bluuebunny/crossref_metadata_2025_split huggingface dataset:
First Successful Use of an Electrical Submersible Progressive Pump with a Y-Tool Implementation
Authors: Al-Shatri Mohammad , Kaipov Yermek , Qoqandi Abdulrahman , Alawagi Ahmed 
Published: October 2024

Abstract
This paper presents a unique case study on offshore exploration to prove the commercial potential of oil reserves in the Gulf. It describes the design of a downhole testing platform with a new type of pump. An operating company drilled new appraisal wells to evaluate the presence of multizone reservoirs with heavy oil. The objectives were to confirm the presence of oil reservoirs and well deliverability and prove the field development concept. The well test included the production of heavy oil with an electrical submersible progressive cavity pump (ESPCP) under different regimes, followed by the build-up. The surface testing system was used to manage the fluid at the surface and measure the flow rates. The downhole testing system (DST) was integrated with ESPCP to lift the fluid and to use wireless real-time telemetry to measure the pressure and temperature at different depths.
The reservoir testing was highly successful in proving the commercial potential of the new reserves. The ESPCP was a key element in ensuring continuous reservoir fluid flowing to the surface to achieve flow stability for accurate estimation of the productivity index. Moreover, the progressive nature of the pumping minimized the effect of asphaltene and wax deposition, which could have solidified the fluid in the wellbore during the shut-in period, requiring intervention with coiled tubing.
The ESPCP system is designed for large range of flow rates and features a specialized Y-tool to address potential contingencies. This solution represents a global pioneering implementation aimed at mitigating the risks associated with electrical generation from the permanent magnet motor (PMM) during well completion and retrieval processes. Additionally, the novel well schematic architecture facilitates well interventions using coiled tubing (CT) and sand screen control, enhancing operational efficiency and safety. The stimulation system was designed to improve reservoir productivity by respecting the pump limitations in terms of pH. It also required that the pump material be upgraded to be able to lift corrosive fluid such as acid.
The downhole testing system allowed us to record the build-up with downhole shut-in, obtain reservoir fluid samples without intervention, and record the data in real time for pressure transient interpretation. Real-time monitoring allowed us to interpret the data in real time and optimize the test duration. Combining multiple gauges at different depths allowed us to evaluate friction losses in completion during high viscous fluid production.
For the first time, the ESPCP was integrated with conventional downhole testing to lift heavy oil reservoirs offshore for production evaluation. In this paper, we provide details about the unique workflow, the lessons learned, and recommendations to the industry based on nine production tests at three wells.
The Discrete-Imitational Modeling of the Pump-Well-Reservior System with a Intermittent Sucker-Rod Pumping
Authors: Jamalbayov Mahammad , Valiyev Nazim 
Published: October 2024

Abstract
The work is devoted to the problem of modeling the filtration processes of light and non-volatile oils in compressible reservoirs with low reservoir pressure, inflow to the well and intermittent pumping of oil from the well by a sucker-rod pump in a integrated system.
The system under study is considered in the context of discrete simulation modeling. It consists of the following objects: Pump, well and reservoir (well-drained zone). An algorithm has been developed for determining the pump idle time based on the criterion of the minimum cost of oil extracted during a full pump cycle.
For the first time, a computer model of the pump-well-reservoir system was created on the base of the discrete-imitational modeling concept taking into account the PVT properties of reservoir fluids and the compressibility of the reservoir rocks. The sucker-rod pumping process in a intermittent mode has been studied, the nature of the influence of the pump idle time on the efficiency of the pumping at various reservoir permeabilities has been established. The developed algorithms can be used to create smart wells.
Ultra Slim ESP - Extending ESP Application
Authors: Nesterov Sergei , Zamesin Evgenii , Repin Vitaly , Stolbov Alexander , Mollaev Aslanbek , Nambiar V. 
Published: October 2024

Abstract
Electrical Submersible Pump (ESP) application is challenged by wells with 4-1/2", 5", 5-1/2" casings and 7" liner/casings with Y-tools. The standard approach was limited to use of conventional 3.75" ESP system with Induction motor, only suitable for 5-1/2" and 7" casings without Y-tool. The Ultra Slim 319 series (3.19" OD) ESP with use of Permanent Magnet Motor (РММ) illustrates the benefits of slim line ESP application under such challenging conditions. The paper discusses 3 successful cases for both Oil and Gas wells. The Ultra Slim 319 ESP with РММ was used:
To increase the flow rate and provide higher reliability from а well that was recompleted with 5" liner. The production achieved was 4000 BPD For gas well unloading from а well completed with 4-1/2" liner or frac tubing Deployed inside а 7" #29 liner with Y-tool having bypass of 2-3/8". The bypass allows standard slick line/WL tools to access the reservoir. The use of Ultra Slim ESP enabled the operator for deeper installation for stable production.
The use of РММ increased the reliability of the entire system by lowering the internal motor temperature rise and in addition lowering the current per barrel produced. The run life achieved is 1300 days in the case of the 5" liner application. The gas well unloading has been successful, however the Operator decided to shut down the project due to macro-economic reasons. The cases of 7" liner with Y-tool are currently under operation and stable. Ultra Slim ESP with Permanent Magnet Motor extends the ESP applications to completions that are out of reach for standard ESP with induction motors. The Ultra Slim ESP with РММ can provide:
Higher production rates Wider ESP application range Longer run life where there is а risk of static pressure depletion Reduced per-barrel production cost due to the use of PPM, which decreases current amperage requirements and enhances efficiency СО2 footprint due to lower energy per barrel produced.
This paper illustrates the versatility of Ultra Slim ESPs, which can address various challenging well scenarios and achieve target performance parameters. This information will be valuable for global ESP applications facing similar issues where solutions have not yet been identified.
Optimizing ESPs in Minutes: Automating Workflows with a THP vs. Surface Rate Approach
Authors: Gioria Gian Marco , Prada Williams , AlIbraheem Abdullah , Alshawi Uday , M. Safaa , Abdulkareem _ 
Published: October 2024

Abstract
Optimizing the operating conditions for an ESP (Electrical Submersible Pump) does not need to be a complicated process. The Petroleum Engineers typically analyse the wells using the charts provided by the vendors, where the pump performance is expressed in terms of Head vs In-Situ Rate. However, field engineers and operators usually control the wells by adjusting choke opening - thus the THP (Tubing Head Pressure) - and Frequency. This logical gap can often cause delays and difficulties in performing a continuous optimization.
The paper presents a tool to close that gap, based on automated workflows; it enabled the direct use of familiar variables so that all teams involved can interact smoothly. The tool generates clear visualizations, combining all the system constraints and operating limits, so that the engineers can visualize the Operating Envelope for each ESP well. This approach drastically decreased the time spent analysing the operability of the ESP and consequently improved the actions implementation speed. The primary benefit is the time saved by engineers, especially important for a giant oilfield where relatively few engineers oversee up to 100 wells each. Additionally, it helped junior and senior engineers alike to quickly identify problematic ESPs, elaborate remedial actions, and propose new optimized setpoints.
The novelty of the tool is the ability to simplify an industry-standard process, offering a straightforward alternative. It can be adapted and scaled to any field with ESP installations, while it only requires simple programming skills.
Understanding the Cause of Impeller Breakdown in ESP Gas Handlers
Authors: Boudi A. A. , Pessoa R. F. , Hasanov E. , Saeed M. Y. 
Published: October 2024

Abstract
Electric submersible pumps (ESPs) are a widely used artificial lift method used to support oil production and boost pressure. They perform excellently in liquid applications and fairly well for gassy applications if properly designed and fitted with the right components, such as a reliable gas separator and/or gas handler (GH). This paper deals with the possible failure analysis of an ESP GH, specifically the consequences of mechanical breakdown of impeller blades.
Solids, such as scale, sand and debris upstream of the ESP, can cause mechanical failures or wear of exposed parts. Impellers or augers used in rotating gas separators and gas handlers are at higher risk of damage due to their hydraulic design and frontline facing the incoming abrasive fluid. Root cause analysis based on Dismantle, Inspection and Failure Analysis (DIFA) can identify the failed component and failure mechanism such as the GH with axial type impellers. A more ductile metallurgy with higher yield-strength can be proposed as corrective action and the improvement can be confirmed through Finite Element Analysis (FEA).
Solids found during ESP DIFA are believed to be the primary trigger of gas handler impellers’ failure. The sources of solids can be several and intrinsic to well operations such as little debris remaining after workover job or corrosion byproducts coming from the casing below the ESP. Because of the impellers axial design, thin blades, limited vane support at the impeller hub, tight clearances and brittle material, it is highly possible one or a few blades broke initially with a catastrophic dominoes effect as the released metal debris can be caught between the impellers and diffusers, crushing in smaller pieces can be dragged up by the produced fluid into the upper stages. The observations suggest that all blades shattered in all the 17 GH impellers, leaving just the impellers’ hub that is attached to the shaft. Likewise, multiple dents and broken vanes can be observed in the diffusers of the GH as a result of the metal crushing. The failure mechanism can extend to the pump stages as some fragments of the GH can be dragged further up that could result in shaft overload and leading to failure of the two-piece shaft coupling between the gas handler and the pump.
This paper provides valuable insight about potential inherent design weaknesses of some gas handlers fitted with axial or helical-axial stages. The DIFA results support the proposal for an upgrade of the metallurgy as a quick fix to cope with rig operation commitments. The higher strength of upgraded GH impellers was validated through FEA; however, additional improvements mainly in terms of mechanical design are also proposed and discussed.
Hybrid Artificial Lift System – Gas Driven High-Speed Pump for Wells with a Lack of Reservoir Energy
Authors: Shakirov Anton , Alexeev Yaroslav , Nizetic Tomislav 
Published: October 2024

Abstract
Over time, with intensive field development, well conditions can deteriorate; there is a risk of water and gas breakthrough, reservoir and bottom-hole pressures may decrease if there is no effective reservoir pressure maintenance system in place. Neither Electric Submersible Pumps (ESPs) nor Gas Lift (GL) are capable of effectively maintaining efficient production in certain conditions. To address these issues a new hybrid production method was developed – a hybrid gas lift system with a turbine-driven centrifugal pump.
The Turbine-driven pumping system effectively solves bottlenecks of both standard ESP and Gas Lift artificial lift methods by use of the most advanced high-speed pump with operating speeds up to 15,000 rpm powered by a non-combustion ultrasonic turbine. Downhole components are integrated in a turbine submersible pump (TSP) set having no electric parts. Pressurized gas is injected into the annulus, entering the gas turbine at its setting depth, it expands creating torque on its shaft and driving a centrifugal pump. Having passed the turbine, the injected gas is discharged to the production tubing where it is utilized again for gas lifting.
The implementation of the Gas Lift with the turbine-driven pumping system enables the highest possible production volumes providing optimization beyond the conventional Gas Lift capabilities. The system can be deployed both on tubing and riglessly, either with a slick line or coiled tubing. Total pumping efficiency can be improved up to 39%. The technology enables production optimization and/or achieving target drawdown with minimized gas injection rate and pressure if compared to traditional Gas Lift. Technology avoids the use of electricity in the well resulting in dramatic improvement of reliability and runlife, reducing the number of shut-ins and minimizing non-productive time.
Unlike conventional methods, that often suffer from high energy consumption, mechanical complexity, and limited adaptability to varying well conditions, the turbine-driven pump offers a novel solution that overcomes these limitations. It is suitable for a wide range of well conditions, including high-temperature environments, where conventional methods may struggle to perform. Potential implementation in the geothermal industry further underscores its importance in driving the green transition of the oil and gas sector towards more sustainable practices.
Automated Control Solutions to Enhance Beam Pump Performance and Increase Well Productivity: Block-5 Oman
Authors: Al Badi Said S. , Al Abri Ahmed T. , Al Hinai Nasser , Al Abri Ahmed N. , AL Busaidi Khalfan 
Published: October 2024

Abstract
Producing wells in tight formations and matured fields with high gas to oil ratio is proven to be challenging approach. Although, these wells have good production initially but they experience a sharp production decline resulted in low oil recovery, well instability and pump performance deterioration. That could end up with higher deferment and frequent beam pump failures. Fully automated solutions using different control options could maximize the well productivity and enhance the run life of the beam pumping surface and subsurface equipment.
This approach of fully automated solutions is integrating the real-time data from downhole sensor and the pump fillage data to continuously monitor and optimize the beam pumping system. The automated solution can be easily configured and controlled on well basis. Basically, this solution is based on two options which are the intake pressure mode and pump fillage mode which could be alternatively used and can be simply configured with present limits to control the well automatically.
This study examines the use of fully automated control solutions in beam pump operations in Block-5, Oman. Implementing Pump Fillage (PF) and Pump Intake Pressure (PIP) modes has optimized well performance, reducing beam pump failures by 9% and extending operational life by 23% from 2015 to 2023. These automated modes also decreased stuffing box leaks by over 85%, reduced environmental leaks by 70%, and cut power consumption by more than 60%. Additionally, surface motor run life increased by 55%, and reduced human intervention allowed for better resource allocation. These results highlight the effectiveness of applying these solutions across all wells in Block-5, particularly under challenging conditions.
This paper offers practical and applied solutions of fully automated methods to monitor and control the beam pumping system depending on data drawn from over 400 wells in block-5 in north of Oman. These solutions meant to maximize the well productivity while enhancing the run life of beam pump system in very challenging reservoirs that are depleted, tight or have high GOR.
Integration of AI and Domain Expert Knowledge to Improve ESP Efficiency and Performance
Authors: Yin Dakai , Li Qian , Karimi Ali , Mitsakos Nikolaos , El Mahbes Reda , Cox Jacob 
Published: October 2024

In the 21st century, the concept of the digital oil field has gained global acceptance and application in gas and oil production. Among the various artificial lift tools, the electrical submersible pump (ESP) stands out as one of the most widely used, with approximately 3,000 installations across Occidental Petroleum Corporation fields. Over the past two decades, enhancements in Occidental in-house-developed ESP surveillance have enabled the company to optimize production and enhance reliability. The surveillance system has also combined extensive real-time operational data, production history, failure analysis, and equipment records.
Over the past few years, machine learning and artificial intelligence have made significant inroads into the energy industry, particularly in oilfield production management. Occidental pioneered the LiftSMART ESP tool system by harnessing these revolutionary technologies alongside its extensive ESP database. This integration promises improved efficiency, reliability, and overall performance in oilfield operations.
The LiftSMART system, with its ongoing development, currently comprises three main modules: Operation Health Check: identifies unusual behaviors in the ESP and detects deviations from expected performance.Auto-Advisory and Optimization: offers suggestions for optimizing ESP operations and provides practical recommendations.Failure Prediction: generates survival curves for each ESP, helping to predict potential failures, enabling proactive maintenance, and minimizing downtime.
Ultrahigh Speed ESP Technology Solution for a 11,400-ft Well: First Successful Deployment with Induction Motor in Ecuador
Authors: Andagoya Kevin I. , Villalobos Jorge L. , León Fernando , Hidalgo. D Mario H. , Vela Nicolás , Sotomayor Alejandro , Orozco Andrés , Ekambaram Raju , Koduru Preethi , Reyes Carlos , Enriquez Luis , Vásquez Hugo 
Published: October 2024

Abstract
The idea of becoming more efficient is in the scope of every industry. Whether we think about the history of chips, computers, cell phones, or medical devices, all of them have successfully developed technologies that can do more as they become smaller. This is not the exception for the oil and gas industry, as demonstrated by this artificial lift development of ultrahigh speed (UHS) electrical submersible pumps (ESPs). This paper covers the challenges, advantages, and the deployment process of this technology in a field in Ecuador. The obtained advantages such as reduction in field assembly time, improved capability to deploy in more aggressive deviated wells, adaptable logistics, and finally successful flow handling. Based on this experience, new candidate wells are currently being studied for this application.
Procedures in Unlocking ESP Full Potential and Extending the Run-Life in High Gas-Oil-Ratio Wells
Authors: Alsayedali A. , Fardan A. , Khamees S. 
Published: October 2024

Abstract
Excessive gas production from high gas-oil-ratio (HGOR) wells imposes multiple challenges on the Electrical Submersible Pump (ESP) systems. The light gassy fluid can compromise both the ESP mechanical and electrical integrity through severe degradation due to operating in upthrust position and through the extreme motor overheating caused by the repetitive gas-locking events. This paper discusses procedures that result in significant improvements in ESP operation in HGOR environments.
The procedures targeted the three main stages of ESP life cycle, namely: ESP design and planning phase, ESP installation and function test phase, and ESP operation phase. The developed procedures are applied for all new and current ESP installations and are continuously updated based on new results obtained through performance and data analysis.
These procedures can have a major positive impact on the ESP mechanical and electrical health. Gas-locking related trips are some of the most challenging trips as they require extensive troubleshooting and analysis to prevent re-occurrence. They also require keeping the ESP and well shut-in for pressure build-up. All of this tremendously affects the field production strategy and hence the reduction of gas-locking trips through these procedures not only improves the ESP health but also ensures the field production is maintained. Through the aid of such procedures, the run-life of failed ESP can exhibit a significant increase. In addition, gas-locking related trips per well can be significantly reduced after successful implementation of these procedures. The reduction in ESP downtime is key in aiding companies achieve their production strategy.
Implementation of the procedures that are discussed in this paper can be utilized for all HGOR fields where ESP installations are planned as the main artificial lift method to reduce gas-locking related trips and improve the run-life.
Role of Plasticity in Induced Seismicity Risk Mitigation: A Case of the Groningen Gas Field
Authors: Zhao Xiaoxi , Jha Birendra 
Published: October 2024

Summary
Earthquakes induced by fluid extraction from deep underground reservoirs are not well understood in rocks that are deforming plastically. The problem grows in importance when seismicity risk mitigation strategies, such as gas injection into a depleting hydrocarbon reservoir, attempt to reverse the declining pressure trend of a poromechanical system deforming irreversibly. This is the case at the Groningen gas field and similar fields worldwide. Poroplasticity associated with half a century of seasonally fluctuating gas production makes it challenging to predict Groningen’s state, especially with hundreds of faults compartmentalizing the reservoir. We provide new insights into the role of plasticity in depletion-induced seismicity and its mitigation via injection. The irreversibility of plastic deformation is key to predicting stress and fault stability when the pressure trend is reversed by fluid injection. The elastic deformation assumption predicts unrealistically high Coulomb failure stresses on the faults, implying a higher risk of induced seismicity than possible under plastic deformation. The inaccuracy in the elastic model’s predicted stress cannot be discerned from the reservoir pressure or subsidence measurements in the field. Therefore, rock’s plasticity must be considered in assessing and mitigating the risk of induced seismicity. The probability distribution of the change in Coulomb failure stress over 115 faults in the field reveals a multimodal shape that emerges from the stabilization and destabilization of different faults depending on the fault’s geometry and position relative to the wells.