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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]