Experimental study on production characteristics and enhanced oil recovery during imbibition and huff-n-puff injection in shale reservoir

In shale oil reservoirs, nano-scale pores and micro-scale fractures serve as the primary fluid storage and migration space, while the associated flow mechanism remains vague and is hard to understand. In this research, a three-dimensional (3D) reconstruction of the shale core and micro-pore structure description technique is established; digital core technology for shale reservoirs was developed using X-ray computed tomography (X-CT), scanning electron microscope (SEM) and a focused ion beam scanning electron microscope (FIB-SEM). Microscopic oil–water two-phase flow is mimicked using the lattice Boltzmann method (LBM), a well-acknowledged approach to exploring nanoconfined fluid dynamics. In addition, coupled with digital cores, the flow characteristics of shale reservoirs are characterized. The total porosities of bedding fractures in shale and lamellar shale are 2.042% and 1.085%, respectively. The single-phase oil flow inside bedding fractures follows Darcy’s linear flow principle. This work can deepen the understanding of the microscopic flow characteristics of continental shale reservoirs and provide a reference for similar problems that may be encountered.

Injectability of the polymer solution is a very important factor that determines the effectiveness of polymer flooding for enhanced oil recovery. Here, the medium and low permeability oil reservoir was taken as a research object, and effects of relative molecular weight, concentration and core permeability on the flow and injection performance of a partially hydrolyzed polyacrylamide (HPAM) solution with and without anionic-nonionic surfactant (ANS) were studied by indoor outcrop core physical model experiments. It was found that the influence of HPAM concentration on the flow performance was related to the core permeability. When the core permeability was lower than 59 mD, the resistance factor and residual resistance factor of HPAM increased with increasing the concentration. High molecular weight and low core permeability were not conducive to the injectability of HPAM solutions. The addition of ANS was beneficial in enhancing the injectability of HPAM solution by reducing the critical value of injectability of HPAM solution, which was elucidated by the Hall curve derivative method. In the presence of ANS, the flow pressure gradient and the residual resistance factor of the HPAM solution decreased. It is believed that the injectability of HPAM solution improved by ANS in the medium and low permeability reservoirs can be attributed to decrease in fluid viscosity and competitive adsorption on the surface of porous media. The study provides a new idea and theoretical basis for improving the injectability of an HPAM solution and the application of polymer flooding and a polymer/surfactant binary flooding system in medium and low permeability reservoirs.

The proppant accumulation form in fractures is related to the formation conductivity after fracture closure, also closely related to the production rate of oil/gas wells. In order to investigate the influence of proppant physical properties on sand accumulation in fractures, a particle–fluid coupling flow model is established based on the Euler two-fluid model. Geometric parameters of a fracture in tight oil wells are approximately scaled in equal proportion as the physical model, which is solved by the finite volume method. And the model accuracy is verified by comparing with the physical experimental simulation in the literature. Results show that the higher proppant concentration corresponds to the faster particle sedimentation rate, and the greater sand embankment accumulation as well. However, the fluid viscosity will increase, inhibiting proppant migration to the deep part of the fracture. Reducing proppant density and particle size will enhance the fluidization ability of particles, which is conducive to the migration to the deep fracture at the initial stage of pumping. But, it is not beneficial to have a desirable accumulation state in the middle and later pumping stage, so it is difficult to obtain a higher comprehensive equilibrium height.

Shale reservoirs have complex mineral compositions and are rich in micro-scale pores. It is of great scientific and engineering significance to explore the mechanism of external fluids on the pore throat structure of shale. In this paper, pure carbonaceous shale is taken as the research object, and the mechanism of the influence of slip water and reflux fluid on the pore throat structure is analyzed by using nuclear magnetic resonance (NMR) technology. Then, the sensitivity of different types of shale to external fluids is comparatively analyzed and summarized. The results show that (1) the oil slick has a certain effect on the total porosity of different types of shale. The rate of change is shown as carbonaceous shale (− 7.1%) > pure shale (− 1.6%). (b) For slickwater, the average reduction of macro- and micro/nanopores in carbonaceous shale is 90.0% and 5.0%, respectively, while the average reduction of macro- and mesopores in pure shale is 17.7% and 6.8%, respectively. (c) Total porosity of different shale types is insensitive to refluxing fluids. The average increase in macro-, meso-, and small pores of carbonaceous shale is 31.8%, 23.6%, and 20.2%, respectively; the average increase in macro- and small pores of pure shale is 17.1%.