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.

No 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 limitation. 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 behavior 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 contribution. Thus, the main objectives are:to perform special core analyses on Berea outcrop core samples as a model of rock.to simulate fracture opening, by cutting these samples in such away to get different fracture apertures.to investigate the effect of dual porosity on the shape of capillary pressure curves, andto 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 clearly observed 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 actual naturally fractured reservoir (NFR) in Algeria. Tin Fouye Tabankort (TFT) reservoir is selected as a prototype of 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 test is 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 TFT reservoir. This study may also lead to the development of a laboratory technique for systematically determining the fracture intensity index. Background Multiphase flow of fluids through porous media can be related to 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 Kaumar1, most of 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. According to Reiss2, petrophysicists assume a straight-line relative permeability curves with a limit of zero to one for both saturation and relative permeability. If the fracture network geometry is not uniform, they assume 0.8 as the limit of water saturation instead of one for taking into account any residual oil in fractures.

This study presents a new concept for the use of non-Darcy flow characteristics in reservoir characterization, development, and well performance. More than 1,000 core samples are analyzed under unsteady-state flow conditions. A universal scale turbulent factor vs. permeability is developed on the basis of the reference base-line of turbulent flow through metallic porous media. This new scale is used to:Classify reservoirs in terms of permeability heterogeneity; and,Establish an iso-turbulence map for reservoir development by selecting adequate zones to drill new wells. In this paper, different applications for Algerian reservoirs are outlined and a new concept for the use of a turbulence factor is highlighted. Introduction This study develops characteristics related to fluid flow through porous media for a turbulent flow regime (high Reynolds number). It involves laboratory experimental analysis followed by numerical and analytical simulations. Six reservoirs are selected: the Upper Trias Shally Sand (TAGS/UTSS) of Hassi R'Mel; the Lower Trias Shally Sand (TAGI/LTSS) of Ourhoud and Rhourd el Khrouf; the Ordovicien of TFT; the Cenomanian Carbonate of Guerguet El Kihal South; and, the Cambrian of both Gassi and Agreb. Data related to these reservoirs include production and core description. The flow of helium under pressure blowdown conditions is performed on 1,600 core samples selected from the above defined reservoirs. In addition, artificial and homogeneous metallic porous media, used for permeameter and porosimeter calibrations, are analyzed in order to establish a base-line for turbulent flow through natural cores. Turbulence factor vs. permeability relationship is developed for each reservoir. A universal scale of these properties is established for improving reservoir characterization in terms of reservoir heterogeneity. Ini tially, analysis is done on the Hassi R'Mel (HR) and Rhourd El Khrouf (RKF) reservoirs(1). The analysis is then extended to additional reservoirs (Sandstone and Carbonates). Layers of the same reservoir are also characterized in order to validate the universal scale. The results show that this developed scale can be considered as a reliable tool for reservoir characterization. The universal scale was also used in the development of the TFT reservoir and to assist with well performance of the Hassi R'Mel field. Literature Review In this section, some ideas that have been developed in the area of non-Darcy flow characteristics are briefly presented. Darcy's pioneering experimental work(2) is well recognized as the key factor in predicting production performance of porous and permeable flow systems. However, in certain circumstances such as the turbulent flow, this law may lead to erroneous results. Forchheimer(3) demonstrated that the pressure gradient to sustain a high flow rate through a porous medium is higher than the one Darcy's equation would predict. As the flow rate increases, the deviation between pressure gradient and flow rate increases. Forchheimer attributed the excess gradient required to inertial flow resistance. As a result, he developed a quadratic form to relate the pressure gradient and fluid flow velocity.

Darcy's law applies only in the region of streamline flow, however when it concerns inertial or turbulent flow regime such as large production or injection rate in the vicinity of the wellbore, the turbulence effects affect considerably the cinematic charges and production rate due to the fact that the pressure gradient increases at a greater rate than does the flow rate. Forchheimer's publication in 1901 is commonly marked as the start of a general understanding that Darcy's law is not universally valid for porous flow. Since then non-Darcy flow has been in continuous investigation.