Polymer microspheres (PMs) are used as a new material to recover residual oil left in unswept oil areas after secondary recovery methods. The fact that the PMs plug the macropores causes the flow direction of the injection fluid to be transferred from macropores to micropores. In order to investigate the plugging and profile control mechanisms of PMs in reservoirs, four kinds of PMs with different particle sizes and four kinds of artificial cores with different permeability were selected for flooding tests, including plugging experiments and profile control experiments. The pore throat size distribution of cores was characterized by nuclear magnetic resonance (NMR) technology. The particle size distribution of PMs used in the experiment was characterized using a laser particle size analyzer. The results showed that there are six matching relationships existing simultaneously between pore throats and PMs based on theoretical analysis, which are completely plugging, single plugging, bridge plugging, smooth passing, deposition, and deformable passing. A key principle for optimizing PMs in profile control is that the particle size of the selected PMs can enter the high permeability layer well, but it is difficult for it to enter the low permeability layer. The results of this paper provide a theoretical basis for the optimal particle size of PMs during the oil field profile control process.

Experimental Study on Stress Sensitivity Considering Time Effect for Tight Gas Reservoirs

Continental shale oil fracturing dynamics are governed by interactions between hydraulic fractures and pre-existing natural fractures. This study establishes a fluid–solid coupling model using globally embedded cohesive elements to simulate fracture propagation in naturally fractured reservoirs. Key factors affecting fracture network complexity were quantified: (1) Weakly cemented natural fractures (bond strength coefficient <0.5) promote 23% higher fracture tortuosity compared to strongly cemented formations. (2) Optimal horizontal stress differentials (Δσ = 8–10 MPa) balance fracture length (increased by 35–40%) and branching complexity. (3) Injection rate elevation from 0.06 to 0.132 m³/min enhances the stimulated volume by 90% through improved fracture dimensions. The findings provide mechanistic insights for optimizing fracture network complexity in shale reservoirs.

The technology of radial-well-assisted hydraulic fracturing is applied in the stimulation of low-permeability hydrocarbon reservoirs where commercial production cannot be achieved by the conventional fracturing method. Here, a study on the reservoir stimulation effect and the fracture propagation pattern of radial-well-assisted deflagration fracturing was carried out. Based on smooth particle hydrodynamics (SPH), rock mechanics theory, and finite element theory, a numerical model of radial-well-assisted deflagration fracturing was established by integrating the JWL state equation. Research on the effects of the deflagration position, radial well azimuth and horizontal principal stress difference on the fracture propagation was carried out. The results show that the deflagration position, radial well azimuth and horizontal principal stress difference have significant effects on the fracture area in deflagration fracturing. The closer distance from the deflagration position is, the larger the radial well azimuth and the smaller the horizontal stress difference are, leading to a larger fracture area, which is conducive to reservoir stimulation. During fracturing, both shear fractures and tensile fractures are formed. The formation and conversion of shear fractures and tensile fractures are related to the deflagration position, radial well azimuth, horizontal principal stress difference, etc.

The development of natural fractures can easily lead to horizontal wellbore instability caused by stress concentration after drilling in shale reservoirs, which is not conducive to the safe development of shale gas, but how different natural fractures impact the horizontal wellbore stability in shale reservoirs is still unclear. Therefore, the effect of single straight, intersecting, and T-shaped natural fractures on horizontal wellbore stability in shale reservoirs is studied. Then a stress distribution model around the horizontal wellbore in shale reservoirs considering natural fractures is established based on linear elasticity theory, the stress distribution around horizontal wellbores in shale reservoirs with single straight, intersecting, and T-shaped natural fractures is acquired through the finite element method (FEM), and the effect of different natural fractures on horizontal wellbore stability is analyzed finally. Results show that among three types of natural fractures, intersecting natural fractures relieve the maximum stress of 1.676 × 10⁶Pa, and the horizontal wellbore is the most stable; T-shaped natural fractures have the largest effect on total stress around the horizontal wellbore, which is the largest and can reach 68.105 × 10⁶Pa, which makes the wellbore the most unstable; single straight natural fractures and intersecting natural fractures can cause the maximum circumferential stress on the wellbore wall respectively in the two directions of the maximum horizontal principal stress and the vertical principal stress, and wellbore wall is prone to compression and tensile failure respectively; circumferential stress and total stress around horizontal wellbore are the largest in the direction of the maximum horizontal principal stress, the wellbore is the most unstable. This work will be helpful for a more reliable assessment of borehole instability and benefit the drilling design in shale reservoirs with single straight, intersecting, and T-shaped natural fractures.

A radial well has a unique wellbore configuration. Fracture propagation in radial well deflagration fracturing is studied rarely. The mechanism of interaction between deflagration fractures, natural fractures, and micro-fractures is still unknown. Based on continuum mechanics, damage mechanics, and variational principles, a numerical model of fracture propagation in deflagration fracturing is established with the Hamilton principle and phase-field fracture theory. The effects of horizontal principal stress difference, natural fracture distribution, and micro-fractures around the wellbore on fracture propagation in deflagration fracturing are studied. First, when no natural fractures are developed around the radial well, fractures are initiated at both ends of the radial well. Second, when there are three natural fractures around the radial well, the created fractures have the morphology of shorter fractures in the middle and longer fractures on both sides under stress interference mechanisms. Third, a larger density of natural fractures causes obvious stress superposition, changes the initiation points of radial wells and fracture morphology, and increases fracture width and reservoir stimulation volume. Fourth, as the micro-fractures increase, their interference and induction effects on deflagration fractures are enhanced gradually, and the deflection angle of fractures increases by 38.7%. The study provides a reference for optimizing deflagration fracturing in a radial well.