Abstract
Abstract It is recognized that most of the available geological storage capacity for CO 2 is in saline aquifers. The best aquifers are likely to be in sedimentary basins (and in many cases near to fossil energy sources). However, unless the formations have been explored for hydrocarbon potential, it is likely that little data exists so significant work will be required to evaluate the realistic storage potential. Depleted gas fields offer more limited capacity but are better characterized, have seals that have successfully retained hydrocarbon gas for millions of years, and may offer a shorter route to practical implementation for early projects. Estimates indicate that depleted offshore gas fields in UK waters have the potential to store around 3.8 billion tonnes of CO 2 . This is a significant capacity and an inviting target particularly if existing infrastructure and wells can be reused. This paper explores the issues around injecting and storing CO 2 in highly depleted gas fields using a case study based on the characteristics of a Southern North Sea gas field. The study shows that assessing and managing the flow control aspects of CO 2 injection, particularly initially when the reservoirs are at very low pressure is going to be a major technical challenge. The challenges include a requirement for a high -tech flow control device at the base of the tubing to allow the dense phase CO 2 to be expanded in a controlled manner. Also the requirement for CO 2 -specific well flow performance software as conventional software, designed to model the flow of hydrocarbons, is not necessarily suffciently rigorous when modeling a complex fluid like CO 2 , particularly the thermodynamics aspects. Understanding and mitigating Joule Thomson effects is necessary to avoid the possible formation of ice and gas hydrates. Without a comprehensive understanding of CO 2 flow systems and accurate modeling of the thermodynamic effects it may not be possible to realize the potential that gas field storage offers.
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