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Collaborating Authors
Results
Abstract Downhole pressure and temperature sensors have been installed either separately as stand-alone sensors hanged on the production tubing of a well or jointly with Electric Submersible Pumps (ESPs) or Intelligent Well Completions (IWC). However, their utilization thus far has been limited to static/flowing bottom-hole pressures measurement for buildup/drawdown pressure tests analysis or ESP/intelligent well performance monitoring. Eighty-eight (88) wells located offshore Saudi Arabia have been equipped with ESPs combined with downhole pressure and temperature sensors installed at the intake and discharge of the pumps. Each well was equipped with a surface coriolis meter to measure the total liquid flow rate and water-cut assuming that the well's production will be maintained above the bubble point pressure. However, the coriolis metersโ readings have become erroneous ever since the wellsโ flowing wellhead pressure declined to and below the saturation pressure due to the flow of liberated gas through the meters. In order to compensate for the metersโ measurement deviation, wellhead samples had to be collected and analyzed to determine the wells water-cuts where the total flow measurement was still acceptable. Alternatively, other means of multiphase flow rate measurements were used. This has proven to be costly and time consuming. This paper proposes a technique which uses real-time data transmitted from existing surface and subsurface sensors to calculate the water-cut and flow rate of each well and avoid the risky and costly field trips for wellhead sample collection and analysis. In addition, the paper describes an innovative technique to estimate the error in the measured density and calculated water-cut based on the bubble point pressure which accurately determines the application envelope of this method. The paper provides examples to illustrate the validity of the proposed technique in comparison with measured and sampled water-cuts which were collected above and below the bubble point pressure. Furthermore, the paper sheds light on the main issues impacting the method's reliability.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Summary Optimizing the completion interval to minimize water coning has been long recognized as a challenge in the industry. After reviewing the mechanism of water coning, a simple analytical model is presented in this study for water-coning systems in high-conductivity reservoirs (reservoirs with low pressure gradient). This model is applicable to predict the critical rate and to determine the optimum wellbore penetration for achieving maximum water-free production rate of vertical oil wells. The developed model predicts the critical rate on the basis of a radial/spherical/combined (RSC) 3D flow field assumption that takes into account the effect of permeability anisotropy, density difference between water and oil, and limited wellbore penetration. Moreover, optimum wellbore penetration into the oil zone has been determined by maximizing the critical rate. This analytical model reveals the optimum wellbore penetration in high-conductivity reservoirs to be almost half of the pay-zone thickness, depending on the radius of wellbore and drainage area, pay-zone thickness, and the permeability anisotropy of the reservoir.
- Europe (0.93)
- North America > United States > Texas (0.68)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)