A fully implicit, three-dimensional simulator with local hybrid grid refinement around the wellbore solving reservoir and horizontal well flow equations simultaneously for liquid-gas flow systems is used to investigate the effects of permeability, gas saturation, well length, well diameter, reservoir anisotropy and perforation/slot phase angle on the well productivity behavior. In addition, the effect of the coil-tubing diameter on the two-phase production logging measurements is studied. The model implements the conservation of mass equations in the reservoir and conservation of mass and momentum in the wellbore for isothermal conditions. The establishment of the continuity of pressure and preservation of mass balance at the sandface satisfy the coupling requirements between the two computational domains. The hydrodynamic model for the wellbore is based on the homogeneous flow assumption.
In this paper, we show that the indiscriminate use of single-phase flow models to predict the productivity of horizontal wells producing under multi-phase flow conditions can lead to significant errors and the magnitude of the discrepancy increases with reservoir permeability and gas saturation. Also, for multiphase flow conditions, pressure drop along the wellbore plays a crucial role in the asymmetrical flux distribution profile and should not be ignored. The seriousness of the problem is considerably aggravated in long wells, slim holes, high permeabilities and high gas saturation systems. In some completion designs, the simulations have shown that 70% of the production comes from the first 1/6 of the total well length. In other examples, the last third of the well length contributes with less then 2% of the total production. It has been shown that in anisotropic systems, a more uniform flux distribution is obtained with openings aligned orthogonal to the larger permeability direction. Regarding to production logging applications, a significant deviation on the measurements and actual behavior can be observed, depending especially on the ratio between well and coil tubing diameter. The proposed model can be a useful tool in generating the appropriate corrections for the undesirable effects of the coil tubing on production logging measurements.
Although a number of numerical and analytical tools have been developed to investigate the flow behavior and predict the performance of horizontal wells, several issues that can significantly affect performance predictions have not been addressed properly. One issue is the improper treatment of wellbore flow and reservoir-wellbore interaction. The earlier studies assuming constant pressure along the horizontal wellbore treated the horizontal well as an infinite conductivity medium. However, as discussed by Ozkan et al.1, the infinite-conductivity idealization is applicable only in low productivity systems in which the pressure loss in the wellbore is negligible compared to the pressure decrease encountered during a drawdown. Utilizing a simplified steady-state wellbore model, they also showed that pressure losses in the wellbore affect the productivity of a horizontal well significantly when the wellbore pressure losses and drawdown are of the similar orders of magnitude. Furthermore, unlike the results obtained with the infinite-conductivity assumption, the flux distribution along the wellbore has been shown to be asymmetrical, with greater amount of fluid entering near the downstream end of the wellbore. Therefore, especially for long wells, high flow rates, slim holes, high viscosity fluids, and multiphase conditions the wellbore hydraulics can play an important role in the production behavior of a horizontal well and they should not be neglected.