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.
Bibliographical noteFunding Information:
The authors would like to thank Richard P. Esser for technical review and comments and CMG Ltd. for allowing us to use the GEM simulator in this research. In addition, we gratefully acknowledge collaboration with the Southwest Regional Partnership on Carbon Sequestration (SWP), the US Department of Energy and the National Energy Technology Laboratory, who provided critical data and information from ongoing field tests. All financial support for this research was provided by the University of Utah and the Utah Science Technology and Research (USTAR) initiative, a program funded by the State of Utah.
All Science Journal Classification (ASJC) codes
- Renewable Energy, Sustainability and the Environment
- Nuclear Energy and Engineering
- Fuel Technology
- Energy Engineering and Power Technology