Abstract

Offshore Coring are time consuming and expensive operations which, if well conducted, provide extremely important information concerning rock and fluid properties. Drilling fluid invasion may be a relevant issue to affect fluid and rock reservoir original properties. Different hypothesis for pressure dissipation in the core are formulated and their impact on invasion are quantified.

This article deals with the derivation of an analytical formulation for drilling fluid invasion in cores, based on filter cake permeability results obtained in lab testing. The formulation represents the radial flow from the external lateral walls of a cylinder and considers plug flow in the porous medium and external filter cake formation. A comparison of the prediction and the observed invasion in real cores obtained in exploratory wells is presented.

Introduction

One of the drilling fluid basic functions is to exert hydrostatic pressure over the permeable formations to avoid the formation fluid invasion to the well while the drilling operation takes place. The fluid pressure is normally kept above the formation pore pressure to prevent from kick events (formation fluid invasion to the well), that, in some cases, can lead to an uncontrolled influx (blowout). This concept, called overbalanced drilling, is traditionally employed in most of the drilling operations worldwide.

Drilling fluid invasion may also cause irreversible reservoir damage, reducing its initial and /or long term productivity. Minimizing fluid invasion is a major issue while drilling reservoir rocks.

In coring operations, a cylindrical sample of rock is removed of the well for gathering petrophysics properties of the reservoir rock 1. Drilling fluid invasion can change rock structure and cause interaction with native fluids, leading to non-realistic sample information. Strategies for field development and economical evaluation depend a lot on the quality of the core samples (Larson and Foss 2, Randolph and Jourdan 3).

In order to control drilling fluid invasion, a common practice in the industry is the addition of bridging agents in the drilling fluid composition, such as calcium carbonates. These products would form a low permeability layer at the well walls which would control invasion. An adequate drilling fluid design requires bridging agent size distribution and concentration optimization. The ability of the fluid system to prevent invasion is normally evaluated by standardized static filtration experiments. In these tests, the fluid is pressurized through a consolidated inert porous medium and the volume which crosses the porous core is monitored along the time.

The present study proposes, to compare the predicted values and the observed invasion in real cores obtained in an offshore operation. The adopted strategy is the coupling of a linear filtration formulation (lab configuration) and a radial single phase formulation (wellbore vicinity) particularized to coring operations (flow through the external walls of a porous cilinder).

Problem Statement

The following derivation represents the fluid flow through a saturated porous medium. The fluid, due to the presence of bridging solids in its composition, tends to form a filter cake on the surface of the porous medium, as illustrated in Fig. 1.

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