Prediction of Temperature Changes Caused by Water or Gas Entry into a Horizontal Well
- Keita Yoshioka (Chevron ETC) | Ding Zhu (Texas A&M University) | Alfred D. Hill (Texas A&M University) | Pinan Dawkrajai (Defense Energy Department) | Larry W. Lake (The University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- November 2007
- Document Type
- Journal Paper
- 425 - 433
- 2007. Society of Petroleum Engineers
- 5.9.2 Geothermal Resources, 2.3 Completion Monitoring Systems/Intelligent Wells, 5.6.11 Reservoir monitoring with permanent sensors, 3 Production and Well Operations, 1.8 Formation Damage, 5.1 Reservoir Characterisation, 5.3.1 Flow in Porous Media, 5.6.4 Drillstem/Well Testing, 3.3 Well & Reservoir Surveillance and Monitoring, 3.3.1 Production Logging, 5.3.2 Multiphase Flow
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With the recent development of temperature measurement systems such as fiber-optic distributed temperature sensors, continuous temperature profiles in a horizontal well can be obtained with high precision. Small temperature changes with a resolution on the order of 0.1°F can be detected by modern temperature-measuring instruments in intelligent completions, which may aid the diagnosis of downhole flow conditions. Since in a producing horizontal well fluid inflowing temperature is not affected by elevational geothermal temperature changes, the primary temperature differences for each phase (oil, water, and gas) are caused by frictional effects.
While gas production usually causes a temperature decrease, water entry results in either warming or cooling of the wellbore. Warmer water entry is a result of water flow from a warmer aquifer below the producing zone (water coning). In contrast, produced water can be cooler than produced oil because of differences in the thermal properties of these fluids. If both oil and water are produced from the same elevation, oil is heated more by friction while flowing in a porous medium than water is resulting in the produced water having a lower inflow temperature than the oil. Water entry by coning is relatively easy to detect from the temperature profile because of its warmer inflow temperature, but water breakthrough from the same elevation as the oil may not be obvious.
In this paper, we illustrate the range of inflow conditions for which water-or-gas entry locations can be identified from the temperature profile of a wellfrom measurable temperature changes. Using a numerical wellbore-temperature-prediction model (Yoshioka et al. 2005a), we calculated temperature profiles for a wide range of water-inflow conditions.In these calculations, we assumed that one section of the well produced water or gas, while the rest of the open section of the well produced oil. From sensitivity studies, we showed the predictions of the relative water-and-gas production rates that create detectable temperature anomalies in the temperature profile along the well. By using the model to match an actual temperature log from a horizontal well, we demonstrate how this model can be used to identify water-inflow locations.
Temperature logs have been used to locate water entries. Some field examples (Tolan et al. 2001; Foucault et al. 2004) reported the successful identification of water entry and prevention of its further production. However, the identification is often made by intuition. That is, gas entries reduce the wellbore temperature, and water entries increase the temperature. The inferences are also qualitative. There is no means to determine the rate of water entry, for example. To optimize well performance, we need a better method to identify water or gas entries.
We will analyze anomalous temperature changes along a flowing horizontal well using a temperature model for horizontal wells. The main difference of the model from the vertical thermal wellbore models (Hill 1990; Ramey 1962; Sagar et al. 1991) is that the geothermal temperature is constant along a horizontal well. Temperature deviations from the geothermal temperature are caused by changes in flow conditions in the reservoir and wellbore. If we assume that all the fluids in the wellbore are produced from the same elevation (i.e.,the temperatures are the same at the boundary), the reservoir energy balance can be solved as a 1D problem. To infer the temperature behavior with water coning, the problem needs to be solved in 3D (Dawkrajai et al. 2006). The detailed discussions of the prediction model are in the following section.
We have used two different models in this study. For water produced from the same elevation as the oil, we consider a segmented reservoir and multiphase flow in the wellbore. We also consider a steady-state reservoir with constant fluxes from both sides and no flow at the other boundaries (Fig. 1). For water coning, a 3D reservoir model is used (Fig. 2). The top and sides of the rectangular reservoir are sealed, and the pressure below the reservoir (the aquifer pressure) is constant. In both cases, we assumed fully penetrating horizontal wellbores.
For nonisothermal flow, we can derive the mass-and-energy balance equations for the reservoir and wellbore. The solution of the coupled reservoir and wellbore equations provides the temperature and pressure profiles in the domain of interest.
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