Imbibition is regarded as an important mechanism for the recovery of oil for tight sandstone reservoirs. In this work, imbibition characteristic of tight sandstone reservoirs is experimentally investigated by nuclear magnetic resonance (NMR) and mercury intrusion porosimetry (MIP) tests. Pore-throat limit for imbibition is determined and its relation to reservoir parameters is examined. The pore-throat boundaries for both imbibition and drainage process are differentiated. An imbibition mechanism of tight sandstone reservoir is proposed where the wetting phase enters smaller pores due to capillary effect and the non-wetting phase is drained through larger pores. Porosity is linearly proportional to the pore-throat limit for imbibition, whereas exponential relationships are discovered between permeability, clay content and the pore-throat limit for imbibition. This work provides an insight into the mechanism of oil displacement through the imbibition process by elucidating the impact of pore-throat size on such a process and, as a consequence, can be applied to screen the target formation and optimize the oil production process that will ultimately lead to an improvement of imbibition recovery rate.

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.