A three-dimensional r-?-z single-phase fully-implicit finite-difference model for a vertical well has been developed to examine how the presence of invaded zones affects the multi-probe and packer-probe pressure measurements in single-layer and multilayer (crossflow) systems. Invasion zones are modeled as composite zones concentric with the wellbore, that have different rock and fluid properties (permeability, porosity, viscosity and compressibility) from those of the native uninvaded formation.
The results show that for multi-probe wireline testers, the sink (or the flowing) and horizontal probe pressure responses are highly affected by the invaded region properties, while the vertical probe pressures are mainly influenced by the properties of the uninvaded zones. For packer-probe testers, similar results are obtained; i.e., the vertical probe pressures are mainly influenced by the properties of the uninvaded zones, while the packer interval pressures at early times are influenced by the invaded zone properties. It is shown that if the invaded zones are incorporated into the interpretation process using the model developed in this work, simultaneous matching of spatially available wireline formation tester pressure data sets using nonlinear regression can provide estimates of both invaded and uninvaded zones parameters. A synthetic example of a multi-probe test is presented to confirm the theory and procedures developed in this work.
Introduction
The multi-probe and packer-probe wireline formation testers1–7 (WFTs) are used to conduct controlled local production and buildup, and horizontal and vertical interference tests. These tools provide formation fluid samples and estimates of horizontal and vertical permeabilities and wellbore damage. Further details about wireline formation testers, equipped with packers and multiple probes, can be found in Refs. 1–7.
It has always been a concern how the pressure transients from these formation testers are affected by the presence of invaded regions around the wellbore. When an oil/gas well is drilled, some of the borehole fluid (mud filtrate) can leak into the formation, displacing the native formation fluid creating an invaded zone around the wellbore. The invading fluid usually has a viscosity and compressibility that differ from those of the formation fluid.
In general, the process of drilling fluid invasion is quite complex as it involves solid and solute (and solvent in the case of oil-based mud) transport and precipitation as well as multiphase flow, capillary pressure hysteresis, wettability alterations, chemical adsorption and gravity effects.8–10 One of the main difficulties is how to rigorously model the initial condition set by the invasion process prior to sampling and pressure transients from WFTs. In addition, modeling rigorously the effects of invasion zone(s) on fluid sampling during pumpout (production) and on pressure transient data from WFTs during pumpout and buildup periods are two challenging problems. However, if one assumes that capillary and gravity effects are negligible and that permeability and porosity impairments due to solid and solute invasion and precipitation are minimal, then one may tackle the invasion problem by considering a simple two-phase immiscible or miscible flow model; filtrate and oil.
