Distributed temperature sending or DTS is gaining increasing popularity because of its potential to generate flow profiles over completed intervals. In fact, several studies have reported successful reproduction of field data, obtained with conventional production logs, in both vertical and deviated wells. One input that enters into typical DTS calculations is the total flow rate at surface. In absence of dedicated flowmetering, uncertainty normally creeps into assigned well rates.

This study provides a methodology wherein both the total and individual layer rates can be computed independently with DTS, completion, tubular, and other related data. To do the entire suite of calculations, a wellbore model handling steady fluid flow and unsteady-state heat transfer estimates a production rate, given wellhead pressure and temperature. The same model is then used to compute the flow profile based on measured DTS data across the producing intervals. The model rigorously accounts for various thermal properties of the fluid and the formation, including Joule-Thompson (JT) heating or cooling. Examples from both gas and oil wells are shown to illustrate the application of the proposed methodology. Good correspondence between the measured and calculated results demonstrates the robustness of the proposed method.


Nowak (1953) pioneered the application of temperature sensors to diagnose zonal flow contributions with a wireline-conveyed tool. Since then temperature sensor has been an integral part of any production logging suite. More recently, flow profiling across different producing intervals has gained increasing popularity with DTS for managing reservoirs. Papers describing zonal-rate inferences from DTS are many. For instance, successful field results have been reported in both production and injection wells in steamfloods (nath et al. 2007; Saputelli et al. 1999), in gas wells (Johnson et al. 2006), and in oil wells (Brown et al 2004, 2006). Unfortunately, interpretation models are lacking in most publications; Ouyang and Belanger (2006); Brown et al. (2006), and Wang et al. (2008) are exceptions in this regard.

Ordinarily, only flow fractions are discerned from DTS and other measurements; the knowledge of independent total rate at the wellhead allows appropriate zonal allocation in accord with zonal-flow fraction. However, to our knowledge, estimation of total rate has not been demonstrated with temperature measurements alone. The intent of this work is to present two methods for estimating rates from temperature data, independent of the flow sensing. The intrinsic idea is to provide engineering tools so that self-calibrated, real-time information gathering can occur wherever permanent DTS sensing is available. The proposed methods offer verification of the flowmeter-derived rate data, whenever available.

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