbents in the mid 1990s, KS-1TM, KS-2 and KS-3 were developed. Based on subsequent rigorous evaluation of the three solvents, KS-1TM was selected for commercialization because of its overall technical and economical merits. During long-term pilot plant testing, the improved absorbents demonstrated superior performance in relation to the regeneration energy requirements leading to the following results: 2.94 MJlkg- CO2 in combination with KS-1TM” and the Kansai Mitsubishi Carbon Dioxide Recovery (KM-CDR ProcessTM) commercial process. In addition, practical, commercially applicable improved absorbent properties such as low corrosiveness and low solvent consumption were also confirmed. KEPCO and MHI continue development work in this area and the current status is summarized as follows: The highly successful R&D phase has led to the commercial deployment of CO2 capture technology and seven (7) commercial CO2 capture plants are currently under operation, with a maximum CO2 capture capacity of 450 metric tons per day (tpd). These commercial plants are deployed in the chemical and fertilizer industry, where the operational performance is assisting in the improved development of R&D concepts. Two (2) further commercial plants are under construction, with commissioning expected in Q3 2010. For further cost reductions in relation to CO2 capture, recent work has focused on developing new energy efficient chemical absorbents and processes. Following modifications to the Nanko CO2 capture pilot plant a new “Energy Saving Process”, was developed, which leads to a greater than 10% steam consumption reduction over the MHI conventional process using KS-1TM absorbent. Additionally the same reduced steam consumption was recorded for tests using the KS-1TM absorbent. A thermal energy requirement of less than 2.5 MJ/kg- CO2 in combination with KS-1TM and the “New Energy Efficient Process” has been confirmed under the optimum operation condition of the CO2 capture process. In addition to select new absorbents which feature the best profile and fit to the actual operating condition, KEPCO and MHI have intensively evaluated vapor-liquid equilibrium (VLE) and reaction kinetics for a range of newly developed absorbents and their performance is presented in this paper. The above data was obtained using the Nanko CO2 capture pilot plant which operates under a natural gas fired boiler condition and we expect that the thermal energy requirement of coal fired boiler flue gas (with greater CO2 concentration condition) will be further reduced. KEPCO and MHI are continuing pilot tests for the “Energy Saving Process”, leading to the application of this new process in commercial CO2 capture plant design. This paper introduces and presents the current status of the KEPCO & MHI CO2 capture technology and concepts for future energy reduction improvements. The paper will also include test results in relation to newly developed absorbents, and the “New Energy Efficient Process”, which have enhanced the performance and reduced the associated energy penalty of the CO2 capture process. KEPCO and MHI are continuing the development of efficient absorbents and optimized processes, thus helping to facilitate the future wide scale deployment of CO2 capture technology as an effective counter measure against global warming. [Copyright &y& Elsevier]

Abstract: In the UK, the Committee of Climate Change (CCC) concluded that in order to meet the 80% emission reduction target set for 2050, the power sector would need to be largely decarbonised by 2030. As the emission reduction required by 2030 is substantial, it is likely to require contributions from renewable, nuclear and CCS. By 2030, any plant running for extended periods will probably have to be able to achieve annual average emissions levels of 100 gCO2/kWh or below vs. the present level of 560 gCO2/kWh. In this context, the new regulations by Department of Energy and Climate Change (DECC) for making power plants CO2 capture ready apply to all combustion plants at or above 300 MW output in the UK. As emissions levels for new built CCGT plants without carbon capture are today around 350 kgCO2/MWh, it is expected that they will not be able to operate without CCS beyond 2030. In order to avoid the deployment of ‘unabated’ gas-fired plants, requirements to fit CCS not only to coal but to gas-fired plants need to be adopted to prevent any inconsistency. Once built, it would be very costly or even infeasible to retrofit the new facilities with CCS, thus “locking-in” many years of CO2 emissions. Currently in the UK there are no new unabated coal plants under construction, whilst around 4.7 GW of new gas plants are expected to come online over the next few years. As in the UK there are a significant number of CCGT power stations recently permitted or waiting to be granted consent they have been required to be CCR so that CCS can be retrofitted once it is commercially viable. It is therefore of a paramount importance to understand what are the feasible options/issues when CO2 capture is applied to the CCGT units. This paper is focusing on capture consideration based on post-combustion technology, the most mature option today. When a CCGT plant is designed to be ready for retrofit one of the most important technical consideration is the steam extraction pressure and flow to provide the energy necessary for solvent regeneration as this will have a large impact on the overall plant efficiency. Available options for steam and electricity supply to meet the requirements of the CCS process have been assessed, focusing on two scenarios–integration scenario where the steam is supplied from the main plant and separate generation scenario where steam is supplied from auxiliary boilers with electricity supplied from the grid connection. The findings of this paper are relevant to project developers, power generators and policymakers internationally who have an interest in the potential for CCS to provide an emissions abatement option for the new CCGT assets in the long term. [Copyright &y& Elsevier]

Abstract: This paper reviews the use of a large group process for engaging the public on energy sources and technologies with a low emission profile. Specifically reported in this paper is how the large group process supports exploring Australian society’s acceptance of energy technologies by examining the effectiveness of the process for informing knowledge and changing attitudes towards low emission energy technologies. Carbon dioxide capture and storage (CCS) is given further attention in the paper because, as a relatively unknown technology with perceived risks, it is useful to examine the effects of information provision on the way the technology is perceived. Given the large group process has proven to be a successful method for accessing and informing larger numbers of stakeholders, it is one recommended to policy makers and other researchers with an interest in low emission energy technologies. [Copyright &y& Elsevier]

Abstract: Carbon capture and storage (CCS) is commonly regarded as a key element in the mitigation of climate change. CCS is of particular interest as it is able to address emissions from fossil fuel power stations, reducing CO2 emissions by 80–90%, without a step change in technology or lifestyle within a country. This is of particular relevance for the large and growing coal fired power plant capacity in the developing world, particularly China and India. If CCS is going to make a significant impact on global CO2 emissions then the development and deployment of the technology over the next 50 to 100 years will have to be significant. Currently however, the global awareness and educational levels around CCS technology is low and mainly confined to the developed world. To meet the requirements of the future CCS industry this educational capacity must be increased. There are a number of key areas relating to the improvement of educational capacity. [•] Information dissemination [•] Undergraduate studies [•] Post-graduate research [•] Professional training program The scope of this paper only includes the undergraduate and post-graduate areas. Post-graduate work in CCS is currently the best developed of the four areas of educational capacity. However the bulk of quality post-graduate research would still only emanate from a small number of universities in developed countries. Undergraduate studies in CCS are currently non-existent. The only inclusion of CCS in undergraduate program currently is the mention of the general principles briefly as part of a much broader engineering program. This paper will look at international efforts to address the need to develop educational capacity in CCS. This will include looking at current training programs that exist such as the European CO2ReMoVe Course on CCS, the US–Norway Summer School for CCS, Research Experience in Carbon Sequestration (RECS), and the IEA GHG International Summer School on CCS. All the current programs are aimed at post-graduate stud ents who are currently conducting research in a CCS relevant field and mainly focus on the developed world. The paper will discuss the history and outcomes of such programs to make some assessment of the impact these programs have had in the CCS industry. The paper will then go on to look at ways in which these could be expanded and developed in the future including how current educational programs could be extended or modified to address CCS education amongst undergraduate students. An assessment will als o be made on how these programs could be transferred and initiated in the developing world. Finally the paper will go on to propose some new ways to improve CCS educational capacity for students around the world. [Copyright &y& Elsevier]

Abstract: ZeroGen Pty Ltd (ZeroGen) recently announced its plan to develop the world’s first commercial-scale 450MW clean coal power plant by 2017 in Queensland, Australia. Since the Queensland Government first announced the project in early 2006, stakeholder engagement activities have been a key priority for ZeroGen. The company understands that stakeholder perceptions, particularly of the safety of carbon dioxide (CO2) capture and storage (CCS) processes, represent a key challenge to the commercialisation of clean coal technologies. As a result, ZeroGen has developed and implemented an advanced consultation framework to actively engage a wide range of stakeholders to address this challenge. This paper details the consultation framework and outlines the findings of research conducted to assess the perceptions of community leaders where the project’s CCS activities are occurring. The paper confirms that the consultation processes deployed by ZeroGen to date have been successful in overcoming a key challenge to the commercialisation of clean coal technologies involving CCS. [Copyright &y& Elsevier]

Abstract: This paper introduces the concept of social site characterization as a parallel effort to technical site characterization to be used in evaluating and planning carbon dioxides capture and storage (CCS) projects. Social site characterization, much like technical site characterization, relies on a series of iterative investigations into public attitudes towards a CCS project and the factors that will shape those views. This paper also suggests ways it can be used to design approaches for actively engaging stakeholders and communities in the deployment of CCS projects. This work is informed by observing the site selection process for FutureGen and the implementation of research projects under the Regional Carbon Sequestration Partnership Program. [Copyright &y& Elsevier]

Abstract: The term ‘capture ready’ has been used by the UK Government when granting licences for power plants. However, the term has not as yet been given an agreed definition. This paper draws on literature on lock-in of large socio-technical systems and on regulation of technology undergoing development. Further, the paper compares some of the versions of the capture readiness concept proposed to date. It also explores capture readiness beyond the minimum requirement of space on the site for capture operations, including integration of capture and power plant, downstream operations, overall system integration and regulation of future retrofitting. [Copyright &y& Elsevier]

Abstract: This paper provides details of the context and background to UK policies for CCS, and critically examines the national strategy and detailed initiatives to date. Interviews with key players inform the analysis. Climate and energy security goals are first set out, and arguments about the place of coal within them discussed. Then the paper turns to the evolution of the debate about CCS in UK policy circles, and rationales for public support. Lastly the paper analyses some of the political, economic and technical issues that have emerged as CCS became more prominent in UK energy strategies. [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: This paper investigates the role of CO2 capture and storage (CCS) technologies as part of a portfolio for reducing CO2 emissions from the European electricity supply system until the year 2050. The analysis is carried out with a techno-economic model (minimizing the system cost) including a detailed description of the present stationary European electricity generation system (power plants) and potential CO2 storage sites as obtained from the Chalmers Energy Infrastructure Database. Since the ability of different EU Member States and regions to facilitate and to benefit from CCS will most likely depend on local conditions in terms of current energy mix, fuel supply chains and distance to suitable storage locations, special emphasize is put on analyzing turn-over in capital stock of the existing power plant infrastructure, timing of investments and the infrastructural implications of large scale introduction of CCS on a regional perspective. The paper discusses the role of and requirements on CCS for meeting strict emission targets of 85% reduction while having a continued growth in electricity demand (according to EU projections). The results show that it is possible to meet an 85% CO2 reduction target by 2050, but this will require large contribution from CCS. As expected, regions which are currently high in carbon intensity and which are located nearby suitable storage sites will benefit mostly from CCS as an option. With the assumption that CCS will be commercially available in 2020 the model results give a steep ramp-up in the use of CCS post 2020 which imposes challenges for timely investments in corresponding CCS infrastructure. [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: In this paper, three biofuel-producing processes with carbon dioxide capture and storage (CCS) are studied: two (fermentation) ethanol processes and one process producing methanol (via gasification). In these processes CO2 is captured from streams which are relatively pure, i.e. the main impurity is water vapour which may be easily removed. Owing to this, the costs for CO2 capture, both in terms of economic cost and energy penalty, are very low and these processes could thus constitute some of the first instances where CCS is implemented. The paper highlights under which conditions biofuel production with CCS may create a CO2-neutral transport sector. [Copyright &y& Elsevier]

Abstract: At present, hydrogen is largely used in refineries and ammonia plants but in future it may be used as an energy carrier for vehicles, power generation and distributed heat production. One of the most promising technologies for hydrogen production with low CO2 emissions is coal gasification with CO2 capture and storage. Hydrogen can be co-produced with electricity in Integrated Gasification Combined Cycle (IGCC) plants. This paper summarizes the results of studies carried out by Foster Wheeler Italiana for the IEA Greenhouse Gas R&D Programme (IEA GHG). Performance and costs data are presented for five different coal gasification plants producing electricity and/or hydrogen with and without CO2 capture. The cost data are on a 2nd quarter 2008 basis and take account of the recent large increases in plant investment costs and coal prices. The paper assesses possible advantages of hydrogen and electricity co-production in future energy supply systems and the advantages of being able to operate plants flexibility to meet the varying demands for hydrogen and electricity. If hydrogen becomes used as an energy carrier it will displace some of the demands for natural gas, gasoline and diesel fuel. A market analysis of the demands for these fuels was performed for The Netherlands and the USA to determine possible future hydrogen demand and how it will vary throughout the year. Demands for electricity were also determined. Plant performance and costs are estimated and electric power production costs are evaluated. Electricity and hydrogen co-production plants are compared to plants that produce electricity only, with and without CO2 capture, to evaluate the cost of CO2 avoidance. The benefits of flexible co-production with and without buffer storage of hydrogen are also evaluated. [Copyright &y& Elsevier]

Abstract: Coal is central to China’s continued economic growth and CCS is one of the most promising technological solutions to curb the CO2 emitted from the continued use of coal. This paper introduces some areas of recent R&D on CCS in China and focuses, in particular, on the Near Zero Emission Coal (NZEC) project, a China-UK CCS initiative. NZEC is being undertaken in three phases, with the current project comprising the first phase. The ultimate aim of NZEC, following Phase 3, is to have constructed and operated a coal-fired power plant with integral CCS in China. In this paper, some of the early progress made in NZEC Phase 1 is described. Launched in November 2007, the objectives of Phase 1 are to build confidence in CCS and to explore technology options for demonstrating coal-fired power generation with CCS in China. The Phase 1 partnership of nine leading UK organisations and 20 from China demonstrates the strong collaborative working relationship that exists between China and the UK, at all levels, to develop CCS as a key climate change mitigation technology. Apart from NZEC, China is involved in several national and international CCS initiatives and some of these will be touched upon in this paper. The success of the 18-month first phase will, to a large extent, be measured against its contribution to increasing CCS capacity in China and against strengthened links between Chinese and British experts. Activities designed to raise capacity are described. [Copyright &y& Elsevier]

Abstract: Modelling CO2 storage in saline aquifers on a reservoir scale, for example, for feasibility studies and risk analyses is very demanding with respect to computational cost due to the complex geometries that need to be described and due to the diversity of interacting hydraulic, thermal, mechanical, and geochemical processes. In most cases it is not necessary to be able to describe all these processes for the whole simulation time period or for the entire model domain. Within this paper it is outlined how model coupling could help in reducing the model complexity and increasing model efficiency while the relevant processes are still taken into account. Since the work on this topic is at an early stage, this paper is restricted to a discussion of coupling concepts. [Copyright &y& Elsevier]

Abstract: This paper presents results from a 30 -month project devoted to taking the chemical-looping combustion (CLC) technology to the next level of development. The project is part of the EU’s Sixth Framework programme with support from the CCP (Carbon Capture Project) and has mainly focused on the critical issues for an up-scaling of the technology. In an earlier project the CLC technology was demonstrated successfully for the first time for 100 h using Ni -based oxyge n carrier particles using natural gas as fuel. The current project has built on these experiences and : i) established industrial-scale NiO particle production with suitab le commercial raw materials. Oxygen carrier particles have been produced with both s pray -drying and impregnation and investigated extensively with respect to parameters important for CLC operation, such as reactivity in batch and continuous operation, strength, defluidization phenomena, operation at high temperatures and effect of imp urities suc h as H 2S in the fuel; ii) extended operational experience in long term tests of particles in the available 10 kW prototype for more than 1000 hours combustion and iii) succesfully scaled -up and operated the process in a 120 kWth combustor using syn gas and natural gas. Further, the project has included extended and verified modelling of the reactor system for scale-up in addition to process and technology scale-up and economic assessment. The paper will present the main results of the project. [Copyright &y& Elsevier]

Abstract: This paper analyzes various aspects of the Zecomix cycle, a novel coal fired power plant, based on various innovative processes to achieve elevated efficiency and zero-emissions. A coal hydro-gasification process, using recycled steam and hydrogen as gasifying agents, converts carbon to CH4, which is then processed by two carbonator reactors where CH4, mixed with steam and contacted with calcium oxide, is converted to an H2/H2O based syngas while CO2 is absorbed by the solid sorbent generating CaCO3. The synthetic fuel produced in the chemical island is burned with oxygen in a semi-closed high temperature steam cycle, with a rather complex supercritical heat recovery steam cycle. The main relevant operating parameters for the chemical island are varied in order to evaluate their effect on plant performance and to optimize the process. In addition, the paper presents a rather detailed analysis of some critical issues, often neglected in previous works from the literature. Net plant efficiency of 44–47% with a virtually complete carbon capture was predicted, a very interesting results with respect to other proposed coal power plants with carbon capture. The high complexity of the chemical island and the importance of a good sorbent performance in the critical conditions typical of this plant should be however taken into account for a fair comparison with other plant concepts. [Copyright &y& Elsevier]

Abstract: This paper presents the results of ASPEN simulations of a carbon-dioxide (CO2) removal and recovery plant that captures CO2 from a 500 MWe (net) conventional coal-fired power plant flue gas stream. At a constant CO2 recovery rate of 86.5% by weight, the performance of aqueous ammonia solution as an alternative to various aqueous amino solvents (MEA, AMP and MDEA) is compared in terms of the process scenarios, solvent loadings and overall energy consumption. The overall mass transfer co-efficient and CO2 loading data generated for aqueous ammonia solutions using a laboratory scale wetted wall gas-liquid contactor are also presented. The ASPEN simulation results in conjunction with the laboratory data show, that capturing CO2 from coal-fired power plant flue gas, using aqueous ammonia solvent, will require ammonia concentration no more than 5% by weight and absorber temperature 10 ∘C or lower, if the vapor phase ammonia losses are to be contained and the precipitation of ammonium bi-carbonate in the absorber is to be avoided. Under such an operating scenario, the aqueous ammonia based CO2 capture process has overall energy requirement comparable to the conventional 30% by weight aqueous MEA based process. The ASPEN results further show that 30% by weight AMP based process has the lowest overall energy requirement among the solvents considered in this paper. [Copyright &y& Elsevier]

Abstract: Aqueous ammonia can be used to capture CO2 from flue gas of coal-fired power plant with quick reaction rate, high removal efficiency, and high loading capacity of CO2. It is thought to be a promising technology. However, the CO2 absorption rate, diffusion rate and VLE (Vapor liquid equilibrium) in aqueous ammonia have still been rarely researched. More research is necessary for these characters of ammonia solution as CO2 absorbent. The paper will focus on the fundamental characteristics of CO2 in aqueous ammonia. A series of tests were conducted in a semi-batch reactor that has been developed in this paper. CO2 removal efficiencies at different concentrations of aqueous ammonia have been studied in the similar operation conditions to compare their basic characters in the CO2 absorption process. And a small wetted wall column (WWC) with a contact area of about 41.45 cm2 was also built for the study of the absorption rate, diffusion, and solubility of carbon dioxide in the aqueous solution. In the paper, reaction rate and overall gas transfer coefficient were studied. The concentration of ammonia ranges from 1, 5, 10 to 15. CO2 and N2 are used to simulate the flue gas. The concentration of CO2 ranges from 5, 10, 15, to 20%. The reaction temperatures are 20 ∘C and 40 ∘C. It is indicated in this paper that the best concentration of aqueous ammonia should be selected from 5% to10%. And aqueous ammonia has a high Flux in WWC, which is three times higher than that of MDEA+PZ, under the same condition. It is also found that is appropriate to be used in the mass transfer process of the carbon dioxide absorption by aqueous ammonia. Alls of these experiments established foundation for the further study of CO2 removal by ammonia. [Copyright &y& Elsevier]

Abstract: The potential benefits of precombustion carbon dioxide capture are well documented, and adsorption remains a promising separation process in this area. This paper details work to identify and assess the potential of high temperature adsorbents suitable for precombustion capture. The aim of this paper is to schematically identify adsorbents that are suitable for carbon capture in different temperature ranges. A critical aspect of this work is to assess the materials not only in terms of carbon dioxide isotherms and absolute loading, but to consider the wide range of other properties that are required to achieve an industrially feasible adsorbent - selectivity, cycling capacity, stability, kinetics, high pressure loading, fate of other components (including water, H2S, NH3, CO and N2). It is only when all these requirements are sufficiently met, that an adsorbent can be consider worthy of industrial consideration. A range of analytic screening tests are described to enable a full characterisation of the merit of a specific adsorbent. The adsorbents investigated are zeolites (NaX, calcium chabazite), commercially available hydrotalcite, layered double hydroxides/oxides (LDH/Os), and magnesium double salts. Each operates in a different temperature range and offers potential for integration within an Integrated Gasification and Combined Cycle precombustion process train. Some of the promising and significant conclusions of this work are - [•] Magnesium double salts present very favourable carbon dioxide isotherms and demonstrate significant carbon dioxide loading and the isotherms are suitable for PSA or TSA operation at high temperature. [•] LDHs or their derivatives as layered double oxides can adsorb up to 1.5mol/kg CO2. Water does not affect CO2 sorption, and the material has good recyclability in TSA. [•] The selectivity of hydrotalcite is well documented. However there is no reported literature on the adsorptive behaviour of these materials with respect to trace components - H2S and NH3. These results are reported. [•] Calcium chabazite displays useful CO2 loading potential in a unique temperature range around 200 ∘C. [•] NaX has the potential to replace Selexol at an operating temperate of 130 ∘C. [Copyright &y& Elsevier]

Abstract: Oxyfuel combustion is one of the promising technologies to enable CCS for new and existing coal-fired power plants. For retrofit applications, oxyfuel is an attractive option because it does not have major impact on the boiler-turbine steam cycle. This paper presents a case study for retrofitting oxyfuel combustion technology in large state-of-the-art power plants that are originally commissioned and operated in air-fired mode. The overall process design for the modified power plant is outlined; necessary modifications of relevant components are explained. The paper also discusses results of experiments and numerical calculations on combustion behavior in the furnace. Retrofit measures ensure that the power stations still can run under both air-fired and oxyfuel-fired conditions if required by regulations/market conditions. This provides additional operational and commercial benefits for the operator of the plant and reduces the technical risk of implementing new components and processes not yet proven in the power sector. [Copyright &y& Elsevier]

Abstract: Steam demand is increasing for Oil & Gas projects, and in particular oil sands and extra-heavy oils thermal recovery schemes. Use of oil residues and bitumen can be a cost-effective solution for natural gas substitution in SAGD (Steam Assisted Gravity Drainage). However, use of such fuels gives rise to higher specific GHG emissions. Oxy-combustion technology is an elegant solution to this problem since oxygen allows complete combustion of very high viscosity and heavy fuels, and because it provides a concentrated CO2 stream, for easier Carbon Capture and Storage (CCS). Air Liquide has acquired over the last two decades extensive industrial experience of full oxy-combustion for the glass, metals, cement and waste treatment industries. This expertise and extensive scientific knowledge have been used to develop an innovative oxy-burner technology, specific to steam and power production applications. This oxy-burner technology presents novel and differentiating features, which will be described in this paper. In particular, it features a direct oxygen injection into the burner, without external mixing of oxygen with the flue gas recycle, which provides additional flue gas recycle rate flexibility, and enables a safe handling of the oxygen. Air Liquide has demonstrated the performance of this oxy-burner concept through downscaled (1 MW) oxy- combustion tests in a dedicated cold-wall test-rig with flue gas recycle. Total will retrofit the air-fired boiler at its Lacq CO2 Project (SW of France) with an intermediate size of this oxy- burner technology (four 8 MW oxy-burners). The paper presents: [•] the innovative oxy-burner technology, its challenges and novelties, [•] a description of the Air Liquide 1 MW oxy-combustion test rig and the test results obtained over a wide range of flue gas recycle rates, [•] the integration of the oxy-combustion system into Total’s existing 30 MWth boiler. [Copyright &y& Elsevier]

Abstract: Ecofys and ECN conducted a study commissioned by the IEA Greenhouse Gas R&D Programme to identify the most suitable combinations of medium-scale CO2 sources (1–100 MWth) and capture technologies, with respect to potential and costs (see parallel paper by Hendriks et al.). An industrial coal-fired Circulating Fluidized Bed (CFB) boiler with oxyfuel combustion and Oxygen Conducting Membranes (OCM) appeared to be an economically attractive combination to capture CO2. This paper describes the principle and economic evaluation of this combination in comparison with a reference coal boiler without CO2 capture, as well as a coal boiler with CO2 capture based on amine scrubbing. [Copyright &y& Elsevier]

Abstract: Greenhouse gas emissions from industrial processes, such as cement manufacturing or steel production, in Australia accounts for more than 40 Mt CO2-e per annum, representing close to 20% of Australia’s potentially sequesterable emissions. Further, the emissions from these processes are highly concentrated in CO2 compared to the emissions from power generation. It is not clear if these higher concentrated gases may provide low cost options for demonstrating CO2 capture or if this benefit will be lost due to the smaller total volume of CO2 emissions of most industrial processes. Nevertheless, this sector of the economy requires further analysis. This paper will provide an overview of the emissions from Australian cement sector including both the emissions from the chemical process itself, as well as the associated emissions from energy use within those processes. Specific attention will be focused on the Australian cement industry. While CCS involves the integrated part of capture, transport and storage, the focus of this paper is on the capture side and will illustrate CCS options for the cement industry. [Copyright &y& Elsevier]

Abstract Carbon sequestration is an important measure to reduce greenhouse gas emissions. This paper introduces a new method of carbon sequestration using CO 2 waterless fracturing technology. Based on the supporting technology system with independent intellectual property rights, waterless fracturing field tests were carried out on 19 wells in Jilin oilfield. The on-site monitoring data shows that CO 2 stays in a supercritical state for a long time in the process of waterless fracturing, soaking and flowback, which is favourable for carbon sequestration. The geological model of H87 test area was established to simulate and evaluate CO 2 recovery after fracturing. The results show that the storage ratio of CO 2 waterless fracturing is 76.46%. Meanwhile, the production after waterless fracturing is 2.4 times that after water-based fracturing with the same scale, and the average single well operation saves 1512 m3 water. It can be seen that CO 2 waterless fracturing is a new type of carbon sequestration technology with high storage efficiency, good stimulation effect, significantly reduction of water consumption during oil and gas reservoir development and has broad market prospects. [ABSTRACT FROM AUTHOR]

Defining the ideal suite of monitoring technologies to be deployed at a carbon capture and storage (CCS) site presents a challenge to project developers, financers, insurers, regulators and other stakeholders. The monitoring, verification, and accounting (MVA) toolkit offers a suite of technologies to monitor an extensive range of parameters across a wide span of spatial and temporal resolutions, each with their own degree of sensitivity to changes in the parameter being monitored. Understanding how best to optimize MVA budgets to minimize the time to leak detection could help to address issues around project risks, and in turn help support broad CCS deployment. This paper presents a case study demonstrating an application of the Designs for Risk Evaluation and Management (DREAM) tool using an ensemble of CO 2 leakage scenarios taken from a previous study on leakage impacts to groundwater. Impacts were assessed and monitored as a function of pH, total dissolved solids (TDS), and trace metal concentrations of arsenic (As), cadmium (Cd), chromium (Cr), and lead (Pb). Using output from the previous study, the DREAM tool was used to optimize monitoring system designs based on variable sampling locations and parameters. The algorithm requires the user to define a finite budget to limit the number of monitoring wells and technologies deployed, and then iterates well placement, sensor type and location until it converges on the configuration with the lowest time to first detection of the leak averaged across all scenarios. To facilitate an understanding of the optimal number of sampling wells, DREAM was used to assess the marginal utility of additional sampling locations. Based on assumptions about monitoring costs and replacement costs of degraded water, the incremental cost of each additional sampling well can be compared against its marginal value in terms of avoided aquifer degradation. Applying this method, DREAM identified the most cost-effective ensemble with 14 monitoring locations. While this preliminary study applied relatively simplistic cost and technology assumptions, it provides an exciting proof-of-concept for the application of DREAM to questions of cost-optimized MVA system design that are informed not only by site-specific costs and technology options, but also by reservoir simulation results developed during site characterization and operation. [ABSTRACT FROM AUTHOR]

Large-scale pressure increases resulting from carbon dioxide (CO 2 ) injection in the subsurface can potentially impact caprock integrity, induce reactivation of critically stressed faults, and drive CO 2 or brine through conductive features into shallow groundwater. Pressure management involving the extraction of native fluids from storage formations can be used to minimize pressure increases while maximizing CO 2 storage. However, brine extraction requires pumping, transportation, possibly treatment, and disposal of substantial volumes of extracted brackish or saline water, all of which can be technically challenging and expensive. This paper describes a constrained differential evolution (CDE) algorithm for optimal well placement and injection/extraction control with the goal of minimizing brine extraction while achieving predefined pressure contraints. The CDE methodology was tested for a simple optimization problem whose solution can be partially obtained with a gradient-based optimization methodology. The CDE successfully estimated the true global optimum for both extraction well location and extraction rate, needed for the test problem. A more complex example application of the developed strategy was also presented for a hypothetical CO 2 storage scenario in a heterogeneous reservoir consisting of a critically stressed fault nearby an injection zone. Through the CDE optimization algorithm coupled to a numerical vertically-averaged reservoir model, we successfully estimated optimal rates and locations for CO 2 injection and brine extraction wells while simultaneously satisfying multiple pressure buildup constraints to avoid fault activation and caprock fracturing. The study shows that the CDE methodology is a very promising tool to solve also other optimization problems related to GCS, such as reducing ‘Area of Review’, monitoring design, reducing risk of leakage and increasing storage capacity and trapping. [ABSTRACT FROM AUTHOR]

Natural gas is considered a cleaner and lower-emission fuel than coal, and its high abundance from advanced drilling techniques has positioned natural gas as a major alternative energy source for the U.S. However, each ton of CO 2 emitted from any type of fossil fuel combustion will continue to increase global atmospheric concentrations. One unique approach to reducing anthropogenic CO 2 emissions involves coupling CO 2 based enhanced gas recovery (EGR) operations in depleted shale gas reservoirs with long-term CO 2 storage operations. In this paper, we report unique findings about the interactions between important shale minerals and sorbing gases (CH4 and CO 2 ) and associated economic consequences. Where enhanced condensation of CO 2 followed by desorption on clay surface is observed under supercritical conditions, a linear sorption profile emerges for CH4. Volumetric changes to montmorillonites occur during exposure to CO 2 . Theory-based simulations identify interactions with interlayer cations as energetically favorable for CO 2 intercalation. In contrast, experimental evidence suggests CH4 does not occupy the interlayer and has only the propensity for surface adsorption. Mixed CH4:CO 2 gas systems, where CH4 concentrations prevail, indicate preferential CO 2 sorption as determined by in situ infrared spectroscopy and X-ray diffraction techniques. Collectively, these laboratory studies combined with a cost-based economic analysis provide a basis for identifying favorable CO 2 -EOR opportunities in previously fractured shale gas reservoirs approaching final stages of primary gas production. Moreover, utilization of site-specific laboratory measurements in reservoir simulators provides insight into optimum injection strategies for maximizing CH4/CO 2 exchange rates to obtain peak natural gas production. [ABSTRACT FROM AUTHOR]

Numerical simulation is an invaluable analytical tool for scientists and engineers in making predictions about of the fate of carbon dioxide injected into deep geologic formations for long-term storage. Current numerical simulators for assessing storage in deep saline formations have capabilities for modeling strongly coupled processes involving multifluid flow, heat transfer, chemistry, and rock mechanics in geologic media. Except for moderate pressure conditions, numerical simulators for deep saline formations only require the tracking of two immiscible phases and a limited number of phase components, beyond those comprising the geochemical reactive system. The requirements for numerically simulating the utilization and storage of carbon dioxide in partially depleted petroleum reservoirs are more numerous than those for deep saline formations. The minimum number of immiscible phases increases to three, the number of phase components may easily increase fourfold, and the coupled processes of heat transfer, geochemistry, and geomechanics remain. Public and scientific confidence in the ability of numerical simulators used for carbon dioxide sequestration in deep saline formations has advanced via a natural progression of the simulators being proven against benchmark problems, code comparisons, laboratory-scale experiments, pilot-scale injections, and commercial-scale injections. This paper describes a new numerical simulator for the scientific investigation of carbon dioxide utilization and storage in partially depleted petroleum reservoirs, with an emphasis on its unique features for scientific investigations. The mathematical foundations of this new simulator for enhanced oil recovery are those of the simulators developed for carbon sequestration in deep saline reservoirs, altered to consider the increased number of potential phases and compositional aspects by considering the oil in the system. As a demonstration of the simulator, a numerical simulation of carbon dioxide utilization for enhanced oil recovery in the western section of the Farnsworth Unit, representing an early stage in the progression of numerical simulators for carbon utilization and storage in depleted oil reservoirs. [ABSTRACT FROM AUTHOR]

This paper is inspired by theory related to the water-food-energy-climate nexus and suggests a novel model, suited for analysing carbon sequestration in dry land agriculture using irrigation. The model is applied specifically to photovoltaic water pumping (PVWP) systems for irrigation of grasslands in China. We argue against the narrow approaches to analysing the water issue often found in literature and propose that carbon sequestration, energy security, food security together with local moisture recycling patterns should be included within the system boundary in order to make analyses of dry land agricultural activities more relevant and accurate. [ABSTRACT FROM AUTHOR]

Abstract: The eddy covariance method is a micrometeorological technique for direct measurements of gas transport between the surface and the atmosphere. It is widely used for quantifying CO2 emission rates from natural, urban and agricultural ecosystems, including areas of agricultural carbon sequestration. In geological carbon capture, utilization and sequestration, emerging projects utilize eddy covariance to monitor large areas where CO2 may escape from the subsurface, to detect and quantify CO2 leakage, and to improve CO2 storage efficiency. This paper describes key principles of the method, main requirements, typical instrumentation and software, and educational resources particularly useful for carbon sequestration research. [Copyright &y& Elsevier]

Abstract: The present renewed interest on CO2 EOR/EGR is led by an environmental concern. The consequence is that, today, we are urgently asked for considering the new CO2 EOR projects in association with CO2 storage. This implies an appropriate production well management allowing for delaying the CO2 breakthrough, while one has to keep a great concern on the safety issues related to the social acceptance, and to ensure a full economical viability of the CO2 injection projects. The picture becomes even more complex when it is planned to link various CO2 emission sites to various remote CO2 injection sites (typically already produced hydrocarbon reservoirs) through a large CO2 transportation infrastructure. In such a situation, it will be needed to harmonize in real time the rate fluctuations of the CO2 sources and the evolution of the CO2 sink injectivities (closely related to the reservoir pressure), while avoiding to meet the surface/transportation equipment limitations. The optimization of such a large system being not solvable rigorously, there is a particular interest towards methodologies allowing for a simplified reservoir modeling of the CO2 sinks (hydrocarbon field or aquifer). This point has been addressed in the work presented hereafter, which has been completed within the frame of the European ECCO project, aiming at providing a techno-economical tool for the CO2 value chain analysis. After a review of possible methods of reservoir conceptual modeling, the paper is presenting the approach followed for modeling reservoir CO2 EOR/EGR candidates in Central Europe. What is emphasized is the quantification of the impact of production constraints on hydrocarbon recovery and CO2 storage, in particular by means of an experimental design based tool. In addition, it is shown how some uncertainty on fluid miscible behavior can influence the hydrocarbon production. [Copyright &y& Elsevier]

Abstract: Recently, the Norwegian authorities have established a number of Centres for Environment-friendly Energy Research (CEER), intended to develop new knowledge, foster breakthrough technology and promote innovation in order to solve specific challenges in the field of energy and environment. The expectation is that these heterogeneous, multipartner research consortia will lead to excellent academic performance and at the same time, that the new knowledge is of such nature that it can be exploited for practical and commercial purposes. This paper suggests that the adoption of two concepts of knowledge production, denoting knowledge produced in an academic context and in a context of application, respectively. These concepts, referred to as Mode 1 and Mode 2 knowledge production, open up for insight and implications about the challenges inherent in the CEER scheme. Our key argument is that in order to move our understanding of innovation in heterogeneous research collaborations, research efforts should be seen as concurrent processes of problem solving around scientific and practical problems. The main management challenge identified is the need to perform well as a manager of basic research and at the same time, lay the groundwork for innovation, that is, to lead according to differing expectations. Our claims are based on an empirical example, drawn on the CEER Centre BIGCCS. [Copyright &y& Elsevier]

Abstract: The BIGCO2 R&D (BIGCO2) Platform is an international collaborative research project aiming at developing several enabling technologies and innovative solutions supporting a large-scale deployment of CO2 capture from power generation and underground storage of CO2. All main routes for CO2 capture are investigated. The project is coordinated by SINTEF Energy Research and the budget of the current project period (2007-2011) is 16 M€. BIGCO2 builds knowledge and technology underpinning demonstration of power generation with carbon capture and storage (CCS) at industrial scale. The project aims at closing critical knowledge gaps in the CO2 chain to enable sustainable power generation from fossil fuels based on carbon capture and underground storage of CO2. BIGCO2 is unique in terms size, diversity, and the fact that it comprises the whole CO2 chain. The project includes extensive international collaborative effort bringing together expertise and research infrastructure of competent research institutes and universities, supported by leading vendors, energy companies, and oil and gas companies. This paper presents the structure, the original objectives and the achievements of BIGCO2. Further, for each research task, the results are analyzed in light of the objectives. Each task leader has analyzed the results in the following context of: originally stated objectives, results, and if the results meet the objectives. The purpose of BIGCO2 is to develop new knowledge to enable power generation with CCS. Tangible objectives are: 90% CO2 capture rate, 50% cost reduction, and a fuel-to-electricity penalty less than 7% compared with state-of-the-art power generation. Partners of the Consortium are: Statoil, GE Global Research, Statkraft, Aker Clean Carbon, Shell, TOTAL, ConocoPhillips, ALSTOM, DLR, TUM, NTNU, CICERO, SINTEF Materials and Chemistry, SINTEF Petroleum Research, and SINTEF Energy Research. The University of Oslo is a subcontractor to the project. Further, BIGCO2 benefits from a strong collaboration between the combustion research facility at Sandia National Laboratories (USA) and SINTEF Energy Research. The main sponsor of BIGCO2 is the Research Council of Norway, with considerable co-funding from the industry partners and Gassnova. The research challenges and approach are extensively presented in . [Copyright &y& Elsevier]

Abstract: Coupling flexible power generation with Carbon Capture and Sequestration (CCS) technology may be important for substantial reductions in CO2 emissions. In this paper we consider some of the implications of flexible power plant operation on the CCS process. Specifically, we consider the CCS chain capacity selection decision, by which we mean the choice of the optimal plant size, to understand what determines the amount of CO2 that is efficient to capture and how the decision to invest in CCS chain capacity is affected by price volatility of CO2 emissions quotas. We found that the plant''s emissions profile determined a range of CCS capacities that could be efficient with the tradeoff between the price of CO2 emissions quotas and the cost of CCS technology determining the specific optimal chain capacity. Secondly, investment into CCS technology for a flexible load power plant was more likely to be delayed in a multiple time point investment decision tree model as a result of price volatility, compared to investment in CCS technology on a base load power plant. [Copyright &y& Elsevier]

Abstract: CCS will play an important role in reducing greenhouse gas emissions in order to limit global warming to 2° Celsius by 2050. Amongst other things, both the costs and the technologies associated with CCS are subject to uncertainties. Cost estimations in the literature vary significantly. Some analyses provide cost estimation for CCS as a generic value, giving only a few distinctive technical options and only a few attempts to investigate the costs separately for each technology. The objective of this paper is therefore to analyze the cost spectrum for CCS provided by different studies and to determine realistic cost estimations for carbon dioxide capture and storage, as well as to investigate the impact of costs on the economic maturity of CCS. Results show that costs of CCS vary significantly along the CCS process chain. Furthermore, it becomes apparent that further efforts need to be taken, both in technology development and in terms of the willingness of an economy to pay high prices for mitigating CO2 emissions, before CCS may be referred to as economic feasible. [Copyright &y& Elsevier]

Abstract: Transport is an important feature of the CCS process as the CO2 quality requested by pipelines may influence the choice of the capture technology and its limit performance requirements. So, the knowledge of the thermodynamic properties of CO2-mixtures has an important role, however a suitable equation of state under the appropriate conditions for pipeline transport has not been clearly defined yet. In this paper different equations of state for predicting densities of CO2 and CO2 mixtures have been analyzed and compared with experimental data found in literature or obtained by authors performing specific laboratory p-ρ-T measurements. [Copyright &y& Elsevier]

Abstract: The recent years have seen growing attention towards the study of dynamic behavior in post-combustion CO2 capture plants using amines, albeit, apparently contesting yet without comparison or critique. This paper reviews what has been reported in literature concerning issues pertinent to transient behavior of CO2 capture including interaction with power plants. Details of models used, their validation and modeling tools as well as an attempt to piece-out convergent points from the various conclusions are given. Knowledge gaps and areas that still need more attention are emphasized. [Copyright &y& Elsevier]

Abstract: Packing is widely used in post-combustion CO2 capture. This paper is focused on the measurement of three fundamental packing characteristics: effective gas-liquid contact area (ae), gas phase and liquid phase film mass transfer coefficient (kG) and (kL). Results show that contact area initially increases with liquid flow rate before it asymptotes to a value nearly equivalent to the nominal surface area. Initial attempts at constructing new mechanistic models have shown that existing kG and kL models can be improved. Both gas and liquid phase film mass transfer coefficients can be described as a power function of superficial gas or liquid velocity. [Copyright &y& Elsevier]

Abstract: Biofixation of CO2 by microalgae has become an effective carbon dioxide capture and storage (CCS) technology and it has the potential for large-scale application in decreasing CO2 emission from combustion flue gases. In general, the production of the microalgae under flue gas CO2 carbon sequestration is closely related with the algae species, culture methods, biological conditions, gas conditions and the CO2 concentration. In this paper, the production parameter (biomass) for microalgae chlorella under flue gas was predicted using response surface methodology. It was found that the model agreed well with the experimental data. Further, the interacted analysis indicated that the carbon source, nitrogen source, cell inoculation density and light intensity had important effect on microalgae production. [Copyright &y& Elsevier]

Abstract: The application of Carbon Capture and Storage (CCS) in the power industry is important for reducing man-made CO2 emissions. This paper proposes new ways to categorize the options for mitigation of man-made CO2 emissions and CO2 capture. A detailed description on the ways to capture, transport and store CO2 has been presented. The power penalties and cost can be big challenges to apply CCS to the power industry, while a lot of opportunities exist, such as value added CO2 storage, industrial utilization of CO2 and the development of the carbon trade market. [Copyright &y& Elsevier]

Abstract: CO2 emission from combustion flue gases has become the primary factor in global warming. Chemical methods of absorbing CO2 from combustion flue gases have been widely used in engineering, because of its simple and convenient operation, high absorption efficiency and economic value. This paper analyses the domestic and foreign researches on chemical methods of absorbing CO2 from combustion flue gases, and summaries the effect of the reactors structure, absorbent type and operating conditions on absorption efficiency. This article also forecasts present developmental directions, and expects to have a certain reference to later research and development. [Copyright &y& Elsevier]

Abstract: Carbon capture and storage (CCS) technology is one of the most effective way of reducing emission. In this paper, we present a carbon capture investment model of power producer under carbon price and CCS technology uncertainties with real option theory. Then the investment t iming of CCS is explored by numerical simulation, the results indicate that the carbon price volatility and technological improvement of carbon capture will both delay carbon capture investment, and power producers will choose not to invest if the volatility is big enough. [Copyright &y& Elsevier]

Abstract: Public perceptions of CCS are seen as crucial in terms of the deployment. Recent opposition to CO2 storage projects, such as Vattenfall’s Schwarze Pump project in northern Germany, demonstrates that addressing public concerns is a crucial factor in securing support for a CO2 scheme. Risk communication will be affected by multiple issues such as the language used, trust in the communicating actors and the opportunities for dialogue. The literature on siting of facilities also cautions that in many cases there in a mismatch between experts and lay perceptions of risk. This paper compares expert and lay perceptions of the risks associated with CCS in two case study areas and is based on the work undertaken in the CASSEM project, which is developing tools for the evaluation of CO2 storage potential in saline aquifer. [Copyright &y& Elsevier]

Abstract: Capturing CO2 from air, referred to as air capture, is being proposed as a viable climate change mitigation technology. Technically, air capture is not a new technology; industrial applications can be traced back to the 1930s. This paper explores the feasibility of this technology as a climate change mitigation option. Two different pathways of air capture are assessed: direct air capture, which uses a chemical process to capture CO2, and biomass coupled with CO2 capture and storage (CCS), which utilizes the biological process of photosynthesis to remove CO2 from the air. We find that direct air capture has prohibitively high mitigation costs compared to the costs of climate change mitigation options being considered today. The pathway of biomass coupled with CCS has much more reasonable costs and could be used to offset certain emissions. However, the large land requirement may limit the amount of offsets available. We conclude that relying on air capture technology to play a major role in mitigating carbon emissions is a very risky policy decision. [Copyright &y& Elsevier]

Abstract: Global climate warming caused by emission of greenhouse gas including CO2 is one of serious problems nowadays. In an effort to mitigate CO2 emissions, one of most effectively clean energy plan is to produce power from coal using the integrated gasification combined cycle (IGCC). However, the cost of existing CO2 capture technologies is still too high. Utilization of large-solubility and low-cost absorbent for CO2 capture in IGCC can effectively reduce the electricity price increase caused by addition of CO2 removal unit. As it needs to trap CO2 before combustion under high pressure in IGCC absorption is considered to be a better choice. HPP (Hot Potash Process) uses aqueous solution of potassium carbonate as the absorbent. Compared to physical solvent absorption method Rectisol and Selexol, HPP has relatively low investment and relatively high CO2 recovery. Even in comparison with other chemical absorbent amine method HPP still has advantages as good chemical stability and low vapor pressure. In this paper several activators piperidine, piperozine, pyrazine, morpholine, imidazole, N-hydroxyethyl piperozine, Naminoethyl piperozine, AMP was tested respectively at 70 °C. As a result, piperidine activation works best, followed by N-(2-hydroxyethyl)piperazine, N-(2-aminoethyl) piperazine, 2-amino-2-methyl-1 -propanol and piperazine, pyrazine and imidazole is at its worst. Among them, N-(2-hydroxyethyl)piperazine is less volatile, more stable and suitable as the activator. Absorbing capacity and absorbing rate of CO2 in carbonate aqueous solution with HPZ increases by 5% or more than those with PZ. An improved HPP process is presented adopting the new activator. In this process two de-absorption two columns is designed operating at different pressure. This makes it possible to reuse the heat of condensation during high pressure de-sorption in reboiler of low pressure de-sorption. By preliminary calculating the novel process can save energy consumption obviously. The steam consumption, cooling water consumption and power consumption declines by 43.30%, 31.81% and 10.57%, respectively. It is expected to develop a low-cost technology for capture CO2 from IGCC in the future. [Copyright &y& Elsevier]

Abstract: Amine based post-combustion capture is seen as one promising technology for future coal fired power plants with CO2 capture. The coupled absorption/desorption system to remove the CO2 from the flue gas is highly integrated with the power plant and the downstream CO2 compression, transportation and storage. With increasing portion of alternative energy forms like e.g. wind power, the demand on modern coal-fired power plants to provide regulating net power is increasing, leading to frequent and fast load changes during operation. To make the implementation of CCS to these plants technically and economically feasible, the capture process has to be able to follow these fast load changes without restraining the overall plant performance. To investigate the transient behavior of the individual plant components, as well as the overall dynamic performance of the capture unit, step response tests have been performed at a 1 ton CO2/hour pilot plant for the amine-based post-combustion process within the EU project CESAR. The purpose of the tests was to gain knowledge about possible problems or bottlenecks during a dynamic operation where the plant is going from one operation point to another. Three operation parameters were changed stepwise and the response of the entire system was monitored. In this paper the results of the tests are shown and the response of the system is analyzed. In general, no unexpected observations were made and no bottlenecks were found during the step response tests performed. The overall system acts like a buffer for any perturbation at the inlet, which is a wanted effect considering the future downstream compression unit. The average time for the entire system to reach the new steady state operating conditions after the perturbation was between 1 h 15 min and 1 h 45 min. However the interaction of the coupled absorber/desorber system led to fluctuations in the system, when all parameters have been changed simultaneously. [Copyright &y& Elsevier]

Abstract: Carbon Capture and Storage (CCS) represents a potentially effective means of addressing climate change. However, CCS processes create a suite of risks, including possibly injury to private and public sector interests, which will continue beyond the operational life of the project. Concerns regarding potential damages and attendant financial liability remain a barrier to commercial-scale deployment of CCS. The public dialogue on ‘liability’ as it relates to CCS has been clouded by a failure to clearly define what is at risk, and whether the consequences of such risks are material from a financial perspective. Focus on anecdotal references has contributed to unreasonable expectations and misunderstanding with respect to the amount and timing of funds necessary for the responsible deployment of CCS. Analytic evaluation of the range of potential impacts and calculation of financial consequences can illuminate: (1) the dollar amounts that need to be managed; (2) the set of circumstances under which amounts will present; and (3) the time frame over which these dollars will be needed. This paper applies an analytic framework drawn from damages estimation methodologies used in comparable contexts and incorporates risk-based probabilistic modeling to assist stakeholders in evaluating the potential consequences of CO2 migration at three candidate CCS sites. Specifically, it presents preliminary, order-of-magnitude estimates for potential public human health impacts associated with the operational phase of CCS activities at three proposed, non-selected USDOE FutureGen sites: (1) Tuscola, Illinois; (2) Jewett, Texas; and (3) Odessa, Texas. Attendant analyses applying the same methodology currently are underway to value damages associated with environmental resources, e.g., ground water, and atmospheric releases of CO2, as well as damages associated with the post-operational period. [Copyright &y& Elsevier]

Abstract: Coal is China’s primary fuel for power generation and will almost certainly remain so for the foreseeable future. At present China’s installed capacity of power generation plant totals about 900 GW with over 70% of that based on coal. Although major Chinese programmes are in place to improve energy efficiency, increase deployment of renewable energy technologies and increase the installed capacity of nuclear plant, coal-fired power plants will continue to be built in large numbers for many years to come. This paper presents the results of an energy systems analysis exercise using the China MARKAL model under the support of NZEC (China-UK Near Zero Emissions Coal) Initiative, to provide a perspective on the energy technologies that may be deployed in China to 2050 to meet its energy needs. The model also examines the cost and impact of deploying CCS in China by simulating several carbon emission constraint scenarios. [Copyright &y& Elsevier]

Abstract: In this paper we demonstrate that the secondary amines piperazine and diethanolamine, and the hindered secondary amine 2-piperidinemethanol, can react slowly with NOx in the presence of O2 to form nitrosamine derivatives under controlled laboratory conditions simulating industrial post-combustion CO2 capture processes. Methyldiethanolamine (MDEA), 2-amino-2-methyl-1-propanol (AMP) and 2-ethanolamine (MEA) were also investigated for control purposes, and no evidence for nitrosamine formation under these conditions could be found. The gas stream used to sparge the aqueous samples consisted of 81.4% N2, 12.8% CO2, 0.8% NO and 5.0% O2 flowing at 1.34 L/min through 200 g of aqueous amine solution maintained at 60 °C. The solutions were sampled at regular three hour intervals and analysed for the presence of N-nitrosamines using direct infusion electrospray ionisation mass spectrometry. Peaks due to the protonated forms of N-nitrosamines of the secondary amines (N-nitrosopiperazine m/z 116; N-nitrosodiethanolamine m/z 135; N-nitrosopiperidinemethanol m/z 145), were detected and their structural identities confirmed using MS/MS experiments. Piperazine was selected for further studies to determine the thermal- and photo-stability of its N-nitrosamine derivative. The results reveal that aqueous N-nitrosopiperazine is thermally stable at 150 °C but will degrade slowly upon exposure to UV light. [Copyright &y& Elsevier]

Abstract: Oxy-fuel combustion of fossil fuels produces a CO2-rich gas stream with some impurities, such as nitrogen, argon, oxygen, nitrogen oxides, heavy metals and sulphur oxides, whose concentrations vary based on the type of fuel, combustion conditions, plant configuration, and other process related parameters. To control the greenhouse gas (GHG) emissions from these plants and sustain their operational competitiveness in a carbon constrained world, the CO2 in the flue gas stream has to be captured, cleaned up and compressed to make it suitable for pipeline transport and permanent storage in geological formations. The flue gas CO2 capture and processing, including integrated multi-pollutant control, provides a feasible and viable technological pathway towards this goal. For oxy-fuel combustion systems, the CO2 capture is best achieved by physical gas separation through a series of compression and cooling stages to liquefy and separate CO2 from non-condensable gases in the flue gas stream. The effectiveness of the CO2 capture and compression system depends on the process design and assessed using removal efficiency, level of purification and energy demand for a unit of captured CO2. If the CO2 capture process can also simultaneously remove other pollutants in the gas stream, then the whole process becomes more efficient and cost-effective. In this case, implementing an elaborate flue gas pre-treatment system will not be necessary. Hence, CO2 capture technologies that are capable of simultaneously controlling emissions of multiple pollutants offer the potential to achieve emissions reduction at lower cost and reduced footprint, when compared to conventional emission control systems. For the new oxy-coal fired power plants, multi-pollutant control technologies can help designers of these plants select effective and less expensive compliance strategies, compared with compliance choices made when the requirements are addressed individually. CanmetENERGY has developed and successfully implemented an advanced and proprietary CO2 capture and compression unit (CO2CCU) that is capable of capturing and generating a relatively pure CO2 product stream, while simultaneously removing the pollutants such as nitrogen oxides, sulphur oxides and mercury in the process condensate streams. The pilot-scale unit is currently integrated with the existing 0.3 MWth oxy-fuel Vertical Combustor Research Facility. This advanced CO2 capture system represents an integrated approach to oxy-fuel combustion with multi-pollutant and CO2 capture and provides a unique test platform for CO2 processing. In this paper, we present and discuss the recent pilot-scale test results of CanmetENERGY’s CO2CCU. The unit was used to conduct experiments with a broad range of flue gas compositions, including different levels of CO2 concentrations and a host of impurities in the flue gas stream. The real-time measurements of CO2 product and vent stream gas compositions as well as the analysis of condensate streams provide insight into the type of chemical reactions that are taking place under different pressure, temperature, and moisture levels. The experimental results help to explain some of the chemical reactions involved in the CO2 capture and compression for better optimizing the capture process. [Copyright &y& Elsevier]

Abstract: The Kyoto Protocol’s flexible mechanisms allow projects that reduce greenhouse gas emissions to generate ‘carbon credits’. The most well known of the schemes is the clean development mechanism (CDM), which applies to emission reduction projects in developing and emerging economy countries that have ratified the Kyoto Protocol. The eligibility of carbon dioxide (CO2) capture and storage (CCS) technologies within the CDM has been a protracted process. One of the concerns hampering progress relates to the possible market implications of inclusion because of the potentially very large number of certified emission reduction units (CERs) that could be generated from CCS projects, which could potentially destabilize the global carbon market, for example, by depressing global carbon prices due to over-supply relative to demand. Drawing on these concerns, this paper provides a summary of analysis undertaken to assess the potential scale of such effects in both 2012 (the end of first commitment period of the Kyoto Protocol to the United Nations Framework Convention on Climate Change) and in 2020, with a view to evaluating the legitimacy of concerns in the short- to medium-term. It also provides some views on the potential alternative mechanisms that could evolve post-2012 for incentivizing and financing investments made in CCS technologies in developing and emerging economies. [Copyright &y& Elsevier]

Abstract: The underground storage of carbon dioxide (CO2) requires building, sizing, and coupling the reservoir and distribution network (pipelines and wells) models. Independent designs of the pipeline network, well, and reservoir models do not account for the effects one system has on the others. Coupling the different models is necessary to effectively design the full system. This paper discusses a methodology of jointly optimizing the pipeline network, well, and storage systems. This method uses simple and fast models instead of fully coupled, complex, and integrated models. It is thus applicable in the early phases of projects, when system parameters are not fully characterized (i.e., for scenario building and sensitivity analysis). Two different projects are examined: a single well with a short pipeline and multiple wells with a long pipeline. These cases can be adapted to offshore or onshore conditions. Although vertical wells were considered for this study, the same methodology can be easily extended to deviated and horizontal wells. Depending on conditions, the constraints that will dominate the full system may come from either the reservoir model or the pipeline network and well models. [Copyright &y& Elsevier]

Abstract: Safe candidate sites of reservoir for geologic storage including some oil or gas bearing structures on-shore or off-shore of the Taiwan island, and some near off-shore sedimentary basins were studied and screened. After screening out several potential engineering sites, an AHP ranking method was applied for ranking and selecting the preferred candidate on account of the economy factors, safety requirements, storage effectiveness, and potential storage capacity volume etc. As a result, preferred engineering site for pilot and demonstration plans were recommended. A deep saline aquifer under a Miocene basin near the western coast of Central Taiwan with estimated storage capacity up to 4 Gt- CO2 is now regarded as a very high potential storage reservoir with advantages of its high capacity volume, geological stability and the short distance away from the largest emission plants. More detailed investigation will be implemented during the year of 2010 to 2013 including works of site conformation, characterization prior to performing a pilot test with injection depth down to 2500 ∼3000 m. In this paper, the process and methodology of the screening potential reservoir and ranking of preferred engineering site are depicted and furthermore the tentative road map concerning Tai-Power’s CCS technology development for coal- fired power plant is introduced. [Copyright &y& Elsevier]

Abstract: Amino acid salts are of great interest as potential solvents for CO2 capture because they are considered to be environmentally friendly. In the present paper, results of experimental work with a pilot plant with 3.5 M potassium sarcosine are presented. Both absorption kinetics and energy consumption are studied. The results show clearly that the amino acid salt system has a high absorption rate and high energy requirement compared to 30 wt-% MEA. The solvent system has been modeled in an in-house tool and simulation results are compared with the some performance results obtained experimentally. The soft-model approach developed for the potassium sarcosine solvent systems represents the absorber fairly well, while it seems to be too simplified to represent the stripper conditions. The present study is part of an ongoing EU project, Cesar. [Copyright &y& Elsevier]

Abstract: Recent work examining likely changes in global temperatures as a result of carbon dioxide (CO2) emissions has suggested that cumulative CO2 emissions (i.e. total emissions over an extended period of time) could be more significant than the differences between particular emissions pathway (e.g. with different timing of emissions or peak emissions rate) in determining how the global climate might change in response to CO2 emissions. This suggests that effective measures to mitigate the risk of dangerous climate change will need to limit cumulative emissions of CO2. Further, if cumulative CO2 emissions overshoot acceptable limits, it will become necessary to remove CO2 from the air–so-called ‘negative emissions’. Technologies that effect ‘negative emissions’ could also be used to offset additional anthropogenic emissions from sectors where greenhouse gas emissions are difficult or impossible to reduce beyond certain, still relatively high, limits. If the prevailing carbon price for marginal abatement options rises significantly from current levels (e.g. of order up to $200/t CO2 has been suggested by some) then a relatively wide range of options for removing CO2 from the air may become cost-effective. Additionally, some options for removing CO2 from the air are likely to have much lower abatement costs. This paper summarises results from research conducted to compare and contrast various options for capturing CO2 from the air, with a particular focus on establishing the potential of these options to have a significant impact in reducing CO2 emissions and, if so, over what timescales. [Copyright &y& Elsevier]

Abstract: This paper describes an investigation for multi-stage systems used in coal-fired power plant. The whole work was divided into two steps: energetic and economic analyses. In the first step: on the basis of a serial concept, through varying the position of compressors and vacuum pumps, recycling the retentate of the 2nd membrane to the feed side of the 1st membrane, a cascade variant was developed and analysed. In the second step: an economic model was developed to calculate the capture cost of the cascade system. The total cost is composed of investment cost, operation and maintenance (O&M) cost and electricity cost. A correlation between the membrane parameters: selectivity & permeability and capture performance: energy consumption & capture cost was built up. Using Polyactive® membrane developed by GKSS with CO2 permeance of 3 Nm3/m2hbar and CO2/N2 selectivity of 50, under the separation target of 70% degree of CO2 separation and 95 mol% CO2 purity, adopting the cascade membrane system in the 600 MW NRW-reference power plant, the specific energy consumption including CO2 compression (110 bar, 30 °C) is 256 kWh/tseparatedCO2 with 6.4%-pts efficiency loss. The capture cost is 31 euro/tseparatedCO2 , which could be a promising solution as a retrofit for the existing power plants. [Copyright &y& Elsevier]

Abstract: This paper presents steady state and dynamic modelling of post combustion CO2 capture using 30 wt% MEA integrated with models of CO2 compression and the steam power cycle. It uses multivariable optimization tools to maximize hourly profit of a 100 MWe coal-fired power plant. Steady state optimization for design provided optimum lean loading and CO2 removal as a function of price ratio (CO2 price/electricity price). The results indicated that for price ratio between 2.1 and 7, the plant should be designed at removal between 70% and 98% and lean loading in the range of 0.22–0.25. Dynamic optimization determined the operation of the capture system in response to two partial load scenarios (reboiler steam load reduction and power plant boiler load reduction) and provided optimum set points for steam rate, solvent circulation rate and stripper pressure control loops. Maximum profit is maintained by allowing the stripper pressure to drop and implementing a ratio control between solvent and steam rate (and flue gas rate for partial boiler load operation). [Copyright &y& Elsevier]

Abstract: Significant quantities of water are utilized in thermoelectric power plants, mostly for the purpose of cooling. Water is becoming critically important for low carbon power generation. To reduce greenhouse gas emissions from pulverized coal (PC) power plants, post-combustion carbon capture systems are receiving considerable attention. However, current systems require a significant amount of cooling, which puts further pressure on cooling water resource. This paper quantifies cooling water use and evaluates technical and economic effects of carbon capture on cooling systems at PC power plants. Included are recirculating systems with wet cooling towers and air-cooled condensers (ACCs) for dry cooling. For a wet cooling tower, water has to be provided to make up losses due mainly to evaporation and blowdown. Adding an amine-based carbon capture system to the plant would approximately double water use. When air-cooled condensers (ACCs) are used as the dry cooling system, in spite of the advantage in reducing water usage, the dry cooling system has a much larger capital cost than the wet cooling system, depending strongly on specific site and system characteristics. [Copyright &y& Elsevier]

Abstract: Carbon Capture and Storage (CCS) is recognised as one of the most effective technologies for reducing CO2 emissions in the short to medium term. From a capacity point of view, deep saline aquifers offer the greatest potential. As supercritical CO2 is injected in the aquifer, a variety of strongly coupled physical and chemical processes occur. Among these various mechanisms, vaporisation of water requires particular attention as it can cause salt precipitation, which reduces the porosity and the permeability of the reservoir in the vicinity of the wellbore. This can lead to significant reduction in injectivity. Research described in this paper aims to provide a relationship between porosity changes and resulting permeability variations representing the effect of salt precipitation due to vaporisation. Supercritical CO2 core flooding experiments were conducted on a St. Bees sandstone core with fully saturated saline water obtaining several levels of alteration due to halite scaling. Porosity reduction ranged from around 4 to 29% of the initial value. Permeability impairments ranged from 30 to 86%. Results were used to calibrate a Verma-Pruess “tube-in-series” model which can be used to obtain more accurate results from numerical simulations. [Copyright &y& Elsevier]

Abstract: Oxyfuel combustion CO2 capture technology presents an excellent opportunity for achieving near zero emissions from the coal-fired power plants. In the oxyfuel technology, the volume of flue gas is reduced by a factor of four to five (on a dry basis) due to elimination/reduction of nitrogen from combustion. This reduced volume of CO2-rich flue gas has to be compressed to 25 to 35 bar (a) for purification, thus further reducing the actual volume of flue gas by a factor of 25 to 35. If the equipment for removing trace impurities (SOx, NOx and Hg) is installed downstream of the flue gas compressor, the capital investment could be significantly reduced compared to that for the air-fired operation. Furthermore, by processing the entire volume of flue gas in the CO2 purification unit, it is possible to remove and concentrate the trace impurities in the solid and liquid waste streams and to produce a vent stream with near zero emissions and a high purity CO2 relatively free of trace impurities. Praxair is developing an oxy-combustion flue gas purification technology that will leverage these synergies. This technology will reduce emissions of CO2, SOx and Hg by >99% and NOx emissions by >95% compared to an air-fired pulverized coal power plant. The benefits of the technology include management of air ingress problems, capital and operating cost savings for SOx and NOx removal, reduction in CO2 capture cost and production of high purity CO2 stream for sequestration. These benefits will translate to lower cost of electricity for power plants with CO2 capture. This paper presents the experimental data for the SOx/NOx removal and high CO2 recovery processes and the results of the commercial viability assessment. [Copyright &y& Elsevier]