(585h) Carbonated High Salinity Waterflooding for Simultaneous EOR, CO2 Storage, and Produced Water Disposal

Excessive use of fossil fuels in industry and transportation is the primary source of CO₂ emissions, a potent greenhouse gas contributing to climate change and global warming. CO₂-based enhanced oil recovery (EOR) methods have gained global interest for their potential to mitigate the emissions while meeting energy demands. Injected CO₂, depending on reservoir conditions, can mix with oils either fully or partially, aided by factors like minimum miscibility pressure. This process leads to permanent sequestration of a significant portion of CO₂ within the reservoir through solubility-, capillary-, and stratigraphic- trapping mechanisms. The extraction of hydrocarbons from approximately 1 million active oil and gas wells in the United States generates produced water. Nationally, the average water-oil ratio (WOR) is about 9.2 barrels of water per barrel of oil, with a weighted gas ratio (WGR) around 97 barrels per thousand cubic feet (bbl/Mmcf) of gas extracted. Injecting produced water into Class II wells is known to trigger seismic activity, underscoring the environmental risks of hydrocarbon extraction.

To address these challenges, we suggest carbonated high salinity produced water flooding for combined EOR, CO₂ storage, and produced water disposal. Our research aims to: (a) assess CO₂ solubility in brines and hydrocarbons; (b) determine IFT of CO₂-saturated brines and hydrocarbons; and (c) conduct microfluidics-based experiments to quantify the EOR, CO₂ sequestration, and produced water disposal potentials.

We developed two experimental setups to measure CO₂ solubility in brines and hydrocarbons. CO₂ solubilities in water and 1, 3, and 5 M NaCl brines were measured under pressures ranging from 150 psig to 1200 psig at 18 °C, and compared with predictions from a state-of-the-art thermodynamic model. Additionally, CO₂ solubilities in n-hexane, n-decane, n-dodecane, and a crude oil were measured at pressures from 150 psig to 700 psig at 18 °C using a swelling-based method. An experimental setup was developed to measure IFT of CO₂-saturated brine-oil systems at various pressures (0 - 700 psig, at 18 °C) and salinities (0 - 5M NaCl). To meet the third objective of this research, we developed an experimental setup for microfluidics-based EOR experiments using model oil-carbonated brine and crude oil-carbonated produced water systems. In each trial, a microfluidic chip was saturated with oil, then flooded with water/brine until irreducible oil saturation was achieved. Carbonated water/brine was subsequently introduced until no further oil was produced, followed by overnight aging. The carbonated water/brine flooding continued to assess additional oil recovery potential after aging. The key findings from the above four studies will be discussed in this presentation.