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In this paper, the research and application of nanomaterials in oilfield chemical engineering was briefly described with emphasis on the nano-silica in enhanced oil recovery, depressure and augmented injection. A study on the modification of nano-silica was carried out indoors, and a modified nano-depressure and augmented injection agent was prepared by using a coupling agent for surface grafting modification, followed by introducing functional monomers for in-situ modification. The effects of silica dosage, coupling agent dosage, dispersant and regulator ratio, and modification time on the modified product were investigated. It was analyzed by infrared spectroscopy, thermogravimetric analysis, nanoparticle size analyzer, transmission electron microscope, atomic force microscope, etc. A series of experiments were conducted to evaluate the temperature and salt resistance, wettability, as well as depressure and augmented injection performance of the modified products.

Tight carbonate reservoirs in the Western Qaidam Basin have complex lithologies and pore structures. The oil–water mobility law in reservoirs has not yet been completely determined, restricting the formulation of rational reservoir development methods. To bridge this gap, in this study, we used several test methods, such as casting thin sections, mercury intrusion, and nuclear magnetic resonance, to obtain the pore structure and oil–water displacement characteristics of tight carbonate reservoirs in the Western Qaidam Basin. The pore structures of the reservoirs could be categorized into three types: microfractures + dissolved pores + micropores (MFD), microfractures + micropores (MF), and matrix (M). The characteristics of single‐phase oil seepage and water flooding in reservoirs with various pore structures differed evidently. For the MF‐ and M‐types, the water‐locking effect caused by the strong capillary force affected oil charging in the micropores. The effect of the pressure drop on the MFD‐type algal limestone was less than that on the MF‐type limestone (dolomite) because of the occurrence of a non‐Darcy flow. The MFD‐type, which contained microfractures, had preferential seepage channels, resulting in obvious fluid channeling and low water displacement efficiency. Oil−water displacement mainly occurred in the dissolved pores and microfractures, suggesting that starting oil accumulation in the micropores was crucial. This study will assist in efficient development of tight carbonate reservoirs in the Western Qaidam Basin. [ABSTRACT FROM AUTHOR]

A BCG − CO2 fracturing fluid composed of a new thickener and CO2 causes low amounts of formation damage, and it can be used to stimulate low‐permeability gas reservoirs with water sensitivity. However, at present the rheological properties of this foam fracturing fluid are unclear, which has limited its field application to some degree. The main purpose of this study was to ascertain the rheological parameters and a model of the BCG − CO2 fracturing fluid. The rheological properties of the BCG − CO2 fracturing fluid were evaluated by using a foam rheological test system. The unfoamed condition test results showed that when the shear rate was lower than 1000 s−1, the effective viscosity exhibited a rapid decreasing trend. The effective viscosity of the BCG − CO2 fracturing fluid was 4 to 26 mPa · s under foamed conditions. The comparison results showed that the viscosity of the BCG − CO2 foam was suitable as a low damage fracturing fluid. The measured data were fitted using the H‐B and power law models in this study. The power law model, by contrast, was fit for describing the relationship between shear rate and shear stress. The foamed condition rheological index n′ first decreased and then increased with increasing foam quality, and the rheological coefficient k′ first increased and then decreased with increasing foam quality. For the different foam qualities, the rheological index n′ first increased and then decreased with increasing temperature. The rheological coefficient k′ showed a decreasing trend with increasing temperature. When an exponential function, in which the foam quality and temperature were independent, was used for fitting, it was not accurate in predicting the rheological properties. The fitting results based on a quadratic polynomial surface model were better. The average calculation errors of the rheological parameters were all less than 3.32%. The findings of this study can help develop a better understanding of the heat transfer and flow coupling process in wellbore and fracture in fracturing treatment. [ABSTRACT FROM AUTHOR]