Non-Destructive Core Analysis Using X-Ray Computed Tomography

Coshell, Lee; Scott, Joy Denise; Knights, A. M.; Evans, Brian; Hill, M.W.

doi:10.1071/eg991071

Cited by 6 publications

(1 citation statement)

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“…The core characterization was carried out considering the following information: a) core selection and porosity map determination by means of X-ray tomography [18][19][20][21] ; b) estimation of the permeability to a liquid; c) porosity and permeability variation with respect to effective stress; and d) capillary pressure. The core characterization was carried out considering the following information: a) core selection and porosity map determination by means of X-ray tomography [18][19][20][21] ; b) estimation of the permeability to a liquid; c) porosity and permeability variation with respect to effective stress; and d) capillary pressure.…”

Section: Porous Mediamentioning

confidence: 99%

Relative Permabilities of Gas-Condensate Fluids in Heterogeneous Porous Media

Moctezuma-Berthier¹,

V.²

2000

Proceedings of SPE International Petroleum Conference and Exhibition in Mexico

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractReservoir cores have complex porous structure and conventional approach to characterize two phase flows in the laboratory can be inadequate, especially in presence of fractured or vuggy porous media. An important problem is the determination of the relative permeabilities to the interpretation of two phase flow experiments. The relative permeability analysis for gas and condensate fluids presents special interest due to changes in fluids properties, like interfacial tension and viscosity due to compositional changes. In this way, relative permeability curves depend on the capillary number; thus the experimental conditions for the fluids and porous media must be carefully analyzed in order to get representative reservoir conditions. This work presents a methodology for the realization of laboratory representative studies of flow in heterogeneous cores flowing with gas and condensate equivalents fluids. The relative permeability curves are found fitting the oil production and pressure drop experimental data with a compositional simulator. This simulator was used to have a detailed behavior of the fluids during the experiment. Selection of the equivalent fluids was made plotting the derivative of the capillary number with respect to pressure vs. capillary number. We analyzed the curve for different mixtures and results compared with the reservoirs fluids curve. With this analysis, we got a pressure interval for the experiment and the required composition, the required to prepare a mixture which capillary number behavior was like reservoir fluids. In order to reproduce the detailed petrophysical model of the sample, the longitudinal porosity distribution was gotten from X-ray computerized tomography. In addition, the petrophysical porosity and effective permeability behavior of the sample for different confining pressures was done. This methodology was applied to fluids and samples from a carbonate fractured gas and condensate reservoir from Gulf of Mexico. It was possible to get the relative permeability curves using a binary mixture of C 1 -C 10 in a specific range of pressure, where the capillary number for both real and mixture was quite similar. The match between laboratory and simulation results was very good.

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