Abstract
Storing CO2 in geological formations is an important component of reducing greenhouse gases emissions. The Carbon Capture and Storage (CCS) industry is now in its establishing phase, and if successful, massive storage volumes would be needed. It will hence be important to utilize each storage site to its maximum, without challenging the formation integrity. For different reasons, supply of CO2 to the injection sites may be periodical or unstable, often considered as a risk element reducing the overall efficiency and economics of CCS projects. In this paper we present outcomes of investigations focusing on a variety of positive aspects of periodic CO2 injection, including pressure management and storage capacity, also highlighting reservoir monitoring opportunities. A feasibility study of periodic injection into an infinite saline aquifer using a mechanistic reservoir model has indicated significant improvement in storage capacity compared to continuous injection. The reservoir pressure and CO2 plume behavior were further studied revealing a ‘CO2 expansion squeeze’ effect that governs the improved storage capacity observed in the feasibility study. Finally, the improved pressure measurement and storage capacity by periodic injection was confirmed by field-scale simulations based on a real geological set-up. The field-scale simulations have confirmed that ‘CO2 expansion squeeze’ governs the positive effect, which is also influenced by well location in the geological structure and aquifer size, while CO2 dissolution in water showed minor influence. Additional reservoir effects and risks not covered in this paper are then highlighted as a scope for further studies. The value of the periodic injection with intermittent CO2 supply is finally discussed in the context of deployment and integration of this technology in the establishing CCS industry.
Highlights
Storing CO2 in geological formations, such as saline aquifers or depleted petroleum reservoirs, is an important component of reducing greenhouse gas emissions
Other scenarios presented in this study showed that combining CO2 -WAG injection wells with continuous water extraction from the brine producers led to acceleration of solubility trapping, reducing the risk of leakage due to mechanical trapping failure, which is relevant in the early years of a CO2 injection project
Analysis of actual Carbon Capture and Storage (CCS) projects with CO2 injection in saline aquifers shows that well injection history is always a combination of sequential injection and shut-in periods related to well tests, treatments, workovers and stimulations
Summary
Storing CO2 in geological formations, such as saline aquifers or depleted petroleum reservoirs, is an important component of reducing greenhouse gas emissions. Several authors have proposed solutions for this scenario, e.g., Buscheck et al [15] developed the Active CO2 Reservoir Management (ACRM) process that aimed to control pressure buildup and brine migration This was achieved by using brine-producing wells in a CO2 injection reservoir, as it was identified that such production in EOR processes helped to increase the volume of CO2 injected and to control pressure buildups [15]. CSI uses two CO2 -rich fluids (with different CO2 mole percentages) which are injected cyclically into the reservoir; one has gas-like properties and the other behaves as a liquid This is done to manage the CO2 plume and counteract pressure buildup [17,18,19,20]. This study aims to cover the periodic (a generalized form of cyclic) injection from the reservoir pressure management and storage capacity points of view by focusing on positive effects of such periodic injection including both pressure and CO2 plume dynamics. The paper concludes with analysing overall effect from the periodic injection studied in the context of a real field-case environment including other benefits from periods in injection like improved permanent reservoir monitoring
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