Optimizing geologic CO₂ sequestration by injection in deep saline formations below oil reservoirs

The purpose of this research is to present a best-case paradigm for geologic CO₂ storage: CO₂ injection and sequestration in saline formations below oil reservoirs. This includes the saline-only section below the oil-water contact (OWC) in oil reservoirs, a storage target neglected in many current storage capacity assessments. This also includes saline aquifers (high porosity and permeability formations) immediately below oil-bearing formations. While this is a very specific injection target, we contend that most, if not all, oil-bearing basins in the US contain a great volume of such strata, and represent a rather large CO₂ storage capacity option. We hypothesize that these are the best storage targets in those basins. The purpose of this research is to evaluate this hypothesis. We quantitatively compared CO₂ behavior in oil reservoirs and brine formations by examining the thermophysical properties of CO₂, CO₂-brine, and CO₂-oil in various pressure, temperature, and salinity conditions. In addition, we compared the distribution of gravity number (N), which characterizes a tendency towards buoyancy-driven CO₂ migration, and mobility ratio (M), which characterizes the impeded CO₂ migration, in oil reservoirs and brine formations. Our research suggests competing advantages and disadvantages of CO₂ injection in oil reservoirs vs. brine formations: (1) CO₂ solubility in oil is significantly greater than in brine (over 30 times); (2) the tendency of buoyancy-driven CO₂ migration is smaller in oil reservoirs because density contrast between oil and CO₂ is smaller than it between brine and oil (the approximate density contrast between CO₂ and crude oil is ∼100 kg/m³ and between CO₂ and brine is ∼350 kg/m³); (3) the increased density of oil and brine due to the CO₂ dissolution is not significant (about 7-15 kg/m³); (4) the viscosity reduction of oil due to CO₂ dissolution is significant (from 5790 to 98 mPa s). We compared these competing properties and processes by performing numerical simulations. Results suggest that deep saline CO₂ injection immediately below oil formations reduces buoyancy-driven CO₂ migration and, at the same time, minimizes the amount of mobile CO₂ compared to conventional deep saline CO₂ injection (i.e., CO₂ injection into brine formations not below oil-bearing strata). Finally, to investigate practical aspects and field applications of this injection paradigm, we characterized oil-bearing formations and their thickness (capacity) as a component of the Southwest Regional Partnership on Carbon Sequestration (SWP) field deployments. The field-testing program includes specific sites in Utah, New Mexico, Wyoming, and western Texas of the United States.