The interaction of the drilling fluid with the formation rock is a key factor that determines the time-dependent stability of wellbores in shale formations. The analysis of wellbore stability in shales requires modelling of various coupled processes that are dependent on the relative properties of the drilling fluid and formation pore fluid. These processes include mud pressure penetration, thermal diffusion, chemical potential mechanism and poroelasticity. These processes affect the formation pore pressure, stresses and deformation. The critical drilling fluid properties include mud type, weight, temperature, and type and concentration of free ions.

Numerical simulations are conducted to model the effect of coupling the various processes on wellbore stability in shales. The simulations used a finite element code SHALESTAB that solves the specific coupled differential equations which describe these processes. It is found that the use of a cooler drilling fluid with a higher salt concentration and the appropriate mud density, viscosity and surface tension reduces the formation pore pressure and helps to enhance the stability while the use of a hotter drilling fluid with a lower salt concentration and less favourable mud physical characteristics has the reverse effect. The coupled simulations show that incorporating the chemical potential and mud pressure penetration mechanisms, depending on the mud properties, can reduce the formation pore pressure. For an effective assessment of wellbore stability in shales, the analyses need to take into account these complex coupled time-dependent processes.


Wellbore instability in shale formations is a major cause of drilling delays and suspension of wells prior to reaching the target. This instability can be a result of too high in-situ stresses compared to the formation strength (Aoki et al., 1994 and Aoki, 1996) or due to the time-dependent interaction between the drilling fluid and the formation (Tan et al., 1996a, 1996b, Tan et al., 1997, Choi and Tan, 1998, and Tan et al., 1998). A better understanding and more accurate modelling of these time-dependent interaction processes are necessary for effective management of wellbore instability in shales.

In this paper we briefly describe the fundamental concepts of the main physico-chemical interactive processes between the drilling fluid and the formation that affect wellbore stability in shales. Then we present results of numerical simulations that model one or more of the processes affecting the time-dependent wellbore stability. The simulations are conducted using a finite element code that is based on solving the differential equations describing these coupled physico-chemical processes. The governing equations that describe the fundamental mechanisms are presented in other publications and therefore, are not presented in this paper.

A range of examples are presented to demonstrate the effect of the various mechanisms on formation pore pressure and the consequent wellbore stability. The effect of coupling these mechanisms in the design of drilling fluids for efficient management of wellbore instability is discussed in light of the simulation results.

Fundamental Concepts of Drilling Fluid-Shale Interaction Mechanisms

Wellbore instability in shales can be an immediate result of stress redistribution and formation pore pressure increase following the removal of the rock mass. Poroelasticity is used to model the mechanical stability in such cases (Naylor et al., 1981, Detournay and Cheng, 1988 and Aoki et al., 1994). In addition, due to the fine-grained nature and low permeability combined with high porosity and saturation with pore fluid, shales are susceptible to time-dependent wellbore instability. Time-dependent processes related to transport of fluid, solutes and heat between the drilling fluid and the formation fluid need to be examined. These processes can increase the formation pore pressure rendering the wellbore unstable.

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