Effects of Swelling and Hydrational Stress in Shales on Wellbore Stability
Authors: Tan Chee P. , Richards Brian G. , Rahman Sheik S. , Andika Rivano 
Published: December 2007

Chee P. Tan, SPE, Australian Petroleum Cooperative Research Centre, CSIRO Petroleum, Victoria, Australia; Brian G. Richards, Geotech Research Pty Ltd, Brisbane, Australia; Sheik S. Rahman, SPE, and Rivano Andika, Australian Petroleum Cooperative Research Centre, Centre for Petroleum Engineering, U. of New South Wales, Sydney, Australia

This paper describes the fundamental concept and a model of the swelling and hydrational stress mechanisms and the associated effective mud support change as the drilling fluid interacts with the shale. When the total aqueous potential (pressure and chemical potential) of the pore fluid increases, water will be absorbed into the clay platelets which will result in either the platelets moving further apart i.e. swelling if they are free to move, or generation of hydrational stress if swelling is constrained. The hydrational stress would result in an increase in pore pressure and a subsequent reduction in effective mud support which leads to a less stable wellbore condition.

The model was verified with laboratory experiments designed for the study of the swelling mechanism. A parametric study was subsequently carried out using the verified model to demonstrate the effects of volume change coefficients of shale on time-dependent mud support change and wellbore instability. The total aqueous potential of the pore fluid should be minimised/reduced by designing drilling fluids based on the mechanisms of mud pressure penetration and coupled osmotic transport in shales.

Introduction

Wellbore instabilities are usually encountered in shales which overlay the reservoirs. Shale, a common sedimentary rock that accounts for 75% of the drilled sections and causing 90% of wellbore instability-related problems, is chemically active and reacts with drilling fluids resulting in time-dependent mud support change and loss of strength. Mud support is additionally affected by mud pressure penetration. The most effective option for solving/managing the shale instability problem concerns drilling fluid design (weight, type, chemistry), drilling practices and, to a lesser extent, casing strategy. Traditionally, physico-chemically-induced instabilities were managed by using oil based mud, however, with increasing environmental concerns, the industry has now refocussed on the use of environmentally friendly and lower cost water-based mud to manage the instability problem. Thus, the problem should be addressed by focussing on the mechanisms of instability as a result of interactions between drilling fluids and shales.

This paper describes the fundamental concept and a model of the swelling and hydrational stress mechanisms and the associated effective mud support change as the drilling fluid interacts with the shale. The model was verified with laboratory experiments designed for the study of the swelling mechanism. Analyses were subsequently carried out using the verified model to demonstrate the effects of swelling and hydrational stress on time-dependent mud support (effective stress) change and wellbore instability in shales.

Fundamental Concept of Swelling and Hydrational Stress Mechanisms

Flow of water (solvent) and salt (solute) into or out of shales would result in a change in pore pressure and chemical potential near the wellbore wall. The driving forces of the flows are basically hydraulic and chemical potential gradients.

When drilling under an overbalance condition without an effective barrier present at the wellbore wall, mud pressure would penetrate progressively into the formation. Due to the low permeability of shales, the mud pressure penetration would result in an increase in pore pressure near the wellbore wall. The rate and magnitude of the pore pressure increase depend strongly on the mud filtrate and pore fluid properties (viscosity and adhesion) and the petrophysical properties of the rock material (permeability, pore size distribution and porosity).

P. 345^