Hydraulic fracturing has become a key technology to economically extract oil and gas from unconventional reservoirs. During hydraulic fracturing, fluid loss and water invasion into formation can cause serious permeability reduction near fracture face. At the same time, field practice also showed that well shut-ins after hydraulic fracturing could significantly increase hydrocarbon outputs, whereas the inner mechanism still remains unknown. In this paper, firstly, we studied permeability reduction after water invasion and permeability enhancement after well shut-ins using a core flooding system. Then, to investigate the inner mechanism, we studied aqueous phase migration during shut-ins using nuclear magnetic resonance (NMR) method. Results showed that fluids invasion reduce matrix permeability while well shut-ins can improve permeability and this improvement depends on the length of shut-ins time. NMR results showed that aqueous phases mainly distribute in macropores and mesopores after water invasion, while in shut-ins period, these invaded aqueous phases redistribute and migrate from larger pore spaces to smaller ones. Aqueous phase redistribution and migration during shut-ins period can remove near fracture water-block, reduce capillary discontinuity and increase the relative permeability of hydrocarbon phase, and this is the reason for permeability enhancement and hydrocarbon output increase after well shut-ins.

To investigate the mechanism whereby well shut-ins and surfactant additivities can increase hydrocarbon output after hydraulic fracturing, in this paper, we simulated well shut-ins with one end open (OEO) rock samples and performed a serious of imbibition experiments with different surfactant additivities based on contact angle (CA) and interfacial tension (IFT) measurements. Scanning electron microscope (SEM) and nuclear magnetic resonance (NMR) methods were also been adopted in the detection before and after shut-ins. The results demonstrated that cationic surfactants result in better improving oil recovery (IOR) performance due to their high wettability alteration ability on vertical fracture faces, while different kinds of surfactants have a similar ability in lowering IFT. As for shut-ins duration, the NMR transverse relaxation time (T₂) spectrum move towards the left side, indicating that aqueous phases migrate to smaller pores spaces and deeper distances. Aqueous migration during the shut-ins period can remove near-fracture trapped water, while surfactant additivities can accelerate and enhance this process, and these two points are the most direct reasons for the observed hydrocarbon output increases.

Spontaneous imbibition is an important mechanism for fractured reservoir to enhance oil recovery. Wetting phase enters porous media with the force of capillary pressure and gravity and replaces oil in matrix. To investigate the imbibition of tight reservoirs, on the consideration of tight formation characteristics, this paper derived a one dimension, two phases, counter-current imbibition model, after dimensionless of distance and time, Galerkin method for spatial discretization and time integration, solutions were given, comparisons of conventional sandstone and tight formation were made. The results have indicated that: (1) Imbibition can be divided into gravity assisting, gravity opposing and zero gravity in terms of different gravity conditions. (2) Saturation front of tight formation moves faster than sandstone because of high capillary pressure. (3) Capillary pressure plays the dominant role than gravity in imbibition. Influence of gravity is much greater in high-permeability sandstone than in tight reservoirs. (4) Horizontal well multi-stage fracturing and massive fracturing can increase fracture area and fracture volume, and increase the contact area with wetting phases, this will result in a greater imbibition and a great recovery of oil.

Multi-stage fractured horizontal wells can create fracture networks and increase the contact area between fracture and matrix to enhance well productivity and EOR. It has become a tendency to pump large volumes of fluids and proppants with higher and higher slurry rate during hydraulic stimulation. While field production has presented that not all productivities have positively relation with the increase of stimulation scales. Some small-scale fractured wells even perform better than the massive treatment ones. To investigate this phenomenon, a new evaluation experiment studied by CT scanning and rock mechanics testified the existence of the fracture surface damage, and some key factors were revealed. Moreover, we established a new mathematical model of fracture surface skin with segment characteristics using fluid coupling method based on the classical model of PKN and KGD. Comparison of the Cinco-Ley model and new model revealed that influence of the fracture surface damage skin on productivity was only 5% using Cinco-Ley model, while the influence was 50% using our new model. The results indicated that for a specific low permeability reservoir, if high net pressure can't create complex fracture, it would bring formation damage in the near well. We put forward a method for low damage treatment as following: 1)utilize the newly developed fracturing fluids such as slick water, low concentration densifier, linear gel (not cross linked), low molecular weight fluid, etc.; 2)Optimize minimum viscosity of fracturing fluid, then optimizing the corresponding pumping rate; 3)Optimize combination of fluid and proppant type and size according new mathematical model; 4) Try acid-fracturing during pad stages so as to minimize formation damage and fracture damage to obtain an optimized propped profile. The technology has been put in to filed application in 45 wells, the performance of post-fracturing is very remarkable with the daily oil rate being 14m3/d increased more than 32.2% that of the past well stimulation, and it has a great significance in the near future.

Nowadays, the fiber has become the most important oilfield chemical material with great advantages in hydraulic fracturing treatment when considering fluid leak off, proppant transportation and fracture damage in tight oil and gas reservoirs. However, it still has some drawbacks, such as mechanical properties, heat denaturation and poor chemical stability, always emerge in oilfield cases. Accordingly, a new type of oil soluble temporary diverting agent is used to overcome these shortcomings in our research. We developed into a new agent with different types of petroleum resin and hydrocarbon resin. A series of evaluation experiment was carried out including temperature compatibility, diverting efficiency and dispersity etc. The results showed that with increasing temperature and prolonging dissolved time, the oil soluble rate of temporary agent in 6 hrs was 95%-99% at 80-120 °C, which indicated good oil solubility. After complete dissolution, the viscosity of 5-20 g/L solution was 12.6-53.7 mPa.s, which had good flowback after treatment. Furthermore, by reducing the diverting particle size and improving the level of aggregation of particles, a specially designed instrument was put forward to evaluate the performances of fracture conductivity, fracture diverting. The length and concentration of the agent were optimized in this study. More than 20 treatments with new agents in Huabei oil field have been performed with encouraging results, 95.2% efficiency with an average post-fracturing rate reach to 21.3m³/d, which was three times of before stimulation. The results have great influences on both theoretical study and field treatments of new chemical material for impoving complex fracure degree of hydraulic fracturing in tight oil and gas reservoirs.