Prediction of Formation-Tester Fluid-Sample Quality In Highly-Deviated Wells

ABSTRACT

Fluid samples acquired with formation testers are often contaminated with mud filtrate. In some cases, it may take hours or even days to achieve acceptable levels of mud filtrate contamination, thereby rendering the fluid-sampling operation undesirable for either economical or safety considerations. We apply 3D numerical algorithms to simulate formation-tester measurements acquired in highly-deviated wells using standard and focused-sampling probes. Because this approach is not restricted to the assumption of single-phase flow nor does it neglect presence of spatially asymmetric mud-filtrate invasion, numerical simulation enables the quantitative appraisal of realistic tool and formation properties under a wide range of deviation angles. Sensitivity studies consider the effects of permeability anisotropy, capillary pressure, gravity segregation, radius of mud-filtrate invasion, fluid viscosity, fluid density, probe diameter, and pump out rate for oil- and dry-gas-bearing rock formations. Moreover, comparisons are made between sampling operations performed in wells drilled with water-based (WBM) and oil-based (OBM) mud. We also appraise the performance of recently-introduced focused fluid-sampling probes for the rapid acquisition of low-contamination fluid samples in highly-deviated wells. Our study indicates that gravity is detrimental to production cleanup times and it also affects focused-sampling probes which, at specific ratios between sample and guard assemblies, achieve cleaner samples than conventional probes. For the cases considered in this paper, the larger the angle of deviation (with respect to the vertical axis), the longer it takes to achieve oil break through. Finally, gravity-segregated invaded formations strongly affect fluid sampling predictions, hence enforcing our notion that a numerical approach, such as the one implemented in this paper, is necessary to accurately predict production cleanup times in high-angle wells.



INTRODUCTION

One of the major technical challenges in collecting fluid samples with formation testers is to achieve minimum contamination within a relatively short period of time. Acquiring clean samples is essential to ensure not only reliable laboratory PVT analysis and chemical characterization but also to provide vital information about phase behavior of in-situ fluids, reservoir characterization, production management, and facility design. There are two situations that can complicate sample acquisition because of miscibility between mud-filtrate and in-situ hydro carbon: (a) sampling hydro carbon when the formation has been drilled with oil-base mud (OBM), and (b) sampling formation water when the formation has been drilled with water-base mud (WBM). Even though there are analytical techniques that can estimate uncontaminated fluid properties from contaminated fluid samples, miscibility between mud filtrate and in-situ hydro carbon introduces large inaccuracies in the calculated fluid properties (Gozalpour et al., 1999). To distinguish filtrate from in-situ fluid, optical density and GOR measurements are included in modern formation testers (Mullins et al., 2000; Hashem et al., 1999; Dong et al., 2002). Optical density measurements are based on detecting differences in the coloration of produced mixtures in the electromagnetic spectrum between 400 nm and 2200 nm. GOR measurements can be inferred with a gas detector located in the tool flow line or by monitoring a methane peak in the color spectrum.