Challenge: Optimize oil production from a new well in a newly developed field with unexpected gas production
Solution:
Results:
One of the main challenges of producing a recently developed field in Western Egypt has been the limited reservoir and production data available to inform the designs of optimized artificial lift solutions, especially for newly drilled wells.
For one well, engineers designed a new ESP for oil production, based on the limited reservoir knowledge. However, the well immediately produced with low bottomhole pressure and significant gas content, two factors that were not expected when designing the ESP. As a result, the ESP began to operate intermittently with at least daily shutdowns because of underload events associated with gas locking. Afterward, the well would remain shut down for several hours while bottomhole pressure built up and field crews mobilized to manually restart the ESP. The ESP would then run until the next underload event.
Intermittent operation rapidly reduces the run life of an ESP, defers oil production, and frustrates the field crews. In addition, this remote well is accessible only during the daytime, so nighttime shutdowns resulted in particularly long restart delays.
One option for the operator was to immediately replace the ESP system with one more optimized for the conditions. However, no rigs were available on short notice. Another solution was required to avoid rapid ESP failure and loss of production for several months.
SLB recommended the Lift IQ service, which monitors and optimizes artificial lift equipment in real time 24/7/365 from Artificial Lift Service Centers around the world. The service relies on data from installed sensors and data acquisition units. In this case, the lift system installed in the well included a Phoenix xt150 system, which monitors downhole pressure, temperature, current leakage, and vibration, providing comprehensive data needed to protect ESP system integrity and optimize well performance. The well was also equipped with an Instruct unit, which acquires data and enables users to program alarm and trip settings locally or remotely.
For the well in this case, surveillance engineers focused on optimizing production performance despite the gas problems. In particular, they focused on avoiding issues that arise because of gas locking events: mechanical damage to pump components because of stage friction, system failure because of high motor temperatures, and electrical system integrity loss because of excessive stops and starts.
Because the ESP system delivered data in real time and enabled remote control, surveillance engineers dynamically adjusted alarm settings and frequency values to suit running conditions. In addition, surveillance engineers were able to monitor downhole pressures and remotely restart the well overnight, speeding up the restart and eliminating the need to mobilize a field crew to the wellsite the next morning.
The engineers also used the real-time data to help them remotely optimize the VSD feedback mode, which can be used to continuously manipulate pump speed to maintain a certain intake pressure. Optimizing this feature enabled the ESP to overcome the gas interference and operate steadily without gas-related trips and associated downtime.
The steady operation enabled oil production of 4,800 bbl and extended the ESP run life while the operator worked to schedule a workover rig to install a replacement ESP designed to better suit the reservoir conditions.
