Artificial lift systems in the oil and gas industry have long relied on Supervisory Control and Data Acquisition (SCADA) technology for monitoring and control. However, as the digital landscape continues to evolve, artificial lift systems must adapt to more dynamic and autonomous operations. In particular, leveraging cloud-native edge computing, microservices, and the Industrial Internet of Things (IIoT) offers the potential to enhance the real-time responsiveness and optimization of artificial lift systems. This paper discusses the transition from traditional SCADA systems to edge computing-driven architectures in artificial lift applications, highlighting the capabilities, challenges, and future potential of this technological shift.

In an effort to address safety concerns, PMM manufacturers and operators have worked together and developed API 11S9 Recommended Practice that covers many of the safety issues relative to PMM operations. The PMM is a very good generator due to “always on” permanent magnet rotor so presents a risk of electric shock and arc flash (AF) hazards if rotation occurs when service personnel handle the ESP cable conductors at surface. The primary methods to avoid these hazards is to insure an EquiPotential Zone (EPZ) is created at surface and to shunt the ESP cable leads. A proper risk analysis can help to determine if additional engineering controls are required to mitigate risks. 

It is not possible to de-energize the PMM so an Energized Electrical Work Permit (EEWP) may be required under Article 110.4(B) of NFPA 70E. The methodology centers on creating an EPZ tailored for PMM cable splicing/wellhead connector operations and testing its effectiveness through actual on-site evaluation of the process. Shunting or shorting the ESP cable at surface is a very good “dynamic brake” preventing rotation. However, there are certain operations where the shunt must be removed as part of regular procedures so strategies are developed to deal with those conditions. 

Arc Flash calculations are presented for when there is motor rotation with the potential for high voltage generation and high incident energy values. This data provides guidance necessary due to the variability in motor sizes and potential flow rates, which aids service personnel in choosing appropriate PPE for the job. Incorrect, or worse-case PPE selection may lead to the arbitrary choice of Cat 4 ARCs which might be over-rated and lead to added risks. 

Of the 20,000+ permanent magnet motor (PMM) electric submersible pump (ESP) installations in the past 15 years, almost all were safely installed without devices intended to prevent inadvertently rotating the motor. These engineering control devices, e.g. tubing flow plugs and mechanical locks, are described along with explanation of the complications they bring to installing, operating, troubleshooting and pulling a PMM. The paper concludes with a summary risk assessment, procedures and implemented training. 

Most frac hits are significant events with large pressure change, followed by enhanced flow of almost all water then declining with increasing oil at a level higher than before the event.  This study examines how best to “ride thru” the frac hit, but also how to manage ESP settings for the rapid fluid rate changes during and after the event.  The frac hits occurred at different points in the wells drawdown so The ESP operation was monitored and setpoints adjusted as needed with the changes in load.  The increase in rates were much less than initial production and peaked after initial pressure change.  The delay from pressure peak to flow peak, was about 6 days on average.  So, what was seen at first was pressure spike above the previous operating point after about 14 days.  Then the flow increased to its peak.  In the interim where the well experiences pressure support and then fluids hit, some ESP’s experienced lighter loading so tripped on previous underload settings.  There appears to be slightly longer runtimes on wells that have seen frac hits most likely due to the ESPs running closer to the original sizing and with lower gas.  From evaluation of times to fail after frac hit and DIFA’s of those failures, it is probably best to keep the ESP running during these events.  After the wells’ normal decline returns, it is recommended that we reset the drive parameters to the new conditions.  We note that some of these wells had multiple events so remaining run life was calculated after the first frac hit.  From a production standpoint, there does not appear to be an advantage or disadvantage to shutting off the ESP during a frac hit, however, ESP’s generally run longer with fewer shutdowns. 

The installation and retrieval of Electrical Submersible Pumps (ESPs) equipped with Permanent Magnet Motors (PMMs) require robust barriers to prevent shaft rotation and the subsequent generation of voltage. Current methods to provide these barriers involve additional operations, equipment, and personnel, which increase associated risks. This paper introduces a new method that is safe, effective, and economical, improving both safety and operational efficiency during the installation, operation and retrieval processes.

Installing ESPs with PMMs typically involves surface monitoring techniques and control barriers, such as blanking plugs and sliding sleeves, to manage communication between the tubing and casing. After installation, these barriers must be removed to produce the well and then reinstalled before pulling the equipment, requiring at least four slickline interventions and extended operation times. The proposed method utilizes a single tool that acts as a positive flow barrier during installation, which is removed by pressurizing the tubing before production begins. This initial barrier maintains minimal differential pressure from top to bottom and offers ten times greater pressure resistance from bottom to top, ensuring a complete seal. Similarly, before retrieval, a dart is used to create a mechanical block and a positive flow seal in both directions, while also opening a drain sleeve. This allows the pump to be pulled with dry tubing and a plug in the production tubing, eliminating the need for slickline intervention and maintaining on-site safety standards.

After multiple installations of this new method in the Permian Basin, analysis has shown zero safety incidents during the operation of ESPs with PMMs. Proper training, socialization, and discussion of this method with field personnel have increased awareness of associated risks and promoted responsible operations, resulting in no reported accidents to date. The implementation of this method has also shortened installation and retrieval times, reducing rig time by up to 50%, which in turn lowers operational costs, reduces emissions by minimizing the number of intervention units required, and accelerates the timeline for bringing wells online. 

This document will present practical applications and guidelines to clearly explain how this technology can be adapted for various operations, making it easier for operators to use worldwide. As the adoption of PMMs increases, it is crucial to continue developing not only surveillance measures but also mitigation strategies to effectively prevent unforeseen events at well sites.

This paper introduces a multi-layered application to tackle two major challenges in unconventional wells within the Permian Basin: gas slugs and high gas-liquid ratios (GLRs) that disrupt electric submersible pump (ESP) operations, and sand fallback during ESP shutdowns, which can cause equipment failures like plugged pumps and broken shafts. These issues reduce efficiency, increase downtime, and drive-up operational costs.
The solution features a gas handler system that regulates free gas flow before it reaches the ESP intake, converting slug flow into dispersed bubble flow. It also incorporates a sand fallback management system, installed above the ESP discharge, which prevents sand settling in the pump stages during shutdowns caused by gas slugs or surface facility issues. The system supports surface injection rates of more than 8 barrels per minute, enables detailed inspection and repair post-retrieval, and accommodates flow rates up to 15,000 BPD with sand concentrations as high as 23,000 mg/L.
Four case studies from the Delaware Basin, where ESP operations were historically hindered by gas and sand, demonstrate the system's effectiveness. Following the installation of the gas flow management tool below the ESP and the sand fallback regulation tool above it, production increased significantly, and operational stability improved. By extending ESP runtime and minimizing premature failures, the solution enhances profitability and reduces the carbon footprint of operations.

High volume, high water cut wells historically represent a challenge in terms of economic production, due to limitations with others artificial lift methods, ESPs are usually chosen for this type of application since it can move great volumes of fluid produced by longer laterals being drilled today. As electrical rates increase exponentially, and notably power grid limitations are becoming more common every day, permanent magnet motor technology can combat these issues with high efficiency, however, most of these unconventional applications experience a significant rapid declination on total fluid rate and an exaggerated increase on gas production, which historically has been a limitation for ESP to operate in gassy conditions efficiently. This paper presents the comparative results of an PMM performance using Vector Control Mode vs Scalar Control to demonstrate PMMs performs successfully in gassy applications, riding thru sudden load changes caused by gas slugs on unconventional wells utilizing vector control method that ensures synchronization of the rotor and constant rotor magnetic field. An ESP System was setup using PMM to test on different drives with different control modes, SUT, SWF, ESP Cable, Dyno and Power analyzer were included, both units were exposed to sudden load changes to mimic gas interference, as well as drastic speed changes to simulate purging operating modes used in the field to ride thru gas slug events. Analyzing the results it was noticed that Scalar (V/Hz) mode, which is generally easier to use caused motor system to experience current torque mismatch, showing speed control issue regardless of the load, which indicates poor control, while under vector control mode which is the preferred mode to drive PMMs to ensure rotor synchronization, it chased the load successfully using modern VFD Technology to ride thru large load variations due to high gas interference simulation, confirming output torque matched desired current regardless of sudden speed changes, decoupling speed from torque control without any special requirement other than known motor parameter based on motor design, like Ld, Lq and back EMF. ESP Systems using Permanent Magnet motor demands special control algorithms for an effective control of the motor like Vector control which is the best option since it can control unstable loads, but it requires good information on electrical parameters.

1. OBJECTIVES/SCOPE: Please list the objectives and scope of the proposed paper.
Environmental performance plays a crucial role in energy production today, and providing effective solutions to reduce carbon footprint of oil field operations is a top priority. Extensive research has been conducted to develop energy efficient technologies aimed at reducing power consumption, particularly in the artificial lift segment. Parment Magnet Motor (PMM) has gained an increasing attention from operators in the Permian, leading to the installation of hundreds of PMMs. This paper presents an evaluation of PMM performance in the field, discuses a case study and highlights lesson learned. 
2. METHODS PROCEDURES, PROCESS: Briefly explain your overall approach, including your methods, procedures and process.
The approach involved evaluating over 170 PMMs installed in the Permian Basin using statistical analysis and survivability curves. A comparison between a PMM and conventional induction motor was carried out to assess energy saving and environmental impact in a gassy well that experienced frequent shutdowns due to high operating temperatures. Initially, the well was equipped with an induction motor, which was later replaced by a PMM. Well models were created to analyze power consumption and motor efficiency. Additionally, CAPEX, OPEX, and carbon footprint reductions were estimated and reported. 
3. RESULTS, OBSERVATIONS, CONCLUSIONS: Please describe the results, observations and conclusions of the proposed paper. 
The results of the study reveal that PMMs offer significant improvements in both efficiency and sustainability compared to traditional Induction Motors (IMs). Statistical analysis shows that around 10% of ESP short runs (less than 60 days) are due to PMM failures, primarily linked to manufacturing defects. However, 24% of ESPs with PMMs have been operational for over a year, with some exceeding 1,000 days. A pilot project demonstrated that switching to PMM reduced power consumption by 25%, saving $10,000 annually in electrical cost. Additionally, the unit uptime with PMM was 97.5%, significantly higher than the 88% uptime with IM, contributing to the production of thousands of barrels of oil annually.
PMM also achieved a higher efficiency of 96%, compared to 77% for IM, and generated less heat, with average motor temperatures of 174°F compared to 205°F for IM. Furthermore, the carbon footprint was reduced by 23%, equating to 0.16 tons of CO2 per well per year, and 27 tons annually for 170 wells. No Health, Safety, or Environmental (HSE) issues have been reported. 
4. Please explain how this paper will present novel (new) or additive information to the existing body of literature that can be of benefit to a practicing engineer.
Operators across the Permian are actively searching for new technologies to reduce their carbon footprint. The results of this effort suggest that PMMs offer both economic and environmental benefits for ESP operations, particularly during the mid-to-late stages of well life when gas-liquid ratios rise.

ESP permanent magnet motors (PMMs) have been confirmed to conserve power when compared to conventional induction motors (IMs) in various industry papers and studies. However, most production comparisons comprise a snapshot in time or the partial life of a single ESP. This analysis is useful, but it doesn’t convey the full power-saving value of a PMM installation.

This paper aims to investigate the energy saving potential of a PMM in comparison to an IM for two asset types: “unconventional” shale oil and conventional waterflood. ESP power data for a selection of IM-driven shale and waterflood wells will be analyzed over several years of installation(s). Power savings from theoretical PMM installations for the same wells will then be calculated based on actual IM system loading. This information will lead to the potential initial value of applying a PMM in each asset type. Theoretical and actual lifting efficiencies will also be compared, and the reasons for discrepancies linked to asset types will be discussed.

The authors expect this paper will assist engineers in high-grading PMM applications, particularly in regard to energy savings. It’s also expected that the lifting inefficiencies identified over the life of a shale oil well ESP will indicate further areas for equipment research & development.

In the realm of artificial lift systems, the monitoring and optimization of Electrical Submersible Pumps (ESPs) are paramount due to the high costs associated with unintended shutdowns and failures. Traditional methods, ranging from simple logic-based local alarms to sophisticated 24/7 surveillance centers, have shown tangible improvements in ESP operation. However, scaling such surveillance systems across large asset fleets cost-effectively remains a significant challenge.

Recent advancements focus on integrating real-time automated event detection engines with AI/ML capabilities to address this challenge. These systems process downhole, surface, and electrical sensor data to identify potentially harmful patterns without requiring human intervention. Unlike traditional multi-level threshold alarms, these engines adapt to each well, minimizing manual finetuning and effectively managing the large volume of notifications and alarms generated by evolving operational strategies and well conditions. The robust design of these engines ensures they are noise-tolerant and capable of differentiating between various sensor failures and harmful ESP conditions, thus reducing false alarms.

Field results from the Oriente Basin, Ecuador’s largest brownfield with approximately 100 producer wells, illustrate the effectiveness of these digital solutions. The integration of a smart digital system equipped with AI/ML allowed for the prediction of critical events, reducing the time of action and avoiding production losses. This led to a significant extension in ESP run life, from 247 days to 950 days. By creating a digital ecosystem that integrates surveillance tools, frequent data gathering, and advanced detection methods, operational efficiency and productivity were maximized while reducing ESP failure events.

The synergy of AI/ML, field knowledge, and real-time data facilitated intelligent actions in digital field operations. This included detecting and ranking operational events, generating focused lists of potential failure threats, and providing actionable insights. Consequently, the number of ESPs needing to be shut down annually was significantly reduced, highlighting the potential of digital transformation in optimizing ESP operations.

As companies move to lower their operating and maintenance costs, gas lift use has seen a dramatic increase in unconventional production patterns in the Permian Basin.1 Due to the corrosivity of acid gasses and the corrosive nature of produced water in these wells, asset protection is crucial to provide long-term production and minimize costly workovers. In this study, we will review a gas lift well in the Permian Basin that utilized internal plastic coatings as an alternative to traditional chemical inhibition methods. 

The results of this study show the ability of a properly selected internal plastic coating, that is suitable for the environment, to protect the tubing string and gas lift mandrels from corrosion and scale deposit buildup. By providing a durable barrier between the steel substrate and corrosive environment, the coating offers a robust solution for maintaining long term asset integrity. This study highlights the potential benefits of internal plastic coatings in optimizing production efficiency and reducing operational costs in both the Permian Basin and other unconventional oil and gas regions.

Electric Gas Lift (eGL) is a relatively new artificial lift method. While fundamentally similar to traditional gas lift, using gas to aid in the production of wellbore fluids, the operating principle of the valves are different. Traditional gas lift systems use nitrogen charged bellows to open and close the valves at certain wellbore conditions, whereas electric gas lift valves (eGLVs) function by electro-mechanical means, such as an electric motor or solenoid.

When using eGLVs, considerations must be made when creating a gas lift design to accommodate for the change in operational principle of the valves. These design considerations are critical in creating an optimal eGL design.

As the use of eGL systems in the Permian Basin grows, so does the question of “What does an optimal eGL design look like?

eGL design is a topic that remains largely unexplored. This paper aims to discuss how characteristics of eGLVs are considered in gas lift designs, as well as explore the idea if a standardized design for the Permian Basin is possible.

The Eagle Ford, Bakken and other operating areas often prove to be challenging areas for the successful, long-term operation of gas lift valves due to numerous factors which may compromise the efficiency of the installation and reduce production and life expectancy of the valve. These factors may include well bore heat, well bore fluids and gases, well bore contaminants and debris, offset fracturing activity, natural formation pressure and introduced, non-naturally occurring pressure. 
Wellbore heat and wellbore fluids act to degrade sealing components by causing expansion and contraction or other deformities of the elastomer, while wellbore gases can also cause degradation of sealing components by permeating into the sealing elastomers. Wellbore contaminants and debris may find their way into the dome bore thus contaminating the valve core causing sticking and/or find their way into the charged chamber. Offset fracturing activity can damage the elastomer or can increase the set pressure in the bellows reducing integrity of the valve.

The robust gas lift valve, suitable for harsh environments, provides a series of multi-layer protection from the negative effects associated with these factors, thus serving to increase the operational success and runtime longevity of the gas lift valve(s) utilized in the system. 

The paper discusses current issues seen with traditional injection pressure operated gas lift valves. Additionally, this paper explains both the similarities and differences between common gas lift valves and the robust Warden valve highlighting the benefits of the Warden gas lift valve.

Results showing improvements in gas lift system operation, a decrease in operator interventions and increased longevity of equipment in these challenging environments are presented in this paper.

High Pressure Gas Lift (HPGL) has established itself as a viable and valuable high-rate artificial lift method well suited to the challenges in modern unconventional production environments. Operators across all unconventional basins in North American unconventional basins are increasingly turning to HPGL to help them produce wells, especially during the initial production (IP) phase of the well’s life. To help operators successfully and efficiently implement HPGL into their operations, learnings from the first seven years of HPGL installations is being compiled into the industry’s first recommended practices for HPGL. The experiences and learnings from multiple operators using HPGL, along with the experience of HPGL experts is sought and shared.

Gas lift remains a cornerstone of artificial lift technology, particularly for addressing challenges in high Gas-Liquid Ratio (GLR) wells and heavily deviated wellbore geometries. However, declining reservoir pressures, high water cuts, and limited gas compression capacity present significant operational challenges. Coupled with increasing emphasis on cost efficiency and sustainability, these factors necessitate innovative solutions to maintain production and optimize lifting costs.

The Gas Lift Production Enhancement Tool introduces a novel application of gas dynamics to address these industry challenges. Utilizing a patented convergence-divergence design based on the Venturi principle, the tool accelerates injected gas to supersonic velocities, creating a low-pressure zone that generates additional drawdown. This enhanced drawdown improves reservoir inflow, reduces lift gas requirements by up to 40%, and frees up compressor capacity for other operations. Its streamlined design enables seamless integration with existing completions, requiring no wellhead modifications or downtime, making it a practical and adaptable solution.

Bison Oil & Gas field deployments in the DJ Basin, have demonstrated its effectiveness. The tools were deployed in 10 wells thus far, the tools have achieved +100BOPD over standalone gas lift. These results highlight the tool’s ability to improve production efficiency, reduce lifting costs, and align with industry sustainability goals.

This paper provides a technical evaluation of the Gas Lift Production Enhancement Tool, offering insights into its design, operational mechanisms, field performance and challenges/lessons learnt. By addressing the limitations of conventional gas lift systems, the tool represents a transformative advancement in artificial lift technology.

Gas Lift (GL) has emerged as a preferred Artificial Lift (AL) technology in the Permian Basin. As GL wells age, operators are looking at late-life AL alternatives, such as Plunger Assisted Gas Lift (PAGL) and Gas Assisted Plunger Lift (GAPL) to reduce gas injection and improve overall lift efficiency. However, conversion to these plunger-based late-life AL systems has been slow and somewhat costly, often requiring surface modifications through a Management of Change (MOC) process and, in some cases, a workover. The number of wells waiting to be converted to plunger alternatives is typically more than can be accomplished during a year due to budget and manpower constraints. For wells waiting for conversion, the Gas Lift Production Enhancement Tool or Super Sonic Tool (SST) was pilot tested to confirm it’s ability to provide a low-cost, through-tubing method to boost production and reduce gas requirements. This paper presents the results of a 4-well pilot test conducted in the Delaware. 

The Gas Lift Production Enhancement Tool is a novel application of gas dynamics utilizing a patented convergence-divergence design based on the Venturi principle. The tool accelerates injected gas to sonic velocity, creating a low-pressure zone below the tool that generates additional drawdown and increases the velocity of the gas introduced into the production flow. Also, this tool improves the ability of the injected gas to lift liquids by reducing the slippage between the gas and liquid phases downstream of the tool. The tool is installed through-tubing via slickline and placed over the active Gas Lift (GL) valve, so the injected gas is forced through the tool as the power fluid. 

Interest in this tool was generated by it’s theorical ability to improve drawdown and reservoir inflow, and the potential to reduce injection gas requirements by up to 40%. Its streamlined design enables easy integration into the existing completion, requiring no wellhead modifications or downtime, making it a practical solution that does not require a MOC. In addition, other field deployments made by the vendor in the Permian Basin seemed to demonstrate its effectiveness. For example, in the Delaware Basin, the tool achieved a 12% production increase while reducing lift gas consumption by 250 MSCFD. Similarly, in the Midland Basin, it delivered a 15% production boost with significant gas savings. 

To confirm/validate performance of this tool, a pilot project was undertaken in the Delaware Basin. After careful review of multiple candidates, 4 wells were selected. The SST was first installed in 2 wells and then installed in an additional 2 wells with a Multiphase Meter (MPM) to confirm baseline well performance and uplift. The tool was installed via slickline in less than one day for each well. This presentation details the findings of these pilot projects and lessons learned. The best response was a 35% uplift in oil production confirmed via a surface multiphase meter. CO2 tracers were shown to be critical in confirming the gas injection location (active valve) which is essential for tool operation. For example, in another well, the tool was installed across the wrong valve and later moved to the correct position based on a CO2 tracer survey. The importance of accurate well testing in a bulk-test system was also a lesson learned from this pilot as was the value of a multiphase meters when continuous real-time metering is needed to quantify uplifts in the 10-35% range. 

Using gas to displace fluid and reduce hydrostatic pressure has been a producing practice since the late 19th century. As time has passed and technology has accelerated, we now are able to build a communication stream between gas lift optimization and the data acquired during production operations. 

In our fast-paced industry, data is often looked upon to help us make decisions and solve problems from upstream to downstream. However, what is not talked about enough is how high frequency data allows us to see problems that should be factored into our decision-making process. Gas lift optimization levers are limited compared to ESP and rod pump systems. Rod pumping optimization can be done through the speed of the unit, also referred to as Strokes per Minute (SPM), stroke length and if the stroke length or current unit is at max capacity, then you can upgrade to a bigger unit. An ESP system’s biggest lever is going to be the wide operating speed range that could change production by over 1K BOPD of liquid. Both ESP and rod pumping systems can optimize through the VFD. ESP’s can chase pump intake pressure; pump discharge pressure and motor amps and rod pumps can chase pump fillage and load. 

Gas Lift Optimization substitutes speed for injection rate but unlike ESP and rod pumping systems we can change our lifting depth along with the ability to produce from a deeper point in the well. With a constant change in lifting depth, we are constantly coming into conflict with understanding where we are lifting from and that is the first step in optimizing a gas lift well with multiple valves in the hole. ‘The great thing about gas lift is it works, the bad thing about gas lift is it works’, this quote I heard when I first started learning how to optimize gas lift wells still sticks with me. There have been hundreds of wells over the years that have had tubing leakage between stuck valves, holes in the tubing and mandrels, and leaking check valves. With the natural decline of an unconventional well merged with the start of a gas lift failure, it can be difficult to detect early. 
By combining physics, gas lift knowledge and data analytics, we can have insight into where we are lifting these wells through a daily surveillance workflow. This is key to optimizing these wells and limiting our deferred production and the risk that goes along with matured failures. 

Gas lift is the primary artificial lift system utilized across approximately 2,000 wells in Oxy’s Delaware Basin assets. As the number of wells increase and personnel resources remain constrained, production engineers frequently focus on resolving urgent operational issues, such as well or equipment failures. This situation results in limited time for consistent and proactive surveillance and analysis of well performance. Advanced analytics offers a solution by enabling the evaluation of gas lift well performance and the rapid identification of wells with a high likelihood of operational issues. Traditionally, this analysis was performed manually, an inefficient and time-consuming process. The predictive gas lift surveillance tool was developed to streamline this workflow by providing a single-page interface that highlights problematic wells, allowing production engineers to efficiently manage multiple wells simultaneously.

The tool was designed to support an "Operate-by-Priority" and "Report-by-Exception" framework, enhancing operational efficiency and effectiveness. A hybrid approach, combining physics-based simulation with data-driven methods, is employed to achieve the following objectives:
• Streamline the surveillance process.
• Develop predictive surveillance capabilities.
• Promote operational efficiency.
• Identify data quality issues.

Methodology:
The tool employs an in-house, proprietary physics-based algorithm to analyze gas lift performance, determining gas lift injection status (e.g., multipointing, single-point injection). It also applies time series analysis to high-frequency sensor data from wells to detect operational anomalies. By combining these approaches, the tool classifies wells into multiple production scenarios. 

Results:
The tool has greatly enhanced production engineers’ efficiency by reducing the need for manual well analysis and providing a prioritized list of wells requiring attention. For example, identification time for major issues, such as tubing leaks, has been reduced from weeks or months to just a few days.

Additionally, automated workflows have been developed to calculate potential oil production uplift based on remedial actions. The tool not only recommends corrective actions but also forecasts the potential production gains, aiding production engineers in decision-making.

The tool is estimated to reduce engineers' time for gaslift well analysis by 70%. Additionally, it accelerates production by enabling engineers to identify and resolve well issues more quickly. This comprehensive solution, which combines issue detection with uplift calculations on such a large scale, represents a significant advancement in the field.

Sucker rod pumps (SRPs) remain the leading artificial lift (AL) method worldwide, with technological advancements tracing back to the wave equation development in the 1960s. Leveraging edge-based technologies, a new workflow has been developed to enhance existing Pump-Off Controller (POC) capabilities. This workflow integrates machine learning (ML)-driven dynamometer card classification for real-time event detection with an advanced logic system that autonomously optimizes SRP operating setpoints. Operating within an Industrial Internet of Things (IIoT) framework, it continuously analyzes high-frequency dynamometer card and pump data.

The workflow consists of two distinct control mechanisms tailored for SRPs:

Fast Loop Mitigation Controls – These controls utilize classified surface and downhole dynamometer cards in real time. Designed for rapid response, they detect and mitigate common SRP issues such as flatlining, fluid pound, gas interference, and tagging as they occur.
Production Optimization (POPT) Algorithm – This algorithm collects and evaluates operational data within a dynamically shifting time window. By synthesizing historical trends into performance indicators, it forecasts the optimal pump operating setpoints to enhance efficiency and production.
Testing results highlight the significant advantages of combining both control systems. Across tested wells, inferred production increased by an average of 15%, while runtime improved by 3%. Additionally, by maintaining optimal pump fillage, cycling was reduced by 29%, leading to more stable operating conditions.

This workflow represents a holistic approach to SRP optimization, bridging short-term issue mitigation with long-term production enhancement. By integrating real-time anomaly detection with predictive optimization, it provides a comprehensive and adaptive solution for maximizing well performance and reliability.

This paper explores the Horizontal Valve System (HVS) and its ability to enhance vortex fluid flow profiles in downhole environments. Initial field trials demonstrated the HVS's effectiveness in lowering pump placement resulting in larger production outcomes, prompting further laboratory testing. The study replicates downhole conditions to compare lab results with field data, highlighting how the HVS extends vortex flow profiles, increases fluid flow efficiency and increases pump longevity. This enables deeper pump placement in high-inclination wells, optimizing production, reducing failure rates, and prolonging pump life.

Pump valve cages play a critical role in fluid flow, and indirectly affect the integrity of the sealing components. Cage beat-out is a common problem, caused by deformation of the steel due to repeated impact from opening or rattling while open. In addition to the cage deformation, damage to the ball itself can also result in poor seal when the valve is closed. The Impact Resistant (IR) cage was developed to absorb the impact of the ball without permanent deformation. The use of a resilient plastic cage has proven successful in 5,000 installations over the last 8 years. A new High Temperature version of the IR cage makes this technology available to a wider range of wells, up to 450 Fahrenheit .

Key features of the IR Cage include its windowless "full open" design, minimized ball travel, and increased flow rate. By increasing the flow path, and reducing the fluid velocity through the cage, a significant reduction in erosion, sand abrasion, and gas breakout is achieved compared to traditional API cages. Real-world case studies showcasing significant improvements in pump run life will further illustrate the IR Cage's superior performance. 

This presentation will discuss case studies of both the standard temperature IR cage and results from field trials of the new High Temperature version. It will further provide a technical overview of the IR Cage’s design, material selection, and operational advantages. Attendees will gain insight into how the IR Cage enhances pumping capacity, reduces downtime, and ultimately lowers operational costs for rod pumped wells.

This paper builds on last year's paper, which detailed the development of a new gas separation method for rod pump wells operating under gassy conditions, without limiting the liquid production rate. In this second part, the focus shifts to results from new applications in a different field within the Midland Basin, highlighting lessons learned from various BHA configurations, performance outcomes, and new challenges encountered during the evaluation process.

Four case studies with two different operators will be presented. The first case involves a conversion from a struggling ESP to rod pump, resulting in a 49% increase in total liquid rate and a 55% uplift in oil production compared to ESP’s performance. The current pump fillage, after 5 months, has stabilized between 96% and 100%.

The second case focuses on a rod pump repair, where the legacy gas separator was not operating effectively and replaced with new technology while using the same type of pump. This allows a direct comparison of performance when replacing a legacy gas separator in an existing rod-pumped well. After the replacement, fluid production increased by 220%, with a 200% uplift in oil production. Average pump fillage before the replacement was 70%, whereas the current average stabilized at 96%. 

The third case study presents another conversion from a low-rate ESP to rod pump. Here, the results not only show an uplift but also consistent pump fillage and 100% runtime, thus reducing wear on equipment from gas interference. 

The fourth case study is a Midland basin well with a high GLR and an ideal application for gas lift that had to be converted from Gas Lift to rod pump due to the pressure restrictions. The production after the conversion was higher and the pump fillage has been high through the evaluation period. 

These case studies were selected to illustrate the economic benefits of optimizing the gas separator to achieve the desired liquid production rate in both existing rod pump wells and ESP to rod pump conversions. Production losses after ESP-to-beam pump conversions are common, and this study has shown that this technology is an effective way to maintain or improve production targets and effectively rod pump horizontal wells.

Throughout the paper, we will cover the challenges faced, as well as the well selection criteria, and engineering solutions implemented or planned to achieve optimal outcomes for each installation. Based on the analyzed cases, a new design was developed, considering not only production rate and pump fillage but also velocity profiles, pressure drop, and tool geometry. Simulations and designs will be shared to explain the analyses conducted. 

Operators have been challenged in designing rod pumping solutions for the life of the well in deviated, horizontal and S curve wells. Overcoming frictional side loading in high-rate producers converting earlier from ESP to rod pumping. The first 6 months of the conversion is the most critical time where operators want to reduce the cost of ESP workovers going to rod pumping earlier. The challenge is rod and tubing wear or corrosion enhanced rod ware, produced solids and gases. Long Stroke pumping units have proven to address some of these problems yielding higher production rates at slower SPM’s, however, designing the rod string with continuous rod can improve the MTBF’s by reducing the overall coefficient of friction while decreasing turbulent flow. There are benefits operators can take advantage of including landing the pump in the curve. This paper will discuss case proven case studies where the combination of coiled rod and LSPU’s have been successful, converting earlier from ESP to rod lift. 

Operators have been challenged in identifying physical defects or discontinuities when adopting continuous rods, in reciprocating rod pumps and PCP wells. Historically, the only method used is a visual, imprecise inspection, often resulting in running bad rod back in hole or removing good rod prematurely driving up LOE. This has been viewed as a barrier to entry for widespread adoption of continuous rod in the Permian & Delaware basins.

 
With LPS proprietary technology, licensed by SPScanco exclusively to LPS for Oil and Gas upstream operations, EMI scanning has enabled operators to scan continuous sucker rods, both round and semi-elliptical rod at the well site as it is being pulled out of hole without any delay to workover operations successfully for the past 3 years by LPS.  Due to its size, functionality, accuracy, user friendly MMI with built in local intelligence, LPS’s EMI system is easily installed in a matter of minutes, scanning in real time capturing and storing data at a high rate is used to identify discontinuities in CR’s. With this next generation of LPS’s EMI technology, consisting of its own datalogger, chassis & sensors and software. This paper will discuss proven case studies where operators have used the data to make critical decisions to retire or rerun the rod as well used for predictive failure analysis. 

The upstream oil and gas industry faces significant challenges in optimizing production from aging assets, particularly in managing the vast amounts of unstructured data generated by rod lift systems. This paper presents field results from the deployment of Cognitive Card Recognition (CCR), a machine learning-based solution for automated dynacard analysis and anomaly detection in rod lift operations.

The CCR system, developed through collaboration between rod lift subject matter experts and data scientists, employs multiple machine learning models trained on millions of expert-labeled dynacards. Current models achieve 85-95% accuracy in identifying twelve distinct non-normal operating conditions, including fluid pound, gas interference, worn pumps, and rod parts. The system continuously improves through regular incorporation of additional labeled data and model retraining.

Field case studies demonstrate CCR's ability to identify critical operational issues days to weeks earlier than traditional methods. In one documented instance, CCR detected a hole in barrel condition before production decline occurred, enabling proactive maintenance scheduling. In another case, early detection of a rod part reduced failure cycle time by 1-2 days, minimizing deferred production and preventing cascading equipment damage.

Results show that CCR implementation enables operations teams to transition from reactive to proactive maintenance strategies, leading to reduced deferred production, decreased well downtime, and optimized maintenance scheduling. This technological advancement represents a significant step forward in leveraging artificial intelligence to improve oil production efficiency and equipment reliability in aging fields.

Keywords: artificial intelligence, rod lift optimization, predictive maintenance, machine learning, oil production, dynacard analysis.

Through the motion of a rod pump well, stress oscillations typically appear in the rod string at the beginning of both the upstroke and downstroke phases. This dynamic phenomenon has several adverse consequences on the well. The load in the road string is drastically increased, thus reducing its service life; the plunger velocity is higher thus increasing erosion and wear on the pumps and the stress on the gearbox and the pumping unit also increases general wear and tear.

It is well known that reducing a unit Stroke-per-Minute (SPM) will reduce the severity of the stress oscillations, at the cost of production. Simple, once-per-stroke, intra-stroke speed changes are used today on long-stroke rotaflex units to reduce equipment wear at the top and bottom of the stroke, and more rarely in wells with gas issues to minimize the pounding buckling effect on the rod string during the downstroke motion of a pumping unit. 

In this paper, we present how multiple dynamic intra-stroke motor speed adjustments can reduce stress or increase production. We also show how the motor speed can be automatically computed to obtain a system that dynamically adapts to any well.
Examples of reducing the stress in the system while maintaining or increasing production are shown on multiple wells in Oklahoma and in the Permian basin. We show how a theoretical control model was developed, and the results of its implementation through AI models running a Variable-Frequency-Drive (VFD) via a machine-to-machine connection.

This paper shows a real-world example of how AI can be used to build flexible well control models which bring drastic positive outcomes. The result is a system that can be used on any rod-pumped VFD-powered well and will deliver optimal production at minimal wear.