Pore-Scale Simulation of Particle Flooding for Enhancing Oil Recovery

Thermo-/pH-Dual-Sensitive PEG/PAMAM Nanogel: Reaction Dynamics and Plugging Application of CO2 Channeling

Smart hydrogels, owing to their exceptional viscoelastic and deformable capacity in response to environmental stimulation involving temperature and pH, have been successfully applied in oilfields for purposes such as water and/or gas shutoff treatments. However, the CO₂ breakthrough problem in low permeability reservoirs has not been well solved. In this work, a rheological method-based Avrami dynamics model and Dickinson dynamics model were employed to investigate the dynamic gelation process of thermo-/pH-dual-sensitive PEG/PAMAM nanogels to further our understanding of the microstructure of their gelation and pertinence plugging application. Plugging experiments were performed by alternating injections of CO₂ and hydrogel solution in a slug type on three fractured low permeability cores with a backpressure of 13 MPa. The nanogels presented a secondary growth pattern from three to one dimension from micrometer to nanometer size with a morphological transformation from a sphere to an irregular ellipsoid or disk shape. The phase transition temperature was 50 °C, and the phase transition pH was 10. If both or either were below these values, the hydrogel swelled; otherwise, it shrank. Plugging results show that the plugging efficiency was higher than 99%. The maximum breakthrough pressure was 19.93 MPa, and the corresponding residual pressure remained 17.64 MPa for a 10 mD core, exhibiting great plugging performance and high residual resistance after being broken through by CO₂.

Method to Generate Random Element Equivalent Core Models Based on the NMR T 2 Spectrum for Waterflooding in Tight Sandstone

Numerical simulation based on the widely used homogeneous equivalent core model can solve the problem of high cost and long duration of coreflooding experiments. However, using the homogeneous equivalent core model, it is difficult to reflect the characteristics of the core interior during waterflooding. In this paper, we provide a method to generate random element equivalent core models based on the nuclear magnetic resonance (NMR) T ₂ spectrum, and it can divide permeability regions by granularity. The permeability calculation formula derived from the complementary correlation principle ensures that most areas of the core satisfy the correlation between permeability and T ₂ relaxation time. Moreover, the generation method can guarantee that the random element equivalent core model is consistent with the homogeneous equivalent core model in terms of the geometric mean of permeability. The simulation results show that the high-resolution random element equivalent core model can better simulate microcosmic fingering inside the core during waterflooding. Nevertheless, the proposed method has some limitations emanating from the demarcation criteria and the porosity assumption. Furthermore, the generation method is expected to be extended to simulate enhanced oil recovery (EOR) mechanisms on the core scale after waterflooding.

Effect of Viscosity Action and Capillarity on Pore-Scale Oil–Water Flowing Behaviors in a Low-Permeability Sandstone Waterflood

Water flooding technology is an important measure to enhance oil recovery in oilfields. Understanding the pore-scale flow mechanism in the water flooding process is of great significance for the optimization of water flooding development schemes. Viscous action and capillarity are crucial factors in the determination of the oil recovery rate of water flooding. In this paper, a direct numerical simulation (DNS) method based on a Navier–Stokes equation and a volume of fluid (VOF) method is employed to investigate the dynamic behavior of the oil–water flow in the pore structure of a low-permeability sandstone reservoir in depth, and the influencing mechanism of viscous action and capillarity on the oil–water flow is explored. The results show that the inhomogeneity variation of viscous action resulted from the viscosity difference of oil and water, and the complex pore-scale oil–water two-phase flow dynamic behaviors exhibited by capillarity play a decisive role in determining the spatial sweep region and the final oil recovery rate. The larger the viscosity ratio is, the stronger the dynamic inhomogeneity will be as the displacement process proceeds, and the greater the difference in distribution of the volumetric flow rate in different channels, which will lead to the formation of a growing viscous fingering phenomenon, thus lowering the oil recovery rate. Under the same viscosity ratio, the absolute viscosity of the oil and water will also have an essential impact on the oil recovery rate by adjusting the relative importance between viscous action and capillarity. Capillarity is the direct cause of the rapid change of the flow velocity, the flow path diversion, and the formation of residual oil in the pore space. Furthermore, influenced by the wettability of the channel and the pore structure’s characteristics, the pore-scale behaviors of capillary force—including the capillary barrier induced by the abrupt change of pore channel positions, the inhibiting effect of capillary imbibition on the flow of parallel channels, and the blockage effect induced by the newly formed oil–water interface—play a vital role in determining the pore-scale oil–water flow dynamics, and influence the final oil recovery rate of the water flooding.