Wellbore instability problems are induced by changes in near wellbore stresses and pore pressure. Thermo-mechanical stresses coupled with the osmotic contributions are used to compute conditions under which the wellbore becomes unstable. Changes in pore pressure due to osmotic effects are a function of the water activity in the mud and the membrane efficiency of the shale. Shale strength alterations with hydration time are considered while determining the critical mud weights. The model presented in this paper is the first complete attempt at including mechanical, chemical and thermal contributions into a general three dimensional wellbore stability model. The results presented from the model clearly indicate the conditions under which all three contributions play an important role in wellbore stability.


Shale instability problems have perplexed the oil and gas industry for many years. Shale drilling problems can be one or more of the following (Bradley, 1979a, b, Hawkes et al. 1998, Lal, 1999): oversized or shrunken hole, hole breakout due to collapse failure, lost circulation due to breakdown failure, stuck pipe, and poor hole cleaning. In addition, excessive volumes of cavings and cuttings, hole fill after tripping, sloughing shale, plastic flow and sand production, well control problems, and borehole breakouts due to low mud density and low mud salinity can also occur during drilling.

These problems are primarily caused by the rock stress being larger than the rock strength when a borehole is drilled. This often happens when the in-situ rock is drilled out and replaced by the drilling fluid.

Factors causing wellbore stability problems can be classified based on their different effects on shale pore pressure and stress alteration: mechanical, chemical, fluid diffusion, solute diffusion, and thermal diffusion. All the factors may disturb the pore pressure and some of them may disturb the rock total stress field. Therefore the effective stress and failure status may become altered.

The discussion of mechanical effects can be found in Bradley (1979a, b), Detoumay & Cheng (1988), and Yew & Liu (1992). Biot (1941, 1955, and 1962) was the pioneer of poroelasticity studies. Based on his original and extended poroelasticity theory, poroelastic effects are incorporated into wellbore stability analyses (Rice & Cleary, 1976, Cheng et al. 1993, Cui et al. 1997).

Experimental results have proved the existence of chemical effects on shale pore pressure (Mody & Hale, 1993a, O'Brien et al. 1996, Chenevert & Pernot, 1998). Even for conditions of original identical wellbore pressure and initial pore pressure, an alteration of pore pressure was clearly observed by Hale & Mody (1992) and Hale et al. (1993). Chemical effects, caused by the difference between shale water activity and drilling fluid water activity, can be treated as an equivalent hydraulic potential (Chenevert, 1969,. 1970) in wellbore stability analysis. Chenevert & Pemot (1998) have successfully measured the membrane efficiency, which is determined as the ratio of the observed osmotic pressure divided by the theoretical osmotic pressure. The effect of chemical osmosis was integrated into wellbore stress calculations and can be found in Hale et al. (1993), Osisanya & Chenevert (1996), and Fonseca & Chenevert (2000). Ion movement can also induce pore pressure change inside the formation, as well as water transport across the wellbore.

Thermal stresses can be induced by the temperature difference between the drilling fluid and the rock matrix. A pore pressure change can occur consequently due to the imbalance of the volumetric expansion between the solid skeleton and the pore fluid. Kurashig

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