In this project, we are developing new methods for interpreting measurements in complex wells (horizontal, multilateral and multi-branching wells) to determine the profiles of oil, gas, and water entry. These methods are needed to take full advantage of "smart" well instrumentation, a technology that is rapidly evolving to provide the ability to continuously and permanently monitor downhole temperature, pressure, volumetric flow rate, and perhaps other fluid flow properties at many locations along a wellbore; and hence, to control and optimize well performance.In this first year, we have made considerable progress in the development of the forward model of temperature and pressure behavior in complex wells. In this period, we have progressed on three major parts of the forward problem of predicting the temperature and pressure behavior in complex wells. These three parts are the temperature and pressure behaviors in the reservoir near the wellbore, in the wellbore or laterals in the producing intervals, and in the build sections connecting the laterals, respectively.Many models exist to predict pressure behavior in reservoirs and wells, but these are almost always isothermal models. To predict temperature behavior we derived general mass, momentum, and energy balance equations for these parts of the complex well system. Analytical solutions for the reservoir and wellbore parts for certain special conditions show the magnitude of thermal effects that could occur. Our preliminary sensitivity analyses show that thermal effects caused by near-wellbore reservoir flow can cause temperature changes that are measurable with smart well technology. This is encouraging for the further development of the inverse model.

With the recent development of temperature measurement systems, continuous temperature profiles can be obtained with high precision. Small temperature changes can be detected by modern temperature measuring instruments such as fiber optic distributed temperature sensor (DTS) in intelligent completions and will potentially aid the diagnosis of downhole flow conditions. In vertical wells, since elevational geothermal changes make the wellbore temperature sensitive to the amount and the type of fluids produced, temperature logs can be used successfully to diagnose the downhole flow conditions. However, geothermal temperature changes along the wellbore being small for horizontal wells, interpretations of a temperature log become difficult. The primary temperature differences for each phase (oil, water, and gas) are caused by frictional effects. Therefore, in developing a thermal model for horizontal wellbore, subtle temperature changes must be accounted for.In this project, we have rigorously derived governing equations for a producing horizontal wellbore and developed a prediction model of the temperature and pressure by coupling the wellbore and reservoir equations. Also, we applied Ramey's model (1962) to the build section and used an energy balance to infer the temperature profile at the junction. The multilateral wellbore temperature model was applied to a wide range of cases at varying fluid thermal properties, absolute values of temperature and pressure, geothermal gradients, flow rates from each lateral, and the trajectories of each build section.With the prediction models developed, we present inversion studies of synthetic and field examples. These results are essential to identify water or gas entry, to guide flow control devices in intelligent completions, and to decide if reservoir stimulation is needed in particular horizontal sections. This study will complete and validate these inversion studies.