This paper quantifies the influence of petrophysical and fluid properties on array-induction resistivity measurements acquired in the presence of oil-base mud (OBM) filtrate invasion. To simulate OBM-filtrate invasion, we consider a simple two-component formulation for the oil phase (OBM and reservoir oil) wherein the components are first-contact miscible. Simulations also include the presence of irreducible, capillary-bound, and movable water. The dynamic process of OBM invasion causes the component concentrations to vary with space and time. In addition, the relative mobility of the oil phase varies during the process of invasion given that oil viscosity and oil density are both dependent on component concentrations. This behavior in turn affects the spatial distribution of electrical resistivity and, consequently, the borehole array-induction measurements.
We use an implicit pressure, explicit concentration (IMPEC) reservoir simulator with two-component formation fluids to simulate the invasion process in axi-symmetric rock formations penetrated by a vertical well. The invasion rate is volume averaged and depends on both mud and formation properties. Simulations of the process of OBM-filtrate invasion yield two dimensional spatial distributions of water and oil saturation that are transformed into spatial distributions of electrical resistivity using Archie?s or Waxman-Smits? formulations. Subsequently, we simulate array induction measurements with a numerical mode matching method.
Simulation of induction measurements in the presence of OBM are compared against the corresponding measurements acquired in the presence of water-base mud (WBM). This helps us to contrast the effect of the two different mud-filtrate invasion processes using field measurements acquired in a deepwater Gulf-of-Mexico reservoir.
We perform sensitivity analysis that includes different values of formation porosity-permeability, movable water zone, relative permeability, mud-filtrate invasion rates, and fluid viscosity to quantify the effect of oilbase mud-filtrate invasion on array-induction logs. In addition, we quantify the effect of changes of rock wettability due to OBM invasion on field measurements. The combined simulation of OBM filtrate invasion and array-induction logs provides reliable estimates of water saturation to improve the assessment of in-place hydrocarbon reserves.
The array-induction imager tool (AIT*) is widely used to measure formation resistivity in the presence of OBM. Resistivity measurements remain influenced by the process of mud-filtrate invasion that takes place under overbalanced drilling conditions. In the case of oil-base muds, invading mud-filtrate is miscible with formation oil. Oil-base mud causes changes in fluid density and fluid viscosity, thereby altering the apparent oil phase mobility in the near-wellbore region. The fluid saturation front in the near-wellbore region varies with time due to invasion. In addition, the saturation front can be altered due to variations of oil-phase mobility. Thus, it becomes imperative to accurately model the effect of OBM on the invasion process and, subsequently, on AIT measurements acquired some time after the onset of invasion.
Oil-base muds contain a mixture of oil, water, and surfactants necessary to maintain the oil-water mixture as an emulsion (Bourgoyne Jr et al., 1986.; La Vigne et al., 1997), in which oil is the continuous phase and encapsulates the water (Proett et al. 2002).