Alternatively Deployed Artificial Lift System for Deepwater Subsea Operations

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.

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.

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.

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.

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.

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.

This paper will present the design, manufacturing, testing and validation of the canned motor pump (CMP) as an alternative to typical electric submersible pump (ESP) systems to produce oil and gas with the goal of developing a robust system to extend the ESP run-life. The CMP technology is a seal-less topology currently employed in demanding applications including highly abrasive radioactive slurry service. This subsea system leveraged knowhow developed in other demanding applications and is adapted for ESP caisson applications. The canned motor ESP development included mockups to validate design features and manufacturing processes. A CMP system was manufactured and tested at the vendor's facility with water and at the end user's test facility with multiphase and viscous fluids. Unit validation included rigorous multiphase testing with fluid viscosities ranging from 2 cP up to 300 cP and varying gas volume factions at different speeds. The typical electric submersible pump has an average run life of approximately 2.5 years in subsea caisson applications. Root Cause Failure Analysis (RCFA) on current ESP systems has revealed that a majority of failures result from the protector seal and motor. The main function of the seal section is to protect the motor and thrust bearings from contamination by the process fluid. The CMP seal-less technology eliminates the need for a protector seal section and dielectric fluid by isolating the wound stator with a corrosion resistant liner and a thrust bearing system that operates in process fluid. This paper will include test data results from thrust bearing testing in varying conditions including multiphase fluid to demonstrate robustness and unit performance test results from testing in water and multiphase fluid with varying viscosities. The canned motor ESP provides a new approach for subsea caisson applications by eliminating the protector seal section and incorporating process lubricated thrust bearings. This paper will share background, learnings, and results that demonstrate that the canned motor pump technology is ready for deployment in a subsea ESP caisson.

A new method for the vibration amplitude assessment of the ESP systems considering the vibration orbit

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.

Electrical Submersible Pumps (ESPs) are commonly used in deep wells in oil and gas industry. In order to monitor ESP systems operating conditions, downhole monitoring tools are used to transmit data representing physical conditions of downhole such as temperature, pressure, and vibration to the surface. The most common downhole communication method implemented in the field is to use a DC signal over three phases of the main power cable and uses the ground as a return path. However, this method cannot operate in the event of a single-phase-to-ground fault, because the signal path would be shorted although the electrical submersible pump is still in operation due to the ungrounding practice in downhole ESP systems. Experience has also shown that this existing method is prone to failure in presence of unbalance conditions in the system. In this paper, a new phase-to-phase communication scheme for the downhole monitoring tool design is proposed where intentional disturbances in the power supply to the motor are used as means of binary communication. The proposed scheme is immune to single-phase-to-ground faults and unbalance conditions. Theoretical formulas defining this method are developed and the performance of the method is evaluated using simulation through case and sensitivity studies.

Chapter 8 - Failures and Troubleshooting

This paper presents the first application of a Dual Electrical Submersible Pump (ESP) system in an onshore well in OMV. It describes the whole process starting with the selection of the technology and candidate wells to the installation of the equipment and the start-up phase. Challenges in the operations as well as the methods for production allocation are addressed. Commingled production was seen as a key approach for production acceleration in the development of a field with multiple-stacked reservoirs. To proof this idea, a number of candidate wells and technologies were screened and the concept of "Dual ESP" was finally selected for a pilot in the well Erdpress 6. The design process required simulations and preparative selective production tests. Production allocation was crucial to evaluate the performance of the pilot; therefore several techniques were used, like fingerprinting based on chromatography and chloride content. The Dual ESP system was a completely new approach in producing multiple targets in one well. The selective production tests proved to be essential for an optimum design of the ESPs. Two different methods were used to allocate the production rates to the respective intervals. The most significant finding was that results of the nodal analysis could be verified by chemical fingerprints. This also proved that the investment in downhole sensors was valuable. Interferences between the two pumps could be determined with the information of the sensors resulting in adjustments in the ESP settings. The conclusions from that pilot are that the application of the Dual ESP system is fulfilling the expectations from a technical point of view and that the information gathered prior to the design was crucial. However it is obvious that the application of this expensive technology has to be evaluated and justified in every technical and economical aspect. In the case of this pilot, an unexpected steep water cut rise impaired the forecasted profitability. The use of the Dual ESP system was an exceptional approach to tackle the concept of commingled production. This paper covers the whole process from design to operation and shares the experiences and lessons learned to support future applications.

The depletion of reservoir energy in mature oil fields poses a significant challenge to sustainable hydrocarbon production. In the prolific Niger Delta basin, many reservoirs have progressed beyond their natural flow potential, necessitating the deployment of artificial lift systems to maintain economic production rates and maximize recovery. This study presents a performance evaluation of natural flow and Electrical Submersible Pump (ESP)-assisted wells in a depleting Niger Delta oil reservoir using an integrated Material Balance (MBAL) and PROSPER modeling approach. The workflow commenced with a rigorous reservoir-level analysis using MBAL to characterize the reservoir's drive mechanism and estimate the Original Oil in Place (OOIP). The analysis confirmed a strong water drive mechanism with an OOIP of approximately 2989.9 MMSTB. Subsequent well-level modeling in PROSPER was used to simulate the well's performance under natural flow conditions, identifying the point of flow cessation at a reservoir pressure of approximately 2000 psig and a water cut of 60%. To address this production gap, an ESP system was designed and simulated. The results demonstrated that the ESP intervention successfully lowered the flowing bottomhole pressure, increased drawdown, and restored production to a stable rate of 1,204 STB/day of oil (3,010.5 STB/day total liquid). A comparative forecast revealed that without the ESP, the well would have ceased production, leaving significant recoverable reserves untapped. The study conclusively demonstrates that the integrated MBAL-PROSPER workflow provides a robust technical framework for diagnosing production constraints, optimizing artificial lift timing, and extending field life.