The storage of carbon dioxide (CO 2 ) in saline aquifers is one of the most promising options for Europe to reduce emissions of greenhouse gases from power plants to the atmosphere and to mitigate global climate change. The CO 2 SINK (CO 2 Storage by Injection into a saline aquifer at Ketzin) project is a research and development (R&D) project, mainly supported by the European Commission, the German Federal Ministry of Education and Research, and the German Federal Ministry of Economics and Technology, targeted at developing an in-situ laboratory for CO 2 storage.The preparatory phase of the project involved a baseline geological-site exploration and the drilling of one injection and two observation wells, as well as the acquisition of a geophysical baseline and geochemical monitoring, in Ketzin, located near Berlin. The target saline aquifer is the lithologically heterogeneous Triassic Stuttgart formation, situated at approximately 630-to 710-m (2,070-to 2,330-ft) depth. A comprehensive borehole-logging program was performed consisting of routine well logging complemented with an enhanced logging program for one well that recorded nuclear-magnetic-resonance (NMR) and boreholeresistivity images, to characterize the storage formation better. A core analysis program carried out on reservoir rock and caprock included measurements of helium porosity, nitrogen permeability, and brine permeability at different pressure conditions.The saline aquifer at Ketzin shows a variable porosity/permeability distribution, which is related to grain size, facies variation, and rock cementation with values in the range from 5 to > 35% and 0.02 to > 5,000 md for porosity and permeability, respectively. On the basis of core analysis and logging data, an elemental loganalysis model for the target formation was established for all three wells. In addition, permeability was estimated using the Coates equation and compared with core data and NMR log-derived permeability, which seems to provide meaningful permeability estimates for the Ketzin reservoir. On the basis of the good core control that guided the petrophysical well-log interpretation in the first two CO 2 SINK wells, a porosity and permeability prediction by analogy for the third well is appropriate and applicable. The availability of cores was crucial for a sophisticated formation evaluation at borehole scale that characterizes the real subsurface conditions.

The storage of carbon dioxide (CO2) in saline aquifers is one of the most promising options for Europe to reduce emissions of greenhouse gases from power plants to the atmosphere and to mitigate global climate change. The CO2SINK project is a R&D project, mainly supported by the European commission, the German Federal Ministry of Education and Research, and the German Federal Ministry of Economics and Technology, targeted at developing an in situ laboratory for CO2 storage. Its aims are to advance the understanding of the processes involved in underground CO2 storage, evaluate applicable monitoring techniques, and provide operational experience, which all contribute to the development of harmonized regulatory frameworks and standards for CO2 geological storage. The preparatory phase of the project involved a baseline geological site exploration and the drilling in 2007 of one injection and two observation wells, as well as the acquisition of a geophysical baseline and geochemical monitoring, in Ketzin located near to Berlin, Germany. The target saline aquifer is the Triassic Stuttgart Formation situated at about 630-710 m (2070-2330 ft), that is made of siltstones and sandstones interbedded by mudstones. A comprehensive borehole logging program was performed consisting of routine well logging to which an enhanced logging program was added for one well that record nuclear magnetic resonance and borehole resistivity images predominantly to better characterize the storage formation. A core analysis program carried out on reservoir rock and caprock included measurements of helium porosity, nitrogen permeability and brine permeability. Carbon dioxide injection started in 2008 and will last for about 2 years. The paper focuses on the integrated approach of combining lithological and petrophysical data from both laboratory and well logging analysis predominantly for the reservoir/storage section of the Ketzin site. This method was successfully applied in two wells with extensive core data. In the third well, where few core data exist, the section was characterized successfully by analogy. Introduction Since the publication of the Intergovernmental Panel on Climate Change Report (IPCC, 2005), geological storage of carbon dioxide (CO2) was recognized in the public as an important concept for reducing greenhouse gas emissions into the atmosphere. Notwithstanding technology, the understanding of the storage geometry, from the near surface to below the storage reservoir is mandatory. Another prerequisite for a successful operating storage project is the detailed knowledge of rock and fluid properties that do depend on pressure and temperature conditions. These data serve as an input for reservoir models and decisions on the injection regime as well as decisions on the monitoring of long-term CO2 migration after injection.

We studied the electric response of fractures with laboratory experiments and numerical simulations for a full-bore formation microimaging tool. The laboratory setup was designed and built to perform controlled experiments with accurate measurements of all principal properties involved for electric borehole imaging. These properties are formation resistivity, mud resistivity, fracture aperture, pad position, and button current. The experiments were conducted on two types of limestone for fracture apertures ranging from 0.1 to 0.9 mm and mud/formation resistivity contrasts varying from 1/100 to 1/10,000. A numerical model was used to reproduce the laboratory configuration and to validate the results. The model proved to be an effective tool to optimize the experimental setup, and it was also used to study the effect of standoff (up to 5 mm) on the measured integrated additional current. Linear relationships between the fracture aperture and measured integrated current were found to be valid for the laboratory experiment and the corresponding numerical simulation. The measured integrated current could therefore be used to determine the fracture aperture if the other parameters are known. Two coefficients in the relationship were found to differ from those previously found using numerical simulations for the actual borehole situation. These differences are attributed to tool-and scale-dependent factors.

The presence of fractures in reservoirs can have a large impact on short and long term production. Electrical imaging tools have a long history in the identification and quantification of fractures in boreholes drilled with water base muds. These tools are particularly sensitive to conductive fractures. The width (also known as aperture) of open fractures is calculated by a well-established equation, relating the fracture width to the excess current measured by the imaging tool (Luthi and Souhaité, 1990). Both mud resistivity and background resistivity of the formation need to be known or measured. The equation was derived from 3-D finite element modeling of the borehole imaging tools of the time. Recent work has revisited the fracture aperture calculations. The work has verified the approach for electrical imaging from modern wireline tools and extended the principle to Logging While Drilling (LWD) tools. A twofold approach has been taken for the work. Firstly 3-D finite element modeling had been carried out. This includes detailed modeling of the tool sensors' geometry and the analysis of the electromagnetic responses when the sensors are passed in front of a range of fracture widths. The modeling is complemented by a series of physical experiments carried out at Delft University. Setups utilized either a wireline pad or an LWD sensor from the relevant imaging tools. The sensors were traversed across two blocks separated by a precisely measured gap. Measured excess current relates to the fracture apertures and verifies the theoretical modeling work. This combined work confirms the equation for the fracture aperture calculation. In addition the coefficients for both the modern wireline and LWD electrical imaging tools are determined. Workflows for the quantification of conductive fractures identified on borehole images have been refined and implemented. Fractures are commonly not continuous across the borehole. The workflow includes a fast automatic extraction of both discontinuous and continuous fracture segments. Fractures are grouped into sets based on relevant criteria (such as orientation). Apertures are calculated using the relevant tool coefficients. The fracture density and porosity are then accurately computed along the well. This enables quantification and characterization of the fracture network, including a fast and easy recognition of intervals with specific aperture or porosity ranges. The workflow is demonstrated by examples.

The CO2CRC Otway Project, in Victoria, Australia, is one of the first projects of CO2 storage in a depleted gas reservoir. CO2 injection in the sandstone reservoir, at a depth of 2,000 mSS, started in March 2008 with the objective to inject up to 100,000 tonnes of CO2 over two years. This study compares the level of predictability obtained with different cases depending on the initial data, using the same numerical compositional simulation package. We use recorded data (production and injection) to build a new numerical reservoir model. A dynamic model had already been built before the injection well started (Xu et al., 2006) and was validated by history matching using the gas production data reported. In this paper, we used the same updated static model (Dance et al. 2007) as used for the pre-injection model, which is based on the production data and the data obtained from the injection well (CRC-1). With this updated static model, a different dynamic model is built using injection data and through a newly developed simulator option, which better simulates the CO2-water behavior. The injection rate and pressure data from CRC-1 are now available and the actual breakthrough time - at which the CO2 plume reached the monitoring well (Naylor-1) located 300 m away from CRC-1 - can be history matched. Various relative permeability curves including new laboratory measurements performed on a core taken from the reservoir formation (Waarre C) were used. The results from the updated dynamic modeling using this measured relative permeability data are compared to results using data from literature. In general, experimental measurements for drainage and imbibition processes are not available This study gives a better understanding of the parameters which strongly influence simulated CO2 behavior. It shows the relation between the data availability and prediction reliability. Introduction Carbon dioxide is a greenhouse gas and has a strong impact on global climate changes. The effect of CO2 on global warming is now well recognized and possibilities to reduce the greenhouse gas emissions are currently investigated. It is not expected that the demand of fossil fuels, which produce most of the greenhouse gases (GHG), will decline in the near future (International Energy Agency, IEA) although significant efforts have been made to use more alternative energy sources. Carbon capture and storage (CCS, i.e. injection of CO2 in deep geological formations instead of being emitted in the atmosphere) is recognized as to be one of the options to reduce the emissions of GHG as described by the IEA (2008) and by the Intergovernmental Panel on Climate Change (Fisher et al., 2007). More and more CCS projects are being developed around the world. Lately, with the support of IEA and to respond to a request from the G8 nations, a CCS Roadmap has been developed to demonstrate and effectively deploy CCS projects.