Abstract

Wellbore stability and integrity issues may be explained by combining thermal modeling and drilling fluid analysis to reveal changes in well conditions that are typically unknown during drilling and completion operations. These changes in fluid temperature, pressure, and density (FTPD) can have a significant effect on wellbore stability and integrity.

This paper describes thermal modeling and drilling fluid analysis of non-circulated and circulated wellbores to identify non-traditional sources of instability and poor integrity. For example, in non-circulated wells that are static for many hours, differences between induced and natural temperatures combined with pressure conditions may lead to severe conversions from an over-balanced to under-balanced state resulting in pore fluid influx, cross-flow, collapse, and other severe wellbore failures.

When circulating long, deep holes, modeling may show FTPD-related issues that aren't revealed by other means. Over-balanced and/or stable rock conditions may actually change to under-balanced pressure and/or unstable rock conditions. The consequences include kicks, solids beds from formation breakouts, flow after cementing, stuck pipe by hole collapse, and salt creep acceleration.

A field application is examined in which modeling successfully identified a non-formation source of wellbore pressure. While a nearby well with similar open-hole conditions experienced a blowout during a long static time period, the prototype model correctly predicted that no formation gas influx would occur in a well with a similarly long static period. Comparison of the well's annular pressure measurements to modeled predictions indicated the pressure changes were thermally induced and not from a formation pore pressure source. When the annular pressures subsided as predicted, no gas was found in the annulus.

Tests of the FTPD model are continuing in different types of wells, well conditions, and applications for drilling and completion operations, and the prototype model may be modified accordingly.

Introduction

In the past, it has been difficult to make a case for temperature modeling. Temperature didn't seem to be an issue in drilling, and production engineers could usually assume worst-case scenarios, such as constant bottomhole flowing temperature throughout the production tubing. Deepwater drilling and high-pressure-high-temperature (HPHT) wells have changed that attitude to a certain degree, and the effects of trapped annular pressure have become design issues for well completions (e.g., Adams 1991; Halal and Mitchell 1994).

The effect of temperature on cementing has long been recognized, and it is understood that the correct determination of retarder can be critical (e.g., Nelson 1990). Otherwise, temperature modeling during drilling has not seemed to be that important. Typically, intermediate string cementing is focused on achieving a good cement job and drilling ahead, and not on issues of temperature and pressure. One reason is the extensive use of water-based drilling muds. Water density is not particularly sensitive to pressure and temperature, so surface measured mud weight doesn't usually vary much in conventional wells. Oil-based and synthetic oil-based muds, on the other hand, are much more pressure and temperature sensitive. Further, as modern deepwater wells encounter even more extreme temperature and pressure conditions, maintaining correct pressure becomes even more critical in weak formations. While the focus on thermally induced annular pressures has previously been a concern only for casing design, it must expand to include wellbore stability and well control. The purpose of this paper is to raise consciousness on these issues and their consequences

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