--> Permeability and Tortuosity Variations in Naturally Fractured Carbonate Reservoirs

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Permeability and Tortuosity Variations in Naturally Fractured Carbonate Reservoirs

Abstract

Natural fractures provide preferential pathways for fluids in otherwise low porosity hydrocarbon reservoirs. These fractures are usually lined or filled with mineral cements, formed from the crystallization of minerals in the fracture pores. The presence of mineral cements can adversely affect the quality of the reservoir. Cementation along the fracture reduces hydraulic fracture aperture and fracture porosity and results in more tortuous flow paths. The presence of cements causes a decrease in the absolute permeability of the fluids; however, the influence of cements on the relative permeability of fluids is not explicit. We study the influence of partial cementation and resulting roughness on flow in the naturally fractured Niobrara and Monterey Formations. We compare the variation of permeability and relative permeability in partially cemented fractures sampled from a Niobrara outcrop and core. We also compare permeability and tortuosity variation in sampled outcrop fractures from the Niobrara and Monterey Formations. Fracture geometries were acquired from x-ray microtomography (XMT) scans. The permeability and tortuosity of the fracture (pore) space were determined from simulations of fluid flow through these geometries with impermeable fracture walls. A combination of the level-set-method-based progressive-quasistatic (LSMPQS) algorithm and lattice Boltzmann simulation were used to characterize the capillary dominated properties and the relative permeability of the naturally cemented fractures from the studied Formations. The influence of digitally increased cementation on the fracture permeability and tortuosity of the pore space were also investigated. The tortuosity and capillary pressure of the pore space both increase with increasing digital cement thickness. While this behavior is qualitatively similar to the effect of pore cementation on fluid flow through the matrix of sandstones, we see a more abrupt behavior in the partially cemented carbonate Formations studied in this work. Relative permeability of flow within the fracture is not only a function of water saturation but also of the degree of fracture cementation and fracture cement geometry which are in part controlled by depth and fracture cement mineral composition among other reservoir-specific parameters.