Electrical Submersible Pump System Research Articles

A critical analysis and improvements of empirical models for predicting the performance of Electrical Submersible Pumps under viscous flow

One of the main challenges associated with Electrical Submersible Pumps (ESPs) system is the correct sizing of the pump. High viscosity fluids, emulsions, or compressible fluids significantly impact the pump’s ability to transfer energy to the fluid. Obtaining ESP characteristic curves in conditions resembling real applications is complex but essential for the correct design, operation, optimization, and safeguarding of ESP systems. The objective of this study is to critical assess the traditional methods for predicting the ESP performance under viscous flow. This study also improves these methods driven by ESP performance data. The results show that the original models have limitations because their databases are primarily based on data from conventional centrifugal pumps. Consequently, using these methods can result in significant errors in the sizing of the production system. The accuracy of the models improved significantly after modifying the methods. Reductions in errors were observed in all correction factors, and particularly in the prediction of global performance. The improvements were effective in mitigating the effects of increased deviations with the reduction in Reynolds number observed when applying the original models to predict flow rate and efficiency.

Maximizing Oil Recovery in a Marginal Oilfield: Niger Delta Case Study

Marginal field development and production are often abandoned by operators because of finding reliable and available equipment and services to enable the field to be developed. These challenges make it difficult to economically produce such fields. This research demonstrates the use of industry-based simulators (PIPESIM, ECLIPSE and PETREL) to design well completion model, Electrical Submersible Pump (ESP). model, simulate, and evaluate the performance of ESP on a typical marginal oilfield. The main objective of this study is to effectively optimize oil production from marginal fields in the Niger Delta using Electrical Submersible Pump (ESP). ECLIPSE software was used for the reservoir description. PIPESIM was used to design the artificial lift system (ESP) for five oil wells and PETREL was used to integrate the whole system for effective production optimization. The performance of ESP wells was simulated and compared with the naturally flowing wells. The results obtained from the production forecast showed that the ESP wells gave superior oil production when compared to natural flowing wells. From the simulation results, it was observed that the cumulative oil recovery without ESP was 33,684,736 stb while that recovered with ESP was 87,751,136 stb (about 261% oil increment). The findings of this study will enable petroleum engineers to design ESP systems and well completion that would effectively optimize oil production from marginal fields in the Niger Delta. Furthermore, the findings of the study will offer new and exciting ways to process and transform abandon oilfields into productive marginal oilfields.

Technology Focus: Artificial Lift (March 2024)

The industry is now in its second year beyond the COVID-19 pandemic, and the workforce has changed in many ways, but issues facing production performance remain. Major conferences saw 116 submissions from 28 countries, with 64% regarding electrical submersible pumps (ESPs), and 18% and 8% devoted to gas lift and rod lift, respectively. Many of the papers dealt with case history successes. That is all well and good, but it doesn’t necessarily drive reader interest if it can’t be applied to their asset. The top three papers were selected on the guidelines of clarity of the abstract in addressing the scope, methods/procedures/process, results/observations/conclusions, and novel or additive information. The papers described here focus on novel unconventional horizontal downhole pump card signatures, carbon reduction through alternative energy to pump wells, and predicting downhole-discharge pressure of ESPs. Paper SPE 214723 presents a discussion of the design, evaluation, and field testing of a new type of mechanical gas separator with what the authors term a “hydrohelical” design. The separator, in Permian Basin tests, almost doubled the flow capacity of conventional gas separators with a high level of efficiency. The authors draw particular attention to the improvement of ESP operations under multiphase conditions. Carbon reduction is a hot topic, and paper OTC 32671 does not disappoint as it looks at the use of a 10-MW floating solar photovoltaic power system to meet the energy needed for 10 ESP wells on an oil platform in the Brazil equatorial region. Collaboration with the National Renewable Energy Laboratory and its System Advisor Model was used with extensive meteorological and wind data to examine the sustainability of green energy use for the petroleum industry and offer valuable guidance for future renewable energy projects in regions with similar characteristics. Finally, paper SPE 216598 comes from Sudan and Saudia Arabia and focuses on digital solutions for the challenge of knowing the downhole-discharge pressure of an ESP system. Most ESP systems do not have downhole gauges, so an artificial neural network (ANN) approach is used to predict the ESP discharge pressure for performance optimization. Forty wells and more than 12,000 data points were reduced to 16 inputs plus one hidden layer of seven neurons to provide a high degree of accuracy in prediction of discharge pressure. The authors state that the ability to accurately predict discharge pressure can lead to the early detection of possible anomalies, which can prevent costly failures and reduce downtime. Artificial intelligence technology may improve the accuracy of ANNs, but, for now, ANNs are worth a look to obtain much-needed ESP discharge pressure. Other notable papers dealt with gas separation, ESP reliability, and the increasing challenges of low rates, low pressures, and high gas fractions. Recommended additional reading at OnePetro: www.onepetro.org. SPE 214913 Solved: ESP Shutdowns and Restart Issues—Novel Pump Protection and Active 3D Dispersion System Improve ESP Performance in Multiple Wells by A. Bhattacharjee, SLB, et al. SPE 215474 A New Artificial Lift Approach in Telisa Low-Productivity Reservoir: Utilized Very Low-Rate ESP by Agus Aryanto, Medco E&P Indonesia, et al. SPE 215170 A Comprehensive Study of a Novel Submersible Pump by Hattan Banjar, Saudi Aramco, et al. SPE 214722 Case Study: Predicting Electrical Submersible Pump Failures Using Artificial Intelligence and Physics-Based Hybrid Models by Shejuti Silvia, Baker Hughes, et al. SPE 214733 Gas-Flow-Management Technology Designed To Decrease Downtime and Improve ESP Efficiency by S. Fulwider, ConocoPhillips, et al.

Hydrohelical ESP Gas Separator Increases Flow Range, Improves Reliability

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214723, “New High-Performance ESP Gas Separator,” by Barry Nicholson, SPE, and Scott R. Harryman, SPE, Oxy, and Donn J. Brown, SPE, Halliburton, et al. The paper has not been peer reviewed. _ The complete paper presents research, design, and field testing of a new type of mechanical gas separator for electrical submersible pump (ESP) systems that increases operating flow range and separation efficiency while decreasing erosion problems and improving reliability. The hydrohelical separator system has been proved effective in different types of wells. Background Several methods and techniques exist for avoiding gas in ESPs, including inverted shrouds, passive separators, mechanical gas separators, and tandem gas separators. Most share the limitations of limited flow capabilities and reduced performance at higher total flow rates. The many variables associated with complex two-phase flow behavior, internal and external pressure variations, separation methods, velocity and viscosity of fluids, effect of the pump bolted above, inherent erosion issues, and single vs. tandem designs add to the challenge of basic mechanical gas-separator operation. In 2016, a program was initiated that featured investment in both experienced personnel and advanced testing technology to unravel the aforementioned challenges and improve understanding of the operation of downhole mechanical gas separation. The team investigated innovative methods of testing and created a transparent testing system that allowed visual observation of individual internal flow regimes as well as component performance. Using a combination of high-speed photography, computational fluid dynamics validation, and specialized instrumentation, every component of a mechanical separator system was enhanced for higher flow capabilities, improved separation efficiency, and higher reliability for a variety of downhole conditions. The result was the development of a new type of mechanical gas separator for ESP use. Development Most gas separators ingest multiphase fluid into a separation chamber, separate the gas and liquid phases, eject the separated gas phase into the well annulus, and provide sufficient liquid phase fluid to the pump to enable efficient pumping. Existing designs vary, but they share separation methods that result in decreased efficiency at higher flow rates and low maximum flow rates compared with the pumps they feed. The hydrohelical gas separator is the first downhole, dynamic gas-separator design improvement in more than 30 years designed to address these deficiencies (Fig. 1). The design was aimed at the following main objectives: - Increase total fluid flow rate through the separator - Maximize efficiency of every internal and external component of the system - Reduce erosion characteristics common in traditional gas-separator designs - Improve reliability The design of the hydrohelical gas separator is based on a stationary helical vortex inducer and pump stages that enable movement of large quantities of fluid while remaining immune to gas locking. The stationary helical vortex inducer design enables increased efficiency and flow rate through the separator by reducing turbulence in remixing regions within the helical inducer and separation chamber.

Sensitivity analysis on tailpipe design for mitigating terrain slug in horizontal wells

Terrain slugs are a common challenge faced in horizontal well completions, leading to significant operational difficulties and reduced well performance. The lateral wellbore can cause hydrodynamic slug problems, even severe terrain slug issues. With undulations along the lateral, gas pockets can build up within the peaks and valleys of the wellbore. These gas pockets can restrict liquid flow until bottom hole pressure builds up enough energy to push the liquid slug to the surface. The terrain slug flow not only frequently results in foaming or emulsions at the surface but also causes downhole equipment failures, especially for Electrical Submersible Pumps (ESPs). Even with the downhole separator and gas handling pump stages, the ESP system is challenged by the elongated gas pocket that results in gas locks and electrical failures. To mitigate these issues, the use of Tailpipes (TP) in combination with ESP has become a popular solution. This study aims to explore the impact of tailpipe design on the performance of ESP systems in horizontal wells. With the help of oilfield operating companies, 5 representative wells are selected from 24 horizontal ESP wells that are facing or will potentially face the slugging issue.A total of 284 simulations are conducted using the transient simulator (OLGA, 2019) to comprehensively investigate the tailpipe design methodology for well conditions that are comparable to this study, i.e., flow rate from 500 to 2000 bpd, GLR from 500 to 2000 scf/bbl, 5 ½” and 7” casing, 9000–12000 ft well depth. Different TP diameters and lengths are simulated to evaluate the TP effectiveness at different flow rates, Gas-Liquid Ratios (GLRs), and well conditions. The results of this study can provide valuable insights and recommendations to the ESP tailpipe design for a wide range of horizontal wells applications, and help to improve their overall performance and reliability.

RANCANG BANGUN APLIKASI PERHITUNGAN GAJI KARYAWAN BERDASARKAN PRESENSI KARYAWAN PADA PT EPSINDO JAYA PRATAMA PRABUMULIH BERBASIS WEB

PT. Epsindo Jaya Pratama Prabumulih is a company engaged in the manufacturing and development of Electric Submersible Pump Systems (ESPS) and Horizontal pumping systems (HPS). This equipment is widely used in the oil and gas mining industry both in Indonesia and abroad. The company is also very aware of the importance of quality human resource (HR) services to encourage company development, so it must improve its employee information system to process employee salary calculations based on employee attendance.However, the problem with this in the HR department is that it is still difficult to make employee salary calculation reports, they still use manual calculations for employee salaries, namely inputting them in Microsoft Exel. The purpose of the research is how to design and build an application for calculating employee salaries based on employee presence at PT Epsindo Jaya Pratama Prabumulih Web-Based. The research method uses a qualitative descriptive method with data collection techniques in the form of observation, interviews and literature study. The type of data consists of qualitative data and data sources consist of primary and secondary data. The device development method uses the waterfall method. System design tools used are use case diagrams, class diagrams, activity diagrams. This application was built using a website with the PHP programming language and MySQL database, and to print reports using a pdf component.

Study Explores Design, Potential of Electric Submersible Generators

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214361, “Electric Submersible Generators: Using ESPs in an Unfamiliar Way,” by Charles E. Collins, Kenneth J. Frazier, and Bryan Coates, SPE, Baker Hughes. The paper has not been peer reviewed. _ The electrical submersible generator (ESG) is a modern interpretation of an old idea. The ESG can generate electricity to meet surface power needs or feed directly into the grid to create a revenue stream under the proper injection conditions. In typical configurations, a standard centrifugal pump is used in combination with an induction motor operated in such a way for the mechanical work of the pump to be converted into electrical energy. The complete paper explores ESG design considerations, theoretical underpinnings, and potential applications. What Is an ESG? A generic geothermal power plant typically consists of production wells that can be either artesian or artificially lifted. The heated well fluid will transfer the heat to a working fluid that rotates turbines to generate electricity. The reservoir fluid eventually will be reinjected into the formation to be warmed again and reproduced. It is common to use conventional electrical submersible pump (ESP) equipment to produce the fluids from the formation. The ESG concept focuses on injection wells from these power plants. Instead of drawing power from a source and moving fluid to the surface, the ESG takes injected fluid from the surface and creates power that can be used to offset surface power requirements onsite or sold directly back to the grid to generate revenue. The components of the ESG are very similar to those of an ESP, with an intake, discharge, seal, and cable attached to the motor. However, many of the components act essentially in reverse. The motor becomes a generator as it is driven by the pump acting as a turbine. The conventional ESP discharge becomes the intake, and the intake becomes the discharge. The cable still transmits the energy from the motor to the surface and vice versa. The seal section isolates the generator from the well fluid, handles thrust from the turbine, and equalizes the external pressure of the well with the internal pressure of the system. The generator effectively acts as a brake for the turbine. While most ESP stages are not typically designed to operate as a turbine, many will still maintain a system efficiency expected of ESPs. Application Guidelines As with conventional ESP systems, proper application of this equipment ensures desired run life and optimal electrical generation. General steps of equipment selection include the following: - Collect basic wellbore information - Verify flow rate, temperature, and pressure of injected fluid - Size the turbine accordingly based on the expected flow rate and pressure - Determine the size of the generator based on the load from the turbine and the expected heat rise

Optimization of the Well Start-Up Procedure and Operating Parameters for ESP Gas Well Dewatering

The Electrical Submersible Pump (ESP) systems were deployed in two gas wells for the dewatering of the gas reservoir. However, problems, such as the failure to start up the ESP, and changes in reservoir parameters occurred during the production. For the first problem, the well start-up operation records indicate that the ESP’s gas locking happened. To avoid this, an optimization method of the well start-up procedure for the ESP well with a check valve was correspondingly proposed, which can solve the problem without any workovers. Secondly, based on the working characteristics of the ESP and the nodal analysis method, a set of optimization methods for the operating parameters of ESPs were introduced to achieve the inflow and outflow balance. For one well, the original ESP system was planned to be installed after hydraulic fracturing. Traditionally, the ESP operating parameters were designed based on the production rate. However, in this case, the production rate and the ESP operating frequency were designed simultaneously to maximize the pump efficiency.

Energy Consumption Analysis and Optimization of Electric Submersible Pump System

Electric submersible pumps account for a considerable proportion in the development of the Bohai Oilfield. Improving the system efficiency of the electric submersible pump wells, ensuring that the units operate in the high-efficiency zone, is essential. Analysis shows that the efficiency of the electric submersible pump system depends on the wear and tear of each component of the submersible pump equipment, the setting of operational parameters, and more importantly, the production status and daily management level of the oil well. Therefore, improving the structural performance of the submersible pump product, optimizing the parameters setting of the oil well, strengthening daily management, establishing a scientific management system, and improving the production management process and system can effectively improve the production efficiency and economic benefits of the oil well, and further achieve the goal of energy saving and emission reduction. In addition, it is necessary to actively promote the concept and technology of energy saving and emission reduction, encourage oilfield enterprises to explore effective measures to reduce the energy consumption of the electric submersible pump system by strengthening the scientific management system, and achieve a green, low-carbon, and high-quality development of oilfield production to achieve the unity of economic benefits, social benefits, and environmental benefits. This article applies the above measures in the P oilfield to achieve energy optimization of submersible electric pump systems, reducing the daily power consumption of single well submersible electric pump systems by 371 kWh per day, increasing the submersible electric pump's lifespan by 200 days, generating considerable project benefits.

Artificial Neural Network Model to Predict Production Rate of Electrical Submersible Pump Wells

Summary Production data are essential for designing and operating electrical submersible pump (ESP) systems. This study aims to develop artificial neural network (ANN) models to predict flow rates of ESP artificially lifted wells. The ANN models were developed using 31,652 data points randomly split into 80% (25,744 data points) for training and 20% (5,625 data points) for testing. Each data set included measurements for wellhead parameters, fluid properties, ESP downhole sensor measurements, and variable speed drive (VSD) sensors parameters. The models consisted of four separate neural networks to predict oil, water, gas, and liquid flow rates. Sensitivity analyses were performed to determine the optimum number of input parameters that can be used in the model. The best performance was achieved with ANN models of 16 input parameters that are readily available in ESP wells. The results of the best ANN configuration indicate that the mean absolute percent error (MAPE) between the predicted flow rates and the actual measurements for the testing data points of the oil, water, gas, and liquid networks is 3.7, 5.2, 6.4, and 4.1%, respectively. In addition, the correlation coefficients (R2) are 0.991, 0.992, 0.983, and 0.979 for the estimated oil, water, gas, and liquid flow rates for the testing data points, respectively. The performance of the ANN models was compared against performance of published physics-based models and the results were comparable. Unlike the physics-based methods, the ANN models have the advantage that they do not require periodic calibration. The ANN models were used to predict the flow rate curves of an oilwell in the Western Desert of Egypt. The results were compared to the actual separator test data. It was clear that the model results matched the actual test data. The ANN model is useful for predicting individual well production rates within wide variety of pumping conditions and completion configurations. This should allow for continuous monitoring, optimization, and performance analysis of ESP wells as well as quicker response to operational issues. In comparison to traditional separators and multiphase flowmeters (MPFMs), the use of the developed ANN models is simple, quick, and inexpensive.

Experimental investigation of the Electrical Submersible Pump's energy consumption under unstable and stable oil/water emulsions: A catastrophic phase inversion analysis

The presence of water in crude oil exploitation by the Electrical Submersible Pump (ESP) systems may cause several problems in energy consumption and operational instabilities due to emulsion formation. Indigenous surfactants in crude oil also contribute to emulsion stabilization, which can exacerbate these problems. In this paper will be experimentally investigated the influence of the emulsion stability on ESP energy consumption and operational instabilities through an 8-stage ESP operating with unstable and stable emulsions, with and without a demulsifier. The experimental tests were performed for one oil viscosity, a constant total flow rate, and two ESP rotational speeds. Initially, the ESP relative dimensionless power (RDP) was analyzed along with the emulsion system and the droplet size distribution (DSD). An interesting difference regarding the presence of surfactants was observed experimentally in the RDP and phase inversion points. The relationship among the ESP dimensionless power, torque, and electrical current with maximum droplet size allowed to conclude that these parameters can be related to the start of the coalescence process, i. e, able to predict the catastrophic phase inversion (CPI) point.

Real-time anomaly detection methodology in the electric submersible pump systems

Trips and failures are common occurrences in the Electric Submersible Pump (ESP) systems. Considering the high maintenance cost of the intervention and workovers post failures, ESPs connected to real-time monitoring and surveillance systems are used to fulfill proactive responses and early detection of incidents. Large amounts of dynamic and historical production data acquired from the surface and downhole sensors can help perform diagnostics and prognostics on ESPs. This study applies the Hotelling T-square statistic (T2) and Squared Prediction Error (SPE) equations combined with Principal Component Analysis (PCA) method to construct a predictive model based on the collected ESP data. This predictive model provides a solution that enables to detect the developing ESP trips and failures in real time. A new input matrix corresponding to any period in the whole ESP life cycle is fed to the predictive model to obtain prediction results. The model validation analysis demonstrates that the predictive model can identify the stable operating regions of ESP and detect the potential ESP trips and failures before the actual failure time. This study concludes that this proposed diagnostic model can serve as a real-time platform to identify dynamic changes and therefore monitoring potential ESP trips and failures in real-time.

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

To avoid premature operational failure of the ESP systems, their vibration levels must be evaluated for acceptance before installation. The vibration assessment of Electrical Submersible Pump (ESP) systems and other rotating machines considers that the most important amplitude occurs in the radial orientation. Typical vibration amplitude estimation uses radial orthogonal sensors and considers the maximum vibration amplitude between the two sensor signals. However, this approach does not account for the orbit's shape, leading to an error up to 41,4% between the maximum estimated amplitude in each sensor and the maximum radial vibration amplitude, the orbit semi-major axis. This paper proposes a method to generate a frequency spectrum with invariance to the shape of the vibration orbit, namely the Orbit Semi-major Axis Spectrum. The proposed method is compared to the typical vibration amplitude estimation approach using individual sensor signals and the Full Spectrum method. The methods are applied on vibration signals from two pumps at different wear states, and results are analyzed. The estimation error of the vibration amplitude in ESP systems due to disregarding the shape of the vibration orbits is shown. The results indicate that the proposed method presented the maximum radial vibration amplitudes of each orbit frequency component (orbit semi-major axis), which is not directly possible with the Full Spectrum and is impossible with the individual frequency spectrum. The orbit semi-major axis amplitudes of the pumps were up to 28% higher than the maximum amplitude estimated from the individual orthogonal sensors.

Switched Reluctance Motor for Electric Submersible Pump

Switched reluctance motors may be advantageous when used as the primary motor for an electric submersible pump system.  They are less susceptible to jamming failures due to their high starting torque and ability to reverse direction.  Driving these motors requires well-timed pulse waveforms and precise control of the motor based on its rotational position.  In general, voltage-based sensing and control systems at the surface see highly unpredictable waveforms with excessive ringing behaviour due to the impedance characteristics of the long cabling between the surface controller and the downhole motor system.  In this work, a system is detailed which monitors the current waveforms on the motor coil excitation conductors at the surface as a source of motor performance feedback and control.  State-space modelling of the system shows stable current waveforms at the surface controller for both short and long interconnect cable systems.  A laboratory demonstration of the surface controller, interconnect cabling, and motor system is shows excellent agreement with the current and voltage waveforms predicted by the state-space system model.

Mechanistic modeling of gas effect on Multi-stage Electrical submersible pump (ESP) performance with experimental validation

The performance of widely used Electrical Submersible Pump (ESP) is significantly affected by gas entrainment, which is a commonly encountered phenomenon in the petroleum industry. The boosting pressure of an ESP gradually degrades with the increase of inlet gas volumetric fraction (IGVF). The flow becomes unstable, and a breakdown occurs when the flow pattern switches from bubble flow to intermittent flow. Therefore, an accurate ESP model is necessary to help design and operate the ESP system under gassy flow conditions. The gas–liquid two-phase tests of different ESPs were extensively carried out at the Tulsa University Artificial Lift Projects (TUALP) to investigate the complex flow behaviors. A mechanistic model was proposed for the gas–liquid flow inside a rotating ESP, which captures the gas–liquid two-phase flow characteristics, including in-situ gas void fraction, flow pattern transition, bubble size, boosting pressure, etc.In the new model, the pump head is calculated by subtracting recirculation head loss, turning head loss, friction head loss, and leakage head loss from the Euler head. The best-match flowrate QBM approach is introduced, and the recirculation head loss is generated by the mismatch between the velocity of Qin and QBM. The drag force coefficient correlations are selected based on flow patterns and bubble sizes. Then, the mixture density and in-situ gas void fraction are calculated according to the force balance on gas bubbles. The proposed model is validated by experimental data of a 5-inch radial-type ESP (TE2700), a 5-inch mixed-type ESP (GC6100), and a 4-inch mixed-type ESP (MTESP) of the TUALP. The predicted ESP boosting pressures and flow patterns agree well with the corresponding experimental measurements.

Implementing the autonomous adaptive algorithm to manage ESP operation in harsh reservoir conditions

The well geometries with a shallow kick-off point in conjunction with surface infrastructure limitations have led to Electrical Submersible Pump (ESP) technologies' application as one of the most suitable artificial lift methods for the harsh reservoir conditions. However, the harsh reservoir conditions in terms of the low reservoir pressure, high reservoir temperature, scaling problems in various forms, and high gas content at the pump intake have reduced the ESP system run life. Therefore, this research represents the Autonomous Adaptive Algorithm (A3) as a holistic approach to integrate analytical and machine learning models to assist production engineers in the early detection of operating problems. The A3 relies on different data sources and uses unique, well diagnostics logic to generate valuable features and prepare data for training. Finally, the paper evaluates different classifiers and explores the possibilities of application A3 as a flexible edge solution. The research benefits will be demonstrated for several problematic ESP wells.

Numerical and Orthogonal Study on Optimization Analysis of Structure Parameters of Bubble Breaker for Electrical Submersible Pump System

Abstract Under slug flow conditions, electrical submersible pumps (ESPs) show a low efficiency due to Taylor bubbles, which cause pressure surging and gas pockets and the further deterioration of pressure boosting ability. In this study, a novel downhole bubble breaker is designed for mitigating the impact in ESP under slug flow conditions. The computational fluid dynamics-population balance model (CFD-PBM) coupled approach was used to calculate the bubble breaker's average bubble diameter to evaluate its efficiency. Meanwhile, experimental studies were conducted and compared with numerical results. Also, matlab and DIP-image technology was used to calculate the bubble diameter. Compared with experimental results, the simulation results agree well. Furthermore, the novel bubble breaker's performance was studied by orthogonal approach. The best result of range analysis is A2B3C4D1E4 (α = 30 deg, L = 300 mm, R = 2:1, vsg = 0.2 m/s, and vsl = 0.08 m/s), and sensitively analysis results present that the range of impact intensity are A (inlet angle) > E (superficial gas velocity) > B (total length) > D (superficial liquid velocity) > C (ratio of the gas–liquid channel). The optimal structure's bubble diameters are all less than that of the original structure, with a superficial gas velocity range of 0.2–0.6 m/s. The downstream bubble diameter of the optimal bubble is about 31.6% lower than the original structure at the maximum value point.

Field Study Examines Wellhead-Penetrator Problems, Solutions in SAGD Operations

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.

Natural Aging of Ethylene-Propylene-Diene Rubber under Actual Operation Conditions of Electrical Submersible Pump Cables.

Ethylene-propylene-diene monomer (EPDM) rubbers used in electric submersible pump (ESP) cables were analyzed after being aged in actual operation conditions in oil wellbores. These rubbers constitute the insulation and jacket layers of the ESP cables. EPDM rubbers from four different cables operating during different time intervals (2 and 4.8 years) at different depths (from 760 to 2170 m) below sea level were studied. To verify the effects of the long exposure on the rubber performance, thermal analysis was performed to determine the thermal stability and activation energy of degradation. In addition, structural analysis, through vibrational spectroscopy and crosslinking fraction assessment, was carried out. The mechanical properties of the aged rubbers were inferred through the measurement of hardness, while the absorption of a service fluid was studied by gravimetry. The results showed only minor changes in the thermal, structural, mechanical and barrier properties of the EPDM-based ESP cable layers. It is suggested that the thermo-oxidation mechanism followed by chain scission does not have a role in the degradation of EPDM within the aged ESP cables, and no sign of variation of crosslink fractions has been encountered. Therefore, it was concluded that EPDM-based layers seem not to be weak links in the configuration of modern ESP systems.

Design of Electrical Submersible Pump system in geothermal wells: A case study from West Anatolia, Turkey

Geothermal is defined as one of the renewable and sustainable energy sources. The sustainability of geothermal wells is highly dependent on the pressure drive mechanism and non-condensable gas (NCG) content of the produced geothermal fluid. Pressure decline and decline of non-condensable gases are commonly observed in geothermal production wells, which is unfavorable for wells’ lifetime. Electrical Submersible Pumps (ESP) are one of the solutions for extending the lifetime of geothermal wells. In this study, the application of ESP in a geothermal well was designed and simulated. The case study well is located in one of the most exploited geothermal fields in Western Turkey: the Alasehir geothermal field. ESP design is performed by using the codes constructed in PYTHON in this study. The sensitivity of production profiles of the well is simulated by using a wellbore simulation program called WELBOR. Sensitivity studies are conducted for different sizes of production tubing (5, 6, 65/8, and 7 inches), setting depths (500, 600, 700 m), and flow rates (85, 150, 180, 250, and 275 ton/hour). The optimum ESP design conditions are determined by considering pump consumption, flashing depth, wellhead flowing pressure, and production rate. Finally, it was found that ESP design will increase the production rate of the case study well by 165 tons/hour. Furthermore, the proposed ESP will make a profit for at least 8 months, according to the economic analysis in this study.