Established operators in the Permian Basin have been producing from legacy mature fields and formations for many years with vertical wells, but the focus has shifted to aggressive growth in new unconventional resource plays. With this shift, a majority of the players have transitioned their programs to horizontal wellbores with multistage completions. Operators drill out frac plugs and let the well flow naturally, either through casing or through tubing after running production tubing. Once the pressure or production declines, a workover rig is brought back to the well to install some form of artificial lift. One operator implemented a strategic procedure to optimize the initial production and resources by utilizing the same completion rig to leave the well ready for production with an electric submersible pump (ESP) before moving to the next well.

There are numerous challenges that come with an ESP installation of this nature, including a live well, high pressure, and flowback of fracturing sand. To overcome these challenges, this operator runs a packer with a pumpout plug to “kill” the well and then installs the ESP with a desander to prevent pump damage from production of fracturing sand. After the ESP is installed, the well is opened for production and flowed naturally up the casing. The tubing wellhead valve is closed to prevent flow through the pumps. After the initial flowback period, the ESP is turned on and operating parameters are adjusted to optimize production and drawdown in the transitional artificial lift stage. Operation of the ESP during this transitional period presents several challenges including high gas, slugging, production decline, scale, and corrosion. Depending on the production decline, a downsized ESP can be used until the production declines enough to require a rod pump system, which can be more efficient at low flow rates. This is the traditional lifting method for the remainder of a well’s productive life.

By installing the ESPs with completion rigs, which operate 24-hr crews, this operator eliminated an average of two days of downtime per well and maintained production throughout the transitional artificial lift stage of the well life cycle. A remote surveillance and control system enabled the operator to increase production uptime across the entire field and reduce the need for lease operators and technician callouts to the wells.

Positive economics, reduced HSE risk, increased production uptime, and controlled well drawdown have all been seen as a result of the new process. We are continuously reviewing and improving upon the process to help maximize ESP run life and reduce premature failures.