Canned Motor Pump Technology for Subsea Boosting Applications

A canned motor pump for technology demonstration in subsea oil and gas systems was tested to provide data to understand the design, modeling and performance characteristics of a canned motor pump operating in multiphase flow. This paper discusses the impact of multiphase flow and fluid viscosity on axial thrust and motor cooling flow characteristics. The technology demonstrator is a two-stage, low specific speed (Ns∼550) centrifugal pump designed to deliver 140 gpm at 600 feet of head at 3930 rpm. The 61 hp canned motor is cooled by a small portion of the pump discharge fluid, which is drawn downward through the motor by pump out vanes on the hub of the second stage impeller. The multiphase test loop is equipped for both water and light oil operation in low pressure and ambient temperature conditions. Testing occurred over a range of conditions to simulate varying fluid properties and operating scenarios. Shaft rotational speed varied between 2000 and 4250 rpm with pump liquid flow rates from 25 to 250 gpm. These operating scenarios were repeated for both water and light oil (∼2 cP) with multiphase flow ranging from 0–20% gas volume fraction (GVF) using injected air. Testing results indicate a detectable impact from the different fluids and GVF’s tested, which can be related to features such as the second stage impeller pump-out vane and regions within the motor cavities. In water-air tests, increasing GVF led to the following: motor input power reduced by 5%; axial thrust increased by 100%; motor cooling fluid temperature rise increased by 100%; and pressure rise in the second stage pump out vanes reduced by 30% - directly impacting motor cooling flow rate, temperature rise, and axial thrust. In the oil-air tests, multiphase flow showed similar tendencies with reduced magnitude. Notably, the effects due to air injection do not appear at GVF below 15% with oil-air mixtures, unlike water-air tests which demonstrated effects across all GVFs. The test results provide insight into the behavior of variable viscosity, multiphase flow in the canned motor pump cooling passages, as driven by the second stage impeller pump out vanes. These observed characteristics can be used to design flow control features and evaluate operational impacts, while the performance data obtained can be used to assess the behavior of flow models for this application.

This study analyzes the results obtained from the world's first installation of a compact ultrahigh-speed electrical submersible pump (ESP) system featuring an induction motor (IM) at the MDC Field in Ecuador. The analysis focuses on a comparative study of this technology, contrasting it against a conventional ESP system in terms of operational risks, rig time, and impact on production resulting from optimizing the ESP setting depth in high-tortuosity and gassy wells. With a 25-year history of conventional ESP installations, the mature MDC Field currently uses ESP systems as the only artificial lift method in its production wells. The extensive knowledge and experience gained from these installations were leveraged to conduct this comparative study and the impacts of the compact ultrahigh-speed IM technology. The first installation of a compact wide-range ESP system with a high-efficiency IM was executed in the MDC-09 well and data were obtained regarding production optimization, pump range extension, reliability improvements in highly deviated wells, and reduced rig times. The traditional technology approach to meet field lifting and production challenges has typically deployed an ESP system consisting of three or four pump bodies for a total of approximately 300 to 400 pump stages. One of the main parts of this study was to confirm if the same total dynamic head (TDH) for lifting can be supplied by only one short pump with 38 stages of the disruptive compact ultrahigh-speed technology. The configuration of a single motor protector, instead of a traditional tandem setup, and the reduced motor length contribute to a significant reduction in the total string length compared with the traditional ESP systems. This length reduction significantly decreased the rig time required for ESP assembly. Less rig time is an enabler for the reduction of deferred production, carbon emissions, and operational risks involved. The main challenge in high-tortuosity wells is to adequately set the ESP to minimize the risk of early equipment failure due to string bending. Shorter strings increase the safety range in terms of dogleg severity for the compact ESP system by 3.5 times compared with traditional strings. In high-tortuosity wells, because ESP setting depths have a substantial impact on the optimization of oil production, this study sought to confirm that the new technology can achieve 25% increase in production. Another important aspect to be analyzed is the extended pump operation range when using the new compact ultrahigh-speed ESP system at MDC Field, where historically 14% of workover jobs were performed due to the pump operating outside the recommended operational range (ROR), leading to an ESP failure. The flexibility to adapt to different production rates can be a key factor in the future of ESP applications in a world where enhanced oil recovery (EOR) techniques and commingled production are starting to play a key role in achieving production targets.

The advent of US unconventional completion presents new challenges for electrical submersible pump (ESP) systems. Rapid production decline from fractured unconventional wells, solid production, and high amount of gas are considered the main challenges for ESP system performance and longevity. In addition to production decline and high free gas, unconventional wells introduce scale, gas slugs, and solids. Consequently, it is important to monitor ESP systems to optimize performance, to detect anomalies, and prevent potential failure. This paper discusses multiple case histories where real-time remote monitoring was deployed to overcome unconventional wells challenges. Real-time ESP monitoring uses downhole and surface data such as pressure, temperature, vibration, production data, motor load, and many other parameters to monitor the system performance. The data are stored in several servers and interfaced in real time with production engineers or production analysts through a web browser for analysis, optimization, and diagnosis of any potential failures. Monitoring helps to identify opportunities for maximizing accumulated oil production and reducing ESP system downtime. Remote monitoring provides analysts with access to the well for remote ESP optimization that significantly reduces the number of ESP shutdowns and decreases HSE incidents related to field trips and interfacing with surface units. This paper presents a comparison between ESP performance before and after remotely adjusting the operation parameters using the monitoring system. The result shows how real-time monitoring system improved ESP system run life and maximized oil production. In addition, we look into details how the monitoring system enhances overall ESP efficiency and reduces the number of trips to the wellsite to adjust the operation parameters. ESP monitoring provides the operator with a good indication of issues related to scale, paraffin, asphaltenes, or system plugging to start chemical treatment promptly. In addition, this paper discuss how remotely modifying the ESP variable-speed drive (VSD) operating mode reduced ESP repeated shutdowns due to possible gas interference.

The canned motor pump has a unique design where the motor rotor and pump impeller are mounted on the same shaft, requiring careful balancing of axial and radial forces to ensure reliable operation. The use of a canned motor pump with a floating impeller system helps to balance the axial forces of the impeller, this balance ensures that the impeller is not subjected to excessive axial forces which can lead to premature wear or failure. The purpose of this study is to investigate the axial force on the canned motor pump when overheating occurs due to an operational fault in the distillation column. Investigation of the pump flow rate over 15 days showed a significant reduction in flow rate from 45,000 to 29,000 kg/h, while investigation of the pump amperage showed that the maximum amperage condition was around 54 to 60 amperes.

In the Gulf of Mexico, the rapid pressure depletion and reservoir depth of the Lower Tertiary intervals lead to low oil recovery. A high-reliability, through-tubing subsea electrical submersible pump (ESP) system that takes an integrated approach to production optimization will enable producers to cost-effectively extract more hydrocarbons from the increasingly challenging reservoirs in today's subsea assets. The potential increase in production depends on the maximum drawdown pressure limitations of both well casing design and rock strength. ESPs in deepwater fields are also considered to be an enhancer rather than an enabler by extending the production plateau 5 to 8 years after initial well/field startup with natural flow and seabed boosting. Hence, a robust ESP system that can be installed and operated a few years after field startup without a workover for replacing the upper completions. A robust, reliable ESP would unlock additional value to deepwater operators by delaying CAPEX and eliminating ESP failures, such as degradation of components due to high-pressure/high-temperature (HP/HT) cycling, during the first few years of nonoperation. Designing ESPs for deepwater application is a multidisciplinary challenge and needs to be approached from a full system-reliability standpoint rather than improvements to the ESP hardware alone. Implementation of ESPs in deep water requires both upfront planning at a full-system level and high degree of flexibility for installation, deployment, and retrieval. Finally, because the impact of an unplanned ESP failure is significantly detrimental to project economics, efforts to improve robustness of the ESP hardware must be complemented with automation of ESP operation to reduce or eliminate operator-induced failures. Recent industry improvements in machine learning and predictive analytics need to be leveraged to implement condition-based monitoring of ESPs to better anticipate failures and plan for replacements and/or adjustments to extend the life of degraded units. A collaborative project was undertaken to develop the concept of an alternatively deployed through-tubing ESP (TTESP) system targeted for deepwater subsea operations. The goal was to reduce intervention costs, which, together with ESP run life, are the primary factors influencing the economics of subsea ESPs, including conventionally deployed through-tubing ESPs. The project scope encompassed the downhole hardware, from immediately below the subsea tree through the upper completion, as well as deployment and retrieval equipment and methodology. Economic analyses of subsea fields were conducted to identify the factors contributing to intervention costs so that alternatives could be developed. Multiple concepts were evaluated, and the proof-of-concept system was selected based on superior economic return compared with the baseline. During this proof-of-concept phase, significant testing of key technologies was conducted. The studies showed that conventional intervention vessels and methods will not reduce the intervention costs associated with TTESPs. Lighter vessels together with technologies and methods that minimize intervention time and frequency—and, consequently, reservoir damage and deferred production—are the answer. Eliminating the wait for an available offshore rig is also a key factor in improving overall production economics. The proposed alternatively deployed TTESP system and its associated deployment methodology could reduce the intervention time by half and eliminate reservoir damage. This unconventional deployment could be conducted with lighter service vessels, further reducing intervention costs.

Due to the advantages of high head and no leakage, multistage canned motor pump is widely used in oil industry, chemical industry, national defense and atomic energy. In order to meet the needs of the market, the multistage canned motor pump is designed. This paper introduced the hydraulic design and structural design. In order to optimizing the performance of the pump, this paper designed and used multistage canned motor pump DBP15–50×8 as the research object. Three-dimensional model of the main flow passage components is built and the mesh is generated respectively by using Pro/E and ICEM software, and we calculated the whole internal flow field of the pump that was selected by using ANSYS CFX14.0 software, achieving the pressure and velocity distribution in the pump and the internal details of flow in impeller and other main flow components. The post-processing showed the fluid in sliding bearing section rotates around the shaft, so the local flow is disorder. The comparison of the performance prediction and the experiment shows that the error is low. The cavitating turbulent flow in the flow field was numerically simulated by using the cavitation model. The cavitation phenomena didn’t occur in the experiments. The condition meets the result of numerical simulation.

Canned Motor Pump (CMP) is widely used in petroleum, chemical, electric power, aerospace engineering, and military manufacturing industries due to its good sealing performance. In the structure of canned motor pump, the rotor of the motor and the impeller of the pump are fixed on the same shaft. Therefore, balancing the axial force and the radical force of the rotor is a key task for its reliable operation. The numerical simulation study of CMP is carried out in this paper, aiming to improve the pump efficiency and balance the axial force and radial force. The internal flow and rotor force characteristics of CMP under different radial clearances of front or back wear-rings and different volute partitions are studied. The results show that with the increase of wear-ring gap, external performances decline, and the front wear-ring gap contributed the largest influence. Under the working conditions of 0.6QBEP and 0.8QBEP, front wear-rings contributed the largest influence to axial force, and the degree of influence decreases with the rate of flow increase. Radial clearances of front or back wear-rings have less impact on the radial force of the impeller. Adding clapboard for volute has a greater impact on the value and direction of radial force, and it can promote the balance of radial force. However, the effectiveness value will decrease. The research in this paper can provide theoretical basis and reference for performance prediction and hydraulic optimization of CMP.

In order to balance axial forces on stamping-welding canned motor pump for safe and reliable operation, the type PBCY80-65-160 pump was selected as the computational model. Combined with various reasons why axial forces of the pump were generated, the theoretical calculation and methods of numerical simulation were chosen to analyze the size, directions and rules of axial force. At the same time, the distribution and trend of the axial force components of the impeller under different working conditions are studied whether there is the balance hole or not. The results show that, in the theoretical calculation and numerical simulation calculation, the gap and internal impact loss of the internal flow field of axial forces were neglected when the internal flow of the motor was seen as an ideal flow through the resistant elements. Hence, it could not fully represent the internal pressure distribution of the pump, which caused the calculated data a little larger than simulated data. Also, the method of combining the balance hole and impeller rear seal ring could effectively balance the axial force and extend the service life of stamping-welding canned motor pump.

Electrical submersible pump (ESP) systems in the oil field have unique features due to the long cabling effect. The electrical system for a typical ESP installation consists of a variable frequency drive (VFD), a multi-tap step-up transformer, a surface cable, a downhole main cable, a motor lead extension (MLE) cable, and an electrical submersible motor. A load filter is usually required in a VFD-ESP system. In this paper, several operational parameters that can significantly affect operating conditions of an ESP system are demonstrated through field measurements and simulation of a practical ESP system currently in operation in Alberta, Canada. The simulation model is also validated by comparing with field measurement data. This analysis is beneficial to field engineers and ESP system operators to understand better the impacts of equipment parameter settings.

Improving Electric Submersible Pump (ESP) system reliability, eliminating or reducing failures, comprise the most frequent requests from O&G operators. Over the last few decades, notable design improvements have been made with the use of computer aided design, rapid prototyping techniques, and use space age materials. But the average ESP run life has increased marginally, and remains at around three years. ESP failures have important economic implications for O&G operators, including: nonproductive time, production deferral, production losses, and high cost of ESP replacements, especially for offshore or remote wells. Operators have tried different approaches to incentivize ESP vendors to improve ESP reliability, including: performance based contracts, internal research, open research, joint industry projects, and market competition. Despite these efforts, the goal of a ten-year run life remains elusive. Saudi Aramco has set a very aggressive target of operating ESPs for an average of ten years without failure. This paper explores the likelihood of developing an ultra-reliable submersible pump system that can meet this challenging objective. It discusses the fundamental issues that currently prevent achieving higher ESP reliability, and also evaluates potential approaches to the reliability improvement challenge. Finally, the paper examines technical, operational, economic and market implications of such alternatives, for both O&G operators and ESP vendors

This paper presents current advances and innovations in gas separation and regulation technologies to address high Gas-Liquid Ratio (GLR) and gas slugging conditions in petroleum wells equipped with Electric Submersible Pump (ESP) systems. The application of this design in severely problematic wells with significant gas production and slugging issues highlights the critical importance of separating and conditioning fluids before they reach the pump intake, serving as a bridge before transitioning to another artificial lift system. Effective gas separation in an ESP system, beyond the existing ESP gas separator, involves shrouding certain ESP components. The engineered design discussed in this paper utilizes casing to enhance gas separation through several stages. These stages include isolating the pump intake using a shroud, sealing the casing with a Triple Seal Cup-Type Packer, and combining outlet and inlet sections that reverse the flow path to significantly reduce fluid velocity. This reduced velocity aids in successful gas separation. A sealed shroud above the pump intake is connected to the gas separator below the sensor, ensuring gas-free liquid flow around the motor, which helps maintain optimal motor temperatures in wells with high gas content. A study on unconventional wellbore simulations, specifically focusing on toe-down completions, highlights the impact on slugging conditions. The formation of gas slugs under these conditions can negatively affect the operation of an electric submersible pump (ESP). An alternative design, which does not require a shroud, regulates gas flow through agitation, pressure and velocity changes, and increased retention time to mix gas slugs into the liquid pool. This creates a homogeneous flow regime, or dispersed bubble flow, which also contributes to maintaining optimal motor temperatures, improving pump efficiency, and preventing gas locking conditions. Case studies from the Permian Basin demonstrate the positive impact of selecting an appropriate downhole conditioning system. Significant improvements in sensor parameters will showcase the benefits of handling gas and sand before the pump intake, resulting in reduced shutdowns and non-productive time, ultimately enhancing fluid production. The flexibility of this design is also noteworthy, as it can be installed across a wide range of fluid production levels, gas-liquid ratios, and various tubing and casing sizes. These advanced technologies maximize ESP efficiency in gassy wells, either by using casing to enhance gas separation or by regulating gas surges with innovative designs that convert slug flow into homogeneous flow.

A dual purpose design is presented in this paper to face high gas presence and sand production conditions in petroleum wells with an Electric Submersible Pump (ESP) system installed. The results of this design's application in severely problematic wells, due to high gas and sand production, will confirm the importance of conditioning the fluid before it gets to the pump intake. This engineered design consists of different stages from the isolation of the pump intake until the tubing bodies in charge of gas and sand handling. Engineering concepts were applied in the construction of this solution such as gas re-solubilization, changes of pressure and velocity, agitation, and vortex effect to finally present a design that is capable of breaking gas slugs into smaller gas bubbles that can be produced by the ESP system without impacting its performance, and at the same time separating fine solid particles (<250 microns) using centrifugal forces. Case studies from wells located in the Permian basin will better explain the positive impact of selecting a proper downhole conditioning system to improve the ESP systems efficiency. A drastic improvement on the sensor parameters will also illustrate the effect of handling the gas and sand before the pump intake, which also leads to one of the most important consequences: A decrease in the number of shutdowns, which in turn decreases non-productive time, resulting in positive impact of fluid production. Additionally, the flexibility of this design is significant, since it allows it to be installed in a wide range of fluid production, gas-liquid ratio, tubing and casing sizes. The novelty of this new design is the addition of the surge valve below the packer, which accomplishes multiple purposes: to avoid surging in the well, to allow testing the packer to assure it is properly set, and finally, allow chemical injection below the packer.

Where the pressure in oil or gas reservoir is not sufficient, in order to increase the production rate, an artificial lift method is required. There are several methods for obtaining artificial lift, including gas injection and electrical submersible pumps. Electrical submersible pumps are more controllable, offer faster installation, and are more economic than other methods, especially for vertical and deviated wells. Electrical submersible pumps systems consist of several parts, including the pump, an electric motor, cables, and a control board. The electric motor plays an important role in an electrical submersible pumps system, and it must produce high torque under high temperature and high-pressure conditions. For small diameter wells, there is also a constraint on the motor diameter. These harsh conditions and constraints require special motors. In this article, the desired criteria for such a motor for this application are represented; then, a comparison is made among several types of motors, including induction motors and various permanent magnet motors, and the resulting best choices are proposed.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201167, “Wellhead-Penetrator Problems and Best Practices in ESP Thermal SAGD Applications,” by Pat Keough, SPE, Jesus Chacin, SPE, and Kyle Ehman, SPE, ConocoPhillips, prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition–Americas, 10–12 November. The paper has not been peer reviewed. Wellhead penetrators are a critical component in electrical submersible pump (ESP) systems. Harsh steam-assisted gravity-drive (SAGD) conditions impose an even higher level of stress on penetrators. Recently, a sudden increase in wellhead-penetrator failures in the Surmont SAGD ESP operation in Canada led to an enhanced fieldwide root-cause analysis (RCA). The complete paper is a field case study that describes the findings of this RCA and the mitigation measures taken. Introduction Fig. 1 shows a wellhead-penetrator assembly typically used in SAGD operations. This assembly consists of two main parts: a mandrel that seals against the wellhead while carrying power from the surface facilities through the tubing hanger and the lower field-attachable connector that splices the ESP cable and threads into the mandrel below the tubing hanger. Because of the design of the ESP, when an electrical-system failure is detected through traditional means, accurate determination of which electrical component has failed is impossible without first sending a rig, killing the well, removing a portion of the wellhead, disconnecting or cutting the penetrator or cable, and completing further resistance testing on the cable components. At Surmont, 230°C-rated penetrators had proved reliable and electrical failures were almost exclusively caused by a failed downhole component. The produced fluid temperature typically is below 230°C, somewhere between 180 and 220°C during normal operating conditions. However, approximately 12 months after a large installation campaign that almost quadrupled the Surmont ESP population, a sudden increase in penetrator failures was observed. Between late 2017 and early 2019, 18 penetrator failures occurred. These failures accounted for approximately 25% of the ESP-related events in Surmont during this period. These penetrator failures occurred at different runtimes, varying from 148 to almost 900 days, with most occurring 12 to 18 months after being installed. In all instances, penetrator failures occurred at runtimes shorter than the expected ESP mean time to failure (MTTF) of the ESP population. Failure Investigations: Approach, Results, and Recommendations At the end of Q1 2018, the first five failures occurred in succession, which prompted a failure investigation on this group of wells. Nearly all field measurements pointed to a short circuit in the field-attachable connector. Given the special nature of the penetrator design and construction, it was thought necessary to send failed specimens to the manufacturer. Dismantles showed that, in all cases, the high- modulus tape was missing. Without the tape in place, rubbing of leads, development of wear, and an eventual short were all possible when considering excessive thermal expansion. RCA techniques were conducted and identified the potential contributing causes described in this subsection.

Electrical submersible pumps (ESPs) are used in the petroleum industry to pump large amount of fluids from subsea deep wells. Currently, ESPs are responsible for approximately 10% of the world’s crude oil production. When high flow rates are required, gas lift and the ESP are the only available technologies that can be applied. ESP systems are much more complex and less reliable than the gas lift method, but they are more efficient and able to yield higher flow rates and pressure. ESPs are installed inside or near production wells, with the entire auxiliary infrastructure for power supply and control system. This means that maintenance is prohibitive because of production losses and the need for expensive and unavailable drill ships. Assembly errors and manufacturing defects must be avoided to make the method feasible and to prevent premature failure and, this goal, can only be achieved through rigorous quality control, operations procedure, qualification and dynamic tests. In this paper, modal parameters of an ESP installed in a test well were experimentally identified using the Enhanced Frequency Domain Decomposition (EFDD) technique. Drop tests were used to excite the ESP and vibration signals were acquired along the equipment’s structure. Results were compared with modal parameters obtained using impact tests and showed that the drop test is an useful method for modal testing of ESP’s in test well.