Mayank Malik

Fluid Density and Viscosity Effects on Borehole Resistivity Measurements Acquired in the Presence of Oil-Based Mud and Emulsified Surfactants

We quantify the influence of oil-base mud-filtrate invasion and formation fluid properties on the spatial distribution of fluid saturation and electrical resistivity in the near-wellbore region. The objective is to appraise the sensitivity of borehole resistivity measurements to the spatial distribution of fluid saturation resulting from the compositional mixing of oil-base mud (OBM) and in-situ hydrocarbons. First, we consider a simple two-component formulation for the oil phase (OBM and reservoir oil) wherein the components are first-contact miscible. A second approach consists of adding water and surfactant to a multi-component OBM invading a formation saturated with multiple hydrocarbon components. Simulations also include presence of irreducible, capillary-bound, and movable water. The dynamic process of OBM invasion causes component concentrations to vary with space and time. In addition, the relative mobility of the oil phase varies during the process of invasion because oil viscosity and oil density are both dependent on component concentrations. Presence of surfactants in the OBM is simulated with a commercial adaptive-implicit compositional formulation that models the flow of three-phase multi-component fluids in porous media. Simulations of the process of OBM invasion yield two-dimensional spatial distributions of water and oil saturation that are transformed into spatial distributions of electrical resistivity. Subsequently, we simulate the corresponding array-induction measurements assuming axialsymmetric variations of electrical resistivity. We perform sensitivity analyses on field measurements acquired in a well that penetrates a clastic formation and that includes different values of density and viscosity for mudfiltrate and formation hydrocarbon. These analyses provide evidence of the presence of a high-resistivity region near the borehole wall followed by a low-resistivity annulus close to the non-invaded resistivity region. Such an abnormal annulus is predominantly due to high viscosity contrasts between mudfiltrate and formation oil. The combined simulation of invasion and array-induction logs in the presence of OBM invasion provides a more reliable estimate of water saturation, which, in turn, improves the assessment of in-place hydrocarbon reserves. Introduction In general, OBM increases drilling rates and provides better quality boreholes than when drilling with water-base mud (WBM). In oil-base muds, the continuous fluid phase is a mixture of liquid hydrocarbons. This continuous phase dominates the process of invasion and mixes with formation fluids. Water is also present in the form of an emulsion. Chemical emulsifiers/surfactants are added in the mud to prevent water droplets from coalescing and leaving the emulsion (Bourgoyne Jr. et al., 1986) and to ensure that the weighting material is wetted by oil (Skalli et al., 2006). Calcium or magnesium fatty acid soaps are typically used as emulsifiers. Array-induction resistivity measurements are almost invariably acquired in OBM environments. Such measurements exhibit several radial lengths of investigation, typically from 10 inches to 90 inches and, in some cases, 120 inches. The variability of resistivity curves exhibiting different lengths of investigation is, in most cases, a footprint of mudfiltrate invasion. When array-induction measurements are acquired in the presence of WBM, large separation of resistivity curves and deep invasion can be expected due to monotonic change of formation resistivity. Ideally, we would not expect such a behavior in the presence of OBM. However, in hydrocarbon zones OBM-filtrate can replace native hydrocarbon and movable water, thereby resulting in an invasion front with different resistivity values in the nearwellbore region (La Vigne, et al., 1997). Moreover, invading mud filtrate is miscible with native oil. In the mixing process, OBM causes changes of fluid density and fluid viscosity, thereby modifying the apparent oil phase mobility in the invaded zone (Malik et al., 2007). The objective of this paper is to quantify the effect of fluid properties (density and viscosity) and composition on arrayinduction measurements acquired in the presence of OBMfiltrate invasion. Special attention is given to the presence of surfactants in the OBM. Previous laboratory experiments with core samples (Van, et al., 1988; Yan and Sharma 1989) show SPE 109946 Fluid Density and Viscosity Effects on Borehole Resistivity Measurements Acquired in the Presence of Oil-Based Mud and Emulsified Surfactants Jesús M. Salazar, SPE, Mayank Malik, SPE, Carlos Torres-Verdín, SPE, Gong Li Wang, SPE, and Hongyan Duan, SPE, The University of Texas at Austin

A Dual-Grid Automatic History-Matching Technique With Applications to 3D Formation Testing in the Presence of Oil-Based Muds

Probe-type formation testers are often used to estimate permeability and permeability anisotropy from pressure transient measurements. The interpretation of these measurements is not trivial in the presence of oil-base mudfiltrate invasion due to miscibility with formation oil and gas. Simple analytical expressions of spherical and linear singlephase flow may not give correct estimates of permeability in miscible or partially miscible flow regimes. A computationally demanding three-dimensional (3D) numerical model is required to provide accurate and reliable estimates of formation properties. Because pressure transients are nonlinearly dependent on the permeability of the formation, repeated 3D numerical simulations are necessary to match the measured pressure transients. We describe the development and successful implementation of a new inversion method that efficiently estimates permeability and permeability anisotropy with a cascade sequence of least-squares minimizations. Measurements consist of pressure transients acquired at the sand face with a probe-type wireline formation tester (WFT). The new inversion method executes the forward 3D problem only in an outer loop. In the inner loop, we perform fast minimizations with an equivalent two-dimensional (2D) cylindrical grid. Transient measurements of pressure at the sand face simulated with the 2D cylindrical grid are correlated to the corresponding measurements simulated with the 3D grid. Once the 2D minimization is completed, we perform a 3D simulation of transient pressure to update the 2D-3D correlation parameter and a new 2D minimization is performed until convergence is reached. The process repeats itself until the simulated 3D pressure transients reproduce the field measurements within pre-stipulated error bounds. We perform tests of the new inversion algorithm on synthetic and field data sets acquired in the presence of oil-base mudfiltrate invasion. Results successfully confirm that our coupled 2D/3D hybrid inversion approach enables significant savings in computer time and provides reliable and accurate estimates of permeability and anisotropy. In most cases, we are able to estimate permeability under 2% error within 20% of the computational time required by 3D minimization. Sensitivity analysis indicates that permeability estimates may be biased by noisy measurements and uncertainty in (a) flow rates, (b) relative permeability, (c) radial extent of invasion, (d) formation damage, and (e) location of bed boundaries.

Robust and Efficient Simulation of Formation-Tester Measurements With a Rigorous Compositional Simulation Code

This paper describes the development, testing, and successful application of a new compositional code for the numerical simulation of oil-base mud invasion and formation tester measurements that involve arbitrary miscibility between oilbase mud and native oil. The simulator assumes axialsymmetric variations of petrophysical properties as well as axial-symmetric flow-rate sources and boundary conditions. However, there are no restricting assumptions to the degree of miscibility between the fluids involved in the simulations. We solve the time-space evolution of component concentration with a time-marching implicit pressure explicit concentration (IMPEC) scheme. This method of solution considers the complete equations of state and implements rigorous and efficient flash calculations to describe the thermo-dynamical evolution of the various compositional phases due to spacetime variations of pressure and concentration. Simulations described in this paper consider the process of oil-base mud-filtrate invasion into reservoirs containing mixtures of connate water and oil. Subsequently, we simulate formation tester measurements by enforcing fluid withdrawal through the dual-packer section of the tester. Measurements consist of fluid pressure, fractional flow rates, fluid density, and fluid viscosity. Examples of application include homogenous and multi-layer formations as well as a capillarytransition zone. Comparison of simulation results against those obtained with a commercial code confirms the efficiency, accuracy, and reliability of our simulator. Sensitivity analysis indicate that time evolution of fractional flow rates, fluid density, and fluid viscosity measured with the formation tester remain influenced by the petrophysical properties of the formation as well as by relative permeability and capillary pressure. The simulations described in this paper accurately predict the measurement times necessary for the acquisition of clean samples of native formation oil in the presence of invasion and heterogeneous spatial distributions of petrophysical and rock-fluid properties.