Highly fractured and vuggy oil reservoirs represent a challenge for enhanced oil recovery (EOR) methods. The fractured networks provide flow paths several orders of magnitude greater than the rock matrix. Common enhanced oil recovery methods, including gases or low viscosity liquids, are used to channel through the high permeability fracture networks causing poor sweep efficiency and early breakthrough. The purpose of this research is to determine the feasibility of using foam in highly fractured reservoirs to produce oil-rich zones. Multiple surfactant formulations specifically tailored for a distinct oil type were analyzed by aqueous stability and foam stability tests. Several core floods were performed and targeted effects such as foam quality, injection rate, injection type, permeability, gas saturation, wettability, capillary pressure, diffusion, foam squeezing, oil flow, microemulsion flow and gravity segregation. Ultimately, foam was successfully propagated under various core geometries, initial conditions and injections methods. Consequently, fluids were able to divert to unswept matrix and improve the ultimate oil recovery. / text

This paper establishes Low-Tension-Gas (LTG) as a method for sub-miscible tertiary recovery in tight sandstone and carbonate reservoirs. The LTG process involves the use of a low foam quality surfactant-gas solution to mobilize and then displace residual crude after waterflood. It replicates the existing Alkali-Surfactant-Polymer (ASP) process in its creation of an ultra-low oil-water interfacial tension (IFT) environment for oil mobilization, but instead supplements the use of foam over polymer for mobility control. By replacing polymer with foam, chemical Enhanced Oil Recovery (EOR) methods can be expanded into sub-30 mD formations where polymer is impractical due to plugging, shear, or the requirement to use a low molecular weight polymer. Overall results indicate favorable mobilization and displacement of residual crude oil in both tight carbonate and tight sandstone reservoirs. Tertiary recovery of 75-95% ROIP was achieved for cores with 2-15 mD permeability, with similar oil bank and other ASP analogous process attributes observed. Moreover, similar recovery was achieved during testing at high initial oil saturation (56%), indicating high process tolerance to oil saturation and potential application for implementation at secondary recovery. In addition, a number of tools and relations were developed to improve the predictive relationship between observed coreflood properties and actual mobilization or displacement mechanisms which impact reservoir-scale flooding. These relations include qualitative dispersion comparison and calculation of in-situ gas saturation, macroscopic mobility ratio at the displacement fronts, and apparent viscosity of injected fluids. These tools were validated through use of reference gas and surfactant floods and indicate that stable macroscopic displacement can be achieved through LTG flooding in tight formations. Furthermore, to better reflect actual reservoir conditions where localized fractional flow of gas can vary substantially depending on mixing or gravity phenomenon, two additional sets of data were developed to empirically model behavior. Through testing of LTG co-injection at a number of discrete fractional flow values over a wide range, recovery was shown to achieve a relative maximum at 50% gas fractional flow which also corresponded with optimal observed mobility control as measured by the previously established tools. Likewise, through testing of surfactant-alternating-gas (SAG) injection cycling, displacement and overall recovery were shown to be improved versus reference co-injection flooding. Finally, by comparing the observed displacement and mobility data among co-injection and surfactant-alternating-gas floods, a new displacement mechanism is introduced to better relate actual displacement conditions with observed macroscopic mobility data. This mechanism emphasizes the role of liquid rate in actual displacement processes and a mostly static gas saturation (independent of gas rate) in altering liquid relative permeability and diverting injected liquid into lower permeability zones. / text

Hybrid gas/chemical Enhanced Oil Recovery (EOR) methods are such novel techniques to increase oil production and oil recovery efficiency. Gas flooding using carbon dioxide, nitrogen, flue gas, and enriched natural gas produce more oil from the reservoirs by channeling gas into previously by-passed areas. Surfactant flooding can recover trapped oil by reducing the interfacial tension between oil and water phases. Hybrid gas/chemical EOR methods benefit from using both chemical and gas flooding. In hybrid gas/chemical EOR processes, surfactant solution is injected with gas during low-tension-gas or foam flooding. Polymer solution can also be injected alternatively with gas to improve the gas volumetric sweep efficiency. Most fundamentally, wide applications of hybrid gas/chemical processes are limited due to uncertainties in reservoir characterization and heterogeneity, due to the lack of understanding of the process and consequently lack of a predictive reservoir simulator to mechanistically model the process. Without a reliable simulator, built on mechanisms determined in the laboratory, promising field candidates cannot be identified in advance nor can process performance be optimized. In this research, UTCHEM was modified to model four-phase water, oil, microemulsion, and gas phases to simulate and interpret chemical EOR processes including free and/or solution gas. We coupled the black-oil model for water/oil/gas equilibrium with microemulsion phase behavior model through a new approach. Four-phase fluid properties, relative permeability, and capillary pressure were developed and implemented. The mass conservation equation was solved for total volumetric concentration of each component at standard conditions and pressure equation was derived for both saturated and undersaturated PVT conditions. To model foam flow in porous media, comprehensive research was performed comparing capabilities and limitations of implicit texture (IT) and population-balance (PB) foam models. Dimensionless foam bubble density was defined in IT models to derive explicitly the foam-coalescence-rate function in these models. Results showed that each of the IT models examined was equivalent to the LE formulation of a population-balance model with a lamella-destruction function that increased abruptly in the vicinity of the limiting capillary pressure, as in current population-balance models. Foam models were incorporated in UTCHEM to model low-tension-gas and foam flow processes in laboratory and field scales. The modified UTCEM reservoir simulator was used to history match published low-tension-gas and foam coreflood experiments. The simulations were also extended to model and evaluate hybrid gas/chemical EOR methods in field scales. Simulation results indicated a well-designed low-tension-gas flooding has the potential to recover the trapped oil where foam provides mobility control during surfactant and surfactant-alkaline flooding in reservoirs with very low permeability. / text