Source term modeling for evaluating the potential impacts to groundwater of fluids escaping from a depleted oil reservoir used for carbon sequestration

Abstract

In recent years depleted oil reservoirs have received special interest as carbon storage reservoirs because of their potential to offset costs through collaboration with enhanced oil recovery projects. Modeling is currently being conducted to evaluate potential risks to groundwater associated with leakage of fluids from depleted oil reservoirs used for storage of CO2. Modeling results reported here focused on understanding how toxic organic compounds found in oil will distribute between the various phases (oil, vapor, and brine) within a storage reservoir after introduction of CO2, understanding the migration potential of these compounds, and assessing potential groundwater impacts should leakage occur. Three model scenarios were conducted to evaluate how organic components in oil will distribute among the phases of interest (oil, CO2, and brine). The three cases were 50wt.% oil and 50wt.% water, 90wt.% CO2 and 10wt.% oil, and 90wt.% CO2, 5wt.% oil, and 5% wt.% water. Several key organic compounds were considered in this study based upon their occurrence in oil at significant concentrations, relative toxicity, or because they can serve as surrogate compounds for other more highly toxic compounds for which required input data are not available. The organic contaminants of interest (COI) selected for this study were benzene, toluene, naphthalene, phenanthrene, and anthracene.Partitioning of organic compounds between crude oil and supercritical CO2 was modeled using the Peng–Robinson equation of state over temperature and pressure conditions that represent the entire subsurface system of the scenario under investigation (from those relevant to deep geologic carbon storage environments to near surface conditions). Results indicate that for the modeled oil reservoir conditions (75°C, and 21,520kPa) negligible amounts of the COI dissolve into the aqueous phase. When CO2 is introduced into the reservoir such that the final composition of the reservoir is 90wt.% CO2 and 10wt.% oil, a significant fraction of the oil dissolves into the vapor phase. As the vapor phase moves up through the stratigraphic column, pressures and temperatures decrease, resulting in significant condensation of oil components. The heaviest organic components condense early in this process (at higher pressures and temperatures), while the lighter components tend to remain in the vapor phase until much lower pressures and temperatures are reached. Based on the model assumptions, the final concentrations of COI to reach an aquifer at 1520kPa and 25°C were quite significant for benzene and toluene, whereas the concentrations of polynuclear aromatic hydrocarbons that reach the aquifer were very small. This work demonstrates a methodology that can provide COI source term concentrations in CO2 leaking from a reservoir and entering an overlying aquifer for use in risk assessments.