This paper studied the strengthening effects of silica nanoparticles on the polyacrylamide (PAM)/hydroquinone (HQ)–hexamethylenetetramine (HMTA) composite gel. Pure PAM/HQ–HMTA gel and PAM/HQ–HMTA gels containing silica nanoparticles up to 0.3 wt % were prepared at 110 °C. Influences of silica nanoparticles on gelation performances were systematically evaluated. By the addition of silica nanoparticles, the gelation time became shorter and the gel strength was improved observably. Rheological measurements showed that silica nanoparticles enhanced both elasticity and viscosity of the gel significantly. Thermal stability of the gel was studied by differential scanning calorimetry (DSC) measurements. The maximum tolerated temperature of the gel was improved from 137.8 to 155.5 °C by the addition of silica nanoparticles with a concentration of 0.3 wt %. Furthermore, to study the strengthening mechanisms of silica nanoparticles to the gel, the microstructure and existing state of water within the gel were investigated by environmental scanning electron microscopy (ESEM) and DSC measurements. Micrographs of the gel showed that massive aggregations and arrangements of silica nanoparticles existed in uniformly distributed three-dimensional network structures of the gel, which greatly improved the structural strength of the gel. Moreover, the mass fraction of bound water within the gel increased from 22.5 to 39.9% by the addition of silica nanoparticles with a concentration of 0.3 wt %. The hydrogen bonds and electrostatic attractions between silica nanoparticles and water molecules/hydronium ions make a higher bound water ratio, which contributes to better water holding capacity and thermal stability of the gel.
Mature oilfields usually encounter the problem of high watercut. It is practical to use chemical methods for water-shutoff in production wells, however conventional water-shutoff agents have problems of long gelation time, low gel strength, and poor stability under low temperature and high salinity conditions. In this work a novel polymer gel for low temperature and high salinity reservoirs was developed. This water-shutoff agent had controllable gelation time, adjustable gel strength and good stability performance. The crosslinking process of this polymer gel was studied by rheological experiments. The process could be divided into an induction period, a fast crosslinking period, and a stable period. Its gelation behaviors were investigated in detail. According to the Gel Strength Code (GSC) and vacuum breakthrough method, the gel strength was displayed in contour maps. The composition of the polymer gel was optimized to 0.25~0.3% YG100 + 0.6~0.9% resorcinol + 0.2~0.4% hexamethylenetetramine (HMTA) + 0.08~0.27% conditioner (oxalic acid). With the concentration increase of the polymer gel and temperature, the decrease of pH, the induction period became shorter and the crosslinking was more efficient, resulting in better stability performance. Various factors of the gelation behavior which have an impact on the crosslinking reaction process were examined. The relationships between each impact factor and the initial crosslinking time were described with mathematical equations.
Aiming at increasing the recovery in tight oil reservoir with fractures, a new kind of mobility control system with function of imbibition (MCSI) was prepared with dispersed particle gel (DPG) and surfactant. The dynamic imbibition can effectively control the mobility ratio in a tight oil fracture network and increase oil recovery. Based on the characteristics of tight oil reservoir fractures, the preparation method of a multiple fracture network model was established. The prepared fracture network model has the characteristics of controllable fracture length, width, and height. The MCSI system can reduce the oil–water interfacial tension to 10–2 mN/m. It features low viscosity, strengthening water wet, thus promoting the imbibition effect. Dynamic imbibition tests of the multiple fracture network model show that the MCSI system has higher oil recovery than each single component. At the same time, the subsequent water flooding after soaking also has the function of enhancing oil recovery. The effects of fluid type, flow rate, fracture width, and matrix fracture network model type on oil recovery of MCSI are clarified.
Tightoil poses huge reservoir in many countries. Due to the poor reservoir properties, such as nanometer to micrometer pores, low permeability, energy deficiency, the oil recovery in tightoil reservoir is very low, even with horizontal drilling and hydraulic fracturing. The small pores are featuring large capillary pressure thus spontaneous imbibition. Surfactant would accelerate this process. However, due to the small amount of oil in core, the accurate recording of oil recovery is challenging, especially during dynamic imbibition within fracture matrix system. Nuclear Magnetic Resonance (NMR) T2 spectra was used to characterized the migration of oil and water in pores and throats during dynamic imbibition. Various phenomenons are revealed and proved by T2 spectra figure, such as: water imbibed into small pores, oil expelled from large pores, and oil film formed on fracture face. The oil recovery during dynamic imbibition was examined online during experiment from the peak area generated by T2 spectra. Before and after the dynamic imbibition, Magnetic Resonance Imaging (MRI) was used to compare the saturation and distribution of oil in the core sample. When the oil drop migrates out of the pores, it will emerge from the surface of rock sample. Its shape on top, lateral, and bottom of the sample was observed with a long distance microscope. Their growth in width and height was compared carefully. The growth rate was categorized into different stages, and quantitatively compared.
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