Jinyu Tang

Summary: Shale reservoirs are characterized by the presence of abundant multicomponent nanopores and microfractures that govern complex oil-water transport behaviors. This study aims to develop an analytical model for oil-water relative permeability in shale reservoirs that explicitly accounts for nanoconfinement effects and pore-shape variability. Unlike previous analytical models that assume circular pore geometries and simplified component structures, this work introduces a morphology-integrated relative permeability model that couples pore morphology, multicomponent characteristics, and interfacial phenomena to describe oil-water transport at the nanoscale. Building upon large-field scanning electron microscopy (SEM-Maps) analyses, the multicomponent nature and morphological diversity of shale pores were quantitatively characterized, forming the basis for constructing a multicomponent nanopore-scale model. A modified Hagen-Poiseuille (HP) equation was then developed to describe two-phase transport in nanopores and microfractures, incorporating pore-shape parameters, wall slip, surface wettability, and tortuosity. By integrating the single-pore models into the multicomponent nanopore-scale framework, a comprehensive relative permeability model for shale was established. The findings indicate that increasing total organic carbon content shifts the iso-permeability point leftward, reducing oil relative permeability while increasing water relative permeability. As the oil-water viscosity ratio rises, oil relative permeability significantly increases, whereas water relative permeability decreases slightly. The morphology of nanopores within shale exhibits substantial variability, ranging from elongated and elliptical to near-circular shapes. Notably, oil relative permeability declines as the aspect ratio of pores increases, while water relative permeability remains relatively stable. Deviation from circular geometry adversely affects oil mobility. Additionally, variations in pore size and contact angle control the contrasting behaviors of wetting and nonwetting phases. This study provides a novel theoretical framework that links experimentally observed shale pore morphology with analytical modeling of nanoconfined multiphase flow. The proposed model provides valuable insights for scaling microscopic analysis to macroscopic numerical simulations, thereby improving the predictive capability of shale reservoir performance models.

Summary: Long-distance propagation of foam is one key to deep gas mobility control for enhanced oil recovery and CO2 sequestration. It depends on two processes—convection of bubbles and foam generation at the displacement front. Prior studies with N2 foam show the existence of a critical threshold for foam generation in terms of a minimum pressure gradient ∇pgenmin or minimum total interstitial velocity vt,genmin, beyond which strong-foam generation is triggered. The same mechanism controls foam propagation. There are few data for ∇pgenmin or vt,genmin for CO2 foam. We extend previous studies to quantify ∇pgenmin and vt,genmin for CO2 foam generation and, for the first time, relate ∇pgenmin and vt,genmin to factors including injected quality (gas volume fraction in the fluids injected) fg, surfactant concentration Cs, and permeability K. In each experiment, steady pressure gradient ∇p is measured at fixed injection rate and quality, with total interstitial velocity vt increasing and then decreasing in a series of steps. The trigger for strong-foam generation features an abrupt jump in ∇p upon an increase in vt. In most cases, the data for ∇p as a function of vt identify three regimes, which are coarse foam with low ∇p, an abrupt jump in ∇p, and strong foam with high ∇p. The abrupt jump in ∇p upon foam generation confirms the existence of ∇pgenmin and vt,genmin for CO2 foam. We further show how ∇pgenmin and vt,genmin scale with fg, Cs, and K. Conditions that stabilize lamellae reduce the values of the thresholds: Both ∇pgenmin and vt,genmin increase with fg and decrease with increasing Cs or K. Specifically, ∇pgenmin scales with fg as (fg)2 and vt,genmin scales as (fg)4, and both ∇pgenmin and vt,genmin scale with Cs as (Cs)−0.4. The effect of K on the thresholds for foam generation is greater than the effects of fg and Cs. Our data in artificial consolidated cores show that ∇pgenmin scales with K as K−2 for CO2 foam, in comparison with K−1 for N2 foam in unconsolidated sand/bead packs. More data are needed to verify these correlations. It is encouraging that ∇pgenmin in the cores with K = 270 md or greater is less than 0.17 bar/m (~0.75 psi/ft), two to three orders of magnitude less than for N2 foam. Such low ∇pgenmin can be easily attainable throughout a formation. This suggests that limited ∇p deep in formations is much less of a restriction for long-distance propagation of CO2 foam than for N2 foam. Foam propagation could still be challenging in low-K reservoirs (∇pgenmin ~10 bar/m for K = 27 md). Nevertheless, formation heterogeneity and alternating slug injection of gas and liquid help foam generation and can reduce the values of ∇pgenmin. More research is needed to predict long-distance propagation of foam at low ∇p and vt.

Geothermal energy plays a crucial role in the large-scale deep decarbonisation process and the transition of energy structure in our country. Due to the complex reservoir environment of geothermal energy, characterised by low porosity and permeability, conventional fracturing methods struggle to create a complex network of fractures. Temporary plugging and diverting fracturing technology (TPDF) is a key technology to improve the efficiency of geothermal reservoir extraction. However, there is still a lack of knowledge about the migration and sealing law of temporary plugging agents in complex fractures. Therefore, in this study, two multiphase flow models of temporary plugging particle transport at the fracture slit and inside the complex fracture were established by using a Computational Fluid Dynamics (CFD)-Discrete Element Method (DEM) algorithm. The influence of fracturing fluid concentration, temperature, the concentration of temporary plugging particles, and particle size combinations on migration blocking in fractures was investigated. The simulation results indicate the following: High-viscosity fracturing fluid may cause plugging particles to adhere to each other to form clusters of plugging particles, reducing dispersion during transport and slowing down the velocity of the plugging particles. A particle concentration that is too high does not have a better temporary plugging effect. The use of different combinations of particle sizes is significantly better than using a single particle size, which is a key factor for the success of fracture plugging. The research findings are of great theoretical and practical significance for scaled-up, vibration-controlled fracturing technology in geothermal reservoirs.

Despite the promising results obtained from the utilization of interfacial-active additives in enhancing imbibition-based oil recovery from tight reservoirs, the predominant mechanisms governing this process remain inadequately understood. In this work, a meticulously designed workflow is implemented to conduct experiments and modeling focusing on imbibition tests performed on tight sandstone cores while utilizing surfactant and microemulsion. Our primary objective is to investigate the response of oil recovery to these additives and to develop a robust and reliable model that incorporates the intricate interactions, thereby elucidating the underlying mechanisms. Two imbibition fluids are designed, namely, surfactant and microemulsion. A comprehensive investigation is performed to analyze the physicochemical properties of these fluids, encompassing phase behavior, density, viscosity, and wettability alteration, with the aim of establishing fundamental knowledge in the field. Three imbibition tests are carried out to observe the response of oil production and optimize the experimental methodology. A numerical model is developed that fully couples the evolution of relative permeability and capillary pressure with the dynamic processes of emulsification, solubilization and molecular diffusion. The results demonstrate the crucial role of emulsification/solubilization in the imbibition process. Document Type: Original article Cited as: Li, Q., Wang, Y., Wei, B., Wang, L., Lu, J., Tang, J. Imbibition oil recovery from tight reservoir cores using microemulsion: Experiment and simulation. Capillarity, 2024, 10(2): 38-47. https://doi.org/10.46690/capi.2024.02.02