Electrical Submersible Pumping (ESP) is the most suitable artificial lift method for producing high flow rates, however, there are shortcomings with the standard ESP technology in slim well applications. On the one hand, well production is often curtailed due to pump performance limitations and on the other hand, long strings and tight clearances make the current slim ESP systems more prone to failure when compared with larger diameter ESP applications. This paper discusses the development and qualification of a new type of High-speed High-rate Slim ESP system that can be installed inside liners as small as 4 ½" and that is able to produce twice the rate of standard ESP technology. This new technology is also designed to increase both performance and reliability of the system. There are many challenges associated with the development of an ESP able to produce high rates in small diameters; this paper discusses mechanical and hydraulic considerations and the evaluation of trade-offs between efficiency, rotational speed and production rate, among others. This paper also discusses the testing and qualification plan, as well as the results obtained during the factory acceptance testing phase.

Sizing electric submersible pumps (ESPs) for unconventional wells presents new challenges compared to traditional applications, typically conventional, vertical wells. These challenges are due to the highly dynamic, rapidly changing nature of unconventional wells compared to conventional wells. Traditional ESP sizing software is not structured to design for dynamic conditions, but rather a single point in time. The objective is to design an ESP tool fit for unconventional design applications. Because of the rapidly changing conditions of unconventional wells, it is difficult to balance the lifetime sizing needs of the equipment with needs of the equipment during peak demand. Changing flow rates, water cuts, pump intake pressure (PIP), and gas oil ratio (GOR) have a great effect on stage size, total dynamic head (TDH), and motor horsepower (HP) requirements at different points over time. The new design tool will allow the user to upload a well type curve and help chose a pump and motor combination by calculating different TDH and motor horsepower requirements for each day over the life of the well. Optimized ESP sizing will allow oil and gas operators to install one initial ESP at the completion of the well which lasts until production rates have declined to the conversion point of a lower rate form of artificial lift. This has significant cost savings implications both for capital and operational budgets, by avoiding overspending on oversized equipment upon the initial install of the wells, and greatly reduced the work of the operations team by eliminating workovers needed to downsize equipment. The use of this design tool allows much more rigorous reviews of vendor designs, to avoid over sizing equipment while still capturing high initial production rates during the early production life of the well. ESPs designed using the new design tool will be compared to historical ESP designs provided by the vendors on analogous wells. Production numbers, run life, and historical ESP data streams will be compared between wells designed using the old methodology vs the new design tool.

Electricity is the lifeblood of the Electric Submersible Pump (ESP), the Variable Frequency Drive (VFD) is the heart that keeps it going, the power cable is the artery that provides the blood and the motor is the equivalent of the body that moves. As Doctors, if we looked at our system "would we pass our annual physical exam"? Surprisingly, there is no specification in our industry for the ‘blood’ or electricity we provide to our ESPs, a shocking (pun intended) omission when most operators desire increased ESP runlife. This paper will identify the key aspects (what and why) of healthy power going downhole and put forward a proposed specification. In the 2017 ESP Symposium a breakout session was run that looked at downhole power quality (PQ) and posed the question "Is our operating environment worse than other industries and do we apply the best practices from other industries?". The short answer was that our operating environment is extremely challenging and that we have not adopted the learnings that other industries have applied. As part of the breakout, these key learnings were presented. There was overwhelming agreement in the room that a downhole PQ specification is required. Volunteers were solicited to work on a committee to put together such a specification. This paper will illustrate the best practices from other industries and put forward the rationale and a practical methodology for applying PQ best practices to ESPs. The key aspects of PQ will be presented in layman's terms so that this work can be easily understood by petroleum engineers using ESPs. Many of the PQ improvements can be implemented retroactively at surface and can provide benefit to existing ESPs as well as provide a basis for technical requirements as part of the surface and downhole specification for new wells. The consequences of poor power quality are ESP component failures (penetrator, cable, splice, MLE / pothead, motor end turn, motor bearing, sensor, shafts) and short runlives. This paper will put the information and practices in the hands of the operator to act to improve ESP runlife.

The effect of Variable Speed Drive (VSD) waveforms on electrical motors is generally well understood; however, typical industrial solutions fail to adequately protect specialized ESP systems, as ESP motors cannot be drive-duty rated. This paper examines VSD/ESP systems, discusses how switching transients and high frequency content may manifest themselves via the carrier frequency of the VSD, addresses the harm those transients may cause to ESP systems, and provides solutions that can mitigate related ESP failures. Dismantle, inspection, and failure analysis of the VSD-powered ESP equipment indicated that there was an underlying electrical issue with these systems, thus comprehensive power quality studies were conducted. Data was collected on unfiltered VSD outputs, after the installation of Sine Wave (line to line) filters, and after the installation of Common mode (line to ground) filters. Current and voltage data was collected using Fluke 1750 power quality analyzers, as well as Tektronix THS3024 and Yokogawa PX8000 oscilloscopes with appropriate high frequency test probes. Spectral analysis (also known as harmonic analysis, or frequency domain analysis) was then performed on the collected data, from which corrective actions were determined. Spectral analysis indicated that even on sine wave filtered systems, there was always significant common mode current present. While these currents contribute relatively little to Total Harmonic Distortion between 20th and 73 rd harmonic (dependent on carrier frequency), it was found if their individual resultant amperage was greater than only 0.3 amps L-G, ESP failures would occur. Failures were caused by bearing fluting; feedthrough and penetrator arcing; stator end turn failures; skin effect heating of cables; and MLE, pothead, or splice insulation failures. Due to the specialized application of ESP's, motor design changes have not been readily implemented to improve their resistance to high frequency electrical content. Therefore, the only reasonable solution is to improve VSD output power quality to conform to IEEE 519-2014 specifications in the high frequency realm, with special attention paid to reducing harmonic content beyond the 20 th harmonic. The installation of well-designed sine wave and common mode filters provides the most cost effective means to correct poor power quality in ESP systems, thus both types of filters were installed in the case presented. Adding these electrical filters resulted in the ESP mean time between failure to typically double, but most importantly, resulting failure modes were attributed to other non-electrical root causes. During testing, an inspection of ESP wellhead cable utilizing airborne ultrasonic scanning tools was performed. The operator detected the distinct sound of an inverter over 1000' away from the VSD that was powering the ESP. As filters were installed, the sound decreased and was ultimately not detectable. It is believed that with enough research, the use of airborne ultrasound may provide a novel, non-invasive means to detect harmful high frequency electrical signals in ESP systems.

Results from two years of validation testing in the Permian region indicate that replacement of direct current (DC) withstand testing procedures with very low frequency (VLF) withstand and tan-delta diagnostic methods promises to provide more accurate and more informative testing with less detrimental effect to cable integrity. The combination of VLF withstand and VLF tan-delta tests, which can both be conducted using the same equipment from HV TECHNOLOGIES, Inc., can provide a more accurate and less intrusive withstand test and a quantitative estimate of cable integrity and defect pattern. Four properties computed from tan-delta measurements, including tan-delta mean, tip-up, tan-delta deviation stability, and tan-delta skirt stability, are examined and upper and lower bounds for acceptance testing are developed for cable testing in the artificial lift industry. For tan-delta mean and tip-up, Korean Electric Power Corporation (KEPCO) degradation classifications should be adopted to enable end-users to make informed risk assessments about cable reuse. In light of a lack of information on the practical significance of stability values, KEPCO criteria for stability should be adopted to identify highly degraded cables without overly pessimistic assessment of cable condition and subsequent needless rejection of good cables. It is feasible to further refine these testing criteria using multi-feature models based on cable run-life and to diagnose cable defect patterns using multi-feature models. Proven methods used in the power distribution industry should be adopted to create artificial lift specific testing criteria and cable run-life models using industry run-life data.

The artificial lift system selected to produce the Jubarte Field uses high-power and high-flow-rate subsea electrical submersible pump (ESP) systems with gas lift as a contingency in case of the need for ESP replacement. The gas lift mandrels are installed in the production well completion. The ESP systems are rated for 1,500 hp at full load and were deployed inside caissons constructed on the seabed, located 210 m downstream of the main production wellhead. The integrated unit is called a pumping module or módulo de bombeio (MOBO) in Portuguese. Industry perception of average ESP run time, high replacement costs associated with intervention of the subsea ESP systems, and the limited track record available for comparable systems at the time of field development required a comprehensive approach to improve on system reliability from the beginning. The use of advanced technologies to extend the traditional concept of industrial process control to the management of the MOBO systems allowed continuous monitoring of ESPs to maintain operation within the design envelope. The development of a complete "ESP culture" became a key element connecting the different teams involved in the operation. This required new procedures to be developed, new monitoring and surveillance teams introduced, and, most of all, management of change practices introduced to avoid issues related to the rotation of personnel involved in the operation of the ESP and related systems. The synergies created allowed the provision of timely solutions to face the challenges across the complete production system. The gap study conducted at the beginning of the Jubarte ESP development identified many barriers and conditions preventing increased system reliability and affecting economic viability of such a large-scale project. This paper builds on such analysis using the operational data gathered during the 8 years of ESP operation, shows improvement in mean time to failure during the period, presents typical failures encountered in equipment and processes, introduces the de-risking process followed to strengthen the system, and provides the reasons behind the enhancements made. Explanation of the measures proposed to significantly improve the reliability of these 1500-hp subsea ESP systems and the reasoning behind the enhancements will facilitate future projects of a similar nature.

The petroleum industry has made significant changes and improvements to extend the run life and the operating envelope of ESP systems. Design improvements have dominantly focused on motors, seals, and pumps through improved material selection, bearings, etc.; changes accepted and deployed by operators without consideration of technology which can be applied to cable design and packaging. The ESP power delivery system (downhole cables and associated components) have remained largely unchanged for nearly 90 years. The ESP cable system is responsible for greater than 20% of ESP failures, with a large portion occurring early in the system life (<2 years). In the last 10 years, offshore cable system failures have risen to more than 30% due to installation in harsher operating conditions. In 2015, two major operators and a rigless ESP provider launched an extensive R&D program to develop a "life-of-well ESP" cable system to complement Wireline Retrievable ESP (WRESP) systems planned for deployment in West Africa and the Middle East. The logic was simple – if a life-of-well cable system could be developed, this could be used with a WRESP to provide rigless ESP operation throughout the life of a well, greatly reducing intervention costs while maximizing production. Once developed, it became apparent that the same technology could also be used in conventional ESP deployments to eliminate cable system failures while reducing the lost rig time and HSE risk associated with traditional ESP cable installations. The proposed ESP cable system is essentially a repackaging of existing, proven components that have been adapted and qualified to the high voltage and high current requirements of an ESP. This new topology was rigorously tested to industry standards by a joint committee of operators under laboratory and field conditions to confirm the thermal, mechanical, and electrical performance of the system. An installation test was performed in an onshore well to validate reliability of the cable system, packer/wellhead penetrations and downhole splices. Qualification testing has proven that a "life-of-well" ESP cable system is achievable. Discussion with other operators indicates the system to be scalable to both onshore and offshore applications for improved reliability at a minimal additional cost.

Most Malaysian oil production is heavily reliant on gas lift. Aging assets experience declining lifting efficiencies due to depleting reservoir pressure and increase in water cut. This impact PETRONAS' capability to deliver national hydrocarbon production targets. New developments and further improvements to gas lift facilities are likely to erode the economic value of assets without even considering the potential time impact due to the complexity in delivering gas compression upgrades or gas import projects. PETRONAS' primary goal within Malaysia is to sustain production and maximize the remaining recoverable reserves. To realize this target it is widely acknowledged that the company must think differently. Alternatives to gas lift have been considered for rejuvenation of brownfield assets and development of marginal assets using a ‘fit for purpose' approach resulting in some relatively low Capital Expenditure (CAPEX)/Operating Expenditure (OPEX) solutions. One such method identified was Through Tubing Electrical Submersible Pumps - Cable Deployed (TTESP-CD). TTESP-CD technology is a game changer that can challenge the boundaries of traditional engineering with a truly rig-less deployment of an ESP system with full compliance to API/ISO requirements and demonstrating up to 70% cost savings over conventional offshore ESP installation methods. The TTESP-CD innovation helps in improving the asset value through gas prioritization, gas lift reallocation, flaring reduction and increase in lifting efficiency. TTESP-CD is also in line with the company digitalization concept due to the baseline data available from surface and downhole equipment. This technology has been declared a success through pilot deployment in an offshore field within the Sarawak Basin with an incremental gain of 250BOPD, 0.3MMSTB in reserves acceleration and 22 months run life as of Feb 2019. This has been a key step for building confidence in the wider application of the technology. Lessons learnt and best practices from the pilot implementation have been applied to ongoing and future projects and serve as a good foundation for further development of the technology. To date, approximately 20 candidates for the TTESP-CD application have been identified for replication in Malaysia within the next 2 years across 3 regions. There are various challenges faced when implementing this technology on aging offshore assets that was never designed for ESPs which include; space availability for deployment equipment and surface electrical equipment, power availability and distribution, instrumentation, data transmission, structural integrity and operational mind set. PETRONAS sees a bright future for TTESP-CD application and technology which includes layer to layer matrix dump flood, interim production and well unloading/DST well unloading.

Qarun Petroleum Company (QPC), a joint venture between the Egyptian General Petroleum Corporation (EGPC) and Apache Egypt, operates over 350 ESP wells in brownfields across the Egyptian Western Desert. QPC's oil production is heavily dependent on the performance of waterfloods and artificial lift systems. In recent years, QPC entered a development campaign in the West of Nile (WON) region, an area located west of the Nile River approximately 159 kilometers from Cairo. The fertile land has ready access to irrigation and therefore long been developed as an agricultural area, surrounded by densely populated villages. Land access is restricted and operations must be conducted to ensure minimal impact to the environment. Oilfield development in WON is challenging and required alternative solutions to conventional waterflood operations. QPC engineers turned to ESP Powered Injection (ESPPI) systems as an alternative to traditional waterflooding and re-engineered the technology to overcome the operational, economic, and environmental challenges. ESP Powered Injection (ESPPI) systems utilize conventional ESPs in combination with a bypass system (Y-tool) and an injection string to provide water production and injection support from a single wellbore to one or more wells in the same injection pattern. The system eliminates the need for surface pumping, water separation, storage, and flow lines. QPC has successfully installed and presently operates nine (9) ESPPI systems in the environmentally sensitive WON region of Egypt. This paper aims to detail the specifications and functionality of ESPPI systems, main challenges and benefits derived from closed monitored installations and operational surveillance, and the economic advantage of its application for QPC.

Electric Submersible Pumps (ESPs) are severely affected by free gas entering into the pump, which can cause significant degradation in pump performance. Gas locking (i.e., a gas bubble blocking the fluid from passing through the impeller) results in frequent shutdowns and restarts, thereby increasing the risk of premature failure. The result is unstable production due to ESP shutdowns caused by underload or high motor temperature. Historically, the industry has used shrouds, reverse flow gas separators, dynamic gas separators, and more recently, multiphase pumps to handle the gas. Such multiphase gas handling technology adds cost and requires additional power. Recently Oxy Permian EOR installed a multiphase encapsulated production solution to separate the gas from the liquid in the wellbore. As produced fluids pass the pump at high velocity, the heavier liquid falls back into the shroud in a low-velocity area between the tubing and the top of the shroud, allowing the gas to continue to the surface. This system has proven to separate the gas from the liquid effectively, stabilizing operations within a certain operating window. In this paper, we share field examples showing the results achieved and how uptime improved over the last year. Twenty-four (24) systems have been installed in the Permian Basin with a 99% reduction in the number of shutdowns. All have had improved operational performance, with an average 30% improvement in drawdown and a 16% increase in total fluid production. These particular fields are constantly being injected with CO 2 , which presents even more challenging conditions for ESPs than merely solution gas. As the CO 2 enters the wellbore, the liquid stream composition changes, as does the gas/liquid ratio (GLR), making it difficult to draw down and function consistently over time. Many different systems have been tried with varying degrees of success. This system has proved to be successful in attaining our objectives of higher drawdown, stable operations, and fewer failures.

Caisson-ESP systems provide a cost-effective means of seafloor boosting. These systems are being applied in applications that requires the ESP to handle unusually higher gas fractions. The objective of this work is to investigate the gas-handling effectiveness of helicoaxial ESP stages used in combination with standard mixed flow pump stages. The results show that helicoaxial stages greatly extend the gas-handling capabilities of an ESP system and eliminate gas-lock over a wide range of conditions. It is well known that high gas fractions and viscous fluids degrade centrifugal pump performance. Additionally, gas locking occurs due to gas entrainment inside the pump causing operational problems. This study investigated the use of 4 helicoaxial pump stages at the entrance of a 48-stage ESP. Testing was performed at the Shell Gasmer Caisson-ESP Facility in Houston, Texas. This full-scale test loop can test ESP's over a wide range of conditions. The test matrix covered viscosities from 2 to 300 cp at different speeds, flow rates, intake pressures and gas volume fractions (GVF). Multiphase flow and viscosities affect the performance of the ESP pump system, degrading pump performance. The test results demonstrate that the high-flow helicoaxial pump can handle up to 73% GVF without gas lock. Pump performance improves at higher intake pressures and pump speeds with less pump degradation. In two-phase flow conditions, as viscosity increases, the pump degradation decreases thus improving gas-handling operations. A homogeneous model has a fairly good agreement with pump performance up to 30% GVF with minimal pump degradation. This work provides an important field-scale validation of the helicoaxial pump hydraulic performance at high GVF with high viscosity fluids. This has benefits to the deep-water industry, which is seeking more affordable seafloor boosting options.

The induction motor has dominated the global ESP market for decades; however permanent magnet motors (PMM) are gaining acceptance for use in artificial lift. Some PMM vendors have made claims of 20% - 30% reduction in electric operating costs, improved efficiency, and wider applications for today's challenging wells. This paper describes a testing program conducted to understand the characteristics of PMM's, to verify vendor claims and evaluate how to leverage this downhole motor technology to reduce operating expenses. Two International Oil Companies (IOC's) partnered to sponsor a Motor Evaluation Test (MET) program from 2014 - 2015. A motor test protocol was drafted, and ESP motor sizes of 100 HP 450 series were targeted for evaluation. Six ESP vendors agreed to participate, contributing their motor and variable frequency drives (VFD). Four induction motors and four permanent magnet motors, each partnered with the vendor supplied VFD, were evaluated. The objective of the testing was not to differentiate the vendor's products, but to understand the differences in the motor technologies. An independent third-party witness was selected from industry experts to supervise the testing, ensuring to follow the test protocols, manage data security, and test validation. The results were analyzed, documented and reported to vendors by the sponsor companies. The PMM was found to be a cost competitive alternative to the IM for equivalent ESP installations with a VFD. In existing fields, a phased-in approach to replace failed IM with PMM may be economic. For new field developments the PMM offers the benefits of power savings and use in challenging well bore configurations. Alternatively deployed (AD) ESP with PMM may offer reduced well intervention cost as well an improved ability to pass through build angles that would challenge the longer IM system.

The application of Electric Submersible Pumps to facilitate well production is a long established production technology; however, the onerous requirements of offshore environment makes the current ESP technology and the associated business model not fit to meet these challenges. An enabling technology for those deep water fields, where physical constraints of gas lift starts to be very challenging and for a drastic improvement of reliability in exisiting offshore fields, is what is needed. A Statoil development for a high speed ESP (AESP) is ongoing to primarily re-design the current machinery arrangements so that many of the key failure modes are eliminated and to tailor the design to high value wells, using an engineered approach. The AESP development focuses on 6000 rpm high speed motor and pump technologies, introduces a seal-less coupling between pump and motor, to build a robust artificial lift system. The goal is to develop an ESP system with 90% survival probability at 5 years.

The V-Pump is a radically new type of pump which has proven to deliver superior performance compared to conventional ESPs in conventional and unconventional wells. Unconventional wells producing at 75+% GVF (based on daily production figures), can often slug liquid followed by very high GVF fluid such that the pump must be capable of handling a very wide, indeed extreme range of fluid conditions. Different wells seem to cause different slug conditions, possibly due to the geometry of the horizontal section and hydraulic fracture network. The V-Pump has been able to work effectively throughout the GVF extremes which occur on such wells. The V-Pump has sand erosion resistance very much higher than previous pump technologies. The V-Pump is expected to be an outstanding pump for high viscosity fluids, with testing in flow loop up to 13,000cP, but has still not been deployed in a high viscosity well, expected soon. It is designed and flow loop tested as a SAGD pump. The V-Pump has operated with high percentage of sand both in flow loops and producing wells; the V-Pump can be used in unconventional wells with high sand concentration and high GVF. The development of this pump has taken a few years with a great deal of flow loop testing and field trial testing. This paper mentions some of the development work, flow loop testing, and case studies; the difficulties of replicating harsh field conditions in pump test flow loops, both the sand erosion loop and the multiphase loop.

Objective The purpose of this paper is to share the experience obtained during the past 15 years, with respect to the re-use of motors, the considerations of the applications and the resulting knowledge from the processes of inspection and unit disassembly, which led to the implementation of improvements in the design of the motors used in Pan American Energy in the Golfo San Jorge basin.

Maximizing production in high gas wells produced with Artificial Lift Systems is one of the greatest challenges operators face daily. The accumulation of gas inside an Electrical Submersible Pump (ESP) creates a condition called "Gas Locking" which prevents fluid production and leads to system shutdown. Multiple shutdowns and frequent Gas Locking negatively affect the runlife and profitability of ESP systems. However, the impact of gas accumulation in ESP applications can be mitigated by implementing intelligent frequency control software included in Variable Speed Drives (VSD's) specifically designed to control and protect ESP's. Baker Hughes has designed an intelligent solution to solve the problems caused by gas locking in ESP systems: a variable speed drive with built-in gas control software that can mitigate and clear gas locking, manage draw down to minimize formation face damage, and avoid gas locking during extended gas slugs to improve production. This paper will present the results of the variable speed drive's gas control software implementation in a high gas well in Colombia. The case history presents a mature well with water injection secondary recovery operated by Ecopetrol in partnership with OXY. The ESP system operation was monitored before and after the VSD's gas control software activation. The following significant benefits in ESP reliability and increased production were achieved: 14% daily production increase, stable operation, lower operating downhole temperatures with no high temperature events, lower pump intake pressure (decrease of 170 PSI) and zero system shutdowns due to gas locking.

Like all production companies Occidental Petroleum (Oxy) is continually searching for new and creative ways to increase production and lower operating costs. Artificial Lift is a major focus due to the large annual expenditures on equipment and electrical power consumption. Oxy faces unique challenges in its Enhanced Oil Recovery (EOR) operations in the Permian Basin where miscible carbon dioxide (CO 2 ) and water flooding are utilized resulting in wells with high gas to liquid ratios (GLR) that challenge the gas handling capabilities of electrical submersible pumps (ESP's). While initially designed for high temperature steam flood applications Geared Centrifugal Pumps (GCP's) have several design advantages that make them attractive to use as an alternative lift option. A GCP is an artificial lift system which utilizes a Progressing Cavity Pump (PCP) drive head and rod string to drive an ESP style centrifugal pump through a downhole speed increasing transmission. The GCP design has the rate capacity of an ESP, but eliminates a downhole motor and power cable. By eliminating the downhole motor the GCP design delivers the ability to run a dip tube below the pump without a shroud through the perforations which should improve natural downhole gas separation. In order to test the performance of the GCP system Oxy chose to conduct a trial in three Permian Basin wells in one of its miscible CO 2 floods. The key objective of the trial was to compare the performance of the GCP system with the previously installed lift methods to confirm if there is an opportunity to increase drawdown, increase daily up time, improve system efficiency, and increase run life. As of the writing of this paper two GCP systems have been installed as part of the trial with one of the installations still being in operation. This paper will present the details of the trial and the results that have been obtained thus far as well as challenges and lessons learned.

Seal/protector sections can be difficult to understand and properly apply. The components in seal/protector sections can fail for reasons that are not fully understood or obvious. Typically, the driving factor for seal/protector section application is temperature (thermal) cycles. Some advocate the use of more mechanical shaft seals, while others advocate parallel chamber configurations, allowing for more expansion/contraction. The question is, "What is the correct approach to take for seal/protector selection?" This paper will attempt to address some of these issues, and focus on seal/protector section failures and areas for improvement. This paper will also give an overall explanation of how seal/protector sections should work and the problems that are often encountered. A current practice in the industry is to apply tandem seal/protector sections as a method of redundancy and in theory, increasing reliability. Advanced materials developed for the harsh temperature environments may be helpful in adapting a single seal section capable of providing superior motor protection in comparison to tandem seals.

This study details the approach adopted by Pan American Energy to reduce power consumption in ESP applications. It is a holistic analysis of the main components that contribute to a significant increase in the system's global efficiency and the solutions implemented, including the use of: – Low Current Induction Motors (IM) – Permanent Magnet Motors (PMM) for slim applications (3.75" diameter) – Suitable pumps – Variable speed drives (Compatible for IM and PMM) PMM provides several advantages to ESP systems while also improving the efficiency of the overall system. Compared to a similar frame size induction motor (IM) the PM motor length is significantly reduced, and when paired with a variable speed drive it has considerable operational advantages. Additionally, this motor will address applications of higher power requirements that cannot be produced today due to limitations on equipment size. These units deliver a substantial improvement on: – ESP overall efficiency – Power Factor – Motor Power Density – HP available for slim wells – Flexibility of sizing for lifting loads – Installation time reduction The experience in Pan American Energy shows the initial results of the field test units. A strict testing plan was implemented to verify the system performance under different production conditions.

This paper provides field experience for the Caisson ESP Technology in subsea boosting system with emulsions and high Gas Volumen Fraction (GVF) using the high power Electric Submersible Pumps (ESPs) systems. Field experience and experimental performance are compared regarding the effects of high viscous emulsion using conventional high capacity ESP systems and the effect of two phase (liquid & gas) fluids on ESP with new technology for high GVF fields and high viscous applications. The Electrical Submersible Pump (ESP) system is an important artificial lift method commonly used for subsea boosting systems. Multiphase flow and viscous fluids cause problems in pump applications. Free gas inside an ESP causes many operational problems such as loss of pump performance or gas lock condition. The objective of this paper is to understand MVP performance for high GVF and viscous emulsions. This paper provides a summary on the performance comparison for a high power ESP system for viscous emulsions and Multi-Vane Pump (MVP) for high GVF wells for Shell major Projects BC-10. These novel projects continue the long tradition of Shell’s leadership in the challenging deepwater environment. Presented is the capability and effects of viscosity and two phase (liquid & gas) fluids using a 1025 series pumps with a charge MVP in series; as well as a 875 series standard ESP system mixed-type pump, which is a multistage centrifugal pumps for deep boreholes. Extensive testing and qualification of the subsea boosting system was undertaken prior to field application. The subsea boosting system experience for offshore operations is reported with new technology, and the effects of viscosity and two phases in real conditions. MVP and high power pumps were proved to be a reliable technology to use in field application managing GVF higher than 50% and high viscous fluid as high as 1200cp as consequence of fluid emulsion. Correction factors needed to be applied to standard design curves to ensure proper field design at opearting conditions.