Integrated Evaluation of Electric Submersible Pump Failures under Diverse Field Operating Conditions

Walid Mohamed Mahmud ^*

1. University of Tripoli, Tripoli, Libya

* Correspondence: Walid Mohamed Mahmud

Academic Editor: Grigorios L. Kyriakopoulos

Received: September 09, 2024 | Accepted: March 17, 2026 | Published: March 26, 2026

Journal of Energy and Power Technology 2026, Volume 8, Issue 1, doi:10.21926/jept.2601006

Recommended citation: Mahmud WM. Integrated Evaluation of Electric Submersible Pump Failures under Diverse Field Operating Conditions. Journal of Energy and Power Technology 2026; 8(1): 006; doi:10.21926/jept.2601006.

© 2026 by the authors. This is an open access article distributed under the conditions of the Creative Commons by Attribution License, which permits unrestricted use, distribution, and reproduction in any medium or format, provided the original work is correctly cited.

1. Introduction

Hydrocarbon production requires energy to lift reservoir fluids to the surface. In the early production phase, most wells flow naturally due to the reservoir's inherent drive mechanisms; these are called naturally flowing wells. In such a well, sufficient energy is stored within the reservoir to flow the produced fluids to the surface [1,2]. However, this natural energy depletes over time. Consequently, the fluids eventually require an external lift method. The rapid increase in energy demand has encouraged producers to seek methods to improve production rates [2]. More than 90% of oil wells require artificial lift at some point, either when reservoir energy is insufficient to lift fluids naturally at an economical rate or to boost production [3]. Several artificial lift methods are available to produce from wells that have ceased flowing or to increase the rate from flowing wells [4]. These methods fall into two main categories: mechanical lifting using pumps and gas lift. In gas lift, a high-pressure gas is injected into the wellbore to supplement formation gas and lift the fluids. Mechanical pump systems are further subdivided into positive displacement pumps, such as sucker rod pumps and progressing cavity pumps (PCP). And dynamic displacement pumps, such as electrical submersible pumps (ESP) and hydraulic jet pumps. Other, less common artificial lift methods include hydraulic piston pumps and plunger lift. ESPs are used in both newly drilled and mature wells, where they boost production and sustain hydrocarbon recovery at higher rates despite diminishing reservoir energy [5,6]. As one of the fastest-growing artificial lift technologies, ESPs are installed in onshore and offshore environments and represent over 33% of the artificial lift systems used across the world's one million operational wells [3]. This method is particularly dominant in offshore applications, where it is considered a highly reliable solution and is deployed in more than 90% of offshore wells to achieve high-volume fluid production efficiently [7]. In terms of market impact, ESPs constituted over 40% of the global artificial lift market value in 2022 and were responsible for roughly 60% of worldwide oil production [8]. ESPs are operationally flexible in terms of production rate, ranging from 150 barrels per day (BPD) to 150,000 BPD [9]. They can also operate with pump intake pressures below 100 psi, handle high water cuts, and perform effectively at significant depths, even under hostile reservoir conditions [10]. Despite these ESPs' capabilities, unforeseen failures may occur, halting production. These failures typically stem from a combination of electrical, mechanical, and operational issues, which include system design issues. Therefore, operational disruptions and financial losses from downtime and intervention costs are inevitable [11].

ESP systems are highly effective in wells with specific conditions, such as low bottom-hole pressure, low gas-to-oil ratio, low bubble-point pressure, high water cut, and deep or deviated wells [3]. However, the components of an ESP system are prone to unpredictable premature failures and short run lives caused by various factors, including challenging well conditions, electrical issues, and design and installation errors [4]. These failures lead to costly workovers and production losses, driving the need for improved reliability through innovations tailored for harsh conditions, preventive maintenance, and root cause analysis [12,13,14,15]. For effective management, establishing clear, context-specific failure definitions is essential. Harsh downhole environments, characterized by corrosion, high temperatures, viscous fluids, free gas, sand production, and scaling [16], can also lead to ESP failures. Furthermore, manufacturing defects and human error contribute to these failures. ESP failures are commonly classified into four main categories: electrical failures, mechanical failures, operational failures, and control and system failures [17,18,19,20]. In the present study, control and system failures are included with operational failures.

Electrical failures encompass short circuits, open circuits, power delivery system deficiencies, cable degradation, motor breakdown, overload tripping, and connection failures. Additional contributors to failure involve blockage caused by solid particles and contamination of produced fluids. Electrical breakdowns resulting from power fluctuations, voltage transients, and phase imbalance impose excessive stress on motors and power cables [21]. Mechanical-type failures, on the other hand, encompass fluid leakage, corrosion, unsuccessful pressure testing, dislocation, structural damage, component misalignment, immobilized or deformed components, equipment breakage or rupture, and separation or disconnection of parts. Failures associated with material degradation include thermal damage, corrosion in both sweet and sour environments, mechanical wear, melting, and overheating. Kalu-Ulu et al. [17] concluded, after a comprehensive review of ESP failure cases, that there was a notable transition in dominant failure mechanisms, from primarily mechanical origins to predominantly electrical-related causes. Motor failure mechanisms include voltage imbalance, fractured rotor bars, rotor-stator misalignment, and inter-turn insulation defects. Operational failures are associated with elevated temperatures, pressure surges, free gas interference in multiphase flow, scale and solid accumulation, and complications associated with deviated wellbore configurations [22]. Corrosion might also be classified as an operational failure, alongside mechanical ones. However, in the present study, corrosion is classified as a mechanical failure. This includes corrosive effects on motor and pump casings, mineral scale formation that insulates housing components and obstructs pump stages, and erosive damage caused by sand and other abrasive materials. Control and system failures include design deficiencies, such as improper pump capacity selection, accelerated component deterioration, and shortened service life. Errors during installation, including insufficient pre-commissioning inspections and proper assembly, introduce latent defects that degrade system reliability. Control and system also include manufacturing defects that contribute to reduced operational performance. It is important to distinguish between anomalies and planned pump shutdown events as failures, as these occurrences frequently represent temporary protective responses triggered by operational limits rather than irreversible breakdowns.

Given the range of failures that can reduce pump run life, a thorough investigation of common ESP system failures and the development of practical mitigation strategies are imperative to extend the operational life of hydrocarbon-producing wells using ESPs.

Effective monitoring is crucial for extending ESP run life. Monitoring vibration, for example, can help prolong operation, as increased vibration is often linked to sand production, thrust issues, motor overheating, and pump wear [23,24]. Vibration analysis thus serves as a useful tool for early failure detection and prevention. Another important approach is to establish standardized practices for collecting, tracking, and sharing ESP run life and failure data [25]. This method relies on two key elements: a common dataset and a standard nomenclature for coding failure information. This enables failures to be described by mode, cause, and detail, helping the industry reduce uncertainty in predicting run life and improve overall performance. Reliable outcomes, however, depend on data derived from large, consistent datasets.

Accurate design, proper installation, and continuous operational monitoring are essential for optimizing ESP run life. The use of a practical checklist [26] can help identify problems across the ESP mechanical, electrical, and hydraulic components and facilitate solutions throughout the ESP lifecycle, from design to operation. Implementing such checklists can help eliminate premature failures and optimize run life.

Failures due to sand production and high gas-to-oil ratios can be minimized and run life extended by using shrouded motors, gas-handling equipment such as the XGC gas handler, slim-hole pumps, and abrasion-resistant pump materials (e.g., ARS or ARM-COM pumps) [27]. They [27] categorized failures by affected hardware components rather than by failure mechanisms. The distribution of failures was reported as motor-related (40%), pump-related (22%), cable-related (26%), and miscellaneous causes (12%). Field data from horizontal wells in the Permian Basin indicated that excessive temperature exposure (35%) and solids-related complications (29%), particularly sand and abrasive materials, are the primary contributors to ESP failures. Secondary causes include oversized ESP installations (16%), cable and pothead malfunctions (15%), and other miscellaneous issues (5%). Collectively, thermal and solids-induced failures constituted more than half of all reported ESP incidents [28].

Several studies have combined field data analysis with laboratory experiments to investigate common ESP failures and challenges [29]. Poor cable quality and scale buildup from asphaltene and calcium carbonate (CaCO₃) were identified as major causes of failure. Mitigation strategies include improving cable technical specifications and injecting solvents like xylene to dissolve scale. A Dismantle Inspection Failure Analysis (DIFA) approach was proposed to analyze ESP data and identify factors behind premature failures [30]. Key contributors included well conditions, installation errors, and material reliability. High-salinity reservoir fluids and corrosive media can also cause premature failures due to corrosion and erosion [31]. Recommended countermeasures include installing freshwater injection lines and upgrading ESP components, such as housing materials, cables, motors, motor lead cables (MLC), protectors, and pumps. Improvements to surface facilities, such as variable-speed drives (VSDs), generators, and control panels, can also reduce failure rates. A stage-by-stage analysis approach was proposed to understand better gas behavior and its effects on pressure control and gas volumes within ESP systems [32]. In wells producing large volumes of free gas, additional pump stages may be required to lift fluids at desired flow rates.

Further studies have applied root cause analysis (RCA), field testing, and system data analysis to ESP design, optimization, diagnosis, failure analysis, and performance in deep wells with high temperatures, high GOR, and corrosive gases such as CO₂, N₂, and H₂S [33].

Inorganic scale buildup in offshore ESP systems was studied using X-ray analysis, lab experiments, corrosion tests, and sensitivity analysis [34]. The study recommended monitoring discharge and intake pressures, motor temperature, and power to prevent failures. A combined chemical and mechanical treatment strategy was suggested for scale removal [35].

Electrical discharge, which can cause motor bearing failure, was investigated using finite element analysis (FEA) and computational fluid dynamics (CFD) to study electric field distribution within ESP motor bearings [36]. Failures can be reduced by ensuring a balanced power system, maintaining good power quality, improving insulation materials, and minimizing voltage stress.

The role of data management systems, including data input and quality, fluid characterization, DIFA, operational procedures, and real-time surveillance in improving ESP run life has also been examined [37]. Implementing these four elements reduced ESP failures by 86% and increased survival probability by 66.6%.

An integrated approach combining ESP design improvements, real-time monitoring, and DIFA was developed to increase run life [38]. Upgrading ESP metallurgy, implementing advanced gas-handler systems, and developing real-time data analytics software contributed to longer average run life and successfully addressed repetitive trips and failures.

A troubleshooting guide was proposed to identify the effects of a worn pump, broken shaft, well sanding, gas block, and sensor data loss on parameters such as flow rate, motor temperature, and motor amperage [39]. The guide provided tests and remedies that reduced the failure index by 60%, thereby improving ESP run life. The effects of viscosity and two-phase flow on ESP performance were studied through experimental tests, analytical approaches, and CFD simulations [40]. Predictive modeling of ESP performance was conducted numerically [41,42]. Well-specific cubic models were used to examine how fluid properties affect ESP performance, finding that higher API gravity, higher GOR, and higher pump intake pressure enhance pump speed. In contrast, higher water cut decreases it [43].

Artificial intelligence systems were applied to mitigate electrical, mechanical, and operational ESP failures, including selecting appropriate materials for downhole environments, optimizing pump design for efficiency and reliability, and implementing real-time monitoring [22]. Statistical failure data evaluation and DIFA have identified electrical and motor failures, followed by gas locking, as the primary root causes of ESP failures [15]. A novel, operationalizable Prognostics Health Management (PHM) engine for ESPs was developed [44] to address challenges such as limited measurements and complex failure modes. A domain-driven machine-learning feature engine was used to extract patterns from typical surveillance data. Thus, continuous predictions for Risk of Failure (RoF) and Remaining Useful Life (RUL) were generated and linked with the data quality module and configurable alarms.

A physical constraint (PC) for the loss function in the Long Short-Term Memory (LSTM) network model for ESP health prognosis was developed to address the lack of comprehensive characteristic parameters and the reliance on purely data-driven models [45]. The study integrated physical constraints derived from the wellbore energy conservation equation into an LSTM network's loss function. Wei et al. [45] report that the physics-informed approach improved the model's accuracy and convergence speed when tested across three failure types: ESP clogging, sand production, and reservoir pressure rise.

A principal component analysis (PCA) based model for real-time ESP failure diagnosis was developed [14] to overcome the limitations of traditional methods like ammeter charts. Using model data, they achieved a diagnostic accuracy of 93.3% when evaluated with logistic regression. A machine learning workflow for enhancing ESP reliability was deployed to integrate real-time sensor data with historical failures to identify anomalies and predict failure probability up to 90 days in advance [46]. Composed of a Healthy Model for anomaly detection and a Survival Model for time-to-failure estimation, the solution generated daily alerts that enabled field interventions such as chemical cleanups and parameter adjustments. Batallas et al. [46] reported a deployment of 72% recall rate, allowed preventive action in 75% of high-risk wells, and successfully extended run life by an average of over 145 days in mitigated cases.

2. Area of Study, Methodology, and Analysis

The ESP data for this study are based on 47 oil wells from two oil fields in the Murzuq and Sirt Basins, Libya. The Murzuq Basin in southwestern Libya represents a prolific hydrocarbon province, containing significant oil fields with reserves totaling billions of barrels. The primary reservoirs in this basin are the Ordovician Memouniat Formation sandstones, which exhibit favorable porosity and permeability, providing excellent reservoir quality. Additionally, subordinate Devonian Tadrart-Kasa sandstones present further potential. These productive units are situated within a complex geological framework, where structural and stratigraphic traps, including large Paleozoic arches, have facilitated substantial hydrocarbon accumulation. In contrast, the Sirt Basin in central-eastern Libya hosts a distinct and diverse petroleum system, with numerous fields along its eastern trend and western fairway. Production is derived from a broader range of reservoirs associated with Mesozoic rifting. Key reservoirs include Cambrian-Ordovician sandstones of the Amal Formation, Cretaceous Nubian sandstones, and Paleocene-Eocene carbonates of the Zelten Formation, with occasional production from fractured Precambrian basement. Hydrocarbons are predominantly trapped within structural features, most notably horst blocks, which were formed during Tertiary rift-related tectonic events.

A thorough evaluation of ESP performance data from multiple production wells across the two fields. The selected wells were intentionally chosen to cover a wide range of reservoir conditions, fluid properties, production behaviors, and artificial lift operating environments. This diversity ensures that the failure analysis captures the various operational challenges typically faced, allowing the conclusions to apply to similar production settings. Well selection depended on having complete operational histories, including continuous production records, detailed ESP run-and-pull reports, and documented failure investigation files. Only wells with reliable, traceable datasets were included, ensuring that the results are both statistically meaningful and relevant to operations.

Failures were classified using a consistent framework aligned with common ESP failure taxonomies in the literature. Each failure event fell into one of three main groups: electrical failures, which include motor insulation degradation, short circuits, cable damage, and surface power disturbances; mechanical failures, such as shaft breakage, bearing wear, pump seizure, corrosion and mechanical deformation; operational or well-condition-related failures, including scale deposition, gas interference, sand erosion, high water cut effects, solids plugging; incorrect pump selection or design mismatch, which encompass improper pump sizing, unsuitable material selection, and misalignment between reservoir conditions and ESP design specifications. Each failure classification was independently verified with corresponding DIFA reports, pull-out inspection results, pre-failure production behavior, and post-failure equipment examination.

A structured Root Cause Analysis (RCA) methodology was then applied to each failure event. This process involved comparing original design specifications with actual operating conditions, predicted performance envelopes with observed field behavior, and documented installation practices with field execution records. This multi-level evaluation allowed for identifying both direct failure mechanisms and underlying contributing factors, such as design deficiencies, operational deviations, inadequate surveillance, or improper equipment selection.

Failure frequencies were quantified for each category and analyzed across different wells. Statistical trend analysis helped identify dominant failure mechanisms and recurring patterns. Emphasis was placed on linking failure occurrences to key operating variables, including elevated water cut and corrosion rates, tendencies toward scale and solids deposition, gas volume fraction, voltage instability, and power quality fluctuations. These correlations offered valuable insights into failure drivers and helped develop predictive relationships between operating conditions and expected ESP reliability.

3. Results

An integrated analysis of operational records, dismantle inspection failure investigation reports, and production histories from forty-seven wells across the Murzuq and Sirte Basins revealed that ESP reliability is governed by a complex interaction between electrical integrity, mechanical robustness, wellbore environment, and system design compatibility. Failures rarely resulted from a single cause; instead, they emerged through cumulative degradation processes that eventually exceeded the tolerance limits of one or more system components. Field inspections and DIFA reports identified recurring physical and operational indicators of degradation, including discolored motor oil indicating thermal stress, sand abrasion in pump bolt holes, scale deposits on protectors and pump stages, and fluid ingress into protector chambers due to seal failure. The predominant failure reasons were motor grounding, overheating, wet protectors, worn gas separators, locked pump shafts, scaled intakes, loose pump shafts, grounded cables, corroded cable armor, tubing pressure loss, and bleeder pin washout. These issues were systematically categorized into electrical, mechanical, and operational/system-level failures, with frequencies derived from the dataset. The consolidated failure classification and distribution are presented below. Table 1 illustrates the classification and Frequency of ESP Failure Modes. The table provides a detailed, itemized list of all ESP problems observed across the 47 wells, ranked by frequency of occurrence.

Table 1 Classification and frequency of ESP failure modes in the 47 wells of the study.

Table 2 aggregates the detailed problems from Table 1 into their major categories and illustrates their relative contribution to the overall failure landscape. The table sums all Mechanical problems from Table 1 for a total of 298 scaled occurrences and calculates that this represents 44.1% of all failures. It does the same for Electrical (27.7%) and Operational/System (25.4%) failures. The Operational/Design sub-category (2.4%) is separated to highlight design-related issues within the broader operational group. The clear takeaway from the table is that Mechanical failures are the dominant category in your study population.

Table 2 Failure distribution by category across 47 ESP installations.

Table 3 synthesizes and interprets the information from Table 1 and Table 2 and explains the cause-and-effect relationships and their consequences for the ESP system. The table also lists the key problems and states, for each problem, the dominant underlying failure mechanism.

Table 3 Mapping of ESP problems to dominant failure mechanisms and system impacts.

3.1 Key Technical Interpretation and Industry Benchmark Comparison

Mechanical failures dominated ESP reliability in the studied fields, accounting for 44.1% of all failure events, primarily driven by solids production, corrosion, and seal degradation. Electrical failures accounted for 27.7%, with grounding and insulation failures being the most common. Operational and system-level issues comprised 25.4%, often related to diagnostic limitations or design mismatches. Figure 1 summarizes the cascade of failures encountered, aligning with the interconnected failure mechanisms: electrical, mechanical, and operational.

Figure 1 Common ESP failure evolution pathways based on field data analysis from the two fields.

Compared with global ESP failure benchmarks, the dataset of the present study illustrates a higher prevalence of mechanical failures (44.1% vs. industry average of ~35-40%) and a relatively lower electrical failure rate (27.7% vs. ~30-40% typical in regions with stable power grids). Studies from the Permian Basin, for example, report electrical failures as the leading cause (~40%), followed by solids-related damage [28]. The elevated mechanical failure rate in Libya is attributable to aggressive sand production, high-salinity corrosive fluids, and scaling tendencies prevalent in the Murzuq and Sirte Basins. Notably, protector-related failures—which often bridge electrical and mechanical domains—were a critical initiator in ≈21% of cases, higher than the ~15% reported in offshore Gulf of Mexico studies [37]. This highlights the need for advanced sealing technologies and improved metallurgy in high-corrosivity environments.

3.2 Failure Distribution and Evolution Pathways

Electrical failures were frequent, dominated by motor grounding, insulation breakdown, cable damage, and fluid invasion into motor-protector sections. DIFA reports consistently noted the presence of well fluids inside the protector chambers, indicating a loss of sealing integrity. Electrical degradation is often initiated at cable terminations, where corrosive fluids, high temperatures, and cyclic loading accelerate insulation aging.

Mechanical failures manifested as pump shaft seizure, bearing wear, impeller erosion, and severe scale accumulation. Many pumps were recovered in a locked state due to sand bridging, scale precipitation, or component deformation. Before failure, systems exhibited noisy operation, elevated current draw, and reduced hydraulic efficiency.

Operational and environmental stressors, such as high water cut, corrosive brine, scaling, gas interference, and sand production, accelerated both electrical and mechanical degradation. Loss of tubing integrity through corrosion perforations or collapsed joints often led to No Flow to Surface (N.F.T.S.) and Off Downhole (O.D.H.) events, destabilizing system operation and hastening failure.

Pump run life varied widely, from immediate failures to several thousand days. Shortened run life correlated strongly with early electrical compromise, uncontrolled solids production, severe corrosion, and operation outside recommended hydraulic and thrust envelopes. Failure progression followed predictable degradation pathways (Figure 1). Electrical failures typically begin with minor deterioration of seals or insulation, followed by moisture intrusion, progressive insulation breakdown, partial grounding, and, finally, catastrophic motor failure. Mechanical failures evolved from early-stage erosion and vibration-induced fatigue into bearing collapse, shaft distortion, impeller interference, and complete mechanical seizure. These processes were often accelerated by hydraulic instability caused by gas interference, fluctuating production rates, and unsteady thrust loading.

4. Discussion

The results of this study confirm that ESP reliability, as observed in the studied pumps, is governed by interdependent failure mechanisms spanning electrical, mechanical, hydraulic, chemical, and operational domains. These findings align with global ESP field studies [4,27], yet reveal distinct regional characteristics due to harsh downhole environments.

4.1 Dominance of Mechanical Failures and Corrosion

The predominance of mechanical failures (44.1%) underscores the severe impact of sand production, corrosion, and scaling. Corrosion emerges as the most pervasive degradation driver, accelerated by high-salinity formation waters, elevated temperatures, and dissolved corrosive gases. This not only weakens structural components but also creates pathways for fluid invasion into electrical systems, leading to cascading failures. The coupling between corrosion-induced tubing leaks, protector failure, and motor grounding mirrors degradation models reported in mature fields [31,47].

4.2 Electrical System Vulnerability

Electrical failures, though less frequent than mechanical ones, remain critical due to their sudden and catastrophic nature. Insulation breakdown and moisture ingress, often initiated by protector seal failure, were the primary electrical failure mechanisms. The frequent observation of wet protectors indicates that conventional elastomer sealing systems are inadequate for aggressive production environments such as those considered in the present study. Advanced protector designs, hermetically sealed motors, and improved polymer insulation systems are recommended to enhance electrical reliability. This is in accordance with recommendations presented by Ye Z and Wilcox S [36], and Bremner C et al. [13] presented similar recommendations.

4.3 Operational and System-Level Challenges

Operational and system-level failures (25.4%) often stem from inadequate real-time monitoring, diagnostic limitations, and design mismatches. The prevalence of ODH and N.F.T.S. classifications underscores the need for improved failure-reporting frameworks and enhanced surveillance capabilities. Implementing downhole sensors for temperature, pressure, vibration, and current monitoring can enable early detection of failure precursors, as demonstrated in modern ESP deployments [12,37].

4.4 Thrust Management and Pump Selection

Improper thrust management due to incorrect pump sizing or fluctuating production rates was identified as a critical reliability weakness. Excessive thrust loading accelerates bearing failure, impeller damage, and shaft deformation, reducing ESP life by more than 50% in severe cases [4,27]. The use of variable-speed drives (VSDs), detailed nodal analysis, and real-time performance matching is essential to maintain operation within optimal thrust windows.

4.5 Recommendations for Mitigation

To extend ESP run life in similar environments, the following integrated strategies are recommended:

• Material Upgrade: Use corrosion-resistant alloys (e.g., REDA alloy, Monel) for tubing, cable armor, and critical components.
• Solids and Scale Management: Implement gravel packs, abrasion-resistant pumps (e.g., ARM-COM), and optimized chemical injection programs.
• Enhanced Sealing and Insulation: Adopt advanced protector designs and hermetic motor sealing to prevent fluid ingress.
• Real-Time Monitoring and AI: Deploy downhole sensors and machine-learning-based prognostic health management (PHM) systems for early failure prediction [44, 46].
• Robust Design Practices: Incorporate reservoir-specific data into ESP design, ensuring proper pump sizing and thrust control.

5. Conclusions and Recommendations

This study presents a comprehensive assessment of ESP performance and failure behavior based on an extensive analysis of operational data from 47 wells in Libya. The integrated evaluation reveals that ESP failures are rarely attributable to a single cause but result from the combined influence of electrical degradation, mechanical wear, operational stressors, and system design deficiencies.

Mechanical failures dominated the failure profile (44.1%), driven by sand production, corrosion, and seal degradation. Electrical failures accounted for 27.7%, primarily due to insulation breakdown and moisture ingress. Operational and system-level issues represented 25.4%, often linked to diagnostic gaps and design mismatches.

Compared to global benchmarks, wells studied exhibited a higher mechanical failure rate, reflecting the aggressive downhole conditions prevalent in the two regions considered. Protector-related failures were particularly significant, acting as a critical bridge between electrical and mechanical failure domains.

To enhance ESP reliability and extend run life, an integrated reliability framework is recommended, encompassing:

• Accurate reservoir-driven design and material selection.
• Advanced chemical and solids management programs.
• Real-time surveillance and predictive analytics.
• Proactive operational control and maintenance practices.

Implementing these strategies can significantly reduce ESP failures, improve production efficiency, and optimize field development economics in similar challenging environments.

Author Contributions

The author did all the research work for this study.

Competing Interests

The author has declared that no competing interests exist.

AI-Assisted Technologies Statement

I utilized the AI-powered tool, DeepSeek, to assist with language editing and to enhance the readability of the resubmitted manuscript. I have subsequently reviewed and revised the AI-generated suggestions to ensure accuracy and originality, and I assume full responsibility for the final content of the work.