Unconventional oil wells present challenges to electrical-submersible-pump (ESP) systems and can limit production potential. An artificial-sump-pumping system used in unconventional oil wells with steep decline curves and high amounts of free gas has been shown to operate reliably and economically. This paper presents a comparison of conventional ESP methods and artificial-sump systems for which free gas and gas slugs are a challenge.
Introduction
Unconventional oil wells usually have inadequate reservoir permeability. To enable a significant amount of fluid flow from the reservoir to the wellbore, the wells are drilled horizontally and multistage hydraulic fracturing is performed to expose as much reservoir to the wellbore as possible.
The long horizontal laterals create unique production challenges. As the reservoir pressure declines in unconventional reservoirs, gas is released from the fluid and accumulates in hump undulations of the horizontal section. When the gas slugs break free, they create cycling and gas locking that has a negative effect on system performance and reliability. Repeated shutdowns because of gas locking have a negative effect on the production and longevity of the artificial-lift system. Reducing the running time for an artificial-lift system can significantly increase operator capital and operational expenses (OPEX).
Some gas slugs can be very large and can create a low-flow or no-flow condition that is challenging for most artificial-lift systems. Therefore, gas slugs must be separated from the liquid before entering the downhole pump to improve production and enhance artificial-lift-system reliability. Designing a system that can avoid slugs and prevent excessive amounts of gas from entering the downhole pumping system is crucial to produce economically from unconventional oil wells.
Artificial-Sump-Pumping System
An artificial-sump-pumping system is a new form of gas mitigation that uses an ESP artificial-lift method with an inverted shroud that surrounds the entire system. The ESP is equipped with a recirculation system to keep the ESP motor cool during slugs. In addition, the fully encapsulated system has enhanced motor-lead-extension (MLE) protection that helps avoid cable damage during run in hole (RIH), especially for 5½-in.-casing applications. This solution is mainly used for wells that are very gassy and have the potential for gas slugs.
Optional components are recommended to be used on the basis of well conditions and fluid characteristics. For instance, a sand-control system is recommended for applications where sand and abrasive risk is high.
Artificial-Sump-Pumping System Main Components
Inverted-Shroud System. The main function of the inverted-shroud system is to protect the ESP system from gas slugs and provide mechanical protection to the MLE during RIH.
Recirculation System. The main function of the recirculation system is to provide proper cooling for the motor inside the inverted shroud by pumping fluid through a recirculation tube to force fluid past the motor. In addition to providing proper cooling to the ESP motor, the recirculation pump is designed usually as a gas-handling pump to provide an extra layer of gas handling.
Other Tools. One tool that is recommended with an artificial-sump-pumping system is a chemical-injection line. Chemicals improve system reliability, especially if the potential for scale and corrosion is high. A chemical-injection line could be installed either at the top of the inverted shroud or connected to the recirculation tube head.
Background
Current unconventional wells in North America introduce a challenging environment for artificial-lift-system performance because of the high amount of gas and gas slugs. To produce from those wells economically and enhance oil recovery, different types of lift have been introduced. For instance, sucker-rod pumps (SRPs) have been deployed in several unconventional wells in North America; however, because of high gas slugs and well geometry, SRPs can operate inefficiently. Furthermore, high well inclinations introduce a high risk for tubing wear. The gas-lift method also has been used in some of those wells; however, two main issues arose when gas lift was introduced. The first issue was lower production and limited drawdown compared with other forms of artificial lift. The second issue was related to setting the gas lift at a high inclination because gravitational differences between liquid and gas (fluid segregation) led to stratification of phases, making the gas lift inefficient. Traditional ESP systems also have been used in those challenging wells, but these systems repeatedly shut down because of gas slugs. Repeated shutdowns because of gas locking have a negative effect on the production and the longevity of artificial-lift systems. Additionally, the short ESP run life increases operator OPEX and significantly affects the well economics.
An artificial-sump-pumping system was introduced to different operators in North America who had problems with gas slugs. The following is a case study in which the system deployed successfully and enhanced overall production and oil recovery.
Case Study
An operator in North America was struggling to maintain production because of repeated ESP shutdowns caused by the high amount of gas and gas slugging. In addition to shutdowns because of gas, the ESP experienced shutdowns because of elevated motor temperature caused by poor motor cooling. The repeated cycling significantly reduced system reliability and shortened the ESP-system run life. Three ESP systems had been installed in this well previously, and the average run life was approximately 157 days. After three short runs, the operator considered the use of an artificial-sump-pumping system to avoid system cycling, increase oil production, and extend ESP-system run life.
Extensive analysis was conducted to determine the inverted-shroud length to handle the 2-minute slug time and required fluid needed to cool down the motor during normal operation and gas slugging.
On the basis of previous ESP performance and production, the length of inverted shroud to override 2 minutes of gas slugs with no issue is 180 ft. The separation efficiency expected from downward flow is approximately 94%.
After installing the artificial-sump-pumping system, the operator immediately measured the fluid level in the well at 2,600 ft from surface, which resulted in incremental production of 90 BOPD.
After the artificial-sump-pumping system was deployed, gas cycling decreased and nonproductive time was substantially reduced. In addition, the overall ESP-system efficiency improved and oil recovery increased.
Conclusion
- The unique design of the artificial-sump-pumping system helped the operator to
- Improve production and oil recovery. This was achieved by stabilizing production, improving system efficiency, minimizing production interruption and system cycling because of gas, and minimizing reservoir pressure drawdown for greater reserve recovery.
- Reduce OPEX by improving system reliability. The artificial-sump-pumping system eliminated wear and tear associated with cycling because of gas slugs, significantly reduced motor heating because of gas slugs and inadequate cooling, and provided mechanical protection to the MLE during RIH.
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