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The Mont Terri Underground Research Laboratory (MT-URL) and Consortia affords member organizations the opportunity to bridge the gap between bench and large field scale experiments. At this underground test site, CCP4 (CO 2 Capture Project Phase 4) partners, a four company collaboration that includes BP, Chevron, Petrobras and Suncor, along with the Swiss Topographic Survey (swisstopo) who operates the laboratory, are conducting 1) an experiment that focuses on the mitigation of pressure leakages associated with CO 2 containment in near wellbore injection well systems using novel sealants and, if resources are available, 2) a fractured caprock breach sealing experiment. The mock well system experiment for CO 2 breach mitigation is of immediate interest. This experiment, designated CS-A, is operational with equipment installation accomplished late 2 nd quarter 2015 and experimental protocols that commenced late December 2015 scheduled to run through the summer of 2017. Sealant testing is scheduled to begin in late 2016. The objective is to assess the ability to characterize and seal induced leaks at micro annular interfaces (casing, cement and country rock) using novel sealants with determination of the long term sealing integrity. The 2 nd experiment is in an earlier stage of development, having been scoped in 2014 for costing and resource alignment. This second project requires additional participants to spread costs before the final design is set.

Two concepts have been very influential in aiding the evolving understanding of CO 2 storage systems. The first of these was the trapping diagram that first appeared in the IPCC Special Report on CCS (2007). This shows the evolution of the balance of trapping processes – physical seals, capillary trapping, dissolution and reactive trapping - over time. This clearly demonstrated the need to move beyond simplistic estimates of storage capacity to understanding the interplay between the trapping processes. The second was a conceptual model of the evolution of risk through the life of a CO 2 storage site presented by Benson at GHGT-8. This showed risk rising to a peak during injection and then declining back to a low level as the site stabilised post injection. Both of these concepts were presented in diagrammatic form and have been the subject of considerable discussion ever since. As an illustration, opinion remains divided as to whether storage risk peaks and declines or whether it continues to rise as buoyant migration causes the plume to contact an ever increasing area of seal. In this study we use a simplified model based upon vertical equilibrium concepts to develop analytically derived versions of both the IPCC trapping diagram and to explore the risk of seal failure in the post-closure period.

[1] Sequestration of carbon dioxide in deep saline aquifers has been proposed and investigated as a viable solution to help mitigate carbon emissions from fossil fuels. Much research has been directed at understanding the transitions of supercritical CO2 from being a mobile fluid phase to being trapped by capillarity or dissolved in groundwater; such transitions lead to a reduction in mobility of CO2 and hence in the risk of leakage to the surface. Following injection, buoyant plumes of CO2 migrate updip towards structural traps in the geological strata; however, some of this CO2 may be capillary trapped in pore spaces or dissolved in groundwater en route. Since CO2 saturated groundwater only has a small CO2 concentration, the dissolution of any large, structurally trapped plumes of CO2 may be controlled by the availability of unsaturated groundwater. In an aquifer of finite vertical extent, this may be rate limited by a combination of (i) the background hydrological flow coupled with (ii) the slow lateral exchange of relatively dense, CO2saturated groundwater with unsaturated groundwater. In an inclined aquifer, this may be controlled by the slow along-aquifer component of gravity. Structurally trapped plumes of CO2 may therefore persist for many thousands of years, and, since they are potentially highly mobile, may represent an important contribution to the long term risks associated with CO2 sequestration at particular sites.

Publisher Summary Risk assessment should be actively used at all stages, before, during and after injection. It is used to identify the key risks that require specific attention for all sites and to inform monitoring strategy. During site selection and evaluation, well and 3D seismic data must be considered essential, and more new data acquisition will normally be required for aquifer options. Understanding the processes and potential leakage mechanisms is vital in developing the framework for managing geological storage. In considering performance criteria, it is important to recognize that the amount of mobile CO2, with potential for leakage as a separate phase diminishes after injection, thereby reducing the risk of leakage. Leakage mechanisms are fairly well understood, although the kinetics and quantification require further research. The local risk of high flux leakage and release is primarily from wells, faults, and possible local overburden accumulators. Seal presence, trap integrity and fault presence and the risk from old wells need to be rigorously assessed in the site selection phase.

Publisher Summary A structured approach to risk mitigation requires a systematic method for identification of scenarios that can lead to risk. There are two approaches to this. The first relies on experience to identify key risks. An alternative approach is being investigated by some groups. This borrows the concept from the nuclear industry of a database of Performance Factors (Features, Events, and Processes in the jargon of the nuclear industry) relevant to the possible release of CO2 from storage. Once Peer Review has identified the relevant Performance Factors, scenarios can be created by inspection and experience.

Publisher Summary This chapter provides an update on the in Salah gas (ISG) project and the accompanying CO2 storage assurance project, which it is proposed and managed under the umbrella of a joint industry project (JIP). It consists of project management, establishing a project baseline, imaging CO2 migration, well based monitoring, rock/fluid interactions, detecting surface (geologic) seepage, integration and risk assessment, and communications. This CO2 project differs significantly in geological character and storage process from the existing Sleipner and Weyburn monitoring projects and offers an ideal opportunity to gain important additional information on the permanence and safety of CO2 geologic storage. The ISG project provides an important opportunity to study a gas field development project where geological storage at a field scale is employed to mitigate the environmental impact of the produced CO2 stream, which represents—60% of the projects emissions footprint.

Publisher Summary This chapter describes the process of geologic storage of CO2 from refineries and chemical plants in the midwestem United States. Three locations in the midwestem United States were evaluated for saline reservoir sequestration of CO2 transported from refineries and chemical plants along existing pipeline rights of way. Based on formation volume calculations, the potential storage capacity in a single formation, the Mt. Simon Sandstone, is in the range of several billion tons. Compositional reservoir simulations were completed to predict the formation pressures, CO2 spreading, and dissolution following injection. Injectivity at all sites was sufficient for more than 1 mt/year/well of CO2 without exceeding the fracture pressure limits, and no leakage of CO2 into shallower horizons was predicted. A horizontal injection well scenario showed a smaller increase in reservoir pressure than vertical wells. The geochemical evaluation included a summary of the brine chemistry and mineralogy of the reservoir and caprock formations. Equilibrium geochemical simulations for several scenarios did not indicate any adverse reactions as a result of CO2 injection. A preliminary economic and engineering assessment of several injection scenarios showed that the cost of CO2 dehydration, compression, transport, and injection is nearly $20 per ton, excluding any capture costs. The largest capital cost is in compression and pipeline systems, and the largest operational cost is that of compression. System costs may be reduced by optimizing the location of storage reservoirs closer to the emission sources or through development of a regional shared transport network and storage site.

The COACH project was an EU-China collaboration funded by the EU’s FP7 R&D programme to assess the potential for a CCS demonstration project in China.The Jing-Jin-Ji Region of North-Eastern China is a major contributor to China’s CO2 emissions profile with large stationary sources currently contributing annual emissions of nearly 350 million tonnes CO2 per year, of which approximately 300 million tonnes CO2 has the potential to be captured and stored annually. Two scenarios for a CCS demonstration project located in the onshore section of the Bohai Bay region in Shandong Province in the North East of China were assessed in this study.Capture studies considered a polygeneration scenario while scoping studies were performed of storage potential within the onshore Bohai Bay area. Size scales of 1Mtonnes/year (c. 100 million tonnes storage capacity) were considered.Introductory screening was performed for four areas to review their potential for development for CO2 storage. These included two oilfield provinces, a regional saline formation and a coal mining area. A preliminary risk assessment was prepared covering both technical and non-technical issues.Order of magnitude costs likely to be incurred in implementing a CCS demonstration project were assessed. These included estimates of the cost of capture and conditioning of the CO2, transportation to a storage site and the storage of the CO2 in a geological formation. The cost of capture was expressed relative to a reference case comprising an IGCC without CCS. A single product, electricity, was considered. Storage costs were assumed to arise from appraisal (saline formations and coal mining areas), wells (new CO2 injectors and remediation or upgrading for existing wells) and monitoring.

The COACH project (Cooperation Action Within CCS China-EU11EC/FP6 Contract #038966, co-ordinated by F. Kalaydjian, IFP Energies nouvelles, France.) was launched on November 1st 2006 for a period of 3 years, as part of the 6th framework programme of the European Commission22The French Agency for Development (AFD) is gratefully acknowledged for its financial support to the dissemination, knowledge sharing and capacity building activities developed in COACH.. Gathering 20 partners comprising 8 Chinese partners and 12 European partners, the COACH project was conceived as contributing to the first phase of the Near Zero Emission Coal fired power plants (NZEC) programme, a 3-phase programme developed between the European Union and China, aiming at combating climate change by enabling the deployment in China of thermal power plants equipped with CO2 capture and storage (CCS) facilities.The objective of the COACH project was to establish the basis for the large-scale use of coal for polygeneration in China with pre-combustion capture, transport and geological storage of CO2. Main efforts were place on a future CCS demonstration operated on an Integrated Gasification Combined Cycle (IGCC) thermal power plant fully equipped for converting and splitting the produced syngas into a hydrogen-rich fuel gas and CO2, and with a subsequent storage of CO2 in either mature hydrocarbon reservoirs (Dagang or Shengli oil provinces), deep saline formations or unmineable coal seams. Focus was made on the emission sources and storage sites located in the part of the Bohai Basin in the Shandong Province.The paper will present the main outcomes of the project as follows : •Structuring the China-EU COACH venture: In order to enabling the sharing of knowledge between European and Chinese COACH partners and building capacity a survey of CCS activities was performed, workshops were organised in EU and China, a cooperative website was created and two one-week long CCS schools were organised in China gathering more than 100 students 2/3 thereof coming from China and the remaining from Europe;•Technical actions and challenges relating to CCS, gasification and polygeneration: A generic IGCC concept implemented with CO2 capture was defined and compared against a plain IGCC based on the GreenGen Phase I system without CO2 capture. A detailed analysis of technologies needed for implementing an option for CO2 capture in an IGCC process with provision for production of electricity and methanol was carried out as well as a cost analysis of both CO2 capture and transport;•Geological assessment and storage sites mapping: A quantitative assessment of the potential storage sites (the Dagang and Shengli oil provinces, the deep saline aquifers nearby and the Kailuan coal mining area) was performed along with a mapping of the possible transport infrastructure (by pipelines or ships) that could be developed to connect CO2 sources to CO2 sites; with regards to storage capacity, the main capacity was found to reside in the deep saline aquifers (several giga tonnes) but would require further geological investigation for delivering definite values. The storage potential in oil fields was found to be much smaller (less than one giga tonne) but could provide opportunities for enhanced oil recovery. Finally, the coals of Kailuan mining area exhibit a high ability to adsorb CO2 and provide enhanced coalbed methane recovery, but their injectivity remains to be verified.•Case studies and recommendations for CCS demonstration in China: By integrating results obtained in the previous tasks dealing with CO2 capture and CO2 storage, two scenarios (one small scale–from 0.1 to 1 million tonnes of CO2 per year, one large scale–2 to 3 million tonnes of CO2 per year) were designed to screen options for a possible CCS demonstration project. These alternative CO2 streams are both considered captured from the GreenGen IGCC power plant in Tianjin and transported to one or more geological formations in the Bohai Bay geological basin for permanent disposal. Storage for the smaller scale scenario could be accommodated in the Dagang or Shengli oilfields. Storage for the larger scale scenario (2–3 million tonnes a year) could be accommodated in the Shengli oilfield province (in a number of fields) or potentially in the saline formations that can be found in the Huimin sub-basin area. For each of these options, a preliminary risk assessment was performed. A thorough cost analysis was performed. Policy and regulation issues pertaining to a shift towards CCS in China. The 3-year targeted cooperative actions under the COACH project have mobilised capacities in China and Europe and paved the ground for subsequent CCS demonstrations in China. The next phase of the China-EU NZEC programme should start in 2010 and deliver FEED studies which should allow starting operating a CCS demonstration in China by 2015.