A nanosilica based fluid system was evaluated for forming in-situ glass-like material inside matrix for permanent gas shutoff. This novel method involves two steps; firstly, pumping low viscosity aqueous nanosilica mixture into the formation and allowing it to gel up. Secondly, gas production dehydrates nanosilica to form glass-like material inside the matrix. For this paper, a nanosilica-based fluid system was assessed for pumping strategy and performance evaluation.
A nanosilica based fluid system consists of a mixture of colloidal silica and activators. It possesses low viscosity, which assists in deeper penetration during placement. With time and temperature, it can lead to in-situ gelation to form a rigid gel to block the pore space. Gas production can dehydrate nanosilica gel to form in-situ glass-like material inside formation porosity for permanent gas shutoff. The nanosilica based fluid system was optimized using gelation tests and core flooding tests to evaluate its performance under high-pressure, high-temperature conditions. Formation of in-situ glass-like material inside pores was analyzed using a scanning electron microscope (SEM).
The gelation time can be tailored by varying the activator type and concentration to match the field operation requirements. Kinetics of colloidal silica gelation at elevated temperatures showed faster viscosity buildup. Before gelation, the viscosity for the nanosilica based fluid system was recorded less than 5 cp at a 10 1/s shear rate, whereas the viscosity was increased more than 500 cp at a 10 1/s shear rate. Using core flow tests, N2 gas permeability of the Berea sandstone core was completely plugged after pumping the 5-pore volume nanosilica based fluid system at 200°F. During nanosilica based fluid system injection through the core, differential pressure was increased to only 10 psi showing better injectivity. The SEM images showed the presence of glass like material filling the porosity, which showed in-situ generation of glass-like material inside pores.
The nanosilica based fluid system has a low viscosity and can penetrate deeper into the formation matrix before transforming into a gel. Undesirable gas flow can dehydrate nanosilica gel to form in-situ glass-like material inside matrix for permanent sealing. This is environmentally friendly and can serve as an alternative to currently used conformance polymers for gas shutoff applications.
The utilization of synergistic mixtures of nanoparticles (NPs) and surfactants for enhanced oil recovery (EOR) has drawn increasing scientific attention. In this study, a series of coarse-grained (CG) molecular dynamics (MD) models were built to study the behaviors of NPs and surfactants in the vicinity of the oil/water interface. Hydrophilic, hydrophobic, and amphiphilic NPs were constructed to investigate the effect of hydrophobicity on the ability of NPs in term of interfacial tension (IFT) reduction. The synergistic effect of surfactants and NPs were also studied.
Surfactants and amphiphilic NPs can both accumulate at the interface of oil and water, while hydrophilic and hydrophobic NPs stay in water or oil phase. The NPs with various ratios of hydrophobic to hydrophilic domains were investigated to determine the types of NPs that result in the most IFT reduction. The comparison of IFTs indicates that amphiphilic NPs has a better ability to assist surfactants in further reducing the interfacial tension. Meanwhile, surface modification and the presence of surfactants can prevent the aggregation of NPs.
These MD simulation results allow us to figure out the physical behavior of NPs and surfactants at the oil/water interfaces. Analysis of the results can further assist the NPs synthesis for surfactant and/or surfactant-nanoparticle EOR applications in unconventional reservoirs.
Enhanced Oil Recovery (EOR) is well known for its potential to produce residual oil after the primary and secondary oil recovery. The residual oil is trapped in the narrow throat due to high capillary pressure, which is influenced by rock wettability and oil/water interfacial tension (IFT) (Wu et al., 2008). Surfactants have been widely investigated and employed in the EOR process to reduce the IFT and to alter the wettability (Sheng et al. 2015; Kamal et al., 2017; Negin et al., 2017). However, during the surfactant flooding, surfactants can adsorb onto the rock surfaces. This may result in the reduction of their concentrations, which significantly reduce the efficiency of surfactants in practical applications. The high cost of surfactants also makes this potential loss a critical issue. Many researchers have focused their studies on reducing the adsorption of surfactants by adding various materials in the chemical formulations.
The oil-water interfacial tension (IFT) is by all means important in capillary pressure estimation and fluid-fluid and fluid-rock interactions analysis. Observations from experimental data indicate that oil-water IFT is a function of pressure, temperature, and compositions of oil and water. A reliable correlation to estimate oil-water IFT is highly desire. Unfortunately to our best knowledge no correlation that uses the compositions of oil and water as inputs is available. Our work is to fill this gap.
In this research, we collected data from former studies and investigations and developed a correlation for oil-water IFT. In the proposed correlation oil-water IFT is a function of system pressure, temperature, and compositions of oil and water. Error analysis was conducted to check the accuracy of the equation by comparing the calculated values with the experimental data. The results indicated that the new correlation predicts reliable oil-water IFTs. Our correlation calculates the oil-water IFT from system pressure, temperature, and compositions of oil and water. It addresses the effect of composition of oil on IFT, which is not presented in existing correlations. Therefore it can not only be applied in the calculation of capillary pressure in the compositional simulation, but also be used in daily petroleum engineering calculation such as waterflooding analysis.
In recent years, nonionic surfactants have been very popular in application such as water flooding, fracturing and acidizing treatments. The most attractive features of this class of chemicals used in acidizing treatments, are their contribution to surface and interfacial tension reduction, water wetting, and low adsorption properties. Almost all surfactants, when applied at low concentrations in a system, alter the surface activities of the fluid by forming aggregates which lower free energy of the system, resulting in lower surface and interfacial tensions. However, many of these surfactants and chemicals adsorb to either the interface or to the solid media such as sandstone, reducing their effectiveness. This phenomenon may result in poor performance of these additives throughout the acidizing treatment and also, may promote emulsion tendencies which may lead to formation damage.
This paper presents results of laboratory studies of various nonionic surfactants and outlines the adsorption of these chemicals within the matrix of sandstone formations. Conditions affecting adsorption properties will also be discussed in this paper.
Various comprehensive studies have been conducted demonstrating the properties and effects of nonionic surfactants. A 1971 study by Gidley demonstrated the effect of ethylene glycol monobutyl ether (EGMBE) in the restoration of water wettability and the improvement of stimulation response during acid treatments. Sutton and Lasater concluded in their study of the effects of EGMBE in reducing the stability of emulsions that adsorption of surfactants by produced fines could reduce the effectiveness of non-emulsifiers. In 1975, B.E. Hall illustrated the effect of various glycol ether solvents on reducing adsorption of cationic surfactants from acid onto silica and clay particles. G.E. King and R.M. Lee studied the adsorption properties of alcohol mixture mutual solvent, such as a blend of isopropyl alcohol and isoctyl alcohol, and EGMBE. In 1985, Gidley showed the importance of using mutual solvents in hydrocarbon after-flush in oil wells alter extensive acidizing treatments. However, the effects of chemical treatments in oil wells were not consistent with the effects in gas wells which suggests probable interaction of the treating fluid with the reservoir fluids.
In this study, we examined the adsorption properties of various alcohol ethoxylates and evaluated other factors affecting the overall performance of these products in petroleum additives. Ethoxylated alcohol was used with petroleum additives. Ethoxylated alcohol was used with ethylene glycol monobutyl ether to optimize adsorption conditions and reduce emulsion tendencies. More knowledge of these products gives us a tool to develop a better additive which leads to faster and cleaner separation of oil and acid, deeper penetration, and reduced emulsion tendencies. A series of adsorption tests were conducted by flowing the treating fluids through two 6-ft. long (1.83 m) by 2 in. (50.8 mm) wide Berea sandstone cores. The cores were equipped with fluid taps at set intervals. Both cores were saturated with 3% NH4Cl brine solution prior to the injection of alcohol ethoxylates. After an optimum alcohol ethoxylate was selected, a mixture of 15% HCl and alcohol ethoxylate was prepared and injected into a separate core to evaluate the effect and condition of these additives in achieving a deeper penetration of acidizing treatments. During injection, samples collected from each interval were tested for their surface tension and emulsion tendencies.