Porous media fracture permeability

Investigations to determine the leak-off control mechanisms of foam have shown (26—29) that the effective permeability of a porous medium is greatly reduced in the presence of foam. Some basic assumptions were used during the testing to determine the leak-off control mechanisms of foamed fracturing fluids. The first assumption was that the liquid or continuous phase moves freely, and permeability reduction is a function of the liquid saturation. The other assumption was that the gas or discontinuous phase flows only by rupture and reformation of the foam film. The resistance of foam to flow through porous media is a function of the stability of the foam. 

Foamed Matrix Acidizing. Matrix addizing is a stimulation treatment used to remove damage near the wellbore without deating a fracture. The process involves the injection of a reactive fluid into the porous medium at a pressure below the fracturing pressure. The fluid dissolves some of the porous medium and consequently increases its permeability. 

A rock sample is considered with an initial permeability assumed to be lO m, both in the porous medium and in the element that will contain the fracture. Capillary pressure to start desaturation (air entry value) in the porous medium is assumed to be 0.3 MPa. 

Importantly, fracture permeabilities may either reduce or increase, in surprising ways, depending on the paths of stress or chemical potential. We illustrate this behaviour through observations during flow-through tests on samples of varied rock types. These include a fractured porous medium (Berea sandstone), and fractures in both silicic (Arkansas novaculite) [Polak et al., 2003 Yasuhara et al., 2004] and carbonate rocks (Bellefonte Limestone) [Polak et al., 2(X)4]. 

Permeability Tensor A study by Long et al. (1982) suggested that rock mass behaves more like a porous medium if many fractures make a sufficient number of flow paths. Using a modified form of Oda s crack tensor theory (Oda 1986), the permeability of the homogenized material is given by ... 

Two types of reservoirs, each with different permeability, are found within the petroliferous bed of the fields in the Krasnodar Petroliferous Region. A number of laboratory models were therefore prepared to reproduce these permeability differences. Models using sand as porous medium (porosity-type models) simulated the reservoirs of the first type. The range of permeability of this medium corresponded to that of the actual reservoirs of the same type. Models characterized by fracture-type porosity (fracture-type models), were used to represent the second type of the reservoir. Again, the permeability characteristics of the medium used in the latter type models were similar to those of the real reservoirs. 

Rocks are nommiform in terms of their permeability. In this connection in them are identified areas with relatively high permeability, i.e., channels, and with low permeability, i.e., blocks, which could be considered impermeable. In loose porous deposits the size of impermeable particles or their blocks is small and comparable with permeable channels in volume, so their effect is disregarded. Contrary to this, in fractured massive rocks impermeable blocks take most of the volume and actually control the nature of the mass transfer. In most fractured-porous rocks the mechanism of mass transfer depends on the ratio of blocks and permeable channel volumes - fractures separating them. Because of this in recent times the structure of enclosing rocks is ever more often interpreted as mosaic heterogeneous bloc structure or as a medium with double capacity. The idea of such a structure is illustrated in Figure 2.8, b. 

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