Impact of CO2 mixing with trapped hydrocarbons on CO2 storage capacity and security: A case study from the Captain aquifer (North Sea)

Abstract

Gas mixing in the subsurface could have crucial implications on CO 2 storage capacity and security. This study illustrates the impact of gas mixing in the "Captain X" CO 2 storage site, an open saline aquifer and subset of the greater Captain aquifer, located in the Moray Firth, North Sea. The storage site hosts several abandoned hydrocarbon fields where injected CO 2 could interact and mix with any remaining hydrocarbon gas left in the depleted structures. For this study, compositional simulation of CO 2 injection into the Captain X storage site reservoir model was conducted to quantify the impact of mixing. Results show mixing of CO 2 with the remaining trapped hydrocarbon gas makes the plume considerably less dense and more mobile. This increases the buoyancy forces acting on the plume, causing it to migrate faster towards the shallower storage boundaries and therefore, reduces the storage capacity of the site. Mixing also compromises the storage security as it mobilises the structurally trapped hydrocarbon gas from within the abandoned fields. Informed injector placement helps to manage and reduce the impact of mixing. Correct assessment of mixing is also considerably dependent on the volume and property of the trapped hydrocarbon gas. To provide a correct long term understanding of storage capacity and security, the impact of mixing, therefore, needs to be correctly considered in all large-scale CO 2 storage operations.

Hydrogen storage in saline aquifers: The role of cushion gas for injection and production

“…All absolute results in this study have a degree of uncertainty because pressure systems in open, undrilled saline aquifers are usually not well understood and hence their pressure dissipation is uncertain. Modelling studies on hydrogen injection and reproduction (Lubon & Tarkowsky, 2020;Pfeiffer et al 2017), as well as studies on CO2 storage (Williams et al, 2013;Ghanbari et al, 2020) have used pore volume modifiers around the reservoir model to simulate an open aquifer. When applied to this study, this method resulted in a more efficient pressure dissipation compared with the Fetkovich analytical aquifer.…”

Mapping geological hydrogen storage capacity and regional heating demands: An applied UK case study

“…This is also true for geological leakage of hydrogen along faults that may be sealing to methane, but their hydrogen sealing is unknown. The use of dynamic simulations is essential as a mitigation strategy and can hel p to forward predict the development of the gas plume and to identify suitable injection locations with [51] or without residual hydrocarbons [52]. Both a vigorous risk analysis for abandoned wells and faults and a detailed dynamic simulation of the hydrogen storage operation can decrease the risk of hydrogen loss along potentially leaky abandoned wells and faults significantly.…”

Identifying and Understanding Microbial Methanogenesis in CO2 Storage

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