Robert K. Svec

THE EFFECT OF SALINITY ON IN-SITU GENERATED CO2 GAS: SIMULATIONS AND EXPERIMENTS

Carbon dioxide (CO2 ) injection has been used as a commercial process for enhanced oil recovery (EOR) since the 1970s. Recently, a new in-situ CO2 gas generation technology has been developed but not well studied. We conducted experiments to observe the dynamics of the system with different temperatures, injection sequences of chemical agents, chemical additives, and behavior of CO2 generation with respect to these varying factors and comparison of the actual CO2 pressure with the calculated values. Experiments on generation of CO2 gas as a result of reactions of gas forming and gas yielding solutions were carried out. It is shown that the injection sequence of the chemicals affects the reaction characteristics, but the total amount of CO2 gas generated does not vary significantly. Regardless of the injected solution (either gas forming or gas yielding) the maximum attainable pressures are less than the calculated pressures as a result of chemical equilibrium in the system; so this difference should be considered while calculating the size of the slug in the field applications. The brine concentration has an impact on CO2 solubility in water and so on CO2 pressure. Because of this impact, brine concentration of formation water should be considered in addition to the brine which is introduced to the system by the reaction.© 2006 ASME

Improving CO2 Efficiency for Recovering Oil in Heterogeneous Reservoirs

The work strived to improve industry understanding of CO2 flooding mechanisms with the ultimate goal of economically recovering more of the U.S. oil reserves. The principle interests are in the related fields of mobility control and injectivity.

Improved efficiency of miscible CO{sub 2} floods and enhanced prospects for CO{sub 2} flooding heterogeneous reservoirs

This project examines three major areas in which CO{sub 2} flooding can be improved: fluid and matrix interactions, conformance control, sweep efficiency, and reservoir simulation for improved oil recovery. This report discusses the activity during the calendar quarter covering October 1, 1999 through December 31, 1999 that covers mostly the second fiscal quarter of the projects third year. Injectivity experiments were performed on two Indian limestone cores. In tests on the first core, a variety of brine, CO{sub 2} WAG, and oil contaminant injection schemes indicated infectivity reduction due to phase conditions and contamination. The results are only quantitative because of plugging and erosion in the core. To date, tests on the second core have investigated the effects of long-term brine stability on the reduction of fluid-rock interaction, in order to quantify fluid effects on infectivity. The authors continue to develop a new approach in reservoir simulation to improve the history matching process on clusters of PCs. The main objective was to improve simulation of complex improved oil recovery methods, such as CO{sub 2}-foam for mobility control and sweep enhancements. Adsorption experiments using circulation and flow-through methods were used to determine the loss of surfactants for economic evaluation. A sacrificial agent, lignosulfonate, was used to reduce the adsorption of the primary foaming agent in both Berea sandstone and Indian limestone. The lignosulfonate has also shown a chromatograph effect, advancing more rapidly through the reservoir, thus initially adsorbing onto the rock before the primary foaming agent arrives. Therefore, considering the simplicity of operation and economics of reducing the cost of expensive surfactant to improve oil recovery, coinjection of lignosulfonate with the primary foaming agent might be a practical approach to consider for field application.