The electrical submersible pump (ESP) transformed U.S. oil production in the 20th century, but in the 21st century, the unconventional oil boom has demanded an upgraded ESP design. And to bring the changes full circle, new improvements in efficiency, performance and longevity benefit not only the North American unconventional oil and gas fields, but also challenging “conventional” reservoirs that would have seemed very unconventional, when the first ESPs were installed.
Evolution of ESP design
Armais Arutunoff developed the first ESPs for the company he founded (REDA) in 1916, to de-water ships and mines. His first major backer, however, was an oil and gas operator, and the slow evolution of ESP performance has largely followed the same track as the industry.
Pastre and Fastovets (2017) offer an excellent example of the typical systematic evolution in ESP performance in a North Sea field.1 From the 1980s through the 2010s, as the field matured, water cut, scale deposition and sand production increased. A first round of failure analysis determined that first-generation mechanical systems failed, due to erosion from unexpectedly high sand production. Iterative improvements to ESP designs improved the hardness of the stage material and the bearings; then shaft stability became the main cause of failure. And so on—with each failure mode stemming a new round of product improvement. Similar analysis and redesign were performed to improve the surface
and downhole electrical systems.
After four generations, the “fit-for-basin” ESP system, combined with the rapidly evolving real-time surveillance service and smarter surface controllers, began delivering performance, efficiency and lifetime far beyond the original requirement. This has been done in an environment that was more demanding than the field’s early developers could have
imagined they would need.
But the changes that made the ESP ideal for the challenging North Sea field—and other changes from similar continuous improvement projects with different challenges—soon became the backbones of a new technology optimized
for today’s most challenging production environment. In fact, the robust pumps and gas-handling technology developed for conventional wells—together with motors and protectors that don’t require oil filling at wellsite—turned out to be critical for making ESPs work in unconventional wells.
Compounded challenges: Coping with new issues in the Eagle Ford shale. Initial attempts to produce unconventional wells with conventional ESPs determined that slow, steady ESP evolution was unlikely to produce useful technology quickly enough to meet market needs. ESP performance was hampered by too many factors at once. Ferguson (2013) describes the initial deployment of a conventional ESP in the Eagle Ford shale,2 "after three
consecutive infant failures in only a few weeks… it was clear that the typical ESP operating approach is not a viable solution in the unconventional plays."
The wells produced 40°-to-51° API oil and less than 25% water, with a GLR of 600 to 1,200 scf/bbl. The operator wanted to produce wells in three stages: natural flow, transitional artificial lift and beam pumps or gas lift. To accommodate the rapid production decline and manage output to the final stage, an unusually flexible ESP would be required: Initial expectations were production rates from 1,000 bopd at startup down to 200 bopd, plus a gas volume fraction (GVF) increase from negligible at startup to episodic slugs of 100% GVF.
In the first well, initial natural production of 1,749 bopd declined to 189 bopd after only four months, and water cut also changed from 48% to 21%. The operator installed the first REDA ESP system engineered from conventional technologies for the expected conditions. The initial ESP production increased to 965 bopd but declined over 20 days to 380 bopd, when facing the extremely challenging environment—and then three ESPs, in a row, failed in a short period.
The next ESP included the same pump and advanced gas-handling device type, but added multiphase gas-handling (MGH) devices, all built with compression-
type construction to provide extended operating ranges to manage the steep decline in fluid flow. The new ESP also used variable-rating motors; a sinewave variable speed drive (VSD) to minimize potential harmonics and stress on the ESP electric system; and real-time surveillance and control systems to enable remote adjustments. In addition, new operating procedures were developed and implemented to manage gas locking and overheating.
The newly redesigned ESP was installed on Sept. 23, 2011, and was pulled out of the well one year later without any interim failures. The ESP system operated, at most times, in a cyclic operating regime. In its unconventional setting, the ESP accumulated a total of 1,478 starts—more than 10 times the starts a conventional ESP would accumulate in its full life cycle.
Incremental improvements: Delivering fit-for-basin technologies. The initial experience producing unconventional wells in the Eagle Ford proved that accelerated early production was possible using ESP systems, and that several factors were critical to that success. Namely, the toughness and reliability of existing power and control components, the criticality of open collaboration between the operator and ESP supplier, and the opportunities to improve the reliability of wet components to mitigate the effects of pumping abrasive and slugging multiphase flow.
To enable additional changes for unconventional well requirements, a bespoke and unique engineering process also was developed, leveraging digital design
tools combined with supercomputing power and optimization engines to fine-tune pump and stage geometry. This vastly improved lift performance while minimizing the negative impact from free gas and solids. Innovative design and manufacturing, and rapid prototyping tools enabled shortening of the development cycle, as best digital designs could be manufactured and tested immediately at the Schlumberger Qualification and Testing Facility in Singapore. As a result, the second generation quickly followed, and the ESP configuration included the D1050N, the first mixed flow pump stage for low rates, with a recommended operating range of 300 to 1,650 bpd at 60 Hz.
Control algorithms were automated and built into the firmware for gas lock protection in the motor controller. Combined with the availability of 24/7 surveillance and remote control, and the reliability improvements in wet components (pumps, gas handlers, gas separator), the algorithms enabled significant improvement in uptime and run life of ESP systems.
Although the success rate of riding through low- or no-flow events improved substantially, resulting in increased production, up-time and run life, mechanical failures continued to occur, due to excessive stress on the system. Each failure contributes to continuous improvement efforts, aimed at identifying the next potential weak point and developing solutions, such as manufacturing and an improved protector configuration.
The lessons learned, and corrective actions proven, in the first unconventional ESP installations in the Eagle Ford, were implemented across North America’s unconventional basins. There, they faced more challenges, and these challenges differed from basin to basin, and even from field to field within a basin.
For example, in one field in the Williston basin, erosion from proppant flowback caused most ESP failures, but in another Williston basin field, the biggest challenge was corrosion.