2025 Southwestern Petroleum Short Course Schedule

Sucker rod pumping can experience reliability challenges when produced fluid contains solids. Any improvement in the ability for a sucker rod pumping system to handle solids would be highly beneficial.
The sucker rod pump is one component of a complex downhole system of components for sucker rod pumping. Other components of this system include a downhole gas separator, a downhole solids separator, a tubing anchor and sucker rods. To maximize the efficiency and performance of a sucker rod pump, all these components must act together harmoniously to effectively feed the pump on demand with liquid that has been gas and solids depleted – unfortunately, achieving this has been particularly challenging. Consequently, the sucker rod pump and sucker rods must still contend with gas and solids.
Solids that travel through a sucker rod pump can be transported or carried to surface only if the average liquid velocity inside the tubing exceeds the solids settling velocity. If the average liquid velocity is less than the solids settling velocity, solids that have travelled through the pump will accumulate inside the tubing. Inevitably, the well will need to be shut down and these accumulated solids can settle on top of the pump and/or around the sucker rods. Upon restarting of the pump, the pump or sucker rods can be seized by the settled solids, forcing a costly workover. This is a common problem for wells that have be hydraulically fracced with sand.
Electrical Submersible Pumps (ESP’s) have employed solids fallback protection tools, which have proven to be effective. They are simple designs; in that they prevent solids from settling in the tubing to the ESP after a shut down. Use of staggered collection chamber weirs and sand screens prevents solids from settling to the ESP. Upon restarting of the ESP, the solids collected are flushed from the chambers with aim to carry the solids to surface and out of the tubing. ESP’s generally are used for higher production rates and often have enough liquid velocity inside the tubing to efficiently carry the solids to surface. Therefore, these existing ESP oriented tools are not designed to permanently contain solids downhole.
For a rod pumping system where the liquid velocity is inadequate for carrying the solids to surface, a permanent “out of harms way” downhole containment solution would be required for a solids fallback prevention tool. Additional design challenges include the need for full tubing internal drift diameter to allow passage of the pump and the fact that there are reciprocating sucker rods inside the tubing.
A new patent pending solids fallback prevention tool has been developed for sucker rod pumping. Tool’s design features include:
• tubing conveyed with no moving parts,
• uses an external to the tubing eccentric solids collection chamber with multiple internal sub-chambers for permanent (large volume) downhole containment of solids until the tubing string is retrieved,
• multiple tools can be run in series above a sucker rod pump,
• has full tubing internal diameter for passage of rod pumps,
• 10,000 psi burst pressure rating, and
• does not interfere with the sucker rod string’s reciprocal motion.
Flow loop testing and field trials have indicated tool’s operability. The design process, prototyping and flow loop testing, and well trials/results will be shared.

As wells decline and available acreage for new wells lessens in the Permian Basin, it becomes increasingly important that operators capitalize on existing wells and maximize reserves. Scaling is a known issue in the basin, and this paper will address a likely solution. Acid treatments have proven to be effective across different levels, and when diverter is additionally pumped, the effectiveness has potential to increase significantly. 

The operator has taken the approach of pumping acid diverter jobs during workover when there is significant concern of blockages due to acid dissolvable scaling in the wellbore. Partnering up with an acid company, five acid diverter jobs have successfully been pumped across five different horizontals in Howard County, TX. These horizontals range across four different benches – Jo Mill, Lower Spraberry, Leonard, and Wolfcamp A. The Jo Mill well additionally had a cleanout across 84% of its lateral prior to pumping the acid diverter job, resulting this well yielding the highest oil uplift at 458% when comparing 30-day averages pre- and post-workover. The average of the other four jobs has oil uplift sitting at 189% with the same 30-day comparisons. Across the five jobs, four were during an ESP swap and one was during a RP workover. 

Other jobs pumped have insufficient days post return to production or faced significant curtailment post-workover, making it difficult to be considered in the study. Based on results thus far, the acid diverter program has been considered a success and candidates will continue to be added as seen necessary by respective production engineer.

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.

This case study examines a selection of 2024 Eagle Ford Refrac(s) that necessitated the removal of cemented slim hole casing before the installation of artificial lift. The operational overview includes discussions on logging considerations, tight tolerance cutting options, well control measures, artificial lift selection, and production outcomes.

Rod rotators are designed to distribute wear evenly around the circumference of sucker rods. However, in practice, rods, guides, and couplings frequently develop flat spots on one side, indicating uneven rotation. The industry has not adequately studied the implications of this condition on the entire pumping system. Instead, solutions have focused on implementing higher torque rotators or positive engagement mechanisms to force rod rotation. These solutions are not driven by comprehensive data and outcomes, but by the assumption that when it is rotating at surface, everything must be fine downhole.

This paper applies to wells where:
• Rods, couplings, or rod guides wear flat on one or more sides
• Rotators appear functional at surface but uneven wear patterns persist
• Excessive torque is present on the rods (i.e. during a workover or re-spacing)

In sucker rod pumps, work at the surface is translated to the pump downhole using a polished rod and rod string. Three factors reduce the energy available at the pump and decrease the efficiency of the rod pump installation.

The first factor is elasticity. Due to the elastic nature of the rod string and the cyclic motion of the pumping unit, stress waves travel up and down the rod string at the speed of sound, reducing the pump stroke and the efficiency of the downhole pump.
Secondly, viscous friction issued from the produced fluids, which impart a viscous force on the outer diameter of the rod string, further dampen the rod string’s movement.

Lastly, due to the deviation in a well, mechanical friction occurs when the rod string, pump or couplings come into contact with the tubing producing a normal force and drag friction that further slows down the movement of the rod string and reduce pump action.
In the great majority of models available to the industry, viscous friction is not adjusted properly, while mechanical friction is not addressed at all. In this paper, results from Liberty Lift’s proprietary diagnostic model are discussed comparing the mechanical and viscous frictions in different Permian and Bakken wells.

Gas lift optimization enhances production efficiency by maximizing uplift and reducing operational costs by addressing common issues such as over-injection. Numerous majors and others admit that over injecting is a serious problem affecting produced oil rates and 30-50% overuse of injection gas. Key steps include gathering well parameters, monitoring casing and tubing pressures with data loggers, and measuring static bottom hole pressure (SBHP) to assess true well conditions. This process integrates field data collection, real-time monitoring, and advanced analytical tools. Nodal analysis is used to evaluate the flow performance of the well by analyzing pressure and flow relationships between the reservoir, wellbore, and surface facilities, helping to identify bottlenecks and optimize production. Additionally, dynamic well simulation models the real-time behavior of the well under varying operating conditions, enabling operators to predict future performance, optimize production strategies, and detect potential issues before they occur.

This paper explores how operators can effectively increase well production, enhance recovery, and reduce operational costs by ensuring that each well operates at peak efficiency. The integration of field data, real-time monitoring, and nodal analysis is fundamental to optimizing gas lift systems and realizing their full potential in maximizing uplift.

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.

In the Bakken, holes in tubing caused by rod-on-tubing wear are one of the most prevalent mechanisms of downhole failures in rod pumped applications, especially in deep, highly deviated wells. A common mitigation method involves using borided tubing in sections where tubing splits occur, typically near the pump where compressive and buckling forces are highest. Installing borided tubing along the entire length of this section would be favorable, however, this approach is cost-prohibitive and wasteful if wellhead Electromagnetic Interference (EMI) scanning determines that the tubing is unfit for reuse. The objective of this study is to explore economical ways to extend the borided section of tubing by focusing on the accuracy and precision of the data interpreted from EMI scans of the borided tubing. 
The methods in this study involved collaborating with Stress Engineering Services to utilize their Bore Erosion Measurement and Inspection System (BEMIS™) for high resolution mapping of surface wall loss in used borided joints of tubing. With more than 30% wall loss, previous EMI scanning during workovers suggested that these joints of tubing were deemed unusable (red/green grade). Pipe samples were scanned at the wellhead, then separated and transported to a designated location to benchmark their relative thickness readings against the BEMIS™ device measurements.
The results of the scanning study evolved through three phases with increasing scope. In the first phase, two red/green joints were cut into 5-6’ lengths and shipped to Stress Engineering in Houston. The results from this phase did not detect any defects. In the second phase, thirty-eight red/green joints were sent to Houston, resulting in a 97% pass rate. Of the thirty-eight joints scanned, 89% were still in yellow condition, three joints were in blue condition, and only one had a surface defect greater than 30%. The third phase involved scanning 170 joints of red/green tubing, which resulted in a 94% pass rate. Although the distribution of blue tubing increased in the third phase, the gap between the BEMIS™ system and EMI scanning was evident. A portion of the surface features found during the laser scanning were deeper than the boride coating penetration depths, but the 3D rendering showed these areas were isolated and few in quantity. Through three phases of tests, the consistent pass rate allowed ConocoPhillips to confirm that EMI scanning is incompatible with accurately reading true wall loss in borided pipe, often skewing high and leading to significant waste.
In conclusion, the data from this scanning project has given ConocoPhillips the confidence to re-run significant quantities of borided pipe. This approach allows for cost-effective reduction in the purchase of new borided pipe and extends the borided section to combat wear. However, there are still risks associated with re-using borided tubing and limitations inherent to the technology used in this study. Variances in the boride coating and potential wall loss missed by the device remain possibilities. Despite these risks, the accuracy and reliability of the results from this trial provide high confidence that significant cost savings and improved runtime on rod pump wells can be achieved.
This project could not have been done without support and assistance from Stress Engineering personnel Brandon McGinn and Jason Waligura and technical support from Craig Zimmerman with Bluewater Thermal Solutions. 

As an operator, success rests in trying to maximize safety and production while minimizing your cost and downtime. Most operators choose ESP as a first form of lift and will later transition to gas lift, rod pumps, jet lift, etc. Other operators choose to use gas lift or rod lift as a first form of lift.

Each of these forms of lift presents its own rewards and drawbacks. 
For example, overtime, ESP can become oversized for the production requirement of the well. At that point, it can become more economical to install gas lift, rather than resize the ESP pump. Solids, Deviation and corrosive environments are inhibitors for ESPs and rod lift limiting the production potential for the operator.

In other applications, long stroke units or conventional rod pumping offer the best solution with high production rates at a much lower cost than an ESP installation.

In this paper, benefits and challenges for each ESP, Gas Lift and Rod Lift and insights on the best conversion time, will be discussed. 
This paper aims to provide data to help the customer understand how employing the best type of lift at the most appropriate time directly translates to maximizing revenue and production while minimizing losses and failures.

There has been a recent shift in the Permian across unconventional frac targets in the Delaware Basin stacked play, shifting to shallower formations. As a result, Avalon targets are becoming more common. When comparing key scale risk drivers such as brine compositions, mol% CO2 and H2S of the Avalon formation to more traditional targets such as the Wolfcamp and 2nd & 3rd Bone Springs, not only does the Avalon present its own unique scaling challenge, but the commingling of these formations can present much greater scale control and asset integrity challenges. Previous work has highlighted the Avalon formation has a high natural potential for carbonate scale precipitation, which aligns with field history presented here. These unique challenges will play a part in the next wave of formation-based proactive chemical treatment strategies across upstream, midstream and water disposal systems.

Here we present a case of severe carbonate surface scaling from Avalon formation brines, with a focus on how risk changes when adding Avalon production to existing fields. The operator was experiencing calcium carbonate scaling on flowlines, water legs of separators and equalizing lines between water tanks every 3 to 4 months. The operator had to choose between using heater treaters in winter to sell oil or scaling off the heaters. Incumbent service companies had successfully controlled downhole scale but could not control the surface scale issues. 

A total systems analysis including field analysis, scale modeling, 21 produced fluid chemical compatibility experiments run across 11 different scale inhibitors, minimum effective dosage (MED) identification through 119 NACE static/synthetic brine and Dynamic Scale Loop (DSL) testing was performed to identify a solution.

The solution highlighted in this paper resulted in zero facility scale-offs (26 month treatment period to date of publication), use of heater treaters in winter to sell oil, and operational efficiency gains in reduced manpower for cleanouts. Additionally, the ability to now commingle high-risk brines at central tank batteries allowed for the decommission of small satellite facilities previously used to isolate the highest scale risk brines.

The Avalon is not a new target but is projected to become more common in the future. The recent shift has implications to change how, where, and why we treat for carbonate scale in the Delaware Basin. 

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 Bakken, holes in tubing caused by rod-on-tubing wear are one of the most prevalent mechanisms of downhole failures in rod pumped applications, especially in deep, highly deviated wells. A common mitigation method involves using borided tubing in sections where tubing splits occur, typically near the pump where compressive and buckling forces are highest. Installing borided tubing along the entire length of this section would be favorable, however, this approach is cost-prohibitive and wasteful if wellhead Electromagnetic Interference (EMI) scanning determines that the tubing is unfit for reuse. The objective of this study is to explore economical ways to extend the borided section of tubing by focusing on the accuracy and precision of the data interpreted from EMI scans of the borided tubing. 
The methods in this study involved collaborating with Stress Engineering Services to utilize their Bore Erosion Measurement and Inspection System (BEMIS™) for high resolution mapping of surface wall loss in used borided joints of tubing. With more than 30% wall loss, previous EMI scanning during workovers suggested that these joints of tubing were deemed unusable (red/green grade). Pipe samples were scanned at the wellhead, then separated and transported to a designated location to benchmark their relative thickness readings against the BEMIS™ device measurements.
The results of the scanning study evolved through three phases with increasing scope. In the first phase, two red/green joints were cut into 5-6’ lengths and shipped to Stress Engineering in Houston. The results from this phase did not detect any defects. In the second phase, thirty-eight red/green joints were sent to Houston, resulting in a 97% pass rate. Of the thirty-eight joints scanned, 89% were still in yellow condition, three joints were in blue condition, and only one had a surface defect greater than 30%. The third phase involved scanning 170 joints of red/green tubing, which resulted in a 94% pass rate. Although the distribution of blue tubing increased in the third phase, the gap between the BEMIS™ system and EMI scanning was evident. A portion of the surface features found during the laser scanning were deeper than the boride coating penetration depths, but the 3D rendering showed these areas were isolated and few in quantity. Through three phases of tests, the consistent pass rate allowed ConocoPhillips to confirm that EMI scanning is incompatible with accurately reading true wall loss in borided pipe, often skewing high and leading to significant waste.
In conclusion, the data from this scanning project has given ConocoPhillips the confidence to re-run significant quantities of borided pipe. This approach allows for cost-effective reduction in the purchase of new borided pipe and extends the borided section to combat wear. However, there are still risks associated with re-using borided tubing and limitations inherent to the technology used in this study. Variances in the boride coating and potential wall loss missed by the device remain possibilities. Despite these risks, the accuracy and reliability of the results from this trial provide high confidence that significant cost savings and improved runtime on rod pump wells can be achieved.
This project could not have been done without support and assistance from Stress Engineering personnel Brandon McGinn and Jason Waligura and technical support from Craig Zimmerman with Bluewater Thermal Solutions. 

This paper discusses and provides a number of routines codified in practical spreadsheets that production engineers and operating personnel will be able to use to do calculations helpful for visualizing, analyzing and evaluating common production problems/scenarios.  Using these spreadsheets will save time and increase the user’s effectiveness in handling various production challenges and Artificial Lift situations.   Spreadsheets that will be included are as follow:
•    Gas lift Performance for Oil Wells
•    IPRs for Oil Wells: PI/Vogel & Back Pressure
•    SRP Pump Efficiency with Gas Separator Performance
•    Rod Loading: New and Old Goodman
•    Gas Well Multiphase Flow Gradients and Critical Flow Calculated
•    Gas Assist Plunger Design
•    Visualize Pump Dynamometers: Gas and PIP
•    Down Hole SRP Pump Clearance
•    Oil Well Tubing Performance: Inject at any Point in Tubing
•    SRP Pump Spacing
•    Calculate Gas Z Factor
•    Analyze Gas lift P & T Surveys
•    Plunger with Time with Declining IPRs
•    Present Value Profit ()of Staged AL with Declining Production
•    Limitations for Drawdown for Pumps
•    ESP Gas Separator Performance: Drawdown Possible 
•    Gas Well gas lift Performance
•    And others

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.

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.

This paper presents a novel technology designed to address the challenges posed by 100-mesh frac sand (149 microns) in rod pumps, particularly in the Permian Basin. This sand often causes premature pump failures by clogging and damaging key components like the plunger and barrel. The solution extends pump run life and prevents pump sticking.

The multilayer filtering system leverages the concept of completion screens, a long-established technology in the industry, but with a redesigned approach to be integrated in the production cycle where it is compatible for rod pumps and is made to filter sand sizes ranging from 60 to 300 microns, effectively removing particles traditional vortex separators miss. Its innovative design includes eccentric layers with dimples, maximizing open area to nearly 40% across its 288-inch length. The modular setup allows multiple units to be combined in tandem, enhancing filtration capacity while minimizing pressure drop.

Field installations in the Permian Basin have demonstrated significant operational benefits. In one case study, pump run time tripled following the system's implementation, reducing well interventions and equipment replacement. This improvement also lowers the carbon footprint of operations.

Uniquely, using patented Dual-Flow technology, this system integrates with vortex and gas separators for added protection against solids and gas. Constructed with premium materials and a robust assembly process, it offers durability and long-lasting performance for rod pump applications.

This paper explores the application of boron-carbide (B4C) treated rod pump parts in sucker rod pump (SRP) wells, as a solution to the challenges posed by modern-day drilling and completions practices. These practices often result in sandy, corrosive, and highly deviated wellbores, leading to increased wear, frequent interventions, and downtime in rod lift systems. The paper highlights the improved run times a large producer in the Permian Basin was able to achieve by utilizing boron-carbide treated components in their sucker rod pumped wells. The evaluation aimed to assess the run time performance of a sample of 30 wells, focusing on wells with prior run-time and failure mode history established. The results showed improved run times in many of the wells evaluated and highlights the components and configurations used. The paper further discusses the B4C treatment technology the potential in enhancing the performance and longevity of various artificial lift equipment.

As global pressure mounts to reduce methane emissions, the energy industry faces increasingly stringent regulations to detect and repair leaks. In December 2023, the EPA finalized rules, including New Source Performance Standards (NSPS) OOOOb and Emissions Guidelines, mandating facilities to implement robust Leak Detection and Repair (LDAR) programs. These programs can leverage either traditional Optical Gas Imaging (OGI) surveys or advanced Alternative Test Methods (ATMs), such as continuous, real-time monitoring technologies.
This paper highlights the transformative impact of continuous monitoring on emissions detection, quantification, and operational cost efficiency. The monitoring system comprises three integrated components: (i) a network of metal oxide semiconductor sensors to measure methane concentrations and environmental parameters; (ii) a cloud-based platform using physics-based Gaussian Plume Modeling to locate and quantify leaks; and (iii) a web-based dashboard that aggregates emissions data and generates actionable alerts for remedial action.

We compare continuous monitoring to periodic OGI surveys, showcasing its ability to reduce compliance costs and expedite leak repairs at facilities in Texas and Colorado. Beyond LDAR compliance, continuous monitoring has proven effective at detecting operational inefficiencies, such as underperforming flares and burners – issues often missed by traditional methods. Real-world deployments achieved a 60% reduction in emissions within three months and an 80% annual reduction by adhering to NSPS OOOOb thresholds. By generating a continuous emissions dataset, the technology also mitigates compliance risks by time-bounding Super Emitter events. These emissions reductions have significantly lowered the frequency of OGI inspections, delivering substantial multi-year cost savings.

Through case studies in the Permian and Piceance basins, we explore strategies for deploying continuous monitoring across diverse facility designs. Participants will gain insights into best practices for visualizing emissions plumes, conducting investigative analyses, and remotely diagnosing leaks to minimize unnecessary field visits.

Continuous monitoring is not just a compliance tool; it is a strategic advantage for reducing emissions, safeguarding operational integrity, and controlling costs. This technology empowers field operators to take ownership of emissions management, ensuring regulatory alignment while mitigating external scrutiny.

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. 

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.

The challenges frequently associated with Endless Rod applications primarily arise from corrosion, particularly mechanical corrosion where the inhibitor film is removed, leading to inadequate protection and allowing corrosion to develop. Barrier coatings can protect the rod from corrosion, preventing the formation of stress risers on the rod surface that, under cyclic loading, can easily propagate across the rod body until there is insufficient section to sustain the load, causing it to fail. Industry studies have demonstrated that certain coatings reduce rod/tubing contact friction, resulting in lower axial loads in rod pump applications. Furthermore, reduced friction has the potential to decrease tubing wear in more aggressive environments.

KeBond Technology incorporates an extruded bonded composite design derived from an engineered thermoplastic (Polyketone) outer coating that is resistant to aggressive oilfield fluids and can withstand elevated temperatures. The bonded high-strength design enables servicing at high loads and associated depths, significantly expanding the historical operating envelope, allowing deployment in deeper unconventional rod pumping applications. We will present performance data highlighting axial load reductions, runtime improvements, and other successes identified along the way. The dataset highlighted was generated from a Permian case study with KeBond Technology installed in Oxy’s unconventional wells with extremely deviated wellbores, high production requirments, highly corrosive fluid properties, and challenging operational conditions. 

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.

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.

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. 

Please refer to abstracts 2025059 and 2025060. 

Reciprocating rod pumps (RRP) have globally shown that with longer strokes increased productivity and reduced operational costs can be achieved over that of a progressive cavity pump (PCP) in clean to moderate solids producing wells. This has also been extended to suggest that with the right equipment mean time to failure can be increased.  This information has been pivotal in a large-scale change for Origin Energy Limited’s fields under the Australia Pacific LNG Pty Limited (APLNG) joint venture with ConocoPhillips Company and Sinopec Australia Pty Limited to address the hypothesis that increased RRP completions will, increase mean time failure past current run lives and reduce the flowing bottom hole pressure for optimal gas production. To do this an economic analysis was undertaken to understand based on cost, what units are applicable to what wellsites. This included a detailed analysis of the inputs and outputs with our Global subject matter expert (SME) partners from ConocoPhillips Company and an economic build-up based on their and local experience. The analysis led to the utilisation of tower units and beam units in conjunction with Linear Rod Pumps (LRPs) and lead to the first successful installation of a tower unit in Australia with a significant ramp of RRP over the near term across three main surface drives. Technology trails, both surface and subsurface, have also been undertaken underpin our current understanding and reach towards goal production and failure statistics. Vendor support and engagement in Research and Development (R&D) projects and continual improvement has also greatly benefited our overall result. Challenges were faced in supply chain and logistics, availability of parts and servicing and the ability to quickly pivot using new information for optimal performance. A large-scale ramp-up has many challenges that have provided opportunities to learn, innovate and implement changes that have resulted in increased performance of the technology and wells.

Rod-lifted wells in U.S. unconventional fields have been pushed beyond their limits since the onset of the unconventional reservoir (UR) revolution. Sixteen years later, the demand for higher production rates with rod-lift systems remains strong. As the industry progresses toward the Aspirational Goal of 1,000 barrels per day (bfpd) at depths of 10,000 feet (1K @ 10K), new challenges continue to emerge.

While previously identified issues, such as wellbore deviation, high sideloads, and compressive loads, have been mitigated through innovative rod guiding techniques (Oliva & Anderson, SWPSC 2024, Sinker Section Design to Reduce Buckling-Related Failures), operators in the 400 to 600 bfpd range now face additional challenges. Specifically, turbulent flow conditions have led to corrosion-erosion mechanisms around rod guides and connections.

This study explores the use of Computational Fluid Dynamics (CFD) as a tool to enhance the design and reliability of sucker rod components in rod-lift systems. By applying CFD techniques to model fluid dynamics, we optimize key properties of rod guides and connections, such as geometry, dimensions, and Erodible Wear Volume (EWV). This approach allows for precise optimization of component placement and design, ultimately improving runtime and reducing wear-related failures in challenging operational conditions.

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.

As the complexity of well profiles on rod pumped wells increases, traditional rod rotators experience more frequent failures due to the challenging conditions. The consequence is a decline in well productivity, often accompanied by a significant increase in well maintenance costs. This session will examine common rod rotator failures and root causes. It will introduce a new alternative rod rotator designed to improve field performance and reduce operating expenses, including a comprehensive review of field trial results during the last 30 months. The field data will include a variety of well profiles and fields including the Permian, Powder River, Eagle Ford and the Bakken with cross section of different producers.

Dynamic sucker rod sucker rod modeling in deviated wells has proven difficult. Wave equation solutions – when applied to measured surface cards - have generally produced dubious pump cards. Recently acquired measurements collected from deviated wells using downhole dynamometers have inspired a new wave equation formulation and a modern finite difference implementation. The new model produces pump cards which are generally consistent with data measured downhole. The new model has been implemented in a commercial rod pump controller. 

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.

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. 

Sucker rod pumping is the main artificial lift system used to exploit the unconventional Vaca Muerta formation situated in the province of Neuquén, Argentina. 

For just over six years, Vista has made a strategic decision to adopt Gas Lift as the primary artificial lift system (ALS) for the production of its wells after the natural flow stage. This transition has positioned Vista as the second-largest shale oil operator in the country, with approximately 60% of its total production coming from its 110 Gas Lift wells.
The journey that Vista has undertaken throughout this period has enabled the establishment of a significant learning curve during the initial productive stages of the wells.

In this document, we aim to outline and discuss some of the various challenges that we have worked on addressing: paraffins, frac hits, the presence of sand, gas recirculation, and other related concerns. In most cases, we have managed to mitigate their negative effects or, at the very least, establish procedures for the necessary maneuvers that can be executed to generate a lower economic impact if any of these issues occur. 

Furthermore, the ability to measure variables in real-time has proven invaluable, as it allows us to engage in optimization efforts and the development of advanced diagnostic tools, including those powered by artificial intelligence (AI). The production engineering team has made significant strides and advancements in this area, emphasizing the importance of safeguarding as much unmeasured data as possible. This effort is crucial for reinforcing our machine learning models and enhancing their effectiveness. By focusing on these aspects, we aim to continuously improve our operations and address the challenges that arise in this dynamic field.

A sucker rod pump is an essential component for rod pumping, but it has been limited by use of machined componentry and a ball/seat valve design. Today’s deep, gassy-sluggy, foamy, solids ladened, horizontal wells commonly have high initial liquid rates that are beyond the rate capacity of sucker rod pumping, which can require use of higher operating expense ESP’s or gas lift methods. Improving the rate capacity and reliability of sucker rod pumping in such challenging environments would be highly beneficial for producers.
The sucker rod pump is one component of a complex downhole system of components for sucker rod pumping. Other components of this system include a downhole gas separator, a downhole solids separator, a tubing anchor and sucker rods. To maximize the efficiency and performance of a sucker rod pump, all these components must act together harmoniously to effectively feed the pump on demand with liquid that has been gas and solids depleted – unfortunately, achieving this has been particularly challenging. Consequently, the sucker rod pump still must contend with gas and solids.
Further, with deep high-rate sucker pumping, an acceptable reliability failure frequency has been particularly challenging. Larger and longer stroke length pumping units have improved the rate capacity of sucker rod pumping but have been limited primarily by excessive pressure loss across the pump’s standing/travelling valves, by pump gas interference and by inadequate reliability from damaging solids. Lastly, compressional loading events on the sucker rods at the commencement of each pump downstroke has also reduced system reliability.
An improved sucker rod pump was conceptualized, and design engineered for such challenging environments:
• minimal standing/travelling valve pressure loss at high pump rates and pump plunger velocities,
• solids tolerant at high concentrations of solids (from concentrated solids slugging events),
• can operate efficiently at all inclinations up to 90 degrees, and
• pressure balances the pump’s travelling valve prior to commencement of the pump’s downstroke to avoid compressional loading events and to avoid efficiency losses due to gas interference.
The Vortex Barbell SystemTM pump valves have demonstrated a step change in performance for high inclination pumping conditions. This unique valve design revealed a transformational opportunity to evolve the valve for improving a sucker rod pump at all inclinations. Three-Dimensional (3D) metal printing has gained significant attention in recent years. The ability to now print hard and tough metals has offed an opportunity to engineer and manufacture reliable sucker rod pump valves with very low-pressure losses, minimal flow turbulence and improved solids handling -- we are no longer design limited by the ball and seat design from circa 1938. A new complex shaped hydrodynamically engineered rod pump valve was developed.
A pressure balanced pump, has offered advantages for reducing the negative impacts of pump gas interference and compressional rod loading events. But this pump design can be limited by solids and can require precise pump space-outs. A hypothesis that instead of tapered top barrel section, a rifled channeled top barrel section would solve existing limitations. A rifled channel offered much greater solids tolerance and avoided the need for precise pump space-outs.
Flow loop testing and field trials have indicated promise for improvement. The design process, prototyping and flow loop testing, and well trials/results will be shared.

Please refer to abstracts 2025057 and 2025058.  

Pump off controllers (POC’s) that produce dynamometer cards are and have been the preferred method of detecting pump off in rod pump applications. In addition to detecting pump off, these devices provide several leading indicators such as run time, cycles, peak and minimum loads, gearbox and rod stress, and a variety of other data points. In order to do this, a load cell, a position measuring sensor and other technology is needed, thus driving up the cost of the traditional POC, and making it harder for a marginal producer to justify the expense of this type of POC. 

With rising cost of downhole failure repairs, electricity, and the increasing need for the ‘pump by exception’ model, a cheaper POC (Smarten Lite) has been developed to do basic pump off control and remote surveillance for marginal wells that cannot justify the expense of the traditional POC. This would include wells with no automation at all, wells on timer, and wells on less robust low-cost devices. It is estimated that there are at least 50,000 rod pumping wells in the US that are operating with no automation or only mechanical timers.

Benefits and capabilities of this new technology are:
1. Reduced electrical costs by running just enough.
2. Reduced downtime through instant notification of down wells.
3. Reduced failure rate through reduced fluid pound.
4. Better staff efficiency by enabling ‘pump by exception’.
This paper will present several case studies to demonstrate the benefits of this new technology as it applies to marginal wells.

The fatigue performance of sucker rods is intrinsically tied to their manufacturing processes and the mechanical properties of various grades. One of the most transformative advancements introduced in the past decade is the application of shot peening, a process that has emerged as a cornerstone of performance enhancement in the sucker rod industry. TRC Services has been a pioneer in integrating shot peening into sucker rod manufacturing, particularly for remanufactured rods, and has developed the most comprehensive database on its effects through years of rigorous field and laboratory testing on both new and previously used rods.

Traditionally, the benefits of shot peening have been evaluated in two dimensions: increasing stress tolerance for a given fatigue life or extending fatigue life under a set stress level. While TRC’s initial efforts focused on prolonging rod life within specific stress ranges, a 2022 engineering initiative shifted focus toward redefining stress tolerance at fixed fatigue lives. This reevaluation of accumulated data revealed groundbreaking improvements in the stress range, demonstrating that treated rods outperformed all commercially available new sucker rods.

This breakthrough technology redefines the operational stress limits for all sucker rod grades. By broadening the fatigue envelope, it allows operators to push the boundaries of their production systems while improving lease operating expenditures (LOE) through reduced downtime and failure rates. Furthermore, this innovation lowers lifting costs by enabling the use of optimized rod strings, such as lighter configurations, or softer materials with lower mechanical properties.

This paper presents a detailed exploration of the process, the testing methodology, and the traceability protocol for these enhanced rods. It further highlights the operational and economic advantages of adopting this fatigue-enhancing technology, including its significant impact on lowering costs and improving operational efficiency across a variety of applications.

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. 

Closed-loop gas capture (CLGC) offers a viable pathway for the oil and gas sector to reduce flaring, improve sustainability, and minimize environmental impact during midstream upsets. Instead of flaring gas during disruptions, this technology re-injects the gas for short term storage until the issue is resolved. Two recent trials in the Midland Basin demonstrated the feasibility and benefits of closed-loop systems, successfully storing and recovering significant volumes of gas. We will talk through Ovintiv's experience with the regulatory framework, candidate selection, trial results, and our learnings.

The contemporary rod pumping strategy for horizontal wells typically involves placing the pump at or above the Kickoff Point (KOP) to ensure the rod string and downhole pump operate in relatively low dogleg severity conditions. However, in certain types of reservoirs and well conditions, it may be beneficial to place the pump below the KOP. This paper presents a case study from Devon Energy’s Powder River Basin and Delaware Basin Assets, where over the past decade, more than 1200 pumps have been operated below the KOP in over 400 unique wells. The study examines the conditions, methodologies, and outcomes associated with this approach, highlighting its potential advantages, operational insights, and recommended best practices.

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. 

Ambyint and PetroBench have each independently developed proprietary downhole equations that provide a better representation of deviated wells compared to the vertical downhole card's prediction model. The deviated well downhole card's prediction model can:

Consider the well geometry to calculate the rod state (velocities, accelerations, forces and stresses) along the well trajectory. These specific forces are represented as axial, normal and binormal.
Calculate the dog severity and predict possible rod/tubing contact along the well trajectory. 
Calculate the lateral load on the rod due to rod/tubing contact. This load is a combination of the normal and binormal forces expressed in vector forces.
Improve the axial force calculation by considering the friction force (Coulomb force) calculation due to rod/tubing contact.
Identify maximum and minimum axial, normal or binormal forces positions during the rod cycle.

Both companies have successfully deployed their proprietary downhole equations into commercially available software. Ambyint has been deployed on thousands of wells over 15 years, while PetroBench's has been deployed on hundreds of wells for 5 years.

In an effort to validate the outputs of their respective models, the companies have both implemented their models on 35 common wells under a number of different scenarios. Despite being developed completely independently, the outputs of the two downhole models are very similar in some parameters with some slight discrepancies in other parameters. This paper aims to highlight the similarities and differences between the two models.

In summary, both models had qualitative similar outputs on Side Loading, Dynamometer cards and absolute values of the surface card. The models demonstrated a slight difference in the load harmonics near the top of the stroke, most likely due to low friction assumptions in the PetroBench's simulation. One noticeable difference between the two models was in the pump fillage calculation, where PetroBench's graphed pump fillage visually showed a lower value than what was reported.

Although the ideal validation exercise would include comparison of results to downhole sensors capable of generating a real-world downhole dynamometer card, the validation exercise described above serves as a reasonable substitute. The nearly identical model outputs observed between the two downhole models should provide users of the respective models with some confidence in the accuracy of those models.

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.

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. 

Distributed Acoustic Sensing (DAS) provides unparalleled insights into the operation and performance of Electric Submersible Pumps (ESPs) and gas lift systems in oil and gas wells. Our proprietary platform, the “Precise Signal Streaming Platform-Artificial Intelligence” (PSSP-AITM, where "TM" denotes trademark in superscript in this abstract), leverages real-time DAS phase data analysis to enable continuous tracking of downhole facilities. This capability not only enhances real-time monitoring but also supports production rate optimization, aligning pump and gas lift performance with production goals. By converting a fiber optic cable into a high-density array of acoustic sensors, DAS facilitates real-time surveillance of ESPs, capturing critical operational metrics such as vibration patterns, flow irregularities, and gas lock events with exceptional spatial and temporal resolution.

In gas lift operations, PSSP-AITM transforms the way operators monitor and optimize injection processes. The platform provides precise tracking of gas injection rates, detecting variations that could lead to inefficiencies such as improper gas allocation or flow instability. Additionally, the platform supports adjustments in gas injection pressure and rate to optimize liquid production while minimizing energy consumption and equipment wear.

This innovative approach significantly enhances the understanding of ESP performance and efficiency, enabling early identification of anomalies that could lead to operational inefficiencies or failures. Furthermore, the platform’s production optimization capabilities extend to both ESPs and gas lift systems. For ESPs, this includes achieving optimal pump efficiency and minimizing energy consumption, while for gas lift systems, it ensures precise control over gas injection cycles and maximized liquid recovery. The real-time feedback loop between DAS data and production metrics empowers operators to make informed decisions that dynamically tune the performance of both systems in response to changing reservoir conditions.

The integration of DAS with PSSP-AITM represents a significant leap forward in intelligent well monitoring. This technology offers a comprehensive framework for real-time diagnostics, dynamic optimization, and long-term performance improvement. By providing deeper visibility into subsurface operations, it enables operators to transition from reactive to proactive management of downhole facilities, delivering transformative benefits in operational reliability, production enhancement, and cost efficiency.

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 relative motion between sucker rods and tubing in rod-lifted wells, particularly in corrosive fluids, leads to degradation mechanisms that often cause material loss, commonly referred to as wear. In U.S. unconventional wells, this wear mechanism accounts for over 50% of the operational expenditure (OPEX) in rod-lifted systems.

Through the application of Root Cause Analysis, the primary mechanisms responsible for this wear—tribocorrosion and three-part abrasion—were identified. These mechanisms can occur individually or in combination.

To better understand these processes and assess the performance of materials and components, Tenaris developed two distinct full-scale testing methods: (1) the Tribocorrosion Sliding Test and (2) the Abrasive Sliding Test. Both testing methods allow for the manipulation of environmental conditions, lateral loads, and key fluid or abrasive components.

Upon completion of the testing protocols, wear levels in each component were quantified using state-of-the-art imaging techniques. This data was carefully analyzed to evaluate the relative performance of materials and identify optimal combinations to mitigate wear, ultimately enhancing the run life of rod-lifted systems.

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.

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.

Current models for design and analysis of rod pumped wells are based on data from vertical wells. The assumption that these models work is only theoretical. Such models have never been validated with actual measurements from deviated or horizontal wells. 
The result has been rod string designs which are either too conservative or overly optimistic. This can result in excess rod string weight which constrains production rates; or premature rod failures that necessitate well interventions and production interruptions. From a diagnostic point of view, the software that is used for analysis and in wellsite controllers today still rely on the vertical hole model, which are inadequate at dealing with deviated wells and the mechanical friction responsible for the majority of today’s failures.
The HWDDDA project aims to gather true measured data such as axial load and tri-axial acceleration to help improve design and control software for rod systems. The goal of the HWDDDA project is to design and manufacture downhole tools and deploy those tools in deviated and horizontal wells. Data gathered during the HWDDDA project can be used to validate existing models and develop models better equipped to handle the complicated balance of forces occurring during pumping in deviated and horizontal wells. Data collected by the HWDDDA tools will be validated, archived, and distributed to the industry.

Thanks to the generous contributions of our member companies, the design and manufacturing of downhole tools is underway. Progress including the rigorous calibration, testing and validation of the downhole tools will be discussed. Results from initial field testing will also be presented and reviewed.

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.

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. 

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.

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.

Reciprocating rod pumps (RRP) have globally shown that with longer strokes increased productivity and reduced operational costs can be achieved over that of a progressive cavity pump (PCP) in clean to moderate solids producing wells. This has also been extended to suggest that with the right equipment mean time to failure can be increased.  This information has been pivotal in a large-scale change for Origin Energy Limited’s fields under the Australia Pacific LNG Pty Limited (APLNG) joint venture with ConocoPhillips Company and Sinopec Australia Pty Limited to address the hypothesis that increased RRP completions will, increase mean time failure past current run lives and reduce the flowing bottom hole pressure for optimal gas production. To do this an economic analysis was undertaken to understand based on cost, what units are applicable to what wellsites. This included a detailed analysis of the inputs and outputs with our Global subject matter expert (SME) partners from ConocoPhillips Company and an economic build-up based on their and local experience. The analysis led to the utilisation of tower units and beam units in conjunction with Linear Rod Pumps (LRPs) and lead to the first successful installation of a tower unit in Australia with a significant ramp of RRP over the near term across three main surface drives. Technology trails, both surface and subsurface, have also been undertaken underpin our current understanding and reach towards goal production and failure statistics. Vendor support and engagement in Research and Development (R&D) projects and continual improvement has also greatly benefited our overall result. Challenges were faced in supply chain and logistics, availability of parts and servicing and the ability to quickly pivot using new information for optimal performance. A large-scale ramp-up has many challenges that have provided opportunities to learn, innovate and implement changes that have resulted in increased performance of the technology and wells.

The relative motion between sucker rods and tubing in rod-lifted wells, particularly in corrosive fluids, leads to degradation mechanisms that often cause material loss, commonly referred to as wear. In U.S. unconventional wells, this wear mechanism accounts for over 50% of the operational expenditure (OPEX) in rod-lifted systems.

Through the application of Root Cause Analysis, the primary mechanisms responsible for this wear—tribocorrosion and three-part abrasion—were identified. These mechanisms can occur individually or in combination.

To better understand these processes and assess the performance of materials and components, Tenaris developed two distinct full-scale testing methods: (1) the Tribocorrosion Sliding Test and (2) the Abrasive Sliding Test. Both testing methods allow for the manipulation of environmental conditions, lateral loads, and key fluid or abrasive components.

Upon completion of the testing protocols, wear levels in each component were quantified using state-of-the-art imaging techniques. This data was carefully analyzed to evaluate the relative performance of materials and identify optimal combinations to mitigate wear, ultimately enhancing the run life of rod-lifted systems.

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.

As the complexity of well profiles on rod pumped wells increases, traditional rod rotators experience more frequent failures due to the challenging conditions. The consequence is a decline in well productivity, often accompanied by a significant increase in well maintenance costs. This session will examine common rod rotator failures and root causes. It will introduce a new alternative rod rotator designed to improve field performance and reduce operating expenses, including a comprehensive review of field trial results during the last 30 months. The field data will include a variety of well profiles and fields including the Permian, Powder River, Eagle Ford and the Bakken with cross section of different producers.

Current models for design and analysis of rod pumped wells are based on data from vertical wells. The assumption that these models work is only theoretical. Such models have never been validated with actual measurements from deviated or horizontal wells. 
The result has been rod string designs which are either too conservative or overly optimistic. This can result in excess rod string weight which constrains production rates; or premature rod failures that necessitate well interventions and production interruptions. From a diagnostic point of view, the software that is used for analysis and in wellsite controllers today still rely on the vertical hole model, which are inadequate at dealing with deviated wells and the mechanical friction responsible for the majority of today’s failures.
The HWDDDA project aims to gather true measured data such as axial load and tri-axial acceleration to help improve design and control software for rod systems. The goal of the HWDDDA project is to design and manufacture downhole tools and deploy those tools in deviated and horizontal wells. Data gathered during the HWDDDA project can be used to validate existing models and develop models better equipped to handle the complicated balance of forces occurring during pumping in deviated and horizontal wells. Data collected by the HWDDDA tools will be validated, archived, and distributed to the industry.

Thanks to the generous contributions of our member companies, the design and manufacturing of downhole tools is underway. Progress including the rigorous calibration, testing and validation of the downhole tools will be discussed. Results from initial field testing will also be presented and reviewed.

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.

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. 

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.

A sucker rod pump is an essential component for rod pumping, but it has been limited by use of machined componentry and a ball/seat valve design. Today’s deep, gassy-sluggy, foamy, solids ladened, horizontal wells commonly have high initial liquid rates that are beyond the rate capacity of sucker rod pumping, which can require use of higher operating expense ESP’s or gas lift methods. Improving the rate capacity and reliability of sucker rod pumping in such challenging environments would be highly beneficial for producers.
The sucker rod pump is one component of a complex downhole system of components for sucker rod pumping. Other components of this system include a downhole gas separator, a downhole solids separator, a tubing anchor and sucker rods. To maximize the efficiency and performance of a sucker rod pump, all these components must act together harmoniously to effectively feed the pump on demand with liquid that has been gas and solids depleted – unfortunately, achieving this has been particularly challenging. Consequently, the sucker rod pump still must contend with gas and solids.
Further, with deep high-rate sucker pumping, an acceptable reliability failure frequency has been particularly challenging. Larger and longer stroke length pumping units have improved the rate capacity of sucker rod pumping but have been limited primarily by excessive pressure loss across the pump’s standing/travelling valves, by pump gas interference and by inadequate reliability from damaging solids. Lastly, compressional loading events on the sucker rods at the commencement of each pump downstroke has also reduced system reliability.
An improved sucker rod pump was conceptualized, and design engineered for such challenging environments:
• minimal standing/travelling valve pressure loss at high pump rates and pump plunger velocities,
• solids tolerant at high concentrations of solids (from concentrated solids slugging events),
• can operate efficiently at all inclinations up to 90 degrees, and
• pressure balances the pump’s travelling valve prior to commencement of the pump’s downstroke to avoid compressional loading events and to avoid efficiency losses due to gas interference.
The Vortex Barbell SystemTM pump valves have demonstrated a step change in performance for high inclination pumping conditions. This unique valve design revealed a transformational opportunity to evolve the valve for improving a sucker rod pump at all inclinations. Three-Dimensional (3D) metal printing has gained significant attention in recent years. The ability to now print hard and tough metals has offed an opportunity to engineer and manufacture reliable sucker rod pump valves with very low-pressure losses, minimal flow turbulence and improved solids handling -- we are no longer design limited by the ball and seat design from circa 1938. A new complex shaped hydrodynamically engineered rod pump valve was developed.
A pressure balanced pump, has offered advantages for reducing the negative impacts of pump gas interference and compressional rod loading events. But this pump design can be limited by solids and can require precise pump space-outs. A hypothesis that instead of tapered top barrel section, a rifled channeled top barrel section would solve existing limitations. A rifled channel offered much greater solids tolerance and avoided the need for precise pump space-outs.
Flow loop testing and field trials have indicated promise for improvement. The design process, prototyping and flow loop testing, and well trials/results will be shared.

Please refer to abstracts 2025054, 2025055, and 2025056.

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 fatigue performance of sucker rods is intrinsically tied to their manufacturing processes and the mechanical properties of various grades. One of the most transformative advancements introduced in the past decade is the application of shot peening, a process that has emerged as a cornerstone of performance enhancement in the sucker rod industry. TRC Services has been a pioneer in integrating shot peening into sucker rod manufacturing, particularly for remanufactured rods, and has developed the most comprehensive database on its effects through years of rigorous field and laboratory testing on both new and previously used rods.

Traditionally, the benefits of shot peening have been evaluated in two dimensions: increasing stress tolerance for a given fatigue life or extending fatigue life under a set stress level. While TRC’s initial efforts focused on prolonging rod life within specific stress ranges, a 2022 engineering initiative shifted focus toward redefining stress tolerance at fixed fatigue lives. This reevaluation of accumulated data revealed groundbreaking improvements in the stress range, demonstrating that treated rods outperformed all commercially available new sucker rods.

This breakthrough technology redefines the operational stress limits for all sucker rod grades. By broadening the fatigue envelope, it allows operators to push the boundaries of their production systems while improving lease operating expenditures (LOE) through reduced downtime and failure rates. Furthermore, this innovation lowers lifting costs by enabling the use of optimized rod strings, such as lighter configurations, or softer materials with lower mechanical properties.

This paper presents a detailed exploration of the process, the testing methodology, and the traceability protocol for these enhanced rods. It further highlights the operational and economic advantages of adopting this fatigue-enhancing technology, including its significant impact on lowering costs and improving operational efficiency across a variety of applications.

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.

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.

Dynamic sucker rod sucker rod modeling in deviated wells has proven difficult. Wave equation solutions – when applied to measured surface cards - have generally produced dubious pump cards. Recently acquired measurements collected from deviated wells using downhole dynamometers have inspired a new wave equation formulation and a modern finite difference implementation. The new model produces pump cards which are generally consistent with data measured downhole. The new model has been implemented in a commercial rod pump controller. 

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.

Ambyint and PetroBench have each independently developed proprietary downhole equations that provide a better representation of deviated wells compared to the vertical downhole card's prediction model. The deviated well downhole card's prediction model can:

Consider the well geometry to calculate the rod state (velocities, accelerations, forces and stresses) along the well trajectory. These specific forces are represented as axial, normal and binormal.
Calculate the dog severity and predict possible rod/tubing contact along the well trajectory. 
Calculate the lateral load on the rod due to rod/tubing contact. This load is a combination of the normal and binormal forces expressed in vector forces.
Improve the axial force calculation by considering the friction force (Coulomb force) calculation due to rod/tubing contact.
Identify maximum and minimum axial, normal or binormal forces positions during the rod cycle.

Both companies have successfully deployed their proprietary downhole equations into commercially available software. Ambyint has been deployed on thousands of wells over 15 years, while PetroBench's has been deployed on hundreds of wells for 5 years.

In an effort to validate the outputs of their respective models, the companies have both implemented their models on 35 common wells under a number of different scenarios. Despite being developed completely independently, the outputs of the two downhole models are very similar in some parameters with some slight discrepancies in other parameters. This paper aims to highlight the similarities and differences between the two models.

In summary, both models had qualitative similar outputs on Side Loading, Dynamometer cards and absolute values of the surface card. The models demonstrated a slight difference in the load harmonics near the top of the stroke, most likely due to low friction assumptions in the PetroBench's simulation. One noticeable difference between the two models was in the pump fillage calculation, where PetroBench's graphed pump fillage visually showed a lower value than what was reported.

Although the ideal validation exercise would include comparison of results to downhole sensors capable of generating a real-world downhole dynamometer card, the validation exercise described above serves as a reasonable substitute. The nearly identical model outputs observed between the two downhole models should provide users of the respective models with some confidence in the accuracy of those models.

Sucker rod pumping is the main artificial lift system used to exploit the unconventional Vaca Muerta formation situated in the province of Neuquén, Argentina. 

For just over six years, Vista has made a strategic decision to adopt Gas Lift as the primary artificial lift system (ALS) for the production of its wells after the natural flow stage. This transition has positioned Vista as the second-largest shale oil operator in the country, with approximately 60% of its total production coming from its 110 Gas Lift wells.
The journey that Vista has undertaken throughout this period has enabled the establishment of a significant learning curve during the initial productive stages of the wells.

In this document, we aim to outline and discuss some of the various challenges that we have worked on addressing: paraffins, frac hits, the presence of sand, gas recirculation, and other related concerns. In most cases, we have managed to mitigate their negative effects or, at the very least, establish procedures for the necessary maneuvers that can be executed to generate a lower economic impact if any of these issues occur. 

Furthermore, the ability to measure variables in real-time has proven invaluable, as it allows us to engage in optimization efforts and the development of advanced diagnostic tools, including those powered by artificial intelligence (AI). The production engineering team has made significant strides and advancements in this area, emphasizing the importance of safeguarding as much unmeasured data as possible. This effort is crucial for reinforcing our machine learning models and enhancing their effectiveness. By focusing on these aspects, we aim to continuously improve our operations and address the challenges that arise in this dynamic field.

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.

Distributed Acoustic Sensing (DAS) provides unparalleled insights into the operation and performance of Electric Submersible Pumps (ESPs) and gas lift systems in oil and gas wells. Our proprietary platform, the “Precise Signal Streaming Platform-Artificial Intelligence” (PSSP-AITM, where "TM" denotes trademark in superscript in this abstract), leverages real-time DAS phase data analysis to enable continuous tracking of downhole facilities. This capability not only enhances real-time monitoring but also supports production rate optimization, aligning pump and gas lift performance with production goals. By converting a fiber optic cable into a high-density array of acoustic sensors, DAS facilitates real-time surveillance of ESPs, capturing critical operational metrics such as vibration patterns, flow irregularities, and gas lock events with exceptional spatial and temporal resolution.

In gas lift operations, PSSP-AITM transforms the way operators monitor and optimize injection processes. The platform provides precise tracking of gas injection rates, detecting variations that could lead to inefficiencies such as improper gas allocation or flow instability. Additionally, the platform supports adjustments in gas injection pressure and rate to optimize liquid production while minimizing energy consumption and equipment wear.

This innovative approach significantly enhances the understanding of ESP performance and efficiency, enabling early identification of anomalies that could lead to operational inefficiencies or failures. Furthermore, the platform’s production optimization capabilities extend to both ESPs and gas lift systems. For ESPs, this includes achieving optimal pump efficiency and minimizing energy consumption, while for gas lift systems, it ensures precise control over gas injection cycles and maximized liquid recovery. The real-time feedback loop between DAS data and production metrics empowers operators to make informed decisions that dynamically tune the performance of both systems in response to changing reservoir conditions.

The integration of DAS with PSSP-AITM represents a significant leap forward in intelligent well monitoring. This technology offers a comprehensive framework for real-time diagnostics, dynamic optimization, and long-term performance improvement. By providing deeper visibility into subsurface operations, it enables operators to transition from reactive to proactive management of downhole facilities, delivering transformative benefits in operational reliability, production enhancement, and cost efficiency.

Pump off controllers (POC’s) that produce dynamometer cards are and have been the preferred method of detecting pump off in rod pump applications. In addition to detecting pump off, these devices provide several leading indicators such as run time, cycles, peak and minimum loads, gearbox and rod stress, and a variety of other data points. In order to do this, a load cell, a position measuring sensor and other technology is needed, thus driving up the cost of the traditional POC, and making it harder for a marginal producer to justify the expense of this type of POC. 

With rising cost of downhole failure repairs, electricity, and the increasing need for the ‘pump by exception’ model, a cheaper POC (Smarten Lite) has been developed to do basic pump off control and remote surveillance for marginal wells that cannot justify the expense of the traditional POC. This would include wells with no automation at all, wells on timer, and wells on less robust low-cost devices. It is estimated that there are at least 50,000 rod pumping wells in the US that are operating with no automation or only mechanical timers.

Benefits and capabilities of this new technology are:
1. Reduced electrical costs by running just enough.
2. Reduced downtime through instant notification of down wells.
3. Reduced failure rate through reduced fluid pound.
4. Better staff efficiency by enabling ‘pump by exception’.
This paper will present several case studies to demonstrate the benefits of this new technology as it applies to marginal wells.

Rod-lifted wells in U.S. unconventional fields have been pushed beyond their limits since the onset of the unconventional reservoir (UR) revolution. Sixteen years later, the demand for higher production rates with rod-lift systems remains strong. As the industry progresses toward the Aspirational Goal of 1,000 barrels per day (bfpd) at depths of 10,000 feet (1K @ 10K), new challenges continue to emerge.

While previously identified issues, such as wellbore deviation, high sideloads, and compressive loads, have been mitigated through innovative rod guiding techniques (Oliva & Anderson, SWPSC 2024, Sinker Section Design to Reduce Buckling-Related Failures), operators in the 400 to 600 bfpd range now face additional challenges. Specifically, turbulent flow conditions have led to corrosion-erosion mechanisms around rod guides and connections.

This study explores the use of Computational Fluid Dynamics (CFD) as a tool to enhance the design and reliability of sucker rod components in rod-lift systems. By applying CFD techniques to model fluid dynamics, we optimize key properties of rod guides and connections, such as geometry, dimensions, and Erodible Wear Volume (EWV). This approach allows for precise optimization of component placement and design, ultimately improving runtime and reducing wear-related failures in challenging operational conditions.

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. 

Closed-loop gas capture (CLGC) offers a viable pathway for the oil and gas sector to reduce flaring, improve sustainability, and minimize environmental impact during midstream upsets. Instead of flaring gas during disruptions, this technology re-injects the gas for short term storage until the issue is resolved. Two recent trials in the Midland Basin demonstrated the feasibility and benefits of closed-loop systems, successfully storing and recovering significant volumes of gas. We will talk through Ovintiv's experience with the regulatory framework, candidate selection, trial results, and our learnings.

The contemporary rod pumping strategy for horizontal wells typically involves placing the pump at or above the Kickoff Point (KOP) to ensure the rod string and downhole pump operate in relatively low dogleg severity conditions. However, in certain types of reservoirs and well conditions, it may be beneficial to place the pump below the KOP. This paper presents a case study from Devon Energy’s Powder River Basin and Delaware Basin Assets, where over the past decade, more than 1200 pumps have been operated below the KOP in over 400 unique wells. The study examines the conditions, methodologies, and outcomes associated with this approach, highlighting its potential advantages, operational insights, and recommended best practices.

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. 

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.

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. 

This paper presents a novel technology designed to address the challenges posed by 100-mesh frac sand (149 microns) in rod pumps, particularly in the Permian Basin. This sand often causes premature pump failures by clogging and damaging key components like the plunger and barrel. The solution extends pump run life and prevents pump sticking.

The multilayer filtering system leverages the concept of completion screens, a long-established technology in the industry, but with a redesigned approach to be integrated in the production cycle where it is compatible for rod pumps and is made to filter sand sizes ranging from 60 to 300 microns, effectively removing particles traditional vortex separators miss. Its innovative design includes eccentric layers with dimples, maximizing open area to nearly 40% across its 288-inch length. The modular setup allows multiple units to be combined in tandem, enhancing filtration capacity while minimizing pressure drop.

Field installations in the Permian Basin have demonstrated significant operational benefits. In one case study, pump run time tripled following the system's implementation, reducing well interventions and equipment replacement. This improvement also lowers the carbon footprint of operations.

Uniquely, using patented Dual-Flow technology, this system integrates with vortex and gas separators for added protection against solids and gas. Constructed with premium materials and a robust assembly process, it offers durability and long-lasting performance for rod pump applications.

Sucker rod pumping can experience reliability challenges when produced fluid contains solids. Any improvement in the ability for a sucker rod pumping system to handle solids would be highly beneficial.
The sucker rod pump is one component of a complex downhole system of components for sucker rod pumping. Other components of this system include a downhole gas separator, a downhole solids separator, a tubing anchor and sucker rods. To maximize the efficiency and performance of a sucker rod pump, all these components must act together harmoniously to effectively feed the pump on demand with liquid that has been gas and solids depleted – unfortunately, achieving this has been particularly challenging. Consequently, the sucker rod pump and sucker rods must still contend with gas and solids.
Solids that travel through a sucker rod pump can be transported or carried to surface only if the average liquid velocity inside the tubing exceeds the solids settling velocity. If the average liquid velocity is less than the solids settling velocity, solids that have travelled through the pump will accumulate inside the tubing. Inevitably, the well will need to be shut down and these accumulated solids can settle on top of the pump and/or around the sucker rods. Upon restarting of the pump, the pump or sucker rods can be seized by the settled solids, forcing a costly workover. This is a common problem for wells that have be hydraulically fracced with sand.
Electrical Submersible Pumps (ESP’s) have employed solids fallback protection tools, which have proven to be effective. They are simple designs; in that they prevent solids from settling in the tubing to the ESP after a shut down. Use of staggered collection chamber weirs and sand screens prevents solids from settling to the ESP. Upon restarting of the ESP, the solids collected are flushed from the chambers with aim to carry the solids to surface and out of the tubing. ESP’s generally are used for higher production rates and often have enough liquid velocity inside the tubing to efficiently carry the solids to surface. Therefore, these existing ESP oriented tools are not designed to permanently contain solids downhole.
For a rod pumping system where the liquid velocity is inadequate for carrying the solids to surface, a permanent “out of harms way” downhole containment solution would be required for a solids fallback prevention tool. Additional design challenges include the need for full tubing internal drift diameter to allow passage of the pump and the fact that there are reciprocating sucker rods inside the tubing.
A new patent pending solids fallback prevention tool has been developed for sucker rod pumping. Tool’s design features include:
• tubing conveyed with no moving parts,
• uses an external to the tubing eccentric solids collection chamber with multiple internal sub-chambers for permanent (large volume) downhole containment of solids until the tubing string is retrieved,
• multiple tools can be run in series above a sucker rod pump,
• has full tubing internal diameter for passage of rod pumps,
• 10,000 psi burst pressure rating, and
• does not interfere with the sucker rod string’s reciprocal motion.
Flow loop testing and field trials have indicated tool’s operability. The design process, prototyping and flow loop testing, and well trials/results will be shared.

As global pressure mounts to reduce methane emissions, the energy industry faces increasingly stringent regulations to detect and repair leaks. In December 2023, the EPA finalized rules, including New Source Performance Standards (NSPS) OOOOb and Emissions Guidelines, mandating facilities to implement robust Leak Detection and Repair (LDAR) programs. These programs can leverage either traditional Optical Gas Imaging (OGI) surveys or advanced Alternative Test Methods (ATMs), such as continuous, real-time monitoring technologies.
This paper highlights the transformative impact of continuous monitoring on emissions detection, quantification, and operational cost efficiency. The monitoring system comprises three integrated components: (i) a network of metal oxide semiconductor sensors to measure methane concentrations and environmental parameters; (ii) a cloud-based platform using physics-based Gaussian Plume Modeling to locate and quantify leaks; and (iii) a web-based dashboard that aggregates emissions data and generates actionable alerts for remedial action.

We compare continuous monitoring to periodic OGI surveys, showcasing its ability to reduce compliance costs and expedite leak repairs at facilities in Texas and Colorado. Beyond LDAR compliance, continuous monitoring has proven effective at detecting operational inefficiencies, such as underperforming flares and burners – issues often missed by traditional methods. Real-world deployments achieved a 60% reduction in emissions within three months and an 80% annual reduction by adhering to NSPS OOOOb thresholds. By generating a continuous emissions dataset, the technology also mitigates compliance risks by time-bounding Super Emitter events. These emissions reductions have significantly lowered the frequency of OGI inspections, delivering substantial multi-year cost savings.

Through case studies in the Permian and Piceance basins, we explore strategies for deploying continuous monitoring across diverse facility designs. Participants will gain insights into best practices for visualizing emissions plumes, conducting investigative analyses, and remotely diagnosing leaks to minimize unnecessary field visits.

Continuous monitoring is not just a compliance tool; it is a strategic advantage for reducing emissions, safeguarding operational integrity, and controlling costs. This technology empowers field operators to take ownership of emissions management, ensuring regulatory alignment while mitigating external scrutiny.

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.

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.

This paper discusses and provides a number of routines codified in practical spreadsheets that production engineers and operating personnel will be able to use to do calculations helpful for visualizing, analyzing and evaluating common production problems/scenarios.  Using these spreadsheets will save time and increase the user’s effectiveness in handling various production challenges and Artificial Lift situations.   Spreadsheets that will be included are as follow:
•    Gas lift Performance for Oil Wells
•    IPRs for Oil Wells: PI/Vogel & Back Pressure
•    SRP Pump Efficiency with Gas Separator Performance
•    Rod Loading: New and Old Goodman
•    Gas Well Multiphase Flow Gradients and Critical Flow Calculated
•    Gas Assist Plunger Design
•    Visualize Pump Dynamometers: Gas and PIP
•    Down Hole SRP Pump Clearance
•    Oil Well Tubing Performance: Inject at any Point in Tubing
•    SRP Pump Spacing
•    Calculate Gas Z Factor
•    Analyze Gas lift P & T Surveys
•    Plunger with Time with Declining IPRs
•    Present Value Profit ()of Staged AL with Declining Production
•    Limitations for Drawdown for Pumps
•    ESP Gas Separator Performance: Drawdown Possible 
•    Gas Well gas lift Performance
•    And others

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.

In sucker rod pumps, work at the surface is translated to the pump downhole using a polished rod and rod string. Three factors reduce the energy available at the pump and decrease the efficiency of the rod pump installation.

The first factor is elasticity. Due to the elastic nature of the rod string and the cyclic motion of the pumping unit, stress waves travel up and down the rod string at the speed of sound, reducing the pump stroke and the efficiency of the downhole pump.
Secondly, viscous friction issued from the produced fluids, which impart a viscous force on the outer diameter of the rod string, further dampen the rod string’s movement.

Lastly, due to the deviation in a well, mechanical friction occurs when the rod string, pump or couplings come into contact with the tubing producing a normal force and drag friction that further slows down the movement of the rod string and reduce pump action.
In the great majority of models available to the industry, viscous friction is not adjusted properly, while mechanical friction is not addressed at all. In this paper, results from Liberty Lift’s proprietary diagnostic model are discussed comparing the mechanical and viscous frictions in different Permian and Bakken wells.

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.

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.

In the Bakken, holes in tubing caused by rod-on-tubing wear are one of the most prevalent mechanisms of downhole failures in rod pumped applications, especially in deep, highly deviated wells. A common mitigation method involves using borided tubing in sections where tubing splits occur, typically near the pump where compressive and buckling forces are highest. Installing borided tubing along the entire length of this section would be favorable, however, this approach is cost-prohibitive and wasteful if wellhead Electromagnetic Interference (EMI) scanning determines that the tubing is unfit for reuse. The objective of this study is to explore economical ways to extend the borided section of tubing by focusing on the accuracy and precision of the data interpreted from EMI scans of the borided tubing. 
The methods in this study involved collaborating with Stress Engineering Services to utilize their Bore Erosion Measurement and Inspection System (BEMIS™) for high resolution mapping of surface wall loss in used borided joints of tubing. With more than 30% wall loss, previous EMI scanning during workovers suggested that these joints of tubing were deemed unusable (red/green grade). Pipe samples were scanned at the wellhead, then separated and transported to a designated location to benchmark their relative thickness readings against the BEMIS™ device measurements.
The results of the scanning study evolved through three phases with increasing scope. In the first phase, two red/green joints were cut into 5-6’ lengths and shipped to Stress Engineering in Houston. The results from this phase did not detect any defects. In the second phase, thirty-eight red/green joints were sent to Houston, resulting in a 97% pass rate. Of the thirty-eight joints scanned, 89% were still in yellow condition, three joints were in blue condition, and only one had a surface defect greater than 30%. The third phase involved scanning 170 joints of red/green tubing, which resulted in a 94% pass rate. Although the distribution of blue tubing increased in the third phase, the gap between the BEMIS™ system and EMI scanning was evident. A portion of the surface features found during the laser scanning were deeper than the boride coating penetration depths, but the 3D rendering showed these areas were isolated and few in quantity. Through three phases of tests, the consistent pass rate allowed ConocoPhillips to confirm that EMI scanning is incompatible with accurately reading true wall loss in borided pipe, often skewing high and leading to significant waste.
In conclusion, the data from this scanning project has given ConocoPhillips the confidence to re-run significant quantities of borided pipe. This approach allows for cost-effective reduction in the purchase of new borided pipe and extends the borided section to combat wear. However, there are still risks associated with re-using borided tubing and limitations inherent to the technology used in this study. Variances in the boride coating and potential wall loss missed by the device remain possibilities. Despite these risks, the accuracy and reliability of the results from this trial provide high confidence that significant cost savings and improved runtime on rod pump wells can be achieved.
This project could not have been done without support and assistance from Stress Engineering personnel Brandon McGinn and Jason Waligura and technical support from Craig Zimmerman with Bluewater Thermal Solutions. 

As an operator, success rests in trying to maximize safety and production while minimizing your cost and downtime. Most operators choose ESP as a first form of lift and will later transition to gas lift, rod pumps, jet lift, etc. Other operators choose to use gas lift or rod lift as a first form of lift.

Each of these forms of lift presents its own rewards and drawbacks. 
For example, overtime, ESP can become oversized for the production requirement of the well. At that point, it can become more economical to install gas lift, rather than resize the ESP pump. Solids, Deviation and corrosive environments are inhibitors for ESPs and rod lift limiting the production potential for the operator.

In other applications, long stroke units or conventional rod pumping offer the best solution with high production rates at a much lower cost than an ESP installation.

In this paper, benefits and challenges for each ESP, Gas Lift and Rod Lift and insights on the best conversion time, will be discussed. 
This paper aims to provide data to help the customer understand how employing the best type of lift at the most appropriate time directly translates to maximizing revenue and production while minimizing losses and failures.

There has been a recent shift in the Permian across unconventional frac targets in the Delaware Basin stacked play, shifting to shallower formations. As a result, Avalon targets are becoming more common. When comparing key scale risk drivers such as brine compositions, mol% CO2 and H2S of the Avalon formation to more traditional targets such as the Wolfcamp and 2nd & 3rd Bone Springs, not only does the Avalon present its own unique scaling challenge, but the commingling of these formations can present much greater scale control and asset integrity challenges. Previous work has highlighted the Avalon formation has a high natural potential for carbonate scale precipitation, which aligns with field history presented here. These unique challenges will play a part in the next wave of formation-based proactive chemical treatment strategies across upstream, midstream and water disposal systems.

Here we present a case of severe carbonate surface scaling from Avalon formation brines, with a focus on how risk changes when adding Avalon production to existing fields. The operator was experiencing calcium carbonate scaling on flowlines, water legs of separators and equalizing lines between water tanks every 3 to 4 months. The operator had to choose between using heater treaters in winter to sell oil or scaling off the heaters. Incumbent service companies had successfully controlled downhole scale but could not control the surface scale issues. 

A total systems analysis including field analysis, scale modeling, 21 produced fluid chemical compatibility experiments run across 11 different scale inhibitors, minimum effective dosage (MED) identification through 119 NACE static/synthetic brine and Dynamic Scale Loop (DSL) testing was performed to identify a solution.

The solution highlighted in this paper resulted in zero facility scale-offs (26 month treatment period to date of publication), use of heater treaters in winter to sell oil, and operational efficiency gains in reduced manpower for cleanouts. Additionally, the ability to now commingle high-risk brines at central tank batteries allowed for the decommission of small satellite facilities previously used to isolate the highest scale risk brines.

The Avalon is not a new target but is projected to become more common in the future. The recent shift has implications to change how, where, and why we treat for carbonate scale in the Delaware Basin. 

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. 

In the Bakken, holes in tubing caused by rod-on-tubing wear are one of the most prevalent mechanisms of downhole failures in rod pumped applications, especially in deep, highly deviated wells. A common mitigation method involves using borided tubing in sections where tubing splits occur, typically near the pump where compressive and buckling forces are highest. Installing borided tubing along the entire length of this section would be favorable, however, this approach is cost-prohibitive and wasteful if wellhead Electromagnetic Interference (EMI) scanning determines that the tubing is unfit for reuse. The objective of this study is to explore economical ways to extend the borided section of tubing by focusing on the accuracy and precision of the data interpreted from EMI scans of the borided tubing. 
The methods in this study involved collaborating with Stress Engineering Services to utilize their Bore Erosion Measurement and Inspection System (BEMIS™) for high resolution mapping of surface wall loss in used borided joints of tubing. With more than 30% wall loss, previous EMI scanning during workovers suggested that these joints of tubing were deemed unusable (red/green grade). Pipe samples were scanned at the wellhead, then separated and transported to a designated location to benchmark their relative thickness readings against the BEMIS™ device measurements.
The results of the scanning study evolved through three phases with increasing scope. In the first phase, two red/green joints were cut into 5-6’ lengths and shipped to Stress Engineering in Houston. The results from this phase did not detect any defects. In the second phase, thirty-eight red/green joints were sent to Houston, resulting in a 97% pass rate. Of the thirty-eight joints scanned, 89% were still in yellow condition, three joints were in blue condition, and only one had a surface defect greater than 30%. The third phase involved scanning 170 joints of red/green tubing, which resulted in a 94% pass rate. Although the distribution of blue tubing increased in the third phase, the gap between the BEMIS™ system and EMI scanning was evident. A portion of the surface features found during the laser scanning were deeper than the boride coating penetration depths, but the 3D rendering showed these areas were isolated and few in quantity. Through three phases of tests, the consistent pass rate allowed ConocoPhillips to confirm that EMI scanning is incompatible with accurately reading true wall loss in borided pipe, often skewing high and leading to significant waste.
In conclusion, the data from this scanning project has given ConocoPhillips the confidence to re-run significant quantities of borided pipe. This approach allows for cost-effective reduction in the purchase of new borided pipe and extends the borided section to combat wear. However, there are still risks associated with re-using borided tubing and limitations inherent to the technology used in this study. Variances in the boride coating and potential wall loss missed by the device remain possibilities. Despite these risks, the accuracy and reliability of the results from this trial provide high confidence that significant cost savings and improved runtime on rod pump wells can be achieved.
This project could not have been done without support and assistance from Stress Engineering personnel Brandon McGinn and Jason Waligura and technical support from Craig Zimmerman with Bluewater Thermal Solutions. 

This case study examines a selection of 2024 Eagle Ford Refrac(s) that necessitated the removal of cemented slim hole casing before the installation of artificial lift. The operational overview includes discussions on logging considerations, tight tolerance cutting options, well control measures, artificial lift selection, and production outcomes.

Rod rotators are designed to distribute wear evenly around the circumference of sucker rods. However, in practice, rods, guides, and couplings frequently develop flat spots on one side, indicating uneven rotation. The industry has not adequately studied the implications of this condition on the entire pumping system. Instead, solutions have focused on implementing higher torque rotators or positive engagement mechanisms to force rod rotation. These solutions are not driven by comprehensive data and outcomes, but by the assumption that when it is rotating at surface, everything must be fine downhole.

This paper applies to wells where:
• Rods, couplings, or rod guides wear flat on one or more sides
• Rotators appear functional at surface but uneven wear patterns persist
• Excessive torque is present on the rods (i.e. during a workover or re-spacing)

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.

Gas lift optimization enhances production efficiency by maximizing uplift and reducing operational costs by addressing common issues such as over-injection. Numerous majors and others admit that over injecting is a serious problem affecting produced oil rates and 30-50% overuse of injection gas. Key steps include gathering well parameters, monitoring casing and tubing pressures with data loggers, and measuring static bottom hole pressure (SBHP) to assess true well conditions. This process integrates field data collection, real-time monitoring, and advanced analytical tools. Nodal analysis is used to evaluate the flow performance of the well by analyzing pressure and flow relationships between the reservoir, wellbore, and surface facilities, helping to identify bottlenecks and optimize production. Additionally, dynamic well simulation models the real-time behavior of the well under varying operating conditions, enabling operators to predict future performance, optimize production strategies, and detect potential issues before they occur.

This paper explores how operators can effectively increase well production, enhance recovery, and reduce operational costs by ensuring that each well operates at peak efficiency. The integration of field data, real-time monitoring, and nodal analysis is fundamental to optimizing gas lift systems and realizing their full potential in maximizing uplift.

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.

This paper explores the application of boron-carbide (B4C) treated rod pump parts in sucker rod pump (SRP) wells, as a solution to the challenges posed by modern-day drilling and completions practices. These practices often result in sandy, corrosive, and highly deviated wellbores, leading to increased wear, frequent interventions, and downtime in rod lift systems. The paper highlights the improved run times a large producer in the Permian Basin was able to achieve by utilizing boron-carbide treated components in their sucker rod pumped wells. The evaluation aimed to assess the run time performance of a sample of 30 wells, focusing on wells with prior run-time and failure mode history established. The results showed improved run times in many of the wells evaluated and highlights the components and configurations used. The paper further discusses the B4C treatment technology the potential in enhancing the performance and longevity of various artificial lift equipment.

As wells decline and available acreage for new wells lessens in the Permian Basin, it becomes increasingly important that operators capitalize on existing wells and maximize reserves. Scaling is a known issue in the basin, and this paper will address a likely solution. Acid treatments have proven to be effective across different levels, and when diverter is additionally pumped, the effectiveness has potential to increase significantly. 

The operator has taken the approach of pumping acid diverter jobs during workover when there is significant concern of blockages due to acid dissolvable scaling in the wellbore. Partnering up with an acid company, five acid diverter jobs have successfully been pumped across five different horizontals in Howard County, TX. These horizontals range across four different benches – Jo Mill, Lower Spraberry, Leonard, and Wolfcamp A. The Jo Mill well additionally had a cleanout across 84% of its lateral prior to pumping the acid diverter job, resulting this well yielding the highest oil uplift at 458% when comparing 30-day averages pre- and post-workover. The average of the other four jobs has oil uplift sitting at 189% with the same 30-day comparisons. Across the five jobs, four were during an ESP swap and one was during a RP workover. 

Other jobs pumped have insufficient days post return to production or faced significant curtailment post-workover, making it difficult to be considered in the study. Based on results thus far, the acid diverter program has been considered a success and candidates will continue to be added as seen necessary by respective production engineer.

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.

The challenges frequently associated with Endless Rod applications primarily arise from corrosion, particularly mechanical corrosion where the inhibitor film is removed, leading to inadequate protection and allowing corrosion to develop. Barrier coatings can protect the rod from corrosion, preventing the formation of stress risers on the rod surface that, under cyclic loading, can easily propagate across the rod body until there is insufficient section to sustain the load, causing it to fail. Industry studies have demonstrated that certain coatings reduce rod/tubing contact friction, resulting in lower axial loads in rod pump applications. Furthermore, reduced friction has the potential to decrease tubing wear in more aggressive environments.

KeBond Technology incorporates an extruded bonded composite design derived from an engineered thermoplastic (Polyketone) outer coating that is resistant to aggressive oilfield fluids and can withstand elevated temperatures. The bonded high-strength design enables servicing at high loads and associated depths, significantly expanding the historical operating envelope, allowing deployment in deeper unconventional rod pumping applications. We will present performance data highlighting axial load reductions, runtime improvements, and other successes identified along the way. The dataset highlighted was generated from a Permian case study with KeBond Technology installed in Oxy’s unconventional wells with extremely deviated wellbores, high production requirments, highly corrosive fluid properties, and challenging operational conditions. 

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.