Improving ESP Performance in Low Productivity Gassy Wells: Case Study

West Java field operated 60 electric submersible pumps (ESPs) as a lifting method with 2.850 BOPD production contribution. These ESP wells produce from a mature structure. At one point, 48% of ESP operation were shut down due to ESP non-optimum operation. The challenges in ESP operations in the asset are high gas-liquid ratio (GLR), impurities, sand and scale buildup, and well integrity where high GLR was deemed as the major problem that deteriorated the ESP's performance. Conventional ESPs gas separator were installed in the field, but the gas-handling device could not handle more than 45% free gas while some wells have more than 50% free gas. Three wells in particular were assessed, Well A, Well B, and Well C, which have 585, 1196, and 1690 average GLR respectively. These wells had problem with reduced pump efficiency and very low run life due to frequent ESP trips which were caused by the gas lock problem. A solution to maintaining oil production was by changing the production zone to zone that producing less gas and by installing more advanced gas-handling device. However, the probability of experiencing high gas production from new zones can't be ruled out therefore other mitigation plan had to be found. Gas lock protection control is an algorithm that manipulates ESP real-time rotational speed to prevent gas interference inside pump. The algorithm was introduced as a mitigation measure and commissioned in July 2020 at Well A where it directly optimized production by 16%. To prove the robustness of the gas lock prevention control, the project was then extended to Well B and Well C which began to implement gas lock prevention control in August 2020 to handle the increase of their gas production. Thanks to this gas lock prevention control, the wells have been able to maintain production without spending either time or money to change production zone or to change the ESP completion. Going forward, gas lock protection control will be set as an option on ESP devices. Thus, unplanned gas interference effects may be reduced in other wells that being produced by ESP thereby helping to maintain production at an optimum level.

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.

The paper introduces a novel methodology for calculating head deterioration in electrical submersible pumps (ESPs) due to mechanical wear, aiming to enhance the understanding of pump head curve performance deviations and improve ESP monitoring. The methodology is grounded in the regression of experimental data from portable separator rate tests and ESP sensor data, using over 100 data points from an oil field. Simultaneous charts and Visual Basic software were utilized to incorporate correction factors and correlations, establishing a new trend. This approach considers variables like pump intake and discharge pressure and frequency during testing, emphasizing the alignment of operational points with the catalogue curve and recognizing potential influences such as measurement errors, pump wear, and fluid property deviations. By applying the Head Derating Factor derived from the new methodology, a better match between downhole and portable separator rate test outcomes was achieved, with the deviation decreasing from 14% to 6%. The developed ESP model, based on this methodology, offers accurate historical matching to conducted rate tests, streamlining ESP diagnosis and decision-making throughout its run life. This has further facilitated improved ESP turnaround, enabling performance forecasting and equipment availability planning. This paper presents a groundbreaking ESP monitoring system, integrating oilfield correlation and all ESP parameters into a unified system. This system, underpinned by the new methodology, offers diagnostic capabilities, production optimization, and ESP well tracking. It provides a comprehensive field overview of all ESP wells simultaneously, identifying wells requiring intervention, optimization, or replacement. The system showcases a dynamic and interactive graphical user interface, offering a holistic view of all ESP wells with three primary modules. This innovation marks a significant advancement in the petroleum industry’s state of knowledge, presenting a more efficient and integrated approach to ESP performance monitoring.

A water injection booster pump system using a below ground "can" Electrical Submersible Centrifugal pump (ESP) will be described. This pump, an integral part of the Milne Point Unit water injection system, is the first such installation on the North Slope of Alaska. The can ESP was chosen as a speedy, flexible, low footprint, cost effective solution to increase water injection. The pump successfully increased water injection capacity to over 20,000 bpd at 3200 psi discharge, an increase from 8000 bpd at 2600 psi As a result of the project, reservoir pressure and oil production has increased substantially in the fault blocks receiving additional water injection support. The paper will provide an overview of the project design and installation, with emphasis on downhole aspects of the pump design (geotechnical, ESP, completion). P. 381

The electrical submersible pump (ESP) is currently the fastest growing artificial-lift pumping technology (Bates, Cosad et al. 2004). Deployed across 15 to 20 percent of oil-wells worldwide, ESPs are an efficient and reliable option at high production volumes and greater depths (Breit and Ferrier 2008). However, ESP performance often declines without much warning and reaches the point of service interruption due to factors like high gas volumes, high temperature, and corrosive environments. The financial impact of ESP service interruption is substantial, from both lost production and replacement costs. Therefore, ESP performance in extensively monitored, and numerous workflows exist to suggest actions in case of service interruption events such as trippings or breakdowns. However, such workflows are reactive in nature, i.e. action is taken after an event occurs. Furthermore, with the emerging trend in the E&P industry of using downhole sensors for real-time surveillance of parameters impacting ESP performance, there is an opportunity to leverage real-time data obtained from sensors for predicting and preventing ESP shutdowns using data analytics. This paper presents an analytical framework towards proactive ESP health monitoring based on data-driven predictive modeling and analysis. This framework can be used to automatically identify real-time patterns and assess ESP health in real time, thus offering to engineers and field personnel early detection of impending problems well before they occur, for mitigation and prevention of ESP service interruptions.

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.

Raudhatain Field North Kuwait is produced with approximately 500 oil wells of which over 200 use Electrical Submersible Pumps (ESP). The ESP is used as a production mechanism to supplement the natural reservoir drive of the wells. Downhole monitoring of the ESP system is one of the most important aspects in maximizing ESP performance with the final objective of increasing in ESP run life and maximize oil production. An old ESP Monitoring system was introduced few years back, however the application and utilization did not fully support the concept of ESP Real Time Monitoring. The new ESP Real Time Monitoring system has been recently introduced to complement the old system. This new system has more significant improvement over the old system. A SCADA system has been utilized to transmit ESP data from well site to the server in the office that allows the engineers to retrieve real time data, monitor the parameters and perform analysis and take necessary actions in the well. Advances in measurement technology have made ever increasing amounts of real time information available for monitoring both pump and well performance. Parameters such multiple downhole pressure readings, temperature and vibration, well head pressure readings as well as the traditional operating voltages and amperages are not only available, but available in real-time at the engineers desk top. Having all of this data on our desk tops has created an environment that allows the engineer to change for a reactive monitoring approach as problems are identified, to a proactive tool, catching potential issues before they become problematic to the ESP performance. The ability of the new ESP Real Time Monitoring Tool to perform data trending of an ESP for any date or time frame, evaluating either some or all of the critical parameters, has allowed the engineers in Raudhatain field to analyze ESP performance more accurately through trend analysis. This allows an engineer to review well performance in a matter of minutes compared to the hours used in the past. This has helped the engineers in making faster more accurate decisions. This paper will address several examples where ESP real-time monitoring lead to an incremental of 3,000 BOPD production North Kuwait Raudhatain field will continue the utilization of this ESP Real Time Monitoring system and seek further improvement. This paper will describe the system, share our experiences and show how the system helps in ESP optimization and, thus maximize production.

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.

Gas lift has been the primary artificial lift method for wells in an offshore brownfield in Malaysia for the past 30 years. However with depleting and unstable gas lift supply coupled with the increase in water production, an alternative artificial lift strategy needed to be developed. A revisit to the Field Development Plan (FDP) in 2003 has found that Electric Submersible Pump (ESP) could be the solution to overcoming the field's overwhelming dependency on gas lift. During a workover campaign in 2008, 3 ESPs were installed – marking the first production ESP in Malaysia. The ESPs have increased the well production from the gas lift baseline production and on top of that, there is a 66% additional incremental production from the re-allocation of approximately 1 MMSCFD of lift gas from the ESP wells. The success of the three ESPs has developed interest from the field operator to have more units installed. By end of 2011, a total of 5 ESPs has been installed in the field. They consisted of conventional ESPs, followed by an ESP in a pod with a Distributed Temperature Sensor (DTS) cable and a dual ESP with bypass tubing. Another 3 installations have been planned in the near future. The operator is also looking at the potential and feasibility of a rigless deployment for the ESP - either by using coiled tubing or a standard slickline service. In an offshore environment where rig cost and rig availability is of concern to well uptime and project economics, alternative ESP deployment has been seen as the next frontier of ESP technology to increase revenue. The transformation of artificial lift strategy in the field – from gas lift to ESPs - has been very progressive and profoundly significant to the operator's continual technological advancement in the industry. Introduction Bokor field is located 45 km offshore Sarawak, East Malaysia. It was discovered in 1974 and started production in 1984. The field reaches its peak production of 30000 barrel of oil production in 1990. Bokor field comprises of 3 production platform which are BODP-A, BODP-B and BODP-C, one processing platform (BOP-A) and one compressor platform (BOK-A). BODP-A, BODP-B and BOK-A are interconnected by bridge link while the BODP-B and C are only accessible via boat. Power generation is located in BOK-A and limited to BODP-A and BOP-A. The rest of the production platforms have solar power system limited to the platform's Supervisory Control And Data Acquisition (SCADA) system and basic utility. Due to the field unconsolidated formation sand, all of the wells in the early years were completed with cased hole gravel pack. Strong water aquifer in Bokor provides good and continuous pressure support, however increasing water cut becomes a severe problems to the surface facilities and increased demand to the lift gas. As an initiative to boost productions in the field, the operator ties a new relationship with Schlumberger to be its technical partner in 2002. The main objective of the partnership is to produce the incremental oil from the field. Bokor field comprises of more than 100 strings of oil wells with half of them is idle and the rest are producing on gas lift with several string on natural flow.

Summary Managing large-scale electrical submersible pump (ESP) operations and assessing their performance can be a challenging task. Diverse operational environments, widely spread geographical areas, large ESP populations, and different service providers are some of the complications facing operators. Nonetheless, it is vital to the success of any artificial lift project to establish a performance evaluation structure that can effectively capture deficiencies and highlight improvements. While many operators focus on run life statistics as the central key performance indicator (KPI) for ESPs, these types of statistics may not be sufficient in providing meaningful information to decision makers. Other important ESP performance parameters include ESP shutdowns (both planned and unplanned), restart time of tripped ESPs, commissioning time, failure rate, and the number of premature ESP failures. Thus, a comprehensive study was jointly initiated between an oil operator and ESP vendors to establish KPIs that drive improvements in all aspects. The selected KPIs were developed in a structure that ultimately focuses on maximizing production availability and revenue generation. By constructing the ESP KPI framework, subpar performance areas were clearly visible by both the operator and the service provider. Decision makers were able to identify and act on fields that lag in performance while exerting efforts to improve underperforming service providers. Furthermore, regular meetings were conducted to review the established KPIs and recommend some action items, which might focus on either technical or operational solutions. Finally, KPI targets were set on the basis of the review of historical trends and were assigned to be challenging yet relevant and attainable. The followed practice can prove to be successful in forming a common ground where service providers can quantify losses by the operator as a result of ESP performance deficiencies. Comprehensive data collection and keeping of ESP trips, failures, and replacements are critical to the success of this work. Regular review of field reports and well performance are imperative to accurately compute the various KPI formulas. In fact, many of the KPI calculations can be automated to capitalize on the available communication networks installed in the field to improve ESP monitoring and accurately assess their performance.

It is estimated that 95% of oil wells globally use Artificial Lift and 2014 statistics show that Electrical Submersible Pumps (ESPs) represents 43% of the global annual artificial lift spend[0]. Occidental Petroleum is a large user of ESPs, with over 2,200 in West Texas alone, and while ESPs can produce at high rate, they are also high cost. In today's low oil price environment, it is imperative that ESPs are operated efficiently to produce at the lowest cost per barrel. When applying ESPs to unconventional wells, efficient production is even more important with the added operational complications of producing frac sand, high gas/oil ratio (GOR) reservoirs, and rapidly changing flow rates. These three factors can dramatically shorten ESP run lives if not properly managed. Providing surveillance, monitoring, and optimization to Occidental's more than 400 unconventional wells required improved field data delivery systems, surveillance practices, and optimization techniques to meet this challenge. To achieve this, Occidental internally-developed a system for real-time ESP decision making that combines real-time data transmission, a data analytics tool, and an ESP analysis engine, all supported by trained staff and engineering workflows. By pulling all of these components together in one platform called "OxyLIFT," production engineers have a tool to enable rapid problem detection and diagnosis. The OxyLIFT system represents a major step forward in real-time decision making. By performing an automated analysis process on thousands of ESPs, Occidental can take proactive action on production losses at any point in the ESP's operational phase, as well as enabling semi-predictive failure analysis. Most importantly, the system highlights proactive ESP replacement opportunities which minimizes both production downtime and equipment losses. This system can be applied to any type of ESP well however the challenges associated with an unconventional well will be specifically investigated and explained with multiple case studies.

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.

When the Beatrice field came into production in September 1981, it was the first North Sea offshore oil field to depend from the outset upon Artificial Lift to maintain production. In view of the low gas-oil ratio of the Beatrice crude, the use of Electrical Submersible Pumps proved the only feasible option, and the maximisation of the operating life of the downhole pump was obviously critical to the economic viability of the project. This paper describes how the Electrical Submersible Pump performance on Beatrice has been progressively improved through diligent analysis of completion performance data and failed completions, the results of which have led to both the optimisation of completion design and the development of new and existing mechanical and electrical components. 1. INTRODUCTION The Beatrice field is located 12 miles offshore Scotland in 150 feet of water in the inner Moray Firth area of the North Sea (Figure 1). The production wells are located on two platforms, 17 on the 'A'fadlity and 8 on the 'B' fadlity, each with an Electrical Submersible Pump installed. Produced fluids from 'B' are transported by pipeline to 'A'for comingling and processing. The combined fluids are transported to Nigg Oil Terminal through a 49-mile long, 16 inch diameter pipeline in the Cromarty Firth (Ref 1.) During the development phase of the project, the major design hurdle encountered was that of completion design. The requirements of North Sea statutory regulations, established safety practices, well conditions and reservoir properties (See Table 1), presented a combination of problems not previously encountered in existing Electrical Submersible Pump applications. The following factors needed to be taken into consideration in the design of the completion and represented problems in terms of equipment performance:-–Production rates up to 11,000 bbls/day would need to be lifted from a true vertical depth of around 6,500 feet.–The downhole electrical system would be subjected to relatively high power loading, 350 HP being typical.–Well deviations of up to 650 would be encountered, resulting in pumps needing to be set at measured hole depths of up to 12,000 feet.–To optimise pump performance, continuous monitoring of pressure and temperature at the pump intake was required, whilst the ability to log wells with the pumps in place was also desirable.–The installation of a packer above the pump was a mandatory requirement, requiring an electrical penetration through the packer, and resulting in the power cable being continuously submerged in completion fluid.–A waxy crude with high pour-point indicated the need for downhole chemical injection.–The effects of the hostile North Sea environment upon electrical equipment installation needed careful consideration.

Improving electric submersible pumps efficiency and mean time between failure using permanent magnet motor

An Ecuadorian oil company recorded multiple early failures of electric submersible pumps (ESP) due to harsh fluid conditions. The extra-heavy (9°API) and high-viscosity (10,000) oil at surface stopped production from a new promising reservoir with approximately 400 million barrels of oil reserves. An oil service company studied the feasibility of injecting hot water in the wellbore to lift the viscous fluid using an ESP by reducing oil's viscosity and improving flow assurance conditions from downhole to surface. The studied production technique injects field-produced hot water in the wellbore through a dual concentric tubing string, controlling injection flow rate and pressure with self-regulated downhole valves, to prevent pressure interference with the reservoir's productivity. The hot water heats the oil, reducing fluid viscosity through the ESP and the tubing. A comprehensive technical feasibility study was carried out by a multidisciplinary team of domain experts using a transient-state, multiphase fluid flow simulator to integrate reservoir performance, fluid dynamics, completion architecture, and ESP operation into one holistic, robust model to analyze various production and sensibility scenarios over time in a selected well candidate. The holistic study demonstrated the proposed production technique could be a cost-effective, technically feasible solution to resume production from the promising reservoir that contained the extra-heavy, high-viscosity oil. On the ESP system side, there was a substantial increase of pump efficiency by 7 times, while the motor's working temperature was reduced by 12%, two factors that would help to extend ESPs run life. For the fluid, the simulation of the production technique proved how injecting hot water would improve fluid mobility, showing a reduction of surface fluid viscosity from 10,000 cP to 1,000 cP, while downhole viscosity dropped from 900 cP to 240 cP; thus, the friction losses in the tubing string declined by 89%. Such improvement in flow assurance conditions and ESP efficiency had one main benefit compared to a conventional ESP configuration producing the extra-heavy oil in the same well candidate: optimization of oil flow rate by 20%. Furthermore, economics of the well improved by the extension of ESP run life expectancy, avoiding workovers, and optimizing flow rate. The innovative production technique represented a more cost-effective solution than a conventional ESP installation by 5.4 times This technique emerges as a solution to meet the challenges presented by the extra-heavy, high-viscosity oil in the studied reservoir; it could allow the operator to reactivate production in 15 wells, where other implemented production configurations have failed to avoid early ESP failures caused by flow assurance problems. The study of the proposed method proved it is technically feasible and is more cost-effective than a conventional ESP configuration.