Based on rock samples of tight oil reservoirs in the buried hills of North China, conventional gas flooding and high-speed centrifugal experiments at different pressures were carried out. Combined with nuclear magnetic resonance experiments, an evaluation method of oil production potential in fractured porous media was established to quantitatively study the gas flooding potential of target reservoirs. Results indicated that the “gas fingering phenomenon” is serious in conventional gas flooding experiments of fractured cores even under low pressures because of fractures. With an increase in flooding pressure, the changes of T₂ (T₂ relaxation time) spectrum and displacement percentage are relatively small, which means that the displacement efficiency has not been improved significantly (the flooding pressure for these three cores increased from 0.014 MPa to 2.6 MPa, with an average increase in displacement percentage of 6.3%). High-speed centrifugation can realize “homogeneous displacement” of the cores and overcome the influence of gas channeling. With an increase in the displacement pressure, the T₂ spectrum and percentage of displaced oil varied obviously, and the displacement efficiency improved greatly (the flooding pressure for these three cores increases from 0.014 MPa to 2.6 MPa, with an average percentage of displaced oil being increased to 16.16%). Using the method of this study, 13 cores of the target reservoir were evaluated for gas flooding potential. The percentage of available pores in the target reservoir ranges from 17.64% to 58.54%, with an average of 33.84%. Movable fluid controlled by microthroats in the reservoirs larger than 0.1 mD is about 20%, while that in the reservoirs smaller than 0.1 mD is about 5%. This study indicates that the development of fractures and microfractures controls the physical properties and fluid productivity of reservoirs.

Rock physical evolution and microscopic flow mechanism of massive energy replenishment in tight oil reservoirs

The precise characterization of a tight glutenite reservoir’s microscopic pore structure is essential for its efficient development. However, it is difficult to accurately evaluate using a single method, and its microscopic heterogeneity is not fully understood. In this study, a combination of X-ray diffraction, casting thin section observations, scanning electron microscopy, high-pressure mercury injection, constant-speed mercury injection, X-ray computed tomography, and the advanced mathematical algorithms in the AVIZO 8.0 visualization software was used to construct the three-dimensional digital core of a glutenite reservoir at the study site, and the parameters of the pore network model were extracted. The overall microscopic pore structure characteristics were quantitatively investigated from multiple scales. Based on this, the mineral quantitative evaluation system (QEMSCAN) examined the microscopic heterogeneity of the glutenite reservoir and its impact on seepage. The results show that the glutenite reservoir in the study block can be classified into three categories based on lithology and capillary pressure curve characteristics. The type I reservoir samples have large and wide pore throats, low threshold pressure, and high reservoir quality; type II reservoir samples are characterized by medium-sized pore throat, medium threshold pressure, and moderate reservoir quality; and the small and narrow pore throat, high threshold pressure, and poor reservoir quality are characteristics of type III reservoir samples. The various pore throat types and mineral distributions are due to the differences in dissolution, compaction, and cementation. The continuous sheet pores have good connectivity, which is related to the interconnection of primary intergranular pores and strip fractures, while the connectivity of isolated pores is significantly poor, which is related to the development of intragranular dissolved pores and intercrystalline pores. This suggests the deterioration of physical properties and pore throat connectivity, reduced average pore radius, and decreased pore sorting as decreasing permeability. The tight glutenite pores range in size from 5 nm to 80 μm and primarily feature Gaussian and bimodal distribution patterns, and submicron–micron pores contribute more to seepage. The effective pores were found to be attributed to the slowing effect of abnormally high pressure on the vertical stress, and the protective effect was positively correlated with the high-pressure strength. Notably, there is strong microscopic heterogeneity in the distribution of the reservoir matrix minerals and the pore throat size. As a result, the injected fluid easily flows along the preferential seepage channel with pore development and connectivity. This study provides new insights into the exploration and development of similar tight reservoirs.

Combining NMR, high-speed centrifugal experiment, high pressure mercury injection and physical simulation experiment technologies, a new quantitative analysis method of oil occurrences in tight reservoir is put forward and applied to two tight oil blocks. Research shows that percentage of free oil is low (about 18%) in tight reservoir, while adsorbed oil is high (about 43%). There is a positive correlation between percentage of free oil and permeability; Free oil in reservoirs greater than 0.1mD are approximately 26% and 35% in block A and B respectively, while in reservoirs less than 0.1mD are only about 12% and 17%. Free oil content controlled by micron-throats is low (only about 4% and 5% in block A and B respectively). Free oil is mainly controlled by Nano-throats. The amount of adsorbed oil on surface of larger pore-throats is the same as amount in small pore-throat in block A reservoir, while adsorbed oil in block B mainly occurs in small pore-throats. Amount of adsorbed oil on surface of larger pore-throat in block A reservoir greater than 0.1mD is lower than reservoir less than 0.1mD, while occurrence law of adsorbed oil in small pore-throat is opposite.

In order to identify and evaluate reservoir wettability, so as to select suitable mining methods to improve oil recovery, wettability evaluation through one-dimensional (1D) and two-dimensional (2D) nuclear magnetic resonance (NMR) technology combined with physical simulation experiments was carried out in this study, and the feasibility of the experimental method was verified by contact Angle method. According to the principle of hydrophilic inorganic content and hydrophobic organic content of shale, the wettability can be evaluated through vacuum self-imbibition oil and self-imbibition water physical simulation experiments combined with 1D NMR technology, that is, total water absorption can be considered as inorganic content, organic content can be obtained by subtracting total water absorption from total oil absorption, and adsorbed oil content can be obtained by subtracting pore volume from total oil absorption. In addition to the wettability measurement by contact Angle method to verify the experimental method, the occurrence ratio of adsorbed oil can also be verified twice by 2D NMR spectrum. The results show that the error between the proportion of adsorbed oil measured by 2D NMR spectrum and that measured by self-imbibition method is within 4%. In the saturated oil-bound water state, the bound water is within the relaxation interval of 1<T₁<10 ms and 1210 ms and T₂>10 ms. And the relaxation time of aqueous phase moved to the right compared with that in the saturated water state, the interaction force between water and the pore wall was weakened, showing the characteristics of free fluid, and the rock sample became oil-wet, which was consistent with the wettability results measured by contact Angle. Therefore, the wettability of rock samples can be evaluated by 1D NMR technique combined with vacuum imbibition method, or by analyzing the changes of NMR spectra of aqueous phase in completely saturated water and saturated oil-bound water.