Commercial-scale deployment of Carbon Capture and Storage (CCS) as a viable greenhouse gas (GHG) emissions reduction technology requires that the CO2 be continuously injected at predictably significant and cost-efficient rates into geological formations (e.g. deep saline aquifers). The Quest CCS operation (located in Alberta, Canada) is a fully integrated carbon capture, transport and storage facility operated by Shell Canada. Quest continuously captures and stores about 1.1 Mt of CO2 per year, and it’s expected to continue until 2040. Quest is a dedicated geological storage project (no EOR component) with multiple injectors and monitoring wells. Injection operations started in August 2015 and by mid-October 2018, more than 3.45 Mt of CO2 has been stored using only 2 out of 3 planned injection wells. To date Quest has observed significant injectivity variability relating to seasonal variation in injected CO2 and bottom-hole temperatures. The high-resolution time-series data from the Quest operations gathered over the first 3 years of CO2 injection indicate the standard models of CO2 injectivity leave out some important physics. Prior to the start of injection, theoretical CO2 injectivity at the CO2 injector wells was initially modelled and calculated to decrease by ∼5% - 8% with decreasing CO2 bottom-hole temperature within the temperature range 20 °C–60 °C at the wellbore largely due to increased fluid viscosity at lower temperatures. However, field observations made to date at the Quest CCS site indicate an inverse relationship between CO2 injectivity and bottom-hole temperature, where injectivity increases of up to 10% due to colder CO2 have been observed in the bottom-hole temperature range of 21 °C–33 °C. This paper presents the field observations of injectivity compared to the theoretically expected and modelled 3D isothermal and non-isothermal conditions of injectivity at various CO2 bottom-hole temperatures, together with an assessment of the dominant controlling mechanisms and parameters that could influence CO2 injectivity under non-isothermal conditions. The assessment results indicate that the seasonal CO2 injectivity correlating inversely with bottom-hole temperature (BHT), cannot be explained by CO2 PVT behaviour under non-isothermal conditions. The inverse correlation is driven by near-wellbore permeability (k), relative permeability (kr) and (non-darcy) dynamic skin factor parameters varying in an inverse relationship with bottom-hole temperature through reversible temperature-driven mechanism(s) such as fluid flow regime changes, fluid-rock interactions and thermally-induced micro-fractures leading to increases in dynamic injectivity at lower CO2 bottom-hole temperatures. A full understanding of the non-isothermal processes and their relative impacts on CO2 injectivity are not only crucial for successful deployment of CCS projects but can also have wider beneficial applications in CO2-EOR modelling and operations cost optimisation.
Field data from three years of operation at the Quest carbon capture and storage project in Alberta has indicated an inverse relationship between injectivity and bottom-hole temperature, with injectivity increases of up to 10% observed with colder CO2 – the opposite of results of previous modelling. The inverse correlation is due to non-isothermal near-wellbore factors, including permeability. The researchers from Shell and the University of Calgary said theoretical models of CO2 injectivity do not include some important physics that affects results, and that full understanding of non-isothermal impacts on CO2 injectivity is crucial for the success of future CCS projects.