The operator of a large field in Argentina’s Neuquén Basin successfully deployed Baker Hughes’ electric submersible pumping (ESP) systems to boost production from more than 350 of its mature wells. Nearly 90% of these systems were monitored on a continuous basis through a series of downhole sensors designed to track operating parameters that included motor temperatures and the ESP intake pressure.

The ESP systems ran efficiently through mid-2012, with an average uninterrupted runtime of 1,800 days per well. The service company’s field engineers continuously monitored the downhole sensors and soon began observing well temperatures around the ESP rising to near 127 C (260 F). At this temperature, the ESP motors began to overheat and fail in less than one year from their installation. Operating costs were rising and production rates were dropping from a growing number of wells exhibiting this temperature increase in the ESP systems.

When these ESP systems were pulled from the well and examined, calcium sulfate scale deposits were found on the motor and pump. This scale deposition was trapping heat around the ESP, lowering the cooling capacity of the motors, decreasing runlife and eventually leading to failure.

Ineffective incumbent scale treatments
An incumbent scale inhibitor chemistry supplied by a local vendor had prevented downhole scale deposition previously. Scaling tendencies tend to rise with rising well temperatures, and at the downhole temperatures encountered in these wells, the scale inhibitor stopped working effectively. The local chemical provider and other companies tried a number of different chemical treatments to control the scale but were unsuccessful.

The operator tasked Baker Hughes with finding an effective scale inhibitor alternative that would curb scale deposition on ESP systems and extend their runtime to pre-2012 levels. The operator also preferred a scale inhibitor that was capable of being reliably delivered downhole via capillary injection.

Uncovering additional challenges
During a kickoff meeting with the operator, representatives of the service company’s chemical’s group determined that a major source of the scale problem was a change in composition of the production brine. The operator had initiated a large-scale waterflood program using water with a different chemical composition than the brine already present in the reservoir. In addition, previously bypassed formations were perforated in an attempt to curb production decline in some existing wells, which further changed the brine composition and increased the scaling tendency of the produced water.

The operator could only provide three water analyses for inhibitor development and screening purposes. The most notable aspect of the brine chemistries was a calcium content of up to 2,600 mg/l. This high concentration, coupled with the elevated downhole temperature, would increase inhibitor-brine incompatibility and serve to limit product selection to just a few options.

Further challenges arose from the limited downhole information available. Formation temperature and pressure data were missing, and a lack of well completion data translated to an incomplete picture of the ESP system’s placement in the well.

Targeting effective treatment
Laboratory testing was conducted to determine which scale inhibitors were compatible with the brine from this field. Brine was prepared in the laboratory with the same composition dictated from the field brine analysis. An initial candidate product base of 13 inhibitors was tested at three concentrations—100 parts per million (ppm), 1,000 ppm and 10,000 ppm—to simulate what would happen upon dispersion of the inhibitor into the actual produced brine in the field.

The preferred results of this compatibility testing would be an inhibitor-brine solution that remained clear. Some degree of cloudiness or flocculation is acceptable at higher inhibitor concentrations for applications such as scale squeezes, but precipitation of solids out of solution is unacceptable.

Three inhibitors passed this initial screening without precipitating. However, all exhibited some degree of flocculation and cloudiness at higher concentrations, which was not ideal for the particular application. Given the challenges associated with developing a product that would remain clear under the field conditions of elevated calcium content and high temperatures, inhibitor testing continued on these products.

Inhibitor efficiency was further examined in a series of dynamic tube-blocking tests, which evaluate an inhibitor’s ability to prevent the formation and buildup of mineral scales in a capillary. The products were tested at different dosages and a temperature of 127 C using the same type and size of capillary in the test apparatus that would be installed in the field.

Scale buildup was measured indirectly by monitoring the pressure differential across the capillary over time. An inhibitor was considered a good field candidate if it could keep the pressure differential, and hence the buildup of scale, low for as long as possible.

Upon reviewing the combined results of the compatibility tests, the tube-blocking tests and the suitability for capillary deployment, one scale inhibitor (Figure 1) was selected for field application. The recommended continuous dosage rate of no less than 25 ppm was based on the results of the tube-blocking test. This low dosage made the inhibitor a cost-effective solution for controlling scale deposition at each ESP.

Focus then shifted to pinpointing the ideal location for the end of the capillary in the well. Further discussions with the operator revealed that the fluid dynamics changed downhole as new parts of the formation were perforated to introduce additional reservoir fluids to the well’s production stream. This prompted the operator to reposition the ESP and install a shroud around the motor to direct more of the production stream through the ESP system.

It was this installation of the shroud that caused a decrease in the motor’s cooling efficiency and made the incumbent inhibitor less effective at mitigating scale deposition. Scale would begin to form in the shroud, leading to a self-perpetuating cycle of even higher operating temperatures, greater scale inhibitor incompatibility and more scale deposition around the motor (Figure 2).

This discussion helped the field engineers arrive at an optimal length of capillary that would inject the new scale inhibitor treatment just below the ESP motor. This placement would allow the chemical to more effectively mix with the production fluids and into the shroud, thus minimizing scale buildup on the motor.

Positive outcome
Since the introduction of the new scale inhibitor solution in 2014, the operator has successfully addressed the problem of calcium sulfate scale deposition in ESP systems and realized safer, more reliable artificial lift operations. What started as a field trial on two wells quickly expanded to treatment of 75 wells. Premature failures on treated wells stopped almost immediately, with average runtimes extending from less than 365 days to more than 1,100 days. Runtime improvements to 1,800 days and more are expected as the program continues.

The new inhibitor formulation is currently being implemented on 90 wells in the field, and the operator has requested that it be used on future wells exhibiting the same telltale signs of scale formation on the ESP. Field crews continue to monitor the temperature sensors on other ESP systems around the field. Once the motor temperature rises and stays above 82 C (180 F), the new inhibitor formulation is injected in the well, thus providing a scale treatment that promises to extend the productive life of this mature field in a reliable and cost-effective way.