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Celia M.A.,Princeton University | Nordbotten J.M.,Princeton University | Nordbotten J.M.,University of Bergen | Court B.,Princeton University | And 2 more authors.
International Journal of Greenhouse Gas Control | Year: 2011

Carbon capture and geological storage (CCS) operations will require an environmental risk analysis to determine, among other things, the risk that injected CO2 or displaced brine will leak from the injection formation into other parts of the subsurface or surface environments. Such an analysis requires site characterization including identification of potential leakage pathways. In North America, the century-long legacy of oil and gas exploration and production has left millions of oil and gas wells, many of which are co-located with otherwise good geological storage sites. Potential leakage along existing wells, coupled with layered stratigraphic sequences and highly uncertain parameters, makes quantitative analysis of leakage risk a significant computational challenge. However, new approaches to modeling CO2 injection, migration, and leakage allow for realistic scenarios to be simulated within a probabilistic framework. Using a specific field site in Alberta, Canada, we perform a range of computational studies aimed at risk analysis with a focus on CO2 and brine leakage along old wells. The specific calculations focus on the injection period, when risk of leakage is expected to be largest. Specifically, we simulate 50 years of injection of supercritical CO2 and use a Monte Carlo framework to analyze the overall system behavior. The simulations involve injection, migration, and leakage over the 50-year time horizon for domains of several thousand square kilometers having multiple layers in the sedimentary succession and several thousand old wells within the domain. Because we can perform each simulation in a few minutes of computer time, we can run tens of thousands of simulations and analyze the outputs in a probabilistic framework. We use these kinds of simulations to demonstrate the importance of residual brine saturations, the range of current options to quantify leaky well properties, and the impact of depth of injection and how it relates to leakage risk. © 2010. Source


Court B.,Princeton University | Bandilla K.W.,Princeton University | Celia M.A.,Princeton University | Janzen A.,Princeton University | And 5 more authors.
International Journal of Greenhouse Gas Control | Year: 2012

Analysis of geological sequestration of carbon dioxide (CO 2) requires mathematical models of different complexity to answer a range of practical questions. A family of vertically-integrated models of intermediate complexity can be derived by assuming that the strong buoyant drive in the system leads to vertical segregation of the injected CO 2 and resident brine on a time scale that is fast enough to model the system as being stratified and in vertical-equilibrium. These models range from vertically-integrated numerical models which include capillary forces via mathematical reconstruction, to analytical models assuming a sharp-interface and homogeneous formation parameters. This paper investigates the limits of numerical vertical-equilibrium models and the more restricted vertical-equilibrium sharp-interface models via direct comparisons with a homogeneous three-dimensional model, exploring the impacts of injection rate, injection time, and formation characteristics. We use the commercial simulator ECLIPSE for the three-dimensional model. Our results demonstrate that the applicability of a vertically-integrated modeling approach to CO 2 sequestration depends on the time scale of the vertical brine drainage within the plume, relative to the time scale of the simulation. The validity of the sharp-interface assumption is shown to depend on the spatial scale of the capillary forces, which drive the thickness of the capillary transition zone. A finite-capillary-transition-zone vertically-integrated numerical model with saturation reconstruction closely matches results from the three-dimensional model (ECLIPSE) including capillary pressure as long as the segregation time scales are respected. Overall, our results demonstrate that vertically-integrated and sharp-interface models are useful and accurate when applied within the appropriate length and time scales. © 2012 Elsevier Ltd. Source


Court B.,Princeton University | Bandilla K.W.,Princeton University | Celia M.A.,Princeton University | Buscheck T.A.,Lawrence Livermore National Laboratory | And 6 more authors.
International Journal of Greenhouse Gas Control | Year: 2012

Mitigation of global atmospheric carbon emissions requires a worldwide ramping up of CO 2 capture and sequestration (CCS) implementation in the next decades. While CCS could be deployed in isolation, there is also the possibility to consider CO 2 injection within a much broader framework of reservoir and resource management including active water (brine) management. The goal of this study is to provide an initial analysis of three identified synergies related to active brine management in CCS operations. The potential advantages of coupling simultaneous brine production to a large-scale CO 2 geological sequestration operation are explored through three separate modeling studies. Our results demonstrate that brine production can provide important pressure-control benefits, including increased injectivity potential through reduction of the injection well pressure, significant reduction of the extent of the Area of Review, within which operators must procure property rights and monitor and remediate potential leakage pathways, and reduction in the risk of CO 2 and brine leakage. The latter is especially important in reservoirs, like many in North America, where a significant number of potential leakage pathways, particularly abandoned wells, may exist within the Area of Review. We also observe that brine production has minimal impact on the overall shape of the CO 2 plume, with plume shape and extent strongly governed by formation parameters. © 2012 Elsevier Ltd. Source


Dobossy M.E.,Geological Storage Consultants, Llc | Dobossy M.E.,Princeton University | Celia M.A.,Geological Storage Consultants, Llc | Celia M.A.,Princeton University | And 3 more authors.
Energy Procedia | Year: 2011

In response to anthropogenic CO2 emissions, geological storage has emerged as a practical and scalable bridge technology while renewables and other environmentally friendly energy production methods mature. While an attractive solution, geological storage of CO2 has inherent risk. Two primary concerns are recognized: 1) leakage of CO2 through caprock imperfections, and 2) brine displacement resulting in contamination of drinking water sources. Three mechanisms for both CO2 and brine leakage have been identified: diffuse leakage through the caprock, leakage through faults and fractures in the caprock, and finally, leakage through man-made pathways such as abandoned wells from oil and gas exploration. While the first two leakage mechanisms are important, we emphasize the risks associated with the presence of abandoned wells. This is due to the large number and density of wells from a history of oil and gas exploration around the world, and the high degree of uncertainty surrounding the properties of these abandoned wells. With current proposed legislation in both the United States and Europe, a need is emerging for practical assessment of leakage risk. In order to accurately predict leakage of brine and CO2 from the injection layer, the geological information for the injection site and the location and makeup of the man-made leakage pathways previously alluded to must be taken into account. Unfortunately, both the geology and abandoned well metadata are typically high in uncertainty, which must be accounted for. With such a high number of random variables, the current state of the art is running many realizations of a system, using a Monte Carlo approach. This requires that the underlying solution algorithms be accurate, and efficient. In the past, many researchers in both academia and industry have turned to robust numerical analysis packages used in the oil industry. However, due to the large range of scales important to this problem (domains of tens of kilometers on a side affected by leakage pathways with diameters of tens of centimeters) such modeling techniques become computationally expensive for all but the most basic analysis. A computational model developed at Princeton University, and currently being commercialized by Geological Storage Consultants, LLC has been shown to be efficient with sufficient accuracy to allow for comprehensive risk assessment of CO2 injection projects. The model allows for mixing solution methods- using computationally expensive algorithms for formations of greater importance (e.g.- the injection formation) and more efficient, simplified algorithms in other areas of the domain. This ability to arbitrarily mix solution methods offers significant flexibility in the design and execution of models. This paper addresses the framework and algorithms used, and illustrates the importance of efficiency and parallelism using the case study of an injection site in Alberta, Canada. We show how the framework can be used for project planning, for risk mitigation (insurance), and for regulatory groups. Finally, the importance of flexible analysis tools that allow for efficient and effective management of computational resources is discussed. © 2010 Elsevier Ltd. © 2011 Published by Elsevier Ltd. Source


Grant
Agency: Department of Energy | Branch: | Program: SBIR | Phase: Phase I | Award Amount: 99.74K | Year: 2010

Geological storage of captured CO2 emissions is a promising carbon mitigation strategy. However, even in ideal injection formations with highly impermeable cap-rocks, both natural (faults/fissures) and man-made (abandoned wells) leakage pathways exist. Due to significant uncertainty in the geology and possible leakage pathways, comprehensive risk assessment tools are necessary to plan, regulate, and insure commercial geological CO2 storage projects. A novel academic software framework developed at Princeton University that is currently the most efficient method for providing a comprehensive risk assessment of geological storage projects, will be developed into an appropriate industrial software package and brought to market. Commercial Applications and Other Benefits: A significant risk involved with geological storage of CO2 is the leakage of both CO2 and brine from the targeted injection formation. The software tools developed under this SBIR will be of significant value to three markets injection project planning and operation, regulation, and insurance. Project planners and operators will be able to use the software developed in order to evaluate potential injection sites and formations. Regulators will need such tools for calculating area of review, and determining the risk to the public (e.g.- contamination of drinking water supplies). Finally, insurance and reinsurance companies will be provided with a much needed method to determine the liability risk of a given injection project to properly price policies

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