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Most emerging techniques for laboratory evaluation of CCUS projects refer to traditional geoscience core analysis methods of porosity, permeability, mineralogy, caprock integrity, etc. However, analytical programs must go beyond typical oil & gas exploration and production reservoir evaluation workflows/ methodologies when assessing injectivity impairment and measures to control it. Introducing enormous quantities of an inherently incompatible fluid into a geological storage prospect introduces a set of different challenges from those encountered during the reservoir fluid production cycle. This work aims to raise awareness of one of the key operational challenges related to CO2 injection in saline aquifers or depleted hydrocarbon reservoirs and provides a new approach to assessing injectivity impairment. Core flooding apparatus was used to measure permeability changes during injection of liquid carbon dioxide to demonstrate the effect of the formation of CO2 hydrates on injectivity of CO2 and brine into a porous core medium. The work required design of a new test rig and approach for the range of conditions expected during CO2 injection into deep saline (high pressure) reservoirs and depleted gas reservoirs (low pressure) which will be discussed. Controlled, repeatable generation of the damage also enables preventive and remedial measures to be evaluated, including the performance of chemical inhibitors. Initial testing of the apparatus involved cycling injection through the hydrate formation window by varying temperature while flowing brine and CO2 into a core. Severe blockages were formed whereupon specific pressure and temperature trajectories were applied to differentiate hydrates formation from that of ice. This paper presents new laboratory equipment for the dynamic assessment of CO2 injection into underground storage reservoirs, determining under which specific operating conditions for CO2 injectivity can be impaired due to formation of hydrates, ice, scale, etc. This apparatus and the associated workflow surpass the existing methods outlined in literature which mostly rely on static measurements of fluids rather than dynamic measurements in reservoir core, which is much more representative of the field scenario for geological carbon storage. In addition to hydrate formation assessment, this equipment has also been used to investigate various other formation-damage mechanisms, including the formation of inorganic scales and ice, across a range of formation water compositions, saturations, temperatures (-25 to +30 °C), and pressures (< 400 bar). Varying the input parameters, including the initial brine salinity enables the locus of CO2 hydrates to be established in this porous medium as well as determining their formation kinetics and likely plugging mechanism, inferred from flow-rate dependence. Reproduction of injectivity impairment under a variety conditions, saturations and flow rates demonstrates the ability to form, dissipate, and reform scales and hydrates within a porous medium, and thus the potential to test inhibition performance. |
