The goal of this work is to develop surfactant systems that can improve oil flow from shale wells after fracturing or re-fracturing. Surfactants can reduce oil-water interfacial tension and wettability of the shale, which in turn can improve water imbibition, increase oil relative permeability and reduce water blockage at the matrix-fracture interface. Temperature in typical shale reservoirs are high and the surfactants need to be aqueous stable to be effective in these treatments. Mixing two surfactants often gives higher aqueous stability than those of the single surfactants. A large number of surfactants (anionic, non-ionic and cationic) and their blends were studied for aqueous stability, contact angle and spontaneous imbibition. Seven single surfactants and nine surfactant blends were found to be stable in both high and low salinity brines at 125 °C. All aqueous stable blends changed wettability of oil-wet shale to preferentially water-wet in both high and low salinity brines. Seven single surfactants and five surfactant blends were tested for imbibition. Surfactant solutions improved water imbibition to the extent of 20% PV. Surfactant blends improved imbibition more than the single surfactants. Imbibition in cores reached a plateau in about 3 days. Surfactant blends have the potential to be used in low salinity fracturing or refracturing fluids to stimulate shale wells.
Summary
The objective of this work is to design and evaluate an effective blend of chemicals that can be injected into shale (black oil or critical fluid) reservoirs to enhance hydrocarbon recovery. The blend can be implemented as a prepad fluid ahead of hydraulic–fracturing fluid or as a remedial fluid later in the life of a well. A chemical blend (CB) consisting of an organic solvent (OS), a surfactant, and an oxidizing agent (OA) (in conjunction with an acid) was designed, developed, and tested in the laboratory on crushed rocks, core plugs, and fractured cores to evaluate the interactions of the chemicals with the shale samples. Microcomputed–tomography (micro–CT) scanning, scanning electron microscopy, and Brinell hardness tests were used to evaluate surface changes in the shales.
The results of laboratory experiments demonstrate that the CB extracts up to 30% of mobile oil in crushed rocks and improves permeability by 25 to 100% in thin core plugs. Some of the mechanisms that might support the CB application are as follows: (1) pressurization of the formation and reopening of the closed fractures, thus improving well productivity; (2) extraction and mobilization of low–mobility oil, remnants of the original kerogen, removal of deposited salt, and trapped water in matrix and fracture network that impedes fluid flow; (3) creation of pathways to high–pressure liquid–rich small organic pores, where hydrocarbon liquids are trapped, adsorbed, and dissolved in the kerogen; (4) creation of flow pathways for the intrusion of aqueous–based fluids in oil–wet organic–rich rocks with wettability alteration to accelerate the injection, countercurrent imbibition, and osmotic processes; and (5) enhancement of porosity and permeability of fracture surfaces by the introduction of a delayed reaction mechanism to deliver acids deeper into the microfracture network without compromising rock mechanical properties. The presence of sulfate ions in the OA did not contribute to any noticeable scale deposit while delaying the reactivity of acid with inorganic components of shale surfaces. Several field trials have been conducted successfully in the Eagle Ford (EF) Formation.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.