Extending ESP service life in unconventional wells

Mounting economic pressure has added urgency to the unconventional community’s long-held directive to increase production and continue development of available reserves, while reducing lease-operating expenses (LOE). To that end, and with shale wells requiring a strategic approach toward the application of artificial lift technology, the deployment of electric submersible pumps (ESP) has become a ubiquitous tool in operators’ efforts to meet investor demands.

While ESP-driven artificial lift strategies have contributed noticeably to enhanced estimated ultimate recoveries (EUR), extending the cycle time of submersible pumps has become a taxing proposition. Between abrasion-related damage associated with tight annular clearances, high sand loadings, and motor failures resulting from gas slugging, premature ESP failures have become habitual, and grudgingly accepted, throughout the unconventional sector. Conventional expectations have held that a three-to-six-month run life was considered an acceptable failure frequency for ESP systems used in the Delaware subset of the West Texas-New Mexico Permian basin.¹ Regardless of the root cause, each failure can cost up to $180,000 in added workover and capital expenses, as broken out in Table 1.

Heavy concentrations of formation and frac sand have been cited as among the leading causes of ESP failures, so much so that some shale wells have required replacement pumps as often as three to four times a year.² Tight economic margins have led to worsening sanding problems, as operators have been forced to switch from premium resin-coated and ceramic proppant to less costly, but more abrasive, pure frac sand.

Fig. 1. The full suite of ESP protective technologies installed within a production string.

The negative consequences of sanding and other failure modes are significantly increased by unavoidable ESP shutdowns required for general maintenance, and operational activities consistent with field level operations. While these routine ESP shutdowns are common across both the unconventional and conventional sectors, the former is distinguished by plays like the North Dakota Bakken, where unreliable electrical grids frequently lead to interruptions and the delivery of “dirty power,” with abnormalities such as voltage and frequency variations, low power factors and surges.

In response to excessive operating and capital costs, as well as delayed production, a suite of new-generation technologies now provides ESP manufacturers a veritable insurance policy against abrasion and sanding failures, Fig.1. Moreover, an emerging technology aims to mitigate persistent gas slugging issues, which can cause overheating and the eventual failure of ESP motors. With these system-agnostic advancements, ESP run life can, conceivably, be extended 1.5 years on average.

PREVENTING CONVEYANCE DAMAGE

It is generally held that 3°/100 ft is the maximum permissible dog leg severity for conveying an ESP in a horizontal well, with more severe deviations requiring further evaluation, such as bending moment analysis. Consequently, in unconventional wells, ESPs typically are installed above the kick-off point, where casing programs often can leave little annular space for running in hole. The space restrictions are especially conspicuous in the Permian basin, where 5½-in. casing is landed primarily at kickoff.

The often-tight annular clearance between the casing ID and production tubing OD during conveyance and retrieval has been cited for all manner of abrasion-engendered damage to highly vulnerable ESP power cables. Together with the delicate motor lead extensions (MLE)—the smaller cable terminated into the pothead motor connector—power cables represent 40% to 60% of total ESP capital costs, while also accounting for upward of 45% of ESP failures. Often, transit voltage conditions, aggravated by frequent starts and stops, exacerbate abrasions and other seemingly minor damage, eventually blowing out the cable.

Fig. 2. Cross-coupling cable and MLE protectors thwart abrasion-related damage to delicate power cables in tight annular clearances.

Traditionally, ESP systems, including some 90% of the submersible pumps employed in the Permian basin, have relied on single-use stainless steel/monel bands with clip attachments to support cable weight. The bands offer no protection against mechanical abrasion, and these thin strips of metal, likewise, are prone to breaking off and falling downhole when installing or pulling ESP equipment. Furthermore, properly securing the cable to the production tubing usually requires no less than three bands/joint of tubing.

Cross-coupling, cable and MLE protectors offer a more reliable option, in that they are secured at multiple points to eliminate shifting or rotating under loads, or when in contact with casing, Fig. 2. They offer a custom-fit cable support based on cable and production tubing dimensions, while providing protection against mechanical abrasion, and most often can be deployed multiple times. Typical installations require a single protector across the coupling of the production tubing, with optional mid joint protectors for severely deviated applications. Available in stamped or cast versions and applicable for all ESP models, the proven cable and MLE protectors have been shown to reduce risks and costs, while increasing opportunities to extend production.

TWO-PRONGED SAND MANAGEMENT

Historically, sand control was generally associated with high-permeability sandstone and equally unconsolidated formations in conventionally produced reservoirs. However, between formation cuttings and frac sand loadings of up to 5,000 lb/lateral ft, multi-stage unconventional completions have further delineated sand management, particularly with respect to ESP systems. While manufacturers have made tremendous strides in addressing the abrasion of internal pump components through exotic coatings and stage geometry, excessive sand volumes, nonetheless, represent one of the leading causes of ESP failures. Sand-related problems are especially pronounced during the unavoidable ESP shutdowns, as a result of sand fallback.

Fig. 3. Sand filtering out of the tube-like Sandguard tool as the ESP is re-started.

Prior to installing an ESP, operators perform flowback operations and clean the well of debris using additional methods, such as jet pumping or similar procedures, yet secondary sand remains in solution within the production stream. Consequently, when an ESP is shut down, sand will inevitably fall out and aggregate in the idled pump as no preventative barrier stands between the tubing and the ESP discharge. Attempting to re-start a pump, with the housing and impellers clogged with sand fallback can result in catastrophic damage, in the form of broken shafts, excessive mechanical torque and failed motors. Usually, the only recourse is a costly workover and a new ESP system.

The development of a dual-approach sand management system is designed to mitigate the catastrophic results of sand fallout, when an ESP is off-line, as well as the abrasive wear of sand-infused production fluids. Applicable for all ESP models and flowrates, the two-part system comprises a uniquely engineered tool positioned in the tubing string above the pump discharge to capture and isolate sand that has fallen into an ESP during shutdown. The technology, containing proprietary diverter and flush-out systems, is installed singularly or in unison with a sand separation tool (de-sander) installed below the ESP to collect sand during production and before it is allowed to enter the pump.

A rather unorthodox approach to sand control, the autonomous self-cleaning SandGuard tool comes into play after residual sand has already produced through the ESP. The technology is designed with exclusive filtration that collects fallback sand, which, in turn, is segregated into an inner chamber, Fig. 3. When production flow halts, a valve within the tool seats, diverting solids-laden fluid to the outer chamber, where a proprietary filtration device filters and segregates the sand, preventing it from entering the internal components of the pump. Unlike standard valves, however, the tool is never in communication with the wellbore.

Once the pump restarts, flow flushes the solids from the chamber and up to the surface. At that point, the re-engaged ESP is started against a filtered production stream within the ESP system.

Eliminating sand deposits enables continuously smooth re-starts, thereby avoiding the torque, abrasion and heat-related issues associated with attempting to restart a solids-plugged pump. Since the introduction of the sand management technology, field data from more than 3,500 installations have shown up to a 1,200% extension in ESP run life. The system, likewise, shortens the time for wellbore cleanup or eliminates the need for an alternate form of artificial lift to rid the well of sand and other residual solids.

During production, the new-generation Cyclone vortex separation system, positioned below the ESP, uses centrifugal force to separate sand, with the now-clean fluids diverted through the discharge ports and into the pump intake. Consequently, a cleaner production stream is produced through the pump, while the separated sand and other solids fall through, or are captured, in the tailpipe tubing. Depending on the well configuration, the captured solids are either flushed down the rat hole or delivered to surface for disposal.

DIFFUSING GAS SLUGS

Another prevailing problem in the ESP sector, and one well documented in the literature,^3,4,5,6 has been dealing with the economically crippling effects of gas slugs, which are aggravated in long-reach, low-permeability wells with disproportionate gas-to-oil ratios (GOR). An ESP pulling hard on a shale well with high gas volume fractions (GVF) accelerates coning effects (oil-gas contact), manifested in gas breaking out of solution and morphing into the formation of slugs beneath the pump intake, thereby reducing the amount of liquid flowing into the pump and resulting in a pump lock condition. With this accumulation of gas bubbles hindering the pumping of liquids, the ESP can no longer generate pressure. This leads to a sudden drop in motor amps and increases the risks of low liquid flow past the motor, which consequently results in higher motor temperature. The risks of gas slugs are particularly prevalent in shale plays like portions of the South Texas Eagle Ford, where crude is interspersed within high dry gas and natural gas liquids (NGL) windows, thus exacerbating the challenges of an ESP artificial lift strategy.

Advancements by ESP providers in the form of stage geometries and gas separator and handling technologies enables submersible pumps to handle free gas volumes, up to a typical maximum threshold of around 65% GVF. Gas separators and advanced gas handling systems can effectively produce with 35% to 45% GVF, respectively. Helicoaxial pumps, which are specially configured ESPs, can typically handle up to the maximum allowable 65% GVF. By contrast, wells in the southernmost segment of the Eagle Ford, for example, are characterized with initial GOR of up to 8,000 cf/bbl, according to the latest U.S. Energy Information Administration (EIA) analysis.⁷

Most ESP motor drives, likewise, are equipped with advanced software and programmable logic controllers (PLC) and engineered to shut down the pump, once it is determined that amps have dropped to a certain level, thereby indicating the potential presence of gas slugs. However, the industry has been unsure on how best to proceed, once slugs have been detected. To date, the only viable option has been to wait until the slug passes through the ESP, hopefully enabling the pump to be restarted smoothly. These shutdowns compound the costs of suspended production.

Fig. 4. A comparative analysis of results from the Sprayberry fi eld trial, detailing production and pump intake pressure with and without the phase regulator.

The potential to prevent, rather than mediate, gas slugs to sustain production and reduce cavitation risks has been heightened with encouraging lab and field test results of a bolt-on technology designed to prevent slugging as it enters the pump. The self-explanatory phase regulator has been shown to decrease the GVF, thus delivering a more consolidated and easier-to-lift production stream, and eliminating or significantly reducing the risk of gas locking up the pump.

Basically, the one-of-a-kind technology incorporates a series of high-pressure nozzles encapsulated in a tool designed for high-tortuosity well paths, and adaptable for either ESP or rod pump-enabled production. In an ESP system, the Phase Regulator is installed immediately below the sensor or motor connection, and between the cup packer/discharge assembly and the optional sand separator. Once production is initiated, flow through the tool creates local recirculation or mixing, which reduces the volume of gas in relation to liquids, effectively decreasing the effective GVF. Additionally, the system modularity enables an application-specific solution tailored to the gas-liquids ratio (GLR) of individual well flows.

To quantify output GVF, test protocol analyzed oil flowrates of up to roughly 1,000 bpd with various input gas volumes. A comparative analysis of the inlet and outlet gas volumes showed a substantial reduction in the GVF exiting the pump. For instance, in one test, the outlet GVF was measured at 20% from a 98% inlet GVF. At 67% inlet GVF, the outlet volume was 14%, while at 44% inlet GVF, the outlet dropped to a low of 1% GVF.

Flow tests, likewise, were carried out with the objective of identifying and minimizing the pressure drop across the tool. Results of the tests, which were orchestrated to characterize pressure drop under multiple flow conditions, demonstrated appreciable decreases in total pressure drops across the tool.

Results seen in the lab were validated in a recent field trial in a 31-stage, 15,525-ft MD well in the Permian basin’s Sprayberry trend, which had been immediately turned-in-line with ESP-centered artificial lift. Following multiple daily shutdowns caused by gas locking, the ESP was pulled and retrofitted with a Phase Regulator, with the latest data available showing the well producing without interruption for more than three months. Key takeaways from the field trial were increased production and an exceptional decrease in inlet pressure, once the Phase Regulator was installed, as illustrated in Fig. 4.

Further investigations are underway to better understand the physics of the novel technology and how it can best be optimized. One possibility is to push the tool farther into the lateral to break up migrating gas well before it reaches the pump inlet, with the aim of further increasing production rates and EUR.

MAXIMIZING RETURNS

Delaying intervention and sustaining production beyond normal shutdowns obviously reduces LOE and help maximize asset value. Moreover, the full suite of protective technologies enables existing artificial lift equipment to operate effectively in more abrasive, gassy and similarly challenging applications, thus maximizing the production potential of deviated unconventional wellbores.

To point: The application of power cable protection, and integrated sand and gas management systems, extends the life of critical ESP production equipment, significantly reducing capital and operating costs, while enhancing EUR and the operating envelope of existing equipment, and increasing the revenue stream. 

REFERENCES

1. Oyewole, P., “Artificial lift selection strategy to maximize unconventional oil and gas assets value,” SPE paper 181233, presented at the SPE North American Artificial Lift Conference and Exhibition, The Woodlands, Texas, Oct. 25–27, 2016.
2. Thompson, J.H., J. Dwiggins, and S. Muster, “Technology solves sanding problems,” American Oil & Gas Reporter, February 2016.
3. Kadio-Morokro, B., F. Curay, J. Fernandez, and V. Salazar, “Extending ESP run life in gassy wells application,” SPE paper 185272, presented at the SPE Electric Submersible Pump Symposium, The Woodlands, Texas, April 24–28, 2017.
4. Zachary, S.C., T. Madrazo, C. Rhinehart, B. Hill, C.M. Grimm, and C. Smith, “New ESP gas separator for slugging horizontal wells,” SPE paper 185147, presented at the SPE Electric Submersible Pump Symposium, The Woodlands, Texas, April 24–28, 2017.
5. Jones, R.S., “Producing gas/oil-ratio behavior of multi-fractured horizontal wells in tight oil reservoirs,” SPE paper 184397, SPE Reservoir Evaluation & Engineering, Vol.1, Issue 03, August 2017.
6. Bagci, A.S., M. Kece, and J. Nava, “Challenges of using electrical submersible pump (ESP) in high free gas applications,” SPE paper 131760, presented at the CPS/SPE International Oil & Gas Conference and Exhibition, Beijing, China, June 8–10, 2010.
7. U.S. Energy Information Administration, “EIA updates Eagle Ford maps to provide greater geologic detail,” Jan. 21, 2015.