To counter dwindling reservoir pressures and maintain production at economic levels, many wells will eventually have to go on some form of artificial lift. And while downhole pumps such as sucker rod pumps and electrical submersible pumps (ESPs) have been widely used to successfully bring oil to surface from low-pressure wells, they share a common challenge in the form of produced gas. High gas volumes entrained in the fluid prevent the use of conventional pumping equipment and require a solution to handle or avoid free gas entrained in the fluid from being produced.

As liquid rates fall and gas production rises in a well (a process that may take only a few months to a few years), these pumps reach a limit on reliable operation. In horizontal wells, for example, the accumulation of gas and water in the low spots of the lateral predispose the well to slug-like production cycles characterized by an alternating flow of gas and liquid. Gas slugs can cause erratic liquid loading, which may cause the pump to cycle on and off. Under such conditions, gas separators and tapered pumps, which are typically used to prevent gas locking, are rendered ineffective.

The industry has deployed several pumping methods to avoid gas ingress, including positioning the pump below the perforations (in the rathole) to take advantage of the natural separation there. Tangent sumps also have proven effective at avoiding gas, particularly in extended-reach drilling applications. However, these solutions are often expensive to build and complex to construct and may prove ineffective in marginal wells with flow rates below 100 bbl/d of fluid.

Artificial sump solution

A new pumping solution has recently been developed that provides simple and low-cost gas management for marginal production wells. Known as an artificial sump configuration, the system features a high-performance, low-flow stage ESP (which can reliably produce wells at rates as low as 50 bbl/d of fluid) in tandem with a system designed to avoid gas without the requirement of drilling a fixed sump. The artificial sump provides the gas-managing benefits of a wellbore sump without the added drilling/completion cost.

The artificial sump pumping system is a self-contained pumping unit designed to ensure reliable operation in high gas conditions consistent with unconventional low-flow applications. The system components are configured to provide adequate flow to cool the motor while achieving the desired production levels. Systems set below the perforations do not have enough fluid flow past the motor to prevent excessive heat buildup during operation and require forced fluid flow to prevent overheating. The recirculation system is designed to provide forced cooling liquid to the motor. It uses a tapered pump system, in which a portion of the output from the lowest pump is redirected into a conduit that transports the cooling liquid and then exits below the motor.

Because it is required to move more liquid volume, the recirculation pump must have a higher flow rate than the lift pump. Ample stages must be included in the recirculation pump to produce sufficient pressure at its discharge so as to overcome the frictional drag that occurs inside the recirculation conduit.

The artificial sump system also enhances capillary deployment of chemical treatments into the ESP system, keeping the system protected from negative effects of scale, paraffin or asphaltenes. Regardless of whether the capillary tube is terminated above the pump or below the motor, a portion of the injected chemicals is carried below the motor along with the recirculation fluid to provide continuous chemical treatment for the motor.

Bringing oil wells back online

An operator in Oklahoma faced gas-ingress challenges with a conventional ESP system installed in several low-flow oil wells. These wells used ESPs from the outset of production, but within nine to 12 months rising gas levels in the produced fluid stream began to cause frequent gas locking in the pumps, leading to overheating and shutdowns. The pumps eventually failed, requiring them to be pulled out of hole and leading to a complete loss of production from the wells.

Since the existing operations were not successful, the operator asked Baker Hughes to test its artificial sump configuration in three wells based in part on their own past work history with the service company and the new system’s successful deployments for other operators in the region. The two companies met several times to discuss the wellbore geometry and reservoir fluid properties, the specifics of the system, how it was performing in similar applications, and how it should be designed and deployed for the operator’s wells.

Three wells were selected for the first field trial with the system, each of which required pumping systems at a depth of about 1,700 m (5,600 ft) and with 36- to 45-hp motors. The installation process was quite straightforward and varied only slightly from normal ESP installations. Each ESP was designed to produce between 200 bbl/d and 300 bbl/d of fluid. Because sand production was a concern (and would compromise the operation of the pumping system), sand-control screen systems were installed on each well.

Installation of the first artificial sump went according to plan. The wells have been back in production for two to three months, and the operator is recording production rates in line with expectations for these marginal wells. The artificial sump is operating much more reliably compared to the previous ESP systems, and nonproductive time due to gas locking and pump overheating has been eliminated.

The operator is confident that this new pumping solution will run longer than conventional pumping systems and has requested that ESPs with artificial sumps be installed in an additional five to six wells as of this article’s publication date. This is in addition to the 15 wells that already have this pumping solution installed, bringing the total number of systems in the field to more than 20.

As more of these ESP configurations are installed in place of gas lift and conventionally deployed ESPs, they continue to demonstrate an ability to dramatically improve the economic viability of so-called “end-of-life” wells that might otherwise be abandoned.