Influence of relative permeability curves on extent of CO₂ plume during injection into deep saline aquifers
A compositional reservoir simulation study of CO₂ sequestration in deep saline aquifers is presented. Numerous scenarios analyzing the different aspects of CO₂ injection, affected by formation relative permeability in heterogeneous geologic domains were performed. Two types of CO₂ injection schedules, each with six different formation relative permeability curves, were set: (1) bottom-hole pressure limited CO₂ injection; (2) constant rate CO₂ injection. Bottom-hole pressure limited injection schedule is a more realistic model for field practice. Imposing a bottom-hole pressure at the injector limited the injection rate almost instantly after injection started at an initial rate of 50 MMscf/D. However, the variation of the injection rate during the injection period was controlled by the characteristics of formation relative permeability. Bottom-hole pressure limited injection scenario provides useful insights into the total mass of CO₂ injected for each formation relative permeability set and its results are analyzed in this study. In the second injection scenario where bottom-hole pressure is not imposed, a constant CO₂ injection rate can be achieved and, ultimately, the same amount of CO₂ is injected into the aquifer regardless of formation relative permeability. Given that the same amount of CO₂ is injected, the effects of the differences between the six relative permeability sets can be summarized as follows: 1. The estimation of CO₂ invasion distance by three different analytical approaches on the basis of Buckley-Leverett fractional flow theory provided estimates close to the simulated results. Out of three approaches, the approach that couples the conventional fractional flow theory and semi-miscibility between the fluid phases provided the most accurate results to the simulated. This analytical approach reduced the error ranges of the results (in estimating CO₂ invasion distance) by up to about 50[varies with]80% compared to the others by taking into account the substantial solubility of the injected CO₂ in formation brine. 2. The lateral (horizontal) extent of the CO2 plume at the end of the injection period was analyzed by investigating the following key control factors: gas relative permeability at average CO₂ saturation, gas relative permeability at relatively high liquid saturation (Sw=0.7[varies with]1.0), and average CO₂ saturation. The collective consideration of these three factors yielded a reliable rationale behind the horizontal extent of the CO₂ plume. 3. The vertical distribution of CO₂ injected was analyzed with the concept of "reverse pressure drawdown" (RPD). RPD is the driving force that displaces the CO₂ injected. RPD is inversely proportional to the effective permeability, thus it has an inverse proportionality with relative permeability as well when the injection rate is constant. The resultant hydrostatic gradient in the wellbore and in the gridblocks containing the well was the key primary factor in vertical distribution of CO₂ because it determines variation of RPD with depth. Formation gas relative permeability influences vertical distribution, by either increasing or decreasing well node pressure depending on the characteristics of gas relative permeability. This research shows that formation relative permeability plays an important role when supercritical CO₂ enters deep saline aquifers. In determining the fate of a successful CO₂ sequestration project into aquifers, regardless of whether the storage process is focused toward greater quantities of CO₂ injection or safer CO₂ injection in a form of near-permanent trapping within a geologic domain, the impact of formation relative permeability during the sequestration process must be considered.