On obtaining optimal well rates and placement for CO2 storage

Large-scale storage of CO2 in saline aquifers is considered an essential technology to mitigate CO2 emissions. Storage potential has mainly been estimated based on volumetrics or detailed simulations for specific injection scenarios. In practice, achievable storage capacity will depend on engineering, economical, and political restrictions and be limited by the length of the injection period, costs associated with potential CO2 leakage, pressure management, etc. We show how achievable storage volumes can be estimated and maximized using adjoint-based optimization and a hierarchy of simulation methods. In particular, vertical equilibrium models provide the simplest possible description of the flow dynamics during the injection and early post-injection period, while percolation type methods provide effective means for forecasting the long-term fate of CO2 during the later migration stages. We investigate the storage volumes that can be achieved for several formations found along the Norwegian Continental Shelf by optimizing well placement and injection rates, and using production wells for pressure management when necessary. Optimal strategies are obtained under various objectives and simple but realistic constraints, namely: penalization of CO2 leakage, minimization of well cost, and restriction of pressure buildup.acceptedVersio

Investigation of geomechanical responses of reservoirs induced by carbon dioxide storage

Assessment of the suitability of potential sub-surface storage sites for CO2 storage cuts across several issues, a dominant part being the sustainability in terms of the retention capacity of prospective reservoirs. Questions often raised but not properly investigated border on the stability of underground reservoirs during the injection process and the protracted effect after injection is fully completed. A review of studies on CO2 sequestration reveals several uncovered areas with one significant aspect being the geo-mechanical effect of CO2 injection and storage within the underground formation. A computational framework has been built as part of a series of ongoing investigations to ascertain the susceptibility of underground formations during and after CO2 is introduced. This is made possible by adopting a discrete element modelling methodology as a first step in the sequence of a designed procedure. By applying this technique, the formation materials are idealised as an assembly of discrete particles interacting in a manner which allows for specific descriptions of the morphology and fracturing events. Computational tests conducted on several types of models representative of reservoir formations reveal reservoir geo-mechanical responses highly dependent on factors, such as material property of rocks, pressure build-up and injection pressure. An example of this is observed in the mode of fracturing events which is significantly influenced by the rate of fluid injection. The outcome of this study forms a strong basis towards a better understanding of the behaviour of reservoir formations subjected to CO2 injection and storage. In addition, information from these studies could serve as a reference for enhanced oil recovery processes and enhanced coal bed methane productions