Wellbore Two-Phase Flow and Heat Transfer During Transient Testing

Abstract

Summary This paper presents a comprehensive wellbore/reservoir simulator to study pressure-transient behavior during two-phase flow in a vertical or deviated wellbore. We adapted a hybrid approach by modeling the wellbore numerically in which mass, momentum, and energy of the fluids are conserved, while treating the reservoir fluid flow analytically. Conductive heat transport occurs through the tubulars, cement sheaths, and formation. Both conductive and convective heat transport mechanisms are operative for the annular fluid, however. For an offshore well, convective heat transfer through seawater and air are also considered. The simulator can be run in two modes. In forward simulation, transient pressure and temperature can be computed at any point in the wellbore, given the reservoir and completion parameters. Conversely, in a reverse simulation, bottomhole pressures (BHP's) can be computed given the pressure and temperature measurements at any other point in the borehole, including at the wellhead. However, the quality of reverse simulation derived solution is likely to suffer with increasing gas/oil ratio (GOR). Field data were used to show both features of the simulator. Computational results show that the effect of heat loss through seawater is marginal for most offshore wells with a short submerged section (<500 ft) because of the fluids' short residence time. However, for wells with long submerged tubulars (>2,000 ft), heat loss to the seawater becomes significant. Similarly, a deviated well loses more heat to the formation than its vertical counterpart because of increased residence time. Among major variables, thermal conductivity of the annular fluid plays a key role in heat retention and, therefore, in the wellhead temperature (WHT). Introduction Most oil wells produce multiphase fluids to surface. Exceptions are those that produce oil with very low saturation pressure and/or against a high backpressure. When a well is opened for flow or shut in at the wellhead, gas and oil phases tend to move at different velocities, thereby complicating the wellbore dynamics. Density effects causing phase segregation often complicate the early-time transient response, leading to reservoir model misdiagnosis. In addition, thermal effects arising from gauge placement in the borehole have the potential to add further woes to the model identification problem. Therefore, the primary motivation of this work stems from understanding the physical process during two phase gas/oil flow while conducting a transient test.

Observations of Thermal and Pressure Transients in Carbon Dioxide Wells

“…The cement thermal conductivity of 1.28 J/(s m K) for a class G wellbore cement is based on reported values (Philippacopoulos and Berndt, 2002), but other estimates are lower by a factor of 2 (Hasan, Kabir and Wang, 1998). Recall that these are steady-state calculations, and do not deal with the observed transients caused by changes in injection or production rate, or the final shut-in.…”

Temperature-Prediction Model for a Horizontal Well With Multiple Fractures in a Shale Reservoir

“…In this model, mass balance, momentum balance, energy balance and an equation of state are combined to solve wellbore pressure implicitly, and then the density, velocity and energy are calculated for new time step. Kabir et al (1996) presented wellbore/reservoir simulator for gas single phase flow, and it was extended to oil single phase flow (Hasan et al, 1997) and two-phase flow (Hasan et al, 1998 Hasan and Kabir (1991) was used, and the temperature of the reservoir inflow was assumed to be the same with the formation temperature.…”

A Comprehensive Statistically-Based Method to Interpret Real-Time Flowing Measurements

“…The main difference from the single-phase flow is that the conserved properties are weighted by their volume fraction (holdup) in the system. As for the momentum balance of multi-phase flow, it needs a special treatment and a number of models have been developed for wellbore pressure and holdup calculations (Hasan and Kabir, 1998;Flores et al, 1998;Taitel and Dukler, 1976). We apply a homogeneous model for oil-water flow and a homogeneous with drift-flux model for gas-liquid flow (Ouyang and Aziz, 2000).…”