Adequate effective reservoir characterization is important for effective development of oil and gas reservoirs. Further, the knowledge of formation properties such as permeability, porosity, water saturation etc. may be important for effective well completion design. This may be particularly true for Inflow Control Device (ICD) completion design, intelligent completion design, and horizontal and multilateral well designs. Also, effective reservoir management in an attempt to optimize the production and oil recovery often depends upon good dynamic reservoir characterization. Among all formation properties, permeability (or fluid conductivity) is often the most difficult to determine or predict, and has been a long-standing challenge specifically in the heterogeneous reservoirs having faults, fractures, Vugs or high conductive flow channels. The general perception is the rock with greater porosity usually correlates with greater permeability, which does not hold true in many cases. For example, a formation with small pore throat size may have highly interconnected pores, but these pores and pore channels are too small and the paths available are too restrictive for fluid movement, which substantially reduces the permeability.
Formation permeability can be directly determined using core plugs in the laboratory, by using a formation fluid tester in a wellbore, or determined with well tests by use of pressure-transient analysis. However, the measured permeability directly from these methods provides permeability at discrete points and has limitations in estimating the permeability continuously across the none-cored wells, particularly in the horizontal wellbore. Also, the amount of core available for direct permeability measurement is typically limited (due to the cost and logistics associated with core sampling), and permeability estimates usually are made by correlations, by use of wireline-log responses. Further, the permeability measured from these sources might have some uncertainty in estimating the permeability at actual reservoir conditions.
Many investigators have attempted to grasp the complexity of permeability function into a model with general applicability. Most of the models developed are empirical models based on the correlation between formation permeability, formation porosity and irreducible water saturation. These empirical models typically involve measuring porosity and irreducible water saturation of the core and developing mathematical models relating porosity and irreducible water saturation to permeability. In order to use this approach, it is desirable to obtain effective porosity, which is the portion of the porosity that is not isolated and is connected to the pore network and therefore can contribute to fluid flow, and irreducible water saturation. These parameters are not available directly from well logs. Instead, they are estimated from other well log data. However, porosity derived from well log data is not necessarily effective porosity, and methods for deriving irreducible water saturation often rely on effective porosity. Furthermore, empirical models developed for certain formations often perform poorly when used in other fields or formations.