To arrest production decline without infill drilling, one must maximize production from existing wells, typically by identifying wells with skin and increasing drawdowns on wells with good pressure support or lower water cut. This paper examines how high-frequency, high-resolution flow rate measurements on ESP wells can identify such opportunities without the need for buildups which cause production deferment. The application of this workflow was examined for wells in Egypt.
To obtain flow rate measurements at frequencies greater than once an hour, without dedicating a test separator or multiphase flowmeter to each well, the method relied on real-time data to calculate liquid rate and water cut. The liquid flow rate calculation was based on the principle that the power absorbed by the pump is equal to that generated by the motor. Water cut was calculated by modelling the production tubing as a gradiometer. Analytical equations ensured that the physics were respected at all times, which yields greater repeatability and resolution than analogous methods based on correlations and artificial intelligence.
The well analysis in Egypt demonstrated that the evolution of depletion and skin could be identified qualitatively using plots of rate-normalized differential pressure. These diagnostic plots are only possible with high-frequency and high-resolution flow rate measurements and could not be generated using traditional monthly production test data. The case studies also illustrated how frequency and resolution enabled real-time measurement of the impact of small changes in pump speed on both the reservoir inflow characteristic as well as production. This qualitative technique makes it possible to fine-tune production iteratively without the need for time-consuming simulation, which was nevertheless also conducted to quantify the changes in reservoir pressure and skin on the wells considered in this case study. Furthermore, with a water cut resolution of less than 1%, potential water coning can be identified rapidly, which allows the production operator to test small drawdown increases. Finally, this method also has the advantage that it can reduce the mobilization of testing equipment to the well site to measure the change in production, thereby minimizing and eliminating health, safety and environment (HSE) risks in remote locations while also optimizing the use of the available test packages.
This novel use of real-time gauge data demonstrates how a cost-effective method can improve well testing quality and thereby identify production optimization opportunities, providing the means to arrest decline. This case study provided a proof of concept on specific wells, however fieldwide application is necessary to identify the wells with the highest production optimization potential because, typically, most of the gain is obtained from a minority of the wells in a given field.
