Modeling Reveals Hidden Conditions That Impair Wellbore Stability and Integrity
- Chris Carpenter (JPT Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- January 2015
- Document Type
- Journal Paper
- 101 - 103
- 2015. Society of Petroleum Engineers
- 1 in the last 30 days
- 100 since 2007
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163476, "Modeling Reveals Hidden Conditions That Can Impair Wellbore Stability and Integrity," by Robert F. Mitchell, SPE, Halliburton; Ronald Sweatman, SPE, Consultant; and Gary Young, Encana, prepared for the 2013 SPE/ IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.
This paper describes thermal modeling and its combination with drilling-fluid analysis to reveal concealed changes in well conditions during various drilling and completion operations. These hidden conditions represent significant changes in the well’s drilling- and completion-fluid temperature, pressure, and density (FTPD) that may help explain wellbore-stability and -integrity issues.
In the past, it has been difficult to make a case for temperature modeling. Temperature did not 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 wells have changed that attitude to a certain degree, and the effects of trapped annular pressure have become design issues for well completions. The effect of temperature on cementing has long been recognized, and it is understood that the correct determination of retarder can be critical. 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 usually does not vary much in conventional wells. Oil-based and synthetic-oil- based muds, on the other hand, are much more pressure- and temperature-sensitive. Furthermore, modern deepwater wells are encountering much more extreme temperature and pressure conditions, and maintaining the correct pressure has become more critical because of weak formations. The focus on thermally induced annular pressures has previously been a concern only for casing design, not for wellbore stability or well control. The purpose of this paper is to raise awareness of these issues and their consequences.
This paper focuses on fluid density because it is generally the principal determinant of annular pressures. Water is the most common base fluid for drilling muds and is probably the most-studied fluid because of its wide use in every aspect of our lives. Water is also difficult to model accurately, but many excellent correlations are available. Water density usually is modeled with hundreds of empirical coefficients.
Closely related to water are brines. Brines are equally difficult to model accurately, and thermodynamics can take one only so far before another list of empirical coefficients is needed to match measured densities. There is a great amount of data on common brines, but there is a need for more data and more correlations for many of the more- exotic brines being considered for use in wells.
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