Transforming challenging well production through advanced engineering

PABLO GARCIA, OSWALDO RODRIGUEZ, PAVEL SVIRIDOV, JAIRO OCANDO and CARLOS BÁEZ, Levare, USA,  

Artificial lift technology has evolved significantly over time, and the latest development represents a fundamental shift from traditional approaches. Electric Submersible Progressive Cavity Pump (ESPCP) systems combine the proven reliability of progressive cavity pumps with the advanced engineering capabilities of permanent magnet motors. 

Unlike conventional PCP systems that rely on surface drives with sucker rods, or alternative solutions that require troublesome gearboxes, the innovative ESPCP technology eliminates mechanical complexity while maximizing operational efficiency. The system uses specialized low-speed permanent magnet motors (PMMs) that operate between 80 and 500 rpm, delivering the precise torque needed to lift production fluid to the surface. These motors connect directly to progressive cavity pumps without requiring intermediate speed-reduction components. 

The elimination of gearboxes is a major deviation in submersible artificial lift design. Traditional systems utilize standard induction motors coupled with gearboxes to achieve the necessary speed reduction for PCP operation and amplify the torque needed. These gearboxes, however, serve as primary failure points, significantly limiting system reliability and operational life. The advanced PMM technology removes this vulnerability entirely, creating a streamlined system architecture that delivers superior performance across diverse well conditions. 

PMM-PCP SYSTEM OVERVIEW  

The PMM-PCP system represents a breakthrough in artificial lift technology, specifically engineered for challenging and deviated wells, where conventional systems face significant operational limitations. This highly efficient production system integrates a downhole PMM with a progressive cavity pump, delivering exceptional performance in wells characterized by low flowrates, unfeasible to be produced by rod-driven PCP system based on wellbore construction, unstable inflow conditions, heavy and viscous oil production, and high solids content.  

The system's low-speed, high-torque PMM operates within a speed range of 100 to 1,500 rpm while generating torque up to 1,670 lb-ft, effectively eliminating the mechanical complexity and failure risks associated with traditional rod strings, tubing strings, and downhole gearboxes. By incorporating an independent thrust chamber to manage developed thrust loads and other flow devices, such as flush valves to minimize starting torque impact, the PMM-PCP (ESPCP-PMM) system demonstrates superior reliability and reduced operational expenditure through lower power consumption.  

The technology extends PCP application capabilities to highly deviated wellbores previously considered unsuitable for this lift method, while maintaining the inherent advantages of handling up to 50% free gas, 0.6 g/l solids content, and viscous fluids without emulsification. Comprehensive field studies have validated that the PMM-PCP (ESPCP-PMM) system consistently achieves the lowest power consumption per unit volume of fluid lifted, compared to alternative artificial lift methods, establishing it as the optimal solution for maximizing well productivity and operational performance in technically demanding reservoir conditions. 

In areas without a PCP system population, it is essential to perform a thorough characterization of the elastomers. To facilitate this, Levare developed a coupon holder that can accommodate up to four different coupons. This accessory enables elastomer conditions to be assessed at both the pump inlet and outlet by attaching it to the sensor and the pump discharge, respectively. 

ADDRESSING CRITICAL INDUSTRY CHALLENGES 

The ESPCP-PMM system addresses several fundamental challenges that have historically limited artificial lift effectiveness in demanding well environments. High-viscosity applications, where traditional ESP systems experience significant efficiency degradation, benefit substantially from the positive displacement characteristics of progressive cavity pumps. The technology enables effective production from wells with fluid viscosities that would otherwise prove problematic for conventional centrifugal pump systems. 

Solid handling capabilities represent another critical advantage. Wells with high sand production or solid content present ongoing challenges for traditional ESP systems, leading to premature wear and frequent interventions. The ESPCP PMM system's robust design accommodates elevated solid concentrations while maintaining operational integrity and extended run life. 

Low-flow applications, which are often economically marginal for conventional ESP systems, due to efficiency limitations, can become viable with ESPCP technology. Similarly, wells using rod pumping or rod-driven PCP systems that frequently experience failures related to the rod or tubing string can achieve more reliable production with ESPCP. The system maintains high efficiency at flowrates as low as 25 bpd, extending the economic threshold for artificial lift applications while providing operational flexibility across varying production conditions. 

The elimination of sucker rod systems in high deviation or complex wellbore geometries provides additional operational advantages. Traditional surface-driven PCP systems encounter limitations in wells with high dog leg severity or extended horizontal sections, due to rod wear and mechanical stress on the tubing string. The ESPCP system enables effective artificial lift installation in complex well trajectories previously considered unsuitable for rod-driven PCP applications and sucker rod pumping. 

FIELD-PROVEN PERFORMANCE: COLOMBIA SUCCESS STORIES 

CASE STUDY 

Challenge. The oil fields in Colombia are mature assets characterized by poorly consolidated sands, high solids concentration, and well depths and deviations that pose significant challenges for traditional artificial lift systems. 

The primary method, PCP, suffered from frequent rod-related failures, leading to an average system run life of less than six months. These premature failures resulted in substantial production losses and high intervention costs. Alternative solutions like ESP were unsuitable, due to the abrasive, high-viscosity fluid conditions and low flowrates. 

Fig. 1. The PMM-PCP system demonstrated greatly increased run life, with the first installation in a Colombian field operating for 1,015 days—representing a 214% improvement over conventional PCP systems. A subsequent installation in another Colombian field achieved a run life of 990 days, marking a 274% improvement.

Solution. To overcome these challenges, a rod-less, low-speed PMM driving a PMM-PCP was implemented. The deployed solution incorporated several advanced features that optimized performance and reliability. It included a high-torque, low-speed PMM that eliminated the need for a speed-reducing gearbox, simplifying the overall design. An enhanced Flex Shaft was implemented to efficiently transmit torque while transferring the pump’s axial load directly to the Motor Seal, reducing complexity in the downhole assembly. To address vibration caused by the PCP rotor’s eccentric motion, PTFE centralizers were added, ensuring smoother operation. Additionally, a Variable Speed Drive (VSD) with Vector Control enabled stable operation at speeds as low as 100 rpm, further enhancing system flexibility and efficiency. 

Results. The PMM-PCP system demonstrated exceptional performance and reliability and a remarkable increase in run life, with the first installation in a Colombian field operating for 1,015 days—representing a 214% improvement over conventional PCP systems, Fig. 1. A subsequent installation in Loma Larga field achieved a run life of 990 days, marking a 274% improvement.  

Beyond extending operational life, the system also delivered significant financial benefits over a three-year period. Energy consumption was reduced 16%, saving 4 kWh per well, while deferred oil production losses were eliminated, resulting in annual savings of $110,000. Additionally, intervention costs were reduced by $245,000, as the operational period was extended from less than one year to nearly three years. By eliminating rod-related failures, the PMM-PCP system further enhanced reliability, validating its higher initial investment as a more efficient and sustainable long-term solution. 

Summary. Comprehensive field testing in Colombia's challenging production environments has validated the ESPCP system's operational effectiveness across diverse well conditions. The La Cira field, characterized by high sand production that historically limited ESP run life to less than one year, provided an ideal testing ground for the technology's sand-handling capabilities. 

Initial installations incorporating lessons learned from field experience resulted in significant design optimization. The elimination of thrust chambers, based on operational feedback and performance analysis, simplified the system architecture while improving reliability. This direct connection approach, utilizing flexible shaft coupling between the PMM seal and PCP pump, has demonstrated exceptional operational performance. 

Two representative installations exemplify the technology's transformative impact. Wells previously experiencing frequent ESP failures, due to sand production, achieved run lives exceeding 1,000 days with ESPCP systems. This three-fold improvement in operational life directly translates to enhanced production reliability and reduced intervention frequency. 

Field data from over 70 installations across Colombian operations demonstrate consistent performance improvements. Wells experiencing continuous rod failures with traditional PCP systems achieved sustained production with ESPCP installations. The technology's ability to operate effectively in high deviation wells while eliminating rod wear concerns has expanded artificial lift application possibilities in previously challenging well configurations. 

QUANTIFIED ENERGY EFFICIENCY 

Comprehensive power consumption analysis reveals significant energy efficiency improvements across diverse operating conditions. Field measurements demonstrate power reduction, ranging from 30% to 70%, compared to conventional ESP systems, with particularly impressive results in low flowrate applications where ESP efficiency typically degrades substantially. 

Independent operator studies, including detailed analysis by Ecopetrol, document average power consumption reductions of 60% when comparing ESPCP systems with traditional ESP installations using induction motors. These efficiency improvements become increasingly pronounced in low-rate production scenarios, where conventional ESP systems operate outside their optimal efficiency ranges. 

The PMM technology contributes substantially to overall system efficiency. Unlike induction motors that experience efficiency degradation across varying load conditions, PMMs maintain high efficiency across the complete operating range. This characteristic proves particularly beneficial in wells with fluctuating production rates or varying reservoir conditions. 

Energy efficiency improvements extend beyond direct power consumption. The system's ability to maintain high efficiency at low flowrates enables economic production from marginal wells that would otherwise be shut-in or produce below economic thresholds with conventional artificial lift systems. 

ECONOMIC IMPACT BEYOND ENERGY 

The economic benefits of ESPCP technology extend across multiple operational categories, creating substantial value propositions for operators managing challenging well conditions. Power consumption reductions translate directly to operational cost savings, with annual energy costs decreasing proportionally to consumption improvements. 

Intervention frequency reduction represents a significant economic advantage. Wells requiring annual ESP replacements, due to sand production or other challenging conditions, achieve run lives of three years or more with ESPCP systems. This threefold improvement in operational life reduces intervention costs substantially while eliminating associated production deferrals. 

Production continuity improvements generate additional economic value through reduced downtime. Traditional systems requiring frequent interventions result in production losses during workover operations, typically requiring three weeks for system replacement and well re-start. Extended ESPCP run life minimizes these production interruptions, maintaining consistent cash flow generation. 

Workover service costs decrease proportionally to intervention frequency reduction. Wells previously requiring annual interventions now operate for multiple years between services, reducing rig time, equipment costs, and service company expenses. The cumulative effect of these savings often justifies the initial technology investment within the first operational cycle. 

Environmental benefits through reduced CO₂ emissions align with industry sustainability objectives. Power consumption reductions of 30% to 60% translate to proportional decreases in carbon footprint, supporting operators' environmental stewardship goals while reducing operational costs. 

SAFETY ENHANCEMENT: RISK MITIGATION THROUGH DESIGN INNOVATION 

The ESPCP system's design philosophy incorporates comprehensive safety improvements, compared to traditional PCP installations. Surface-mounted dry heads, common sources of rotating equipment injuries, are eliminated entirely. This design modification removes exposure risks associated with surface rotating components while maintaining operational effectiveness. 

Its wellhead design closely resembles conventional terminations, making this solution suitable for deployment in urban areas. Unlike traditional rod-driven PCP and sucker rod systems, it inherently reduces methane gas emissions that typically escape from the stuffing box.  

Electrical safety systems integrated within variable speed drives provide multiple protection layers. Resistance braking systems absorb energy during reverse rotation conditions, preventing equipment damage and ensuring safe operation. These built-in safety barriers operate automatically, reducing dependence on operator intervention during abnormal conditions. 

In addition, a standard safety practice is to equip the cable reel with an electrical safety system that monitors the cable’s condition and integrity, reducing human exposure to electrical hazards. 

The elimination of sucker rod systems removes associated safety hazards during installation, operation, and maintenance activities. Rod handling risks, particularly prevalent during interventions in complex well geometries, are eliminated entirely with the ESPCP approach. 

Standardized electrical safety protocols, consistent with ESP PMM installations, ensure comprehensive protection during installation and maintenance activities. These established procedures, along with new technological devices, serve as safety barriers that minimize electrical exposure risks while maintaining operational efficiency. 

CONCLUSION: STRATEGIC TECHNOLOGY FOR SPECIALIZED APPLICATIONS 

The ESPCP system represents a targeted solution for specific artificial lift challenges rather than a universal replacement for conventional ESP technology. Wells experiencing continuous failures, due to sand production, high viscosity fluids, or complex geometries, benefit substantially from this specialized approach. The technology excels in applications where traditional ESP systems prove inadequate while offering superior performance compared to conventional PCP alternatives. 

The elimination of gearbox failure points, combined with proven PMM reliability, creates a robust solution for demanding operating environments. Field-proven performance across diverse Colombian operations demonstrates the technology's effectiveness in real-world conditions, with run life improvements exceeding 300% in challenging applications. 

Power consumption advantages, particularly pronounced in low flowrate applications, extend economic viability to marginal wells while supporting industry sustainability objectives. The comprehensive savings profile, encompassing energy costs, intervention frequency, and production continuity, creates compelling economic justification for operators managing challenging well portfolios. 

As the industry continues addressing increasingly complex reservoir challenges, specialized technologies like ESPCP systems provide essential tools for maintaining production efficiency in demanding environments. The proven Colombian field experience establishes a foundation for broader global deployment in similar challenging applications, offering operators reliable alternatives for wells where conventional artificial lift systems prove inadequate. 

PABLO GARCÍA is an application engineer at Levare, a position he has held since 2016, where he supports technical operations in the oil and gas industry across various regions. His work is centered on artificial lift technologies, with a strong focus on sizing and troubleshooting electric submersible pump (ESP) systems and progressive cavity pump (PCP) systems driven by downhole permanent magnet motors (PMMs). He holds a degree in electronic engineering from Universidad Rafael Belloso Chacín. 

OSWALDO RODRÍGUEZ has been a senior account manager at Levare International Ltd since July 2021. Mr. Rodríguez previously worked for 15 years at SLB, where he held numerous roles, such as application engineer, sales engineer, field service manager, Sales and Commercial manager and Country manager. He earned a BS degree in electrical engineering from Universidad Central de Venezuela in 2005. 

PAVEL SVIRIDOV is director of Technology applications at Levare US (formerly Borets US Inc.), a position he has held since May 2023. Previously, he worked at the company for eight years, in positions of increasing responsibility, ranging from senior application engineer to director, Technology Application. He also spent time at Borets in Moscow, from November 2011 to March 2015. Mr. Sviridov began his career at JSC Oil and Gas Company Slavneft, working from August 2009 to November 2011. He graduated in 2009 from Tyumen State University in Tyumen, Russia, with a masters degree in petroleum engineering. He is also due to earn an Executive MBA, Business Administration and Management, General, from Texas A&M University in May 2026. 

JAIRO OCANDO has been technical manager at Levare U.S. Inc. since January 2023. He began his career in Venezuela in 2005, working at BCPVEN/Netzsch pumps and then worked on a joint venture between Chevron and PDVSA as a production engineer. In 2011, Mr. Ocando worked in artificial lift systems, providing solutions and technical support to new technologies offered by companies, such as Weatherford, John Crane Production Solutions, BCP-Group Artificial Lift and Baker Hughes. Mr. Ocando earned BS and MS degrees in petroleum engineering from the University of Southern California in 2021. 

CARLOS BÁEZ is senior application engineer at Levare Services Limited, a position he has held for the past 15 years. He also worked at Wood Group in the same position for two years. He has led the market expansion and technical development of PMM-PCP systems in Colombia. He holds a degree in petroleum engineering from the Industrial University of Santander.