A Holistic Approach in Establishing a Structured Framework to Maximize Production Availability through Integrated ESP Key Performance Indicators

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 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 intake plugging of an electrical submersible pump (ESP) has presented a formidable challenge to conventional ESP wells. Attention to cumulative solid deposition is essential since it intensifies the intake plugging severity and impedes ESP performance. We present a new approach to evaluate the ESP performance degradation during increased intake plugging severity. In particular, we employ the intake plugging factor, rate-derating factor, and affinity law to calculate the new ESP speed at different plugging conditions. We used Schlumberger PIPESIM software to perform nodal analysis of the newly calculated ESP speed. The result was validated using the actual field data and compared to the field cases that reported the intake plugging issue. The nodal analysis showed a steady maximum ESP head with zero rate derating at the shut-in point. The intake plugging factor caused a significant reduction in the ESP operating rate and increased pump intake pressure and annulus liquid level. Based on the existing intake plugging field data, we established the quantitative standard for the normal and abnormal intake plugging factor range. The observed results agreed with the field downhole data recorded during the intake plugging problem. We identified that regulating the ESP speed to the reduced operating rate could minimize unexpected pump stoppage. It is also possible to carefully monitor the intake plugging problem by combining the annulus liquid level, the signature of pump intake pressure, and a deadhead test.

Real-time Performance Monitoring of Electrical Submersible Pumps in SAGD Process

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

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.

Wintershall Dea is developing together with partners a digital system to monitor and optimize electrical submersible pump (ESP) performance based on the data from Mittelplate oil field. This tool is using machine learning (ML) models which are fed by historic data and will notify engineers and operators when operating conditions are trending beyond the operating envelope, which enables an operator to mitigate upcoming performance problems. In addition to traditional engineering methods, such a system will capture knowledge by continuous improvement based on ML. With this approach the engineer has a system at hand to support the day-to-day work. Manual monitoring and on demand investigations are now backed up by an intelligent system which permanently monitors the equipment. In order to create such a system, a proof of concept (PoC) study has been initiated with industry partners and data scientists to evaluate historic events, which are used to train the ML-systems. This phase aims to better understand the capabilities of machine learning and data science in the subsurface domain as well as to build up trust for the engineers with such systems. The concept evaluation has shown that the intensive collaboration between engineers and data scientist is essential. A continuous and structured exchange between engineering and data science resulted in a mutual developed product, which fits the engineer's needs based on the technical capabilities and limits set by ML-models. To organize such a development, new project management elements like agile working methods, sprints and scrum methods were utilized. During the development Wintershall Dea has partnered with two organizations. One has a pure data science background and the other one was the data science team of the ESP manufacturer. After the PoC period the following conclusions can be derived: (1) data quality and format is key to success; (2) detailed knowledge of the equipment speeds up the development and the quality of the results; (3) high model accuracy requires a high number of events in the training dataset. The overall conclusion of this PoC is that the collaboration between engineers and data scientists, fostered by the agile project management toolkit and suitable datasets, leads to a successful development. Even when the limits of the ML-algorithms are hit, the model forecast, in combination with traditional engineering methods, adds significant value to the ESP performance. The novelty of such a system is that the production engineer will be supported by trusted ML-models and digital systems. This system in combination with the traditional engineering tools improves monitoring of the equipment and taking decisions leading to increased equipment performance.

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.

The electrical submersible pump (ESP), has become the most efficient and reliable artificial-lift method worldwide. However, in wells with high gas volume, they are highly affected by gas bubbles flowing through each component, affecting: the motor temperature, lifting efficiency, the integrity of the motor and cable. Thus, High gas interference might cause multiple intermittent shutdowns due to Gas Lock and eventually shorten the run life of the ESP.ESP at Well #A was first installed and directly had a problem with High Gas Interference resulting in a pre-mature ESP failure and costly well intervention to restore well-deferred production. A detailed discussion with a technology provider and reference case studies come up with an integrated solution to have the proper gas handling system in addition to adjusting VSD logic to operate on PID current mode. The present study shows a successful ESP optimization through VSD settings in combination with a comprehensive gas handling system that allowed management of low productivity high GOR ESP applications.This gas handling system for ESP was complemented by installing [PMM motor, tandem gas separators with vortex technology, compression mixed-flow stages in a wide range centrifugal pump, advanced gas handler (AGH), and Monel armor leaded power cable]. The system was able to manage GOR>2,000 SCF/STB with WC of <10%, Productivity index of 0.2 BPD/psi, and 75% of free gas flowing into the pump intake. This paper contains all the descriptions of each component in the ESP gas handling system. The system was able to increase well production by reducing gas-locking production shutdowns, stabilizing motor current fluctuations, increasing ESP lifetime, and increasing reservoir life by increasing drawdown and allowing effective pump operation at lower intake pressure.The same directions were successfully applied in another two wells with low productivity gassy behavior; Well #B and Well #C. And, by monitoring ESP performance for a longer period, the pump showed a stable operation, by successfully mitigating the high gas interference trips. Thus, the implementation of this integrated solution in wells with high GOR has been demonstrated to be an effective solution. Also, it provides opportunities to expand the use of ESP in gassy wells, previously thought to be unsuitable.

The electrical submersible pump (ESP), an efficient artificial lift method, was developed to increase production rates from wellbores (Bates et al. 2004). As the number of ESP installations increases annually, there is a greater awareness of their environmental impact and a growing responsibility to reduce the associated carbon footprint because frequent workovers to replace failed ESPs are primary sources of carbon dioxide emissions from the oil and gas industry. Because of this, companies are beginning to pursue cost reductions and look for methods to mitigate the consequences of production. Systems for monitoring ESP performance in real time are currently being developed on the basis of data analysis to detect potential problems in advance. This paper presents a digital solution for tracking ESP performance that includes an automated data processing pipeline and the use of statistical metrics to analyze the dynamics of failure and run life at the system node level. This comprehensive analysis helps diagnose problematic equipment nodes using developed web applications. The recommendation system determines the most-reliable ESP configurations under the necessary operating conditions.

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.

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.

This paper discusses the experience and lessons learned during three years of electrical submersible pump (ESP) operation in heavy and viscous oil in the Peregrino field. Artificial lift applications on heavy oil fields have been a challenge for operators, and the Peregrino field is a good example for this type of ESP application. An ESP was designed to enable a wide operation window to fulfill reservoir conditions changes and to focus on the extended run life and overall lifting efficiency. Three different ESP configurations were applied to produce liquid rates from 1500 to 20000 STB/d utilizing 1100-HP and 540-HP motors. Upper completions using a packer and capsule solution were selected to comply with all production conditions. Peregrino field is a Statoil asset located in Campos Basin, approximately 85 km offshore from Cabo Frio/Rio de Janeiro state in Brazil. The oil in Peregrino has viscosity between 129 cp to 364 cp, and the API gravity varies between 13° and 15° API. The first phase of field development comprised two drilling-capable wellhead platforms and a centrally moored FPSO. Currently, there are 27 producer wells, including 3 multilaterals and 6 injectors in operation. The field is currently producing close to 100,000 STB/d of oil and has achieved a production record of 104,292 STB/d in July 2013. The learning and experience developed from the ESP design phase through three years of operation represents a very important set of best practices. This information can be used by the industry as a complete field-proven method of ESP project implementation, particularly when dealing with high flow rates, high horsepower, and viscous oil ESP operations in an offshore environment.