Flow Profiling by Distributed Temperature Sensor (DTS) System - Expectation and Reality
- Liang-Biao Ouyang (Chevron Energy Technology Co.) | David L. Belanger (ChevronTexaco Overseas Petr.)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- May 2006
- Document Type
- Journal Paper
- 269 - 281
- 2006. Society of Petroleum Engineers
- 3.2.8 Well Performance Modeling and Tubular Optimization, 5.9.2 Geothermal Resources, 1.9 Wellbore positioning, 5.8.7 Carbonate Reservoir, 5.1.5 Geologic Modeling, 5.6.4 Drillstem/Well Testing, 2.4.3 Sand/Solids Control, 3.3 Well & Reservoir Surveillance and Monitoring, 3.3.1 Production Logging, 4.6 Natural Gas, 5.3.2 Multiphase Flow, 5.5 Reservoir Simulation, 5.6.11 Reservoir monitoring with permanent sensors, 5.4.2 Gas Injection Methods, 4.2 Pipelines, Flowlines and Risers, 2.2.2 Perforating
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Permanent downhole monitoring can provide valuable information for production decisions in real time without the need to perform an intervention to collect data. One of the commercial permanent monitoring technologies is the fiber-optic DTS, which can record the wellbore temperature profile in real time with decent accuracy and resolution. A key potential application for DTS data is to profile injection or production for wells, which is the primary motivation and focus of this project.
In the present paper, a thermal model recently developed for single-phase- and multiphase-fluid flow along a vertical, deviated, or horizontal well will first be briefly described. The model can be applied for both wellbore temperature prediction (forward modeling) and for flow profiling using a measured temperature profile (inverse problem).
The model has successfully been applied for investigating key thermal characteristics of single-phase- and multiphase-fluid flow along a wellbore. In particular, the dependence of wellbore temperature upon phases, flow profile, fluid type, fluid properties, well deviation, and Joule-Thomson effect will be demonstrated in the paper. The model has further been adapted for directly predicting production and injection profiles (i.e., flow profiling) based on a given wellbore temperature profile. The potential impact of noise in the DTS measurement on flow profiling has been explored.
It is found that the wellbore temperature does not change significantly along horizontal or near-horizontal sections because of the small variation in geothermal temperature. Therefore, based only on steady-state DTS data, the amount and the location of each fluid entry would be difficult to identify. The current study shows that a maximum wellbore deviation of 75° should be honored to appropriately estimate flow profile directly through steady-state DTS data. The study has also led to an observation that under certain circumstances such as multiphase flow, a production profile may be determined through DTS temperature measurement with extra data or information provided. The types of the extra measurements and the appropriate approaches will be recommended.
The DTS system has become a compelling piece of equipment to be considered for permanent downhole monitoring design. DTS provides real-time temperature profile measurement, which can enhance understanding of the flow downhole. DTS systems have been installed all over the world (Johnson et al. 2004; Brown et al. 2005; Tolan et al. 2001; Brown et al. 2004; Brown et al. 2000; Kragas et al. 2001; Lanier et al. 2003; Fryer et al. 2005; Kluth et al. 2000; McKay et al. 2000)—including the North Sea, the Gulf of Mexico, Asia Pacific, Mexico, Venezuela, Texas, and California, to name a few—for steam breakthrough detection, water and gas injection management, production profiling, behind-pipe flow diagnostics, and reservoir surveillance.
Flow profiling by temperature log can be traced back to the 1960s and 1970s, when a couple of techniques (Ramey 1962; Curtis and Witterholt 1973; Romero-Juárez 1969) were proposed to quantitatively estimate flow rates at various wellbore positions. The techniques are based on analytical solutions [e.g., the Ramey solution (Ramey 1962)] and have not gained much success because of certain limitations associated with temperature acquisition, data resolution, and the techniques themselves. More details can be found in SPE Monograph No. 14 (Hill 1998).
Similar thinking has been extended to single-phase and multiphase flow along more complex wellbore configurations. Models, procedures, and applications have been developed for wellbore temperature profile prediction and flow profiling through temperature logs. Partial details will be documented in the present paper. The focus will be on the impact of fluid phase on wellbore temperature profiles as well as exploring the scenarios where it is feasible to predict flow profiles with temperature logs. Addressing these issues would help petroleum engineers set realistic expectations for a DTS system that can easily take up a significant portion of well Capex expenditures.
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