Flow Profiling Gas Wells With Distributed-Temperature-Sensing Data

Abstract

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 103097, "Successful Flow Profiling of Gas Wells Using Distributed-Temperature-Sensing Data," by D. Johnson, SPE, J. Sierra, SPE, J. Kaura, SPE, and D. Gualtieri, Halliburton Energy Services, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September. Distributed-temperature sensing (DTS) coupled with a temperature/pressure simulator was used to determine flow profiles from multilayered commingled reservoirs in gas wells. Quantitative individual-layer contributions to gas-flow rates and main water entries were determined, which in turn, helped engineers evaluate production conditions, track individual-layer recovery, identify problem zones, and plan remedial actions. Introduction DTS can provide continuous real-time flow information for the entire wellbore. However, DTS analysis is complex, and there is a current lack of user-friendly interpretation software. Production optimization requires continuous production information of each layer to design and plan preventive or remedial actions. A production-logging tool (PLT), the popular flow-allocation solution, is a snapshot-type survey. Also, PLT results from low-rate or unstable-downhole environments can be misleading. Other methods such as mixed-fluid signatures (e.g., gravity and salt content) are quasicontinuous, but their application is restrictive, requires special contrasting fluid properties, and cannot handle more than three layers. Background It is recommended that the reader review Appendix A in the full-length paper. The discussion shows unpublished work previously developed by the authors and provides the develop-mental work conducted on the transient analytical/numerical wellbore-temperature and -pressure model. This model was used to perform temperature analysis for flow allocation and fluid identification. One of the first successful applications of this model with actual DTS data was in low-rate oil- and water-producing wells and achieved a good match between DTS data and simulated temperature. Temperature in Gas Wells Gas production from a single reservoir was used as a simple example in material-balance calculations. While pressure-transient analysis in gas wells is considered simple (if one uses the pseudo pressure approach), wellbore hydraulics in gas wells, sometimes considered complicated, can be simplified by accounting for temperature changes related to frictional and Joule-Thomson effects (JTEs). The global trend when producing dry gas is to produce multiple small or low-productivity reservoirs commingled in a single well to allow for exploitation of gas that was not considered economically feasible to produce. This scenario can lead to differential depletion, cross-flow, and water breakthrough, which can impair gas production and under-standing of reservoir dynamics. These scenarios offer many conditions for use of DTS data for better quantification of flow rates and fluid types from individual reservoirs. JTE. The JTE is the phenomenon whereby fluid that is subjected to a pressure change experiences a change in temperature. The JTE is a cooling of produced gas or a warming of produced water caused by pressure drop during flow through formation, perforations, and wellbore.