Adsorption of surfactants in shales is not well studied. The goal of this work is to quantify and understand surfactant adsorption in several shale samples. Shale samples were obtained from several formations and are referred to by the formation names; but considering the fact that these formations are highly heterogeneous and huge, these few samples do not represent the shales. Shales are multimineral substrates with pores in the range of 1–300 nm. The adsorption capacity of three surfactants (cationic, nonionic, and anionic) on an Eagle Ford reservoir shale sample was measured. The cationic surfactant, cetyltrimethylammonium bromide (CTAB), showed the highest adsorption capacity in molar units, followed by anionic internal olefin sulfonate (IOS) C15-18 and then nonionic NP-40s. CTAB also had the highest adsorption in mass units, followed by NP-40 and then IOS. Adsorption of the anionic surfactant onto two pure minerals (calcite and quartz) and six shales were investigated, and all of them showed Langmuir-type sorption. The adsorption capacity of calcite and quartz are about the same (∼1.1 mg/g of rock). The adsorption capacity of shales depends on the mineral composition. The adsorption in Mancos outcrop and Green Shale samples is dominated by clay, whereas that in Wolfcamp and Eagle Ford outcrop shale samples is dominated by calcite. The adsorption in Eagle Ford (reservoir) and Marcellus shale samples is dominated by total organic carbon (TOC). An additive model was built to estimate the adsorption capacity, given the mineral composition and TOC. The model shows that organic matter and clay have the most significant impact on adsorption per unit mass; the contribution of each shale component on adsorption depends on its corresponding mass fraction.
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.
Application of horizontal wells and multi-stage fracturing has enabled oil recovery from extremely low permeability shale oil reservoirs, but the decline in production rate is more than two thirds in the first two years. We are trying to develop chemicals that can be injected into old wells to stimulate oil production before putting the well back in production. The goal of this work is to evaluate chemical blends for such a process at the laboratory scale. The chemical blend contains surfactants, a weak acid, a potential determining ion, and a solvent. Six different solvents were screened: Cyclohexane, D-Limonene, Dodecane, Kerosene, Turpentine, and Green Solvent®. Most of the chemical blends with the solvents extracted about 60% of the oil from shale chips, but the Green Solvent® extracted about 84%. Spontaneous imbibition tests were performed with outcrop Mancos shale cores. Oil was injected into these outcrop cores at a high pressure. NMR T2 distributions were measured for the cores in the original dry state, after oil injection and after imbibition. The aqueous phase from the chemical blend imbibed into the cores and pushed out a part of the oil and gas present in the cores. The surfactant in these blends can change wettability and interfacial tension. The solvent can mix with the oil and solubilize organic solid residues such as asphaltenes. The weak acid can dissolve a part of the carbonate minerals and improve permeability. The synergy can make these chemical blends strong candidates to stimulate oil recovery in shale formations.
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