Relative Permeability in Dual Porosity Porous Media

Abstract

Reliable relative permeability data is an essential input parameter in reservoir engineering, most significantly in the area of reservoir simulation of dual porosity systems. However, measurements of relative permeability do not work well, because of laboratory limitations. Also, reservoir core samples are generally extracted from zones where induced or natural fractures are absent. Obviously, data obtained from these cores may not reflect the real behaviour of naturally fractured reservoirs. Because of this laboratory limitation, many commercial reservoir simulators neglect the effect of dual porosity on relative permeability, and implicitly assume that relative permeability is a straight line. This assumption in naturally fractured systems may lead to erroneous results. The purpose of this study is to rectify these shortcomings by laboratory experimental contributions. Thus, the main objectives are: (a) to perform special core analyses on Berea outcrop core samples as a model of rock; (b) to simulate fracture opening by cutting these samples in such a way as to get different fracture apertures; (c) to investigate the effect of dual porosity on the shape of capillary pressure curves; and (d) to evaluate the effect of fracture opening on both absolute and relative permeability. A good correlation between absolute permeability and fracture aperture is obtained. The effect of dual porosity is observed clearly on capillary pressure curves. Unsteady-state tests could not be used to measure relative permeability on these specially prepared core samples. This is due to the fact that fractures become the easiest pathway for water flow, which results in high residual oil saturation in the matrix. However, the centrifuge technique test is run with success because both matrix and fracture are subjected to the centrifuge field. These findings are extended to an actual naturally fractured reservoir (NFR) in Algeria. The Tin Fouye Tabankort (TFT) reservoir is selected as a prototype of an Algerian NFR. Availability of naturally fractured cores and published data are the principal reasons for this selection. A discussion of TFT natural fracture indicators is presented, including core observations, well test analysis, and borehole imager tools. Displacement tests are conducted on a full diameter core in order to solve the laboratory limitations, and to obtain representative data of relative permeability. These laboratory tests indicate the existence of a good correlation between permeability and fracture opening. The correlation is used to estimate the aperture of natural fractures in the TFT reservoir. This study may also lead to the development of a laboratory technique for determining systematically the fracture intensity index. Background Multiphase flow of fluids through porous media can be related to the relative permeability of each phase. These flow properties are the composite effect of several petrophysical parameters, including: pore geometry, wettability, fluid distribution, and saturation history. This concept of relative permeability is utilized extensively in reservoir engineering for understanding and predicting many physical phenomena that occur during reservoir exploitation. According to Rossen and Kaumar(1), most reservoir simulators neglect the effect of the dual porosity on relative permeability. However conventional fractured-reservoir simulators assume that straight-line relative permeability curves apply within the fracture pore space.

Numerical simulation of gas and water flow mechanism in hydraulically fractured shale gas reservoirs

“…Due the complex flow in shale gas reservoirs, gas desorption in the matrix, gas diffusion from the matrix to natural fractures, Darcy flow in natural fractures and non-Darcy flow in hydraulic fractures are considered in the simulation. In this study, the water and gas flow in shale matrix and fractures are described with two different sets relative permeability curves based on the previous study (Deghmoum et al, 2001;Shanley et al, 2004), as shown in Fig. 2.…”

“…Considering the fracturing water injected during the hydraulicfracturing treatment, the water-phase imbibition caused by the capillary pressure between water and gas phases is important in the gas production performance. Based on the empirical correlation (Deghmoum et al, 2001;Shanley et al, 2004), the capillary pressure curve used in the matrix is illustrated in Fig. 3.…”

Integrating Inertial Factor Obtained From Turbulent Gas Flow in Reservoir Characterization and Well Performance

“…The introduction of this law, i.e. the linearity between pressure gradient and flow rate, in petroleum industry is well recognized as the key factor in reservoir engineering (2) . However, in certain circumstances such as the turbulent flow, this law may lead to erroneous results.…”

How Can Horizontal Wells Help in Naturally Fractured Reservoir Characterization?

“…The upper VI-3 unit is overlain by the Gothlandian shale, which has uniform petrophysical properties and thickness. The lower VI-2 unit exhibits rapid changes in both thickness and facies where the depositional environment is mainly of glacial influence 5,6 .…”

“…To consider the effect of fracture on the flow of fluid through natural porous media for reliable data, it is recommended to perform permeability measurement on a full diameter that contains natural fractures 6 .…”