A gel system has been widely used in many mature oilfields for water shut-off treatment. In the present study, the hydrophobically associating polymer (HAP) was cross-linked with the polyethylenimine (PEI) to form a HAP/PEI gel system which contains 0.35 wt % HAP and 0.60 wt % PEI. Gelation behaviors of the HAP/PEI gel formed in bottle and in core were studied, respectively. Results show that the gelation behaviors of the gel system were greatly affected by the concentration of HAP and that of PEI. The addition of the sodium chloride or calcium chloride generally resulted in a decrease of the apparent viscosity and an extension of the gelation time. However, a low concentration of sodium chloride led to a slight increase of the gel viscosity in bottle due to the intensification of the hydrophobic association. The rock skeleton of the core had a great effect on the gelation behavior. Compared with the results obtained in bottle, the apparent viscosity of the HAP/PEI gel system in core was obviously reduced, and the gelation time in core was extended two times or even longer. Both the gelation times achieved in bottle and in core decreased with the increase of temperature following the relationship of Arrhenius-type. The activation energy of the HAP/PEI gel system was 41.57 kJ/mol in bottle but increased to 60.95 kJ/mol in core. Data collected from the core flowing tests present a favorable shut-off performance and a strong wash-out resistance of the HAP/PEI gel system. In addition, the in-depth flow diversion and water permeability reduction were two main mechanisms of this gel system for water shut-off treatment.
Ethanolamine (ETA) was used together with surfactant to form the ETA/surfactant flooding system. The interfacial tension (IFT) and emulsification of Gudong oil and chemical aqueous solutions were studied. The results indicate that the oil/water IFT can be reduced by 2 orders of magnitude, the oil can be emulsified and dispersed more easily, and the emulsion stability is strengthened due to the synergistic effect of ETA, surfactant, and the in situ soap at the oil/water contact. Seventeen sandpack flooding tests were conducted to investigate the effects of ETA concentration, chemical slug size, chemical slug type, and experimental temperature on the incremental oil recovery. The results show that the highest incremental oil recovery is obtained when 0.065 wt % surfactant and 0.300 wt % ETA are simultaneously injected. In addition, the increase of oil recovery is always accompanied by a sudden pressure drop in the injection process of the ETA/surfactant slug. Larger ETA/surfactant slug size contributes to a higher incremental oil recovery, but there is an optimal slug size (0.8−1.0 PV in the test) when the economic factor is taken into consideration. Moreover, a high experimental temperature has an adverse effect on the synergistic effect of ETA and surfactant because of the volatility of ETA molecules.
A hydrophobically associating hydroxyethyl cellulose (HAHEC) used for enhanced oil recovery (EOR) was studied in the present study. The effects of HAHEC concentration, temperature, and shear rate on apparent viscosity of HAHEC solution were explored. Results show that, because of the hydrophobic association of HAHEC molecules and the formation of supramolecular aggregates, the viscosifying performance of HAHEC is obviously better than that of HEC. But the apparent viscosity of HAHEC solution is sensitive to the temperature and it declines significantly especially when the temperature is less than 50 °C. HAHEC solution also has satisfactory shear resistance performance, and its apparent viscosity can basically return to the initial value after withdrawing severe shear action. Moreover, HAHEC shows favorable surface and interfacial activities because of the adsorption and arrangement of HAHEC molecules onto a water/air surface and water/oil interface. Sand pack core experiments were conducted to investigate the EOR ability of the HAHEC flooding system; results display that both the resistance factor and the residual resistance factor of HAHEC solution in cores are higher than those of HEC solution. Favorable EOR performance of the HAHEC flooding is proved, and high incremental oil recovery can be achieved with the application of optimized injection concentration, injection rate, and injection slug size after initial water flooding. In addition, the emulsification phenomenon is obvious during the HAHEC flooding because of the favorable surface and interfacial activities of HAHEC.
Wellbore instability and formation collapse are crucial issues in the process of well excavation in the oil industry under extreme salinity and high-temperature conditions. This study demonstrates that a salt-responsive zwitterionic polymer brush (NS-DAD) based on modified nanosilica as a fluid-loss additive utilizing the anti-polyelectrolyte effect in water-based drilling fluids (WDFs) to overcome the wellbore instability caused by the failure of polyelectrolytes at extreme salinity and high temperature. Additionally, a nonionic polymer brush (NS-D), an anionic polymer brush (NS-DA), and a cationic brush (NS-DD) were also prepared for comparison. Compared with NS-D, NS-DA, and NS-DD, NS-DAD exhibited the anti-polyelectrolyte phenomenon, in which the sodium chloride electrolyte shields the electrostatic interaction in the molecular chain of the polyzwitterion and the molecular structure changes from a collapsed sphere to a more open helix. Macroscopically, NS-DAD exhibited a higher viscosity than NS-D, NS-DA, and NS-DD in saturated salt-based mud (SSBM). A typical “star-net” structure was observed between NS-DAD and the bentonite layer. Energy-dispersive spectroscopy (EDS) analysis of filter cakes showed that NS-DAD could significantly reduce the content of chloride and sodium ions in the bentonite layer. Therefore, compared with NS-D/SSBM, NS-DA/SSBM, and NS-DD/SSBM, NS-DAD/SSBM had excellent rheological properties, thermal stability, less fluid-loss volume, and thinner filter cake under extreme salinity and high-temperature conditions. The fluid-loss additive can be used to reduce the fluid-loss volume of WDFs in harsh reservoir conditions of high temperature and high salinity.
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