Optimizing geologic CO 2 sequestration by injection in deep saline formations below oil reservoirs

Abstract

The purpose of this research is to present a best-case paradigm for geologic CO 2 storage: CO 2 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 CO 2 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 CO 2 behavior in oil reservoirs and brine formations by examining the thermophysical properties of CO 2, CO 2–brine, and CO 2–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 CO 2 migration, and mobility ratio ( M), which characterizes the impeded CO 2 migration, in oil reservoirs and brine formations. Our research suggests competing advantages and disadvantages of CO 2 injection in oil reservoirs vs. brine formations: (1) CO 2 solubility in oil is significantly greater than in brine (over 30 times); (2) the tendency of buoyancy-driven CO 2 migration is smaller in oil reservoirs because density contrast between oil and CO 2 is smaller than it between brine and oil (the approximate density contrast between CO 2 and crude oil is ∼100 kg/m 3 and between CO 2 and brine is ∼350 kg/m 3); (3) the increased density of oil and brine due to the CO 2 dissolution is not significant (about 7–15 kg/m 3); (4) the viscosity reduction of oil due to CO 2 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 CO 2 injection immediately below oil formations reduces buoyancy-driven CO 2 migration and, at the same time, minimizes the amount of mobile CO 2 compared to conventional deep saline CO 2 injection (i.e., CO 2 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.