The application of horizontal well volume fracturing technology is an important method for enhancing oil recovery in tight oil reservoirs. However, the influence mechanism of the fracture placement scheme (FPC) on postfracturing productivity is still unclear. Based on the theory of the black oil model, combined with the reservoir stimulation characteristics of horizontal well volume fracturing in tight oil reservoirs, this paper established a postfracturing reservoir production simulation model. History fitting was used to verify the accuracy of the production model simulations. A series of numerical simulations was carried out to study the influence mechanisms of the fracture parameters and FPC on productivity. The simulation results show that compared with the fracture conductivity, the fracture length and number are the main parameters affecting tight oil reservoir productivity. Selecting a reasonable fracture length and number can realize the economical and efficient production of tight oil reservoir volume fracturing. Compared with the traditional fracture equal-length scheme, an FPC with an uneven fracture length can increase the cumulative oil production of oil wells. Under the condition of the same total fracture length, the scheme with a staggered distribution of long fractures and short fractures has the largest cumulative oil production over five years. A reasonable well spacing can greatly reduce the impact of interwell interference on postfracturing dual branch horizontal well productivity. When dual branch horizontal well fractures are alternately distributed, the postfracturing productivity is higher. The production simulation model established in this paper provides a method to accurately evaluate the productivity of horizontal wells after volume fracturing, which can provide guidance for the optimization of hydraulic fracturing operation parameters.

Fracture network fracturing combined with oil–water infiltration and replacement is an effective approach to develop tight sandstone reservoirs. How to further improve oil recovery based on imbibition is a problem encountered during production. In this study, the core of the CHANG-7 tight sandstone reservoir in the Changqing oilfield of the China National Petroleum Corporation (CNPC) is studied. Combined with the newly designed core self-imbibition experiment, the mechanisms of salinity action are studied, and the influence of salinity on the process of imbibition oil recovery is quantitatively characterized. Research results show that the influence of salinity on the imbibition process of tight sandstone reservoirs takes place mainly through two ways; one is to reduce the oil–water interfacial tension, and the other is to construct an osmotic pressure displacement model. The salinity has significant influences on interfacial tension. The interfacial tension of low-salinity brine is only 1/5 of that of distilled water, but in the presence of high-efficiency surfactants, the influence of the salinity on the interfacial tension can be ignored; the greater the difference in salt concentration, the higher the core permeability and the greater the influence of salinity on the process of imbibition and oil recovery in tight sandstone reservoirs. At the initial stage of imbibition, the effect of salinity is less important than that of capillary force. On the contrary, the effect of salinity is much more important than that of capillary force in the middle of imbibition, and the imbibition curve shows a downward trend. At the later stage of imbibition, the fluid tends toward imbibition equilibrium, and the effects of capillary force and salinity are not obvious.

Tight sandstone reservoirs are often produced by shutting in the well and inducing imbibition. However, by adopting current reservoir classifications, the heterogeneity of reservoirs cannot be properly treated. Based upon the analysis of the imbibition curves and mercury intrusion porosimetry tests, Chang-7 tight sandstone reservoirs were classified into three categories according to the newly proposed standards. Imbibition tests demonstrated that for the first category, imbibition and drainage occurred continuously and never reached the plateau within the experiment duration. It was suggested that a longer shut-in time favors the production of oil. For the second category, a steady state for imbibition was reached and a shut-in time as short as three days resulted in a high imbibition rate. For the third category, a plateau was reached for the first time and imbibition restarted until a steady state was reached. The average shut-in time for the third category was eight days. Compatibility between reservoir characteristics and a soaking development regime based upon the proposed classification methods effectively enhances the oil recovery efficiency of formations with distinct petrophysical properties. This provides insight into the classification methods of tight sandstone reservoirs.

As a fluid flows through a porous media, a drag force, called seepage force in the paper, will be formed on the matrix of the media in the fluid flowing direction. However, the seepage force is normally ignored in the analysis of wellbore fracturing during hydraulic fracturing operation. In this paper, an analytical model for seepage force around a vertical wellbore is presented based on linear elasticity theory, and the effect of the seepage force on wellbore breakdown has been analyzed. Also studied are the effects of the two horizontal principal stresses and the reservoir permeability on the action of seepage force. The paper proves that seepage force lowers formation breakdown pressure of a vertical wellbores; the deeper a formation is, the greater action of the seepage force; seepage force contributes more to breakdown formation with small difference of the two horizontal stresses such as unconventional reservoirs; seepage force increases as rock permeability decreases, and it should not be ignored in hydraulic fracturing analysis, especially for low-permeability formation.

A model suitable for evaluating a tight sandstone reservoir is established. The model includes two oil-water replacement modes: capillary force mode and osmotic pressure mode. The relationship between oil-water displacement rate and dimensionless time under different parameters is drawn considering the influence of capillary force, osmotic pressure, production pressure difference, and starting pressure gradient. Results indicate that the higher the relative permeability of the water phase, the lower the relative permeability of the oil phase, the smaller the oil-water viscosity ratio, and the higher the oil-water replacement rate. The relative permeability of the water phase also affects the infiltration stabilization time. Low salinity fracturing fluid infiltration helps to improve the oil-water replacement rate.