Increasing Production With High-Frequency and High-Resolution Flow Rate Measurements from ESPs
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
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.