Numerical Simulation of Fluid Flow in Carbonate Rocks Based on Digital Rock Technology

• Published in: Energies (Basel) 2022-05, Vol.15 (10), p.3748
• Main Authors: Hu, Yong, Wei, Jiong, Li, Tao, Zhu, Weiwei, Gong, Wenbo, Hui, Dong, Wang, Moran
• Format: Article
• Language: English
• Subjects: Alliances; carbonate rock; Carbonate rocks; Digital imaging; digital rock; Finite element analysis; Flow velocity; Fluid dynamics; Fluid flow; Fractures; Gas pressure; Heterogeneity; Hydrocarbons; Image processing; Mathematical models; Medical imaging; Membrane permeability; Multiphase flow; Natural gas; NMR; Nuclear magnetic resonance; numerical analysis; Numerical models; Outlet flow; Permeability; Pore pressure; Pores; pore–fracture–vug; Porosity; Preferential flow; Pressure; Pressure distribution; Pressure effects; Reservoirs; Simulation; Single-phase flow; Technology; Trace elements; Two phase flow; Vapor phases; Water velocity
• ISSN: 1996-1073; 1996-1073
• DOI: 10.3390/en15103748

Strong heterogeneity, low matrix permeability, and complex oil–water interaction make the fluid flow in carbonate rocks extremely complicated. In this study, we quantitatively characterize and simulate single-phase and multiphase flows with multiscale pore–vug–fracture structures involved in the carbonate reservoir developments. The main studies and conclusions include: (i) The CT technology is utilized to characterize the pores, fractures, and vugs of carbonate cores at multiple scales. It is found that even if the CT resolution reaches 0.5 μm, the pores of the core are still unconnected as a network, indicating that the carbonate matrix is particularly tight. The existence of fractures can increase the effective permeability, and even poorly connected fractures can significantly increase the permeability because it reduces the flow distance through the less permeable matrix. (ii) A numerical model of low-porosity strongly heterogeneous carbonate rocks was constructed based on digital image processing. Simulations of single-phase fluid flow under reservoir conditions were conducted, and the effects of surrounding pressure, pore pressure, and core size on the single-phase flow were investigated. Due to the strong heterogeneity of carbonate rocks, the pores, vugs, and fractures cause local preferential flow and disturbance within the core, which significantly affects the fluid flow path and the pressure distribution in the core. The overall permeability is a composite representation of the permeability of numerous microelements in the specimen. Permeability increases with an increasing pore pressure, and it decreases with increasing circumferential pressure. (iii) The gas–water two-phase flow model of a low-porosity strongly heterogeneous carbonate rock was established based on digital image processing. The variation law of the two-phase outlet flow velocity with the inlet gas pressure and the movement law of the two-phase interface of carbonate rock samples were obtained. Under certain surrounding pressure, the outlet gas velocity is larger than the outlet water velocity; with the increase of the inlet gas pressure, the pore space occupied by the gas phase in the rock becomes larger. With the increase of the surrounding pressure, the velocities of both outlet gas and water decrease. As the sample size decreases, the velocities of both outlet gas and water increase.