Novel Laboratory Testing to Assess Suitability of Geological Storage Prospects and the Associated Risks of CO2 Hydrate Formation During Carbon Dioxide Injection (II)

Abstract

Abstract Although sufficient capacity exists in theory to substantially increase the geological storage of CO2 to limit or reverse the effects of climate change, various challenges remain to be addressed regarding sustained, unimpeded and prolonged injectivity of CO2 into the various types of target reservoirs. Improved understanding of the physics and chemistry of subsurface CO2 flow for the purposes of geological storage is required. As CO2 is injected, geochemical reactions between CO2, brine, and minerals will occur, and this can lead to formation damage which compromises the injectivity of the CO2, either by fines migration or the precipitation of various undesirable solids, e.g., scale, hydrates, and ice. There are various near-well treatments available to maintain or restore injectivity. However, effective selection and deployment of these treatments requires improved understanding of the underlying damage mechanisms that occur during CO2 geological injection and storage. This understanding requires effective experimental protocols to generate field-representative phenomena reproducible at the laboratory scale. The current paper aims to highlight key operational challenges related to CO2 injection in low-temperature environments at various pressures. A new approach is provided in this paper to assess injectivity impairment phenomena, and their remediation, both at the laboratory scale. A novel core flooding-based testing apparatus was used to measure permeability changes of a porous core medium during injection of liquid or gaseous carbon dioxide across a range of saturations, temperatures, and pressures. This demonstrates the effect on injectivity of various formation-damage mechanisms, including formation of CO2 hydrates. The new dynamic dual-phase injection test rig was designed, built, and used to assess a range of conditions expected during CO2 injection either into deep saline aquifers or depleted oil and gas reservoirs. Injection of CO2 into a brine-saturated porous core medium, with manipulation of the pressure into the hydrates-formation envelope, resulted in severe blockages in the core sample. Manipulation of the temperatures and pressures at specific trajectories allowed for determination of CO2 hydrates blockages. Reproduction of injectivity impairment under a variety conditions, saturations and flow rates demonstrated the ability to form, dissipate, and reform CO2 hydrates within a porous medium. The equipment allows for near wellbore treatment assessment (including inhibition, remediation, prevention and induced fractures methods) which are now being developed exclusively as CO2-specific additives to manage injectivity and well integrity. This paper presents new laboratory workflow for the dynamic assessment of CO2 injection into reservoirs, determining under which specific operating conditions CO2 injectivity is impaired due to formation of various solids. This apparatus surpasses existing methods outlined in literature which mostly rely on static measurements of fluids rather than dynamic measurements in reservoir core, a much more field representative scenario for geological carbon storage.