On the Relationship Between Formation Resistivity Factor and Porosity

Perez-Rosales, Candelario

doi:10.2118/10546-pa

Cited by 35 publications

(18 citation statements)

References 5 publications

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“…Furthermore, as described above, there are some other factors that may influence permeability. These include micropores [5], pore dead-ends or blind pores [3,8], symmetrybypassed pores [34], and pore body-pore throat constrictions [7]. Since no means is available at present for determining the fractions of all such pore geometrical features, only micropores is considered and can be derived from mercury intrusion capillary pressure (MICP) measurements.…”

Section: Permeability Equation For Fractal Porous Mediamentioning

confidence: 99%

A Study of Sandstone Permeability Anisotropy Through Fractal Concept

Sumantri¹

2018

AJSET

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Most correlation equations of rock permeability are usually based on the Euclidean geometry concept. Pore geometry and structure of most porous rocks are very complex, therefore non-Euclidean geometry concept, e.g. fractal theory, is needed to handle such a complexity. This paper presents a new equation for sandstone permeability involving other properties and fractal dimensions of pore space and surface. The equation is derived by combining Newton's Law of viscosity, Darcy equation, and fractal geometry concept. It is shown that parameters such as tortuosity, internal surface area, and shape factor can be replaced by fractal dimensions. As natural porous media are mostly anisotropic, this study enables us to identify factors that affect the anisotropy. Eighteen sandstone samples with porosity and permeability range from 21 to 37% and 2.76 to 3,644 millidarcies, were employed in this study. The pore space and surface fractal dimensions for each orthogonal direction for each sample was determined by box counting method. The results of this study demonstrate that calculated directional permeability of the high permeability samples is very close to the measured one after corrections were made for pore sizes of less than one micron. This finding suggests that micropores of the samples may be a major factor not contributing to fluid flow. For the low and medium permeability samples, however, an additional pore geometrical correction is needed. The additional correction factor is considerably different for different directions of fluid flow, indicating that the anisotropy is due to the difference in directional pore structural characteristics.

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Section: Permeability Equation For Fractal Porous Mediamentioning

confidence: 99%

A Study of Sandstone Permeability Anisotropy Through Fractal Concept

Sumantri¹

2018

AJSET

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“…[1][2][3][4][5][6][7][8][9] Previous work Previous theoretical and experimental works 1,2 on the flow of electric current through fractured rocks have shown that the relationship between formation resistivity factor, F R , and total porosity, φ tot , is of the form F R = Cφ tot -m (1) where φ tot refers to total interconnected or effective porosity. This is due to the huge reserves contributed by naturally fractured reservoirs, and to the need of having reliable techniques for their characterization.…”

Section: Introductionmentioning

confidence: 99%

“…From the Maxwell equation and through some generalizations 1,2,8,9 Eq. From the Maxwell equation and through some generalizations 1,2,8,9 Eq.…”

Section: Introductionmentioning

confidence: 99%

Simplified Method for Characterizing Fractured Carbonate Media

Perez-Rosales

Luna

Medina-GonzC!lez

2006

International Oil Conference and Exhibition in Mexico

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractQuantitative characterization of fractured carbonate rocks is of interest for several reasons: first, because naturally fractured carbonate oil reservoirs are among the most important in the world; second, because fluid flow through the pore system depends on the internal geometry of the rock; and, third, because numerical simulation of such reservoirs require reliable values of matrix porosity, fracture porosity, and block size.Naturally fractured reservoirs are complex systems whose flow properties are not well understood. From the fluid transport viewpoint, fractured carbonate reservoirs can be considered to consist of two basic components: matrix blocks and fracture network. Matrix blocks are characterized by their low fluid conductivity, and their main function is to storage fluids, whereas the fracture network is composed of highly conducting channels. This paper describes a simplified method for determining matrix and fracture porosities of carbonate media, as well as block size. The method makes use of total interconnected porosity and formation resistivity factor data. Of fundamental importance to the method is the fact that, in the case of fractured carbonate media saturated with a conducting fluid, the conductivity of the fracture network is much greater than that of the matrix blocks, so that, for practical purposes, the latter can be considered as negligible.For illustration purposes, an application to a real case is presented. To this end, use is made of two procedures, one for fracture porosity and the other for block size. A step by step description is given for each procedure. It is considered that the simplicity of the procedures make the methodology an attractive tool for the characterization of carbonate fractured reservoirs.

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“…Fundamental to this work is a theoretical development due to Maxwell 4 appeared at the end of the nineteenth century, from which a formula relating formation resistivity factor and porosity of suspensions of spheres can be obtained. Subsequent developments [5][6][7] have lead to a general equation applicable not only to dispersive but also to continuous systems (e.g. rocks), and of which the Archie equation is a particular case.…”

Section: Introductionmentioning

confidence: 99%

Naturally Fractured Reservoirs: How To Estimate Secondary Porosity

Perez-Rosales

Luna

2005

SPE Latin American and Caribbean Petroleum Engineering Conference

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractNaturally fractured rocks are very complex systems. Due to their morphological complexity, numerical simulation of naturally fractured reservoirs is lacking wholly reliable procedures for determining secondary porosity. The use of incorrect values for this variable may lead to significant deviations when simulating secondary or enhanced oil recovery processes. In this work, a procedure is presented for estimating secondary porosity. The proposed procedure is based on new ways of analyzing well log data of total porosity and formation resistivity factor. It takes into account the fact that fractures behave as flow channels whose conductivity is much greater than that of the matrix. Fundamental to the procedure is a precise physical interpretation of the parameters appearing in the generalized Archie equation, and an adequate use of the concept of rock tortuosity. This concept is used as a classifying tool to identify: (1) useful data for estimating secondary porosity, (2) zones containing conductive material, and (3) very low conductivity compact zones. Two application examples are presented to illustrate the operational aspects of the procedure.

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On the Relationship Between Formation Resistivity Factor and Porosity

Cited by 35 publications

References 5 publications

A Study of Sandstone Permeability Anisotropy Through Fractal Concept

A Study of Sandstone Permeability Anisotropy Through Fractal Concept

Simplified Method for Characterizing Fractured Carbonate Media

Naturally Fractured Reservoirs: How To Estimate Secondary Porosity

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