Based on contact angle and interfacial tension measurement, this paper concentrated on adding surfactants agent into fracturing fluids to increase oil output after hydraulic fracturing. Cationic, anionic and nonionic surfactants were added into slickwater to perform a serious of one end open (OEO) imbibition experiments at a certain concentration. Scanning electron microscope (SEM) and nuclear magnetic resonance (NMR) method were also applied in the detection before and after the imbibition process. Results demonstrated that core samples changed from oil-wet to intermediate-wet or water-wet after soaked in surfactants, cationic surfactant shows a better performance in changing contact angle while different kinds of surfactants have a similar ability in lowering IFT. In the soaking duration, NMR transverse relaxation time (T2) spectrum showed that oil recovered by counter-current imbibition mainly distributed in intervals of 10-1000 ms while oil remained uncovered mainly distributed in intervals of 0.1-10 ms. T2 spectrum moved towards left side and this indicated that aqueous phase migrate from larger pores to smaller ones. Both laboratory experiments and field applications have indicated that adding surfactants into fracturing fluids can significantly increase oil outputs for tight oil-wet reservoirs. Application of this technology can be a good way to solve low production problems for this type of reservoir.

In tight oil reservoir, the flow channel of fluids is tiny and the boundary layer effect is obvious, resulting in large flow resistance and high threshold pressure gradient. A fractal model for calculating the threshold pressure gradient of tight oil reservoir is established considering the fractal dimension of the pore throat and the tortuosity. In this model, the rock is considered as a capillary bundle with different diameter distribution as obtained from high-pressure mercury injection measurements for tight rocks. The mathematical model expresses the fractal threshold pressure gradient as a function of ultimate shear stress (η0), pore throat fractal dimension (Df), tortuosity fractal dimension (DT), the maximum pore radius (rmax), the characteristic length of the core (L0) and the connate water saturation (Swi). For 27 tight cores obtained from Changqing oilfield, threshold pressure gradients were determined using the established model and compared with experimental results and a good fit was found especially for the rock with lower permeability. The relative error is less than 14% for all the rock tested and is only 1.77% for the cores with permeability in the range of 0.001~0.01mD. This model has the advantage of being able to check the impact of the connate water saturation on the threshold pressure gradient of tight rock, which is usually neglected in previous work. The results show that higher Swi results in largely increased threshold pressure gradient. This fractal model is of great importance in studying of the mechanism of tight oil flow in porous media.