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When applied as conformance treatments, foams are required to effectively reduce gas injectivities over prolonged periods of time. Frequently, this ability must be manifested in the presence of a residual oil saturation which often exerts a destabilizing effect on foam and the capacity to generate foam. In this study, the capacity to generate and sustain foam in the presence of a residual oil saturation was examined by each of two methods. The first method monitored the in-situ generation of nitrogen foam at constant pressure drop for 1-ft Berea cbres at a residual oil saturation to surfactant. Gas mobility reduction, foam longevity, and the rate of foam decay were quantified for a variety of surfactants and oils at constant salinity and concentration at room temperature. The second procedure involved the constant quality injection of pregenerated foams into Berea cores at residual oil saturation to water flooding. The liquid requirement to reach steady state and the absolute pressure drop were determined under test conditions identical to the aforementioned method. In each method, foam stability showed a strong sensitivity to surfactant, oil type, in-situ foam quality and oil desaturation kinetics. In a companion laboratory study, the degree of correlation between these results and a variety of benchtop measurements was established. Benchtop measurements included interfacial and surface tensions, film elasticities, oil spreading, pseudoemulsion film drainage times, and film disjoining pressure for oil equilibrated and nonequilibrated surfactant solutions. From these studies, it is concluded that foam destabilization by oil is dictated primarily by pseudoemulsion film stability. The relative stability of the pseudoemulsion films in-situ, however, is dependent upon the prevailing pore level conditions of oil and liquid saturation. Oil spreading, wave dampening, and lamellar film strength had little effect on foam stability to oil. Given this information, one can easily choose test design criteria upon which to screen surfactants for foam conformance treatments in the presence of oil.

Summary Between 2014 and 2016, ConocoPhillips drilled five deviated wells adjacent to a multistage, stimulated horizontal producer to sample the physical characteristics of the reservoir stimulation caused by hydraulic fracturing in the Eagle Ford Formation in DeWitt County, Texas. The design, execution, and results of the pilot are described. This pilot establishes the paucity of pre-existing natural fractures in this locale and enables the determination of the spatial characteristics of the stimulation using information derived from the core, cuttings samples, borehole-image logs, tracer logs, microseismic, distributed temperature sensing (DTS)/distributed acoustic sensing (DAS), and pressure data. Results show that stimulation effectively breaks the reservoir rock and makes a complex array of hydraulic fractures that are more closely spaced near the producer. Some fractures, however, extend interwell distances of more than 1,000 ft. The pilot data indicate that abundant proppant transport appears to be limited to distances less than 75 ft from the producer, which suggests that the stimulated rock volume (SRV) might be greater than the volume of rock that can be effectively drained.

Foams that effectively reduce gas permeability were formed over a wide range of experimental conditions. The ability of selected foaming agents to form foam was evaluated in bulk foam measurements, screening core tests, and in reservoir condition core tests. Results reported show that oil usually adversely affected foam performance with higher molecular weight alkanes showing less of an adverse effect for the foaming agents tested. Foam can be effectively generated in an oil-wet porous medium but was shown to be much less effective than in a water-wet medium for the foaming agents studied. High pressure gradients of up to 4524 kPa/m (200 psi/ft) resulted in effective foam generation with an effective foam continuing to 8500 pore volumes of injected nitrogen. The enriched gas mixture used in this study was shown to adversely affect foam even though the foaming agent was selected through screening testing. This showed the importance of including reservoir condition testing prior to the final selection of a foaming agent for a given reservoir application. Effective foaming agents were identified for use in pilot tests in a typical West Texas CO2 flood and in a typical Canadian hydrocarbon miscible flood.