Abstract

A proven field wellbore stability model provided mud weight (MW) calculations with high confidence for a shelf sea project in the Caribbean region. A well was drilled that experienced instability and presented with drilling temperatures that were much higher than any offset wells or the geothermal gradient would suggest. The drilling fluid temperatures recorded by the measurement-while-drilling (MWD) equipment were as high as 43°C (110°F) above in situ values. This study concluded that the wellbore failure could be predicted through the recalibration of the model to include the impact of additional temperature and the results successfully delivered improved wellbore quality. Field data is also presented to show how this method was derived and successfully applied in recovery from operational issues. This includes process used to explain the origin of the excess heat created a solution to reduce mud temperatures that wasn't disruptive to the overall drilling performance.

Introduction

The impact of high or low temperature differentials in the annulus between the drilling fluid and exposed lithology has been studied for some time. Thermal stresses can be induced by the temperature difference between the drilling fluid and the rock matrix (Chen et al, 2001).

As a basic concept, heating induces expansion of the rock. When this expansion is resisted by the adjacent formation (which is also being heated), additional compressive stresses are generated in the rock. Conversely, cooling induces contraction of the rock. This contraction causes near wellbore stresses to become less compressive, even tensile, if the amount of cooling is high enough.

Thermal stress is calculated using the following equation (Perkins & Gonzalez, 1984):

(equation) (1)

Where:

E = Static Young's Modulus

ν = Poisson's Ratio

αt =Formation Linear Thermal Expansion Coefficient,

Tm = Mud Temperature

Tf = Formation Temperature.

There has been a study bias towards the cooling effect of the fluid since this is the most common occurrence. This is probably because changes in wellbore temperature usually have a greater effect on the formation breakdown pressure than on the formation collapse pressure (Yu et al., 2001).

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