CO2 Foam Flooding Performance vs. Rock Wettability

Abstract

CO2 Foam Flooding Performance vs. Rock Wettability B.M. Lescure; B.M. Lescure U. of Houston Search for other works by this author on: This Site Google Scholar E.L. Claridge E.L. Claridge U. of Houston Search for other works by this author on: This Site Google Scholar Paper presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, October 1986. Paper Number: SPE-15445-MS https://doi.org/10.2118/15445-MS Published: October 05 1986 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Lescure, B.M., and E.L. Claridge. "CO2 Foam Flooding Performance vs. Rock Wettability." Paper presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, October 1986. doi: https://doi.org/10.2118/15445-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE Annual Technical Conference and Exhibition Search Advanced Search AbstractCO2 flooding projects have shown large potential for oil recovery but in many cases the volumetric sweep efficiency is greatly limited by gravity tonguing and/or viscous fingering. To reduce these effects foam could be used as an alternative to WAG CO2 injection. Experiments on the CO2 foam process were conducted in a 1/4 5-spot reservoir model in order to investigate the effect of rock wetting state and total CO2 slug size on secondary and tertiary extra-oil recovery. Laboratory model results show that the process is more successful in an oil-wet medium than in a water-wet medium due to larger surfactant adsorption in the water-wet medium. Also, requirements for optimal CO2 slug size are smaller than in the WAG process, with larger extra oil recovery for both secondary and tertiary floods.IntroductionSignificant amounts of residual oil can be recovered by carbon dioxide (CO2) flooding. However, oil recovery is severely reduced by gravity tonguing and viscous fingering of CO2. Reduction in the mobility of CO2 would greatly improve the overall sweep efficiency. A need for mobility control during CO2 flooding has led to the study of numerous methods. A process that has received much experimental and theoretical attention is the WAG (water alternate with gas) process. Although this method helps minimize fingering, the mobile water traps oil which cannot be contacted by CO2, thus lowering the oil recovery, and this method also introduces gravity segregation problems. An alternate approach to reduce the mobility is to disperse CO2 as a foam or an emulsion in a continuous aqueous liquid phase. This method of mobility control has been studied in several other applications including nitrogen and, steam drives. Early papers by Holm and Bernard et al. describe the principles papers by Holm and Bernard et al. describe the principles involved in increasing the resistance to gas flow in a process. Holm recently reported the successful field application process. Holm recently reported the successful field application of CO2 foam as a substitute for the WAG process in the Wilmington field in California. Other studies conducted in laboratory linear cores or packs show how promising the foaming technique can be. Further studies are necessary to understand the flow behavior of foam or emulsion in a porous medium in order to model the oil recovery process and to develop foam simulators. In this work, we physically modeled the CO2 foam or emulsion process, conducted experiments in a laboratory model of a 1/4 process, conducted experiments in a laboratory model of a 1/4 5-spot reservoir and studied the effects of CO2 slug size and rock wetting state on secondary and tertiary foam flooding.MODELThe scaling used here has been successfully applied by Jackson et al. to study the WAG process. The goal is to reproduce the behavior of a large actual reservoir in a small laboratory model. Since no real criteria existed for the laboratory scaling of foam flooding we used the same model conditions as used by Jackson. In such a choice we avoid a high pressure design. Liquid substitutes are used to represent the different phases (see table 1). The foam is thus simulated by an emulsion. Heller shows that in surfactant testing, liquid hydrocarbons can be used to find the softable foaming agent. We extended this idea to study the foaming process. In fact, the density of CO2 does not vary greatly over process. In fact, the density of CO2 does not vary greatly over the range of 1500 to 3500 psi at moderate reservoir temperatures, because the Z factor is increasing almost proportionately to the pressure increase. Hence for this range of proportionately to the pressure increase. Hence for this range of pressures the simulation of CO2, with a constant density fluid is a pressures the simulation of CO2, with a constant density fluid is a satisfactory approximation. Therefore, the modelling approach we have chosen consists of characterizing the fluids at reservoir conditions for a normal flood and extending it to the case of foam flooding. Keywords: oil-wet case, slug size, fluid dynamics, surfactant, biliquid foam, recovery, five-spot model, oil recovery, emulsion, flow system Subjects: Reservoir Fluid Dynamics, Improved and Enhanced Recovery, Flow in porous media This content is only available via PDF. 1986. Society of Petroleum Engineers You can access this article if you purchase or spend a download.