2026 Southwestern Petroleum Short Course Schedule

As the global oil industry increasingly relies on unconventional and marginal assets, operators face a complex array of production challenges. These include high viscosity fluids, significant solid content, gas interference, and the need for deployment in deviated wellbores. Traditional lift methods, such as beam pumping and conventional rotary electric submersible pumps (ESPs), often reach their mechanical or economic limits under these conditions. This paper introduces a next-generation Linear Electric Submersible Pump (LESP) system that integrates advanced permanent magnet linear motor technology with intelligent control algorithms to address these specific downhole complexities.

The discussion focuses on the system's unique mechanical architecture, including a modular motor design and a plug-in power cable connection that significantly reduces rig time and maintenance complexity. Furthermore, the paper details specific proprietary software algorithms designed to manage "stuck" conditions and gas slugs autonomously. These include "Jogging" and "Swing" modes for freeing wedged pumps and gas plug removal logic that prevents underload faults. By combining robust hardware options—such as magnetic flow cleaners for paraffin control—with smart surface control, this technology offers a comprehensive solution for extending run life and optimizing production in challenging well environments.

Production operations have traditionally relied on routine well checks and daily to weekly trips to verify well performance and status. While this ensures coverage, it consumes significant field time, fuel, and labor on wells that are already performing as expected.
With the vision to transition from a schedule-based to exception-based well management and with the goal to empower operators to focus their expertise on wells that truly needed attention, while letting data and AI-ML powered automation handle wells that are running smoothly, a small footprint digital ecosystem was deployed on a remote producing facility in West Texas. This facility consisted in six producing wells, one injection well and their respective surface facilities.
The digital ecosystem is designed to enable pump-by-exception operations, and it includes smart controllers and sensors on each well, providing real-time production and equipment data; a centralized analytics platform powered by AI/ML algorithms that identify anomalies, pump-off events, or mechanical issues automatically; automated alerts and dashboards that highlight wells needing attention and suppress noise from normal operations; and mobile tools that allowing field technicians to view pump cards, alarms, history and control wells from anywhere.
This enabled a shift from “checking every well every day” to “checking the wells that need it today.”
This paper shows how next generation technologies that use , small footprint and quick deployment micro controllers powered by AI and ML algorithms can boost operational efficiencies and maximize well’s profitability in all types of wells, including those wells with marginal economics.

The Resin-in-Cement (RIC) system is a hybrid technology that merges thermosetting epoxy resin emulsions with traditional Portland cement systems, creating a stable emulsion for superior wellbore sealing and bond-adhesion in oil and gas wells. It solves key integrity issues like micro-annuli , and debonding in harsh downhole conditions. Conventional resin-cement mixes often fail due to density-driven separation, causing incompatibility and a non-homogeneous slurry. RIC counters this with proprietary chemistry of dry and liquid additives, ensuring uniform resin dispersion, additive compatibility, and strong adhesion to casing and formations.
RIC excels over traditional cement in flexibility and durability. Portland cement is economical but rigid—high Young's modulus, low toughness, moderate bonds, and permeable set cement sheath—leading to stress-induced cracks. RIC cuts Young's modulus while boosting flexibility against temperature, pressure, and mechanical loads. The RIC system shows an increase in modulus of toughness against conventional cement blends, absorbing energy to resist fracture. In cyclic pressure wells such as injection wells, it adapts to expansions/contractions, preventing fatigue cracks and prolonging life. In mobile formations such as highly mobile salts, lower stiffness allows elastic deformation, easing shear stress and avoiding debonding or isolation failures. Shear bonding to casing and formation shows formidable adhesion, curbing migration; permeability falls, compressive strength rises, fluid loss drops, and free fluid is non-existent. Typical temperature profile of this system can range from Surface ambient to 200oF+, and density of the systems can be run from a conventional 10 ppg up to a heavyweight 18 ppg slurry.
Economically, RIC delivers resin's premium traits—impermeability, resilience—through bulk cement, using 15-30% resin to cut costs dramatically versus pure resin. This system is ideal for P&A, HPHT wells, and injection applications.
Ultimately, RIC transforms zonal isolation: cement strength plus resin agility, affordably, for enduring well integrity.

Sucker rod pumping for horizontal wells has advanced considerably over the past few years. Advancements in sucker rod pump technologies and bottomhole assembly (BHA) components/configurations have allowed for more efficient downhole gas separation and greater production drawdowns. The unintended consequence has been an escalation of solids in the produced fluids with increased failure frequencies.
Solids control while sucker rod pumping horizontal wells is risky, complex and tricky, especially for when lowering a pump into the curve or using Extended Dip Tube systems in the curve. Extended Dip Tube systems position the pump in the vertical or near vertical and place the gas separator deeper in the curve.
Lab and field studies confirm that gassy-slug flow moves solids as migrating dunes/beds. These dunes accumulate (over weeks and months during steady production) in the lower portion of the wellbore’s curve section where gravity starts limiting dune migration. The risk is any surge in gas rate, flow interruption, or shutdown instantly mobilizes the accumulation of solids as high-concentration solids slugs—overwhelming BHA’s and causing stuck/failed pumps.
A comprehensive systems solution was essential: advanced BHA’s paired with targeted operating practices to defeat solids slugging. The following solution has proved effective:
1. Apply operational practices to control and limit formation high concentration solids slugs:
a. Invoke a preventative maintenance casing flush program, especially after shutdowns
b. Employ operational practices that avoid gas rate surging and spiking
c. Employ rod pump controller logic that reduces slug flows
2. Design the BHA with technologies and configurations that limit slug flows.
3. Design the BHA with technologies that firstly “bust up” solids slugs and then separate solids for containment out of harm’s way. This includes a slug busting solids separator that operates at high inclinations (such as 90 degrees).
4. Design the pump to efficient convey solids through itself.
Results from implementation of this comprehensive approach with innovative solids control and separation technologies will be shared and discussed.

1. OBJECTIVES/SCOPE: 
Horizontal drilling is an essential technology for exploiting unconventional resources. However, wellbores often include zones with high Dog Leg Severity (DLS), which can limit the installation of Electrical Submersible Pumping (ESP) systems at the deepest possible setting depth. Placing the ESP as deep as possible is critical to maximizing recovery and cash flow. This work highlights the successful application of curve ESP systems in Permian Basin wells with DLS values of 17°/100 ft, and discusses both the challenges encountered and the potential benefits of this technology.

2. METHODS PROCEDURES, PROCESS: 
The industry standard tolerance for deviation is approximately 6° per 100 ft for a conventional ESP system to reliably pass through the curved section of a wellbore. In this study, deviation surveys from several wells were carefully evaluated, and stress analysis was performed to assess mechanical stresses and the potential risk of equipment failure when navigating high-DLS zones. A group of wells with elevated DLS values was selected as pilot candidates for deployment of the new curve ESP system. Well models were developed, and sensitivity analyses were conducted to evaluate the impact of pump setting depth on production performance. The ESP systems were subsequently designed and installed, with production data collected and operating parameters closely monitored.

3. RESULTS, OBSERVATIONS, CONCLUSIONS: 
Based on stress analysis simulations, a standard ESP system wouldn’t be able to pass through zones with high DLS. In the first install a conventional ESP was installed and the system setting depth was shallow. The unit was subsequently pulled and replaced with a curve ESP system, allowing for a deeper setting depth while passing through zones with DLS of 12°/100 ft. The pump setting depth was increased from 6,660 ft to 7,800 ft—an additional 1,100 ft. As a result, production increased by 75%, adding 550 BOPD and generating approximately USD 1 million in the first 30 days of operation. The unit has since demonstrated stable operating trends with minimal X- and Y-axis vibration, indicating limited mechanical wear.
In a separate case study, two curve ESP systems were deployed in a well with DLS of 17°/100 ft consecutively. The first unit achieved a run life of 802 days, while the second operated for 551 days, further demonstrating the reliability and field-proven performance of this technology.

4. The standardized industry practice for deploying ESP systems in wells with high DLS is to avoid traversing the curved section by setting the pump at a shallower depth. Alternatively, operators may attempt to pass through by reducing pump length, which typically requires decreasing the number of stages, thus limiting lift capacity and selecting smaller motors, which reduces available power. Both approaches compromise system performance and production potential. The curve ESP system provides a viable solution to these mechanical and hydraulic limitations, enabling reliable installation at greater depths and unlocking the full production capacity.
In short, the post is important because it demonstrates Baker Hughes’ thought leadership, technical expertise, and investment in the next generation of engineers, while also reinforcing their role in delivering measurable value to the energy industry.

Objective/Scope:
Presentation will review design, installation, and results of recent novel artificial lift pilot in the DJ Basin.
GALLOP (Gas Assisted Liquid Lift Oscillating Pressure) is a new variant of gas-lift, designed to unload
horizontal wells from the lateral. Unloading from the lateral can add years to a well’s life by preventing
heel loading when reservoir pressure drops too low to keep a well unloaded between the lateral and the
end of tubing.
Methods/Procedures/Process:
GALLOP system pilot was meticulously planned over multiple years prior to execution, in close collaboration with Scott Wilson (patent holder), Well Master / VaultPC (manufacturers), PETEX, and internal Oxy teams. Detailed system modelling was performed prior to install to ensure success (GAP
Transient, CFD modelling of downhole valve assembly, etc). Custom wellhead and downhole equipment were designed and manufactured to meet project scope. Candidate well was identified (low reservoirpressure well with existing gas lift infrastructure). GALLOP was successfully installed (workover / surface construction) following extensive planning with the Well Intervention and Surface Construction teams.

Results/Observations/Conclusions:
GALLOP pilot has successfully extended the life of the candidate well, which otherwise would have beena P&A candidate. Initial production with GALLOP proved that the system is capable of moving the target outflow – 20 BLPD flowrate for the pilot well, and modeling indicates the system is capable of producing rates up to ~40 BLPD if inflow will permit. Pilot well rates have fallen off faster than expected due to productivity being below expectation (well-quality inflow issue as opposed to artificial lift outflow issue). Even with inflow-related drop in production, GALLOP system has proven that it can stably produce rates as low as ~3 BLPD from the lateral, and potentially lower. Due to low rate nature of late life production,
GALLOP system will be most economically attractive on wells with existing gas lift infrastructure, and is potentially broadly applicable across US Onshore assets.

Novel/Additive Information:
GALLOP is a new type of gas lift that utilizes concentric tubing to produce from the lateral. Fluid enters into the tubing system through a downhole check valve during the ‘fill’ phase. Injection is intermittently applied down the annulus between the concentric tubing strings, which closes the check valve and lifts fluid that has entered the tubing system to surface. The Oxy pilot in the DJ Basin was installed and kicked off in early 2022, and is the first and only pilot of this system in industry to date. A review of the system with the wider SPE audience could unlock late life production from wells that would otherwise be candidates only for P&A.

Sand production has been recognized by the oil and gas industry as one of the most significant challenges affecting the operation, efficiency, and longevity of unconventional rod-pumped wells. As sand and other solid particles migrate into the pump assembly, they create abrasive conditions that accelerate wear on critical components. This abrasion not only reduces pump efficiency but also increases the risk of premature equipment failure, unplanned downtime, and costly maintenance interventions. 

Given these challenges, operators have expressed the need for sand fallback protection for wells produced on Sucker Rod Pump (SRP) lift.  The industry has responded to this challenge by developing tools that trap sand above the rod pump during a shutdown state. These tools have proven to reduce the total cost of operating a rod pump system by reducing pump plugging and wear. Rod pump sand management tools have improved economics by increasing run life and reducing operational costs.

This paper provides an in-depth look at a commercially available SRP sand management tool. PetroQuip has shared the operating mechanism and operational benefits of the Sand Maze SRP. The operator will share a seven-well study that evaluates the use of this tool on unconventional wells within the Midland Basin.  The operator’s data shows that SRP sand management tools extend run life and reduce the need to pull tubing on standard rod pump failures.

Effective back-check performance is critical in gas-lift systems to prevent reverse flow during injection shut-in. As well-integrity requirements strengthen, operators require barrier solutions that do not impede unloading efficiency or gas-lift performance.

This paper presents a Patented, barrier-qualified 1-inch back-check system engineered to maximize flow capacity while delivering reliable reverse flow isolation. The design increases flow area and positions the check mechanism outside the primary flow stream during injection, protecting it from solids and erosive flow while maintaining low pressure drop and high injection efficiency.

Performance verification using CFD-based flow path optimization, HPHT qualification testing, erosion and solids-tolerance testing, extended cycling and flow endurance trials, and successful field runs. Achieved all acceptance criteria for seal integrity, pressure-drop performance, and actuation reliability.

This technology builds on the proven 1.500-inch platform originally developed for wireline retrievable applications and further development with double-barrier mandrel systems, which established the benchmark for redundant well-integrity protection in gas-lift completions. The 1-inch design utilizes that barrier-qualified back-check technology, delivering high flow efficiency and reliable isolation performance without reliance on a dual-valve mandrel configuration.

This development sets a new standard for flow-efficient, barrier-qualified gas-lift performance in modern completions.

Frac hits in unconventional developments often cause persistent liquid loading, increased flowing pressures, and reduced lift efficiency in offset gas-lift wells. These effects are largely driven by trapped frac fluids, elevated water saturation, and unstable multiphase flow, all of which delay production recovery. This paper evaluates the use of targeted surfactant treatments to accelerate post–frac-hit cleanup and restore gas-lift performance.

Laboratory screening—including foam height, foam break test, and emulsion tendency test on fluid samples collected from candidate wells. The results confirmed the efficacy of the surfactant and showed no adverse effects on oil emulsion or water quality. The surfactant was then tested for compatibility with the combination corrosion/scale inhibitor to verify no adverse effects. Field applications in impacted gas-lift wells showed improved unloading, lower flowing bottomhole pressures, and faster stabilization compared to conventional lift optimization alone. Several wells achieved earlier return to pre-hit production trends and incremental oil uplift.

Results demonstrate that surfactant-assisted recovery provides a low-cost, low-intervention method to mitigate frac-hit impacts and enhance gas-lift effectiveness in tightly spaced unconventional developments.

The Appalachian Basin, specifically the Marcellus and Utica shales, are known for their initial low water-to-gas ratios and appealing high gas rates.  This, however, leaves operators with establishing phase of life flow paths as the well declines.  Installing production tubing too early leaves the asset producing at a constrained rate due to frictional losses downhole.  These constraints have been observed to be as much as 30% - 40% depending on flowing conditions.  Installing production tubing too late; leaves the asset vulnerable to slug flow and deviation from natural decline impacting cash flows.  Utilizing a Production Engineer to run nodal analysis to understand exact timing of tubing install can be unrealistic and logistically challenging for procuring material and resources for large-scale tubing programs.    
  
Through engineering efforts along with automation of field devices, an evolution of previously deployed plunger lift optimization efforts traditionally leveraged for optimization of depleted wells and assets resulted in the successful implementation of a unique artificial lift technique called Plunger Assisted Annulus Flow (PAAF).  PAAF is targeted to be installed in combination with the installation of production tubing which is approximately 30% above the calculated Turner critical rate in 5-1/2” production casing.  PAAF allows for bottom hole pressure to be drawn down until the full well stream can be diverted up tubing without any constraints.  This is achieved by simultaneously flowing the annulus and tubing while cycling a continuous-style plunger in the tubing.  Each plunger cycle is initiated when flow rates drop below annulus critical rate and is needed to help evacuate fluid hold up that starts to occur in the annulus.  

PAAF allows Production Engineers to focus on evolving their business, provide a smooth decline to aid in more accurate forecast generation, and support more predictable cashflows in volatile market conditions.  
 

This case study presents a comprehensive evaluation of how the integration of advanced electric submersible pump (ESP) technologies, efficient gas handling devices, high-efficiency induction motors, and continuous real-time digital surveillance can drive both operational efficiency and sustainability in upstream oil production. The focus is on 22 wells operated by SOGC, Inc. in the Williston Basin, USA, between June 2024 and May 2025. The primary objective of this study is to illustrate how these technological advancements, combined with proactive remote operations, can minimize downtime, extend ESP run life, and significantly reduce the carbon footprint associated with oilfield operations. 
The methodology involved a comparative analysis of production data and downtime before and after the digital service center assumed full control of remote interventions for the operator. The study meticulously tracked ESP performance indicators, such as mean time to failure (MTTF), average run life, and uptime, to assess the impact of digitalization and proactive interventions. Environmental impact was quantified by translating operational improvements into tons of Co2 emissions reductions, directly linked to the prevention of field trips and workovers. The analysis also considered the broader implications of these operational changes on safety and labor efficiency, including the reduction of nonessential field visits and the prevention of potential ESP failures. 
Results from the study demonstrate a substantial improvement in ESP performance and a marked reduction in environmental impact. The adoption of high-performance ESPs and digital operations led to a mean time to failure of 249 days, a significant increase in average run life from 225 days (with standard ESPs) to over 249 days, and ESP uptime consistently exceeding 90%. Real-time surveillance and remote interventions played a critical role in achieving these outcomes by enabling early identification of critical events and minimizing downtime. The adoption of advanced ESP technology and digital operations led to a substantial reduction in carbon footprint by 6% per well per year (approximately 194 TCo2e), achieved through reduced field trips, fewer workovers, and remote interventions that saved over 18,000 km (over 11,322 miles) in driving, reducing emissions by about 5 TCo2e. Three critical remote interventions prevented ESP failures, eliminating additional workover jobs and further reducing emissions by almost 1 TCo2e, for a total reduction of approximately 6 TCo2e. 
This case study offers novel, real-world data on the environmental and operational benefits of enhancing ESP survivability and leveraging digital solutions, an area not previously addressed in the existing literature. By minimizing production loss and nonessential field trips, the operator not only improved operational efficiency but also made a positive impact on the environment. The findings provide actionable insights for practicing engineers seeking to improve both operational and environmental performance in oilfield operations. This work demonstrates that the strategic deployment of advanced ESP technology, combined with digital optimization and proactive remote management, can serve as a model for sustainable practices in the oil and gas industry.

With an estimated 46,000 producing horizontal wells in the Permian Basin currently yielding less than 200 BOPD, operators are facing a growing inventory of declining wells. This base production decline must be continually offset by new well additions—an increasingly costly and resource-intensive strategy. As a result, the industry is experiencing a resurgence of acidizing treatments in horizontal wells as a means to restore productivity and extend asset life.

Transitioning from traditional acid treatments applied to short vertical pay zones to long horizontal laterals introduces new complexities in treatment design and execution. Achieving consistent production uplift and sustained well performance requires innovation across multiple technical dimensions. Advances have emerged in candidate selection methodologies, surfactant chemistry, diversion techniques, equipment design, stage optimization, and scale management practices following acid stimulation.

This paper presents the latest strategies and innovations driving the effective revitalization of horizontal wells through acid stimulation. Emphasis is placed on integrating modern chemical systems, operational best practices, and field-proven designs to maximize production gains while maintaining long-term well integrity.

1. OBJECTIVES/SCOPE
Modern wellhead inspection systems depend largely on operators interpreting electromagnetic signal graphs displayed on their laptops. Because this task demands both extensive training and unwavering focus, results can vary or be inconsistent due to the subjective nature of human judgment.
This work seeks to present an approach based on intelligent algorithms to reduce such dependency, standardize the results and improve the reliability of the scanning process of production pipes and rods directly at the wellhead.
The current technical and regulatory framework includes the API 5CT standards, with guidelines applicable to EMI (Electromagnetic Inspection). Although these inspections are derived from standards designed for workshops or plants, their adaptation to the field environment presents additional challenges due to the variability of conditions for example the speed of the pipe pulling is not controlled by the EMI inspector, but depends on the capacity of the rig, well conditions and safety concerns on everyday operations of workover rigs.
After completing the testing period in March 2025, the results have been highly satisfactory. To this date ending 2025 approximately 50,000 tubing joints between 2 3/8 and 4 1/2", have been scanned using the algorithm, no errors attributable to the implemented algorithm have been identified. In addition to fulfilling its main objective – to support and improve the interpretation of EMI signals – there has been evidence of significant standardization of results between operators with different levels of technical expertise.
The use of intelligent algorithms has been well received by users, to the point that some operators have begun to require the integration of this type of system in scanning processes. This trend has also aroused the interest of service companies that seek to integrate technologies based on artificial intelligence into their services, as a tool to improve the quality of the results delivered to their clients.
The software significantly reduces the time required to train new operators, allowing them to generate reliable results in less time. The algorithm incorporates a sequence of steps which allow large volumes of data to be evaluated and interpreted in real time.
Programmed logic automates technical decisions based on set parameters and historical defect patterns. Studies show the system's results match or surpass human expert accuracy. This automation is designed to boost operator efficiency and reduce errors, not eliminate human input.

3. RESULTS, OBSERVATIONS AND CONCLUSIONS
The implemented software has proven to be an effective and reliable tool in real field conditions. It can be installed on any Windows operating system and is currently compatible with EMI inspection platforms for tubing and rods.
Among its main functionalities are:
• Elimination of interference and noise typical of the operating environment.
• Real-time processing of electromagnetic signals from MFL (Magnetic Flux Leakage) and MFD (Magnetic Field Detection) systems.
• Generation of automatic classifications based on technical criteria defined by regulations.
The algorithm significantly enhances signal amplitude quality, based on the interplay between tubular velocity, the electromagnetic field within the coil, and the gains applied to digitized signals. This advancement enables more precise classification of tubulars, including in areas that are typically challenging, such as near coupling where signal distortion frequently occurs.

4. NOVEL/ADDITIONAL INFORMATION
This technology represents an evolution in wellhead inspection processes, integrating intelligent analysis tools to reduce human error and standardize results. The algorithm allows for precise filtering and processing of signals, improving the interpretation of defects in production tubulars.
Wellhead scanning is a technically and economically efficient alternative that eliminates the need to transport components to inspection plants, reduces operating time, minimizes environmental impacts from cleaning agents, and lowers costs related to tubular replacement and inventory.
This innovation has significantly enhanced operational efficiency and delivered substantial economic advantages to workover operations.

This study analyzes a comprehensive dataset of mid-to-late life Electric Submersible Pump (ESP) designs deployed in Delaware Basin wells to identify the most effective configurations for high Gas Volume Fraction (GVF) environments. Downhole GVFs are normalized across wells, and ESP designs are categorized by pump stage count, gas-handling pump type, gas separator configuration, and casing size. Cumulative distribution functions (CDFs) are used to evaluate statistical performance differences among these design groups, highlighting which configurations best accommodate elevated GVF conditions. Additionally, run life statistics are assessed using CDFs to determine the optimal ESP design for each installation scenario. Final, relative recommendations are made to balance reliability and produce at maximized GVFs for multiple well conditions.

As rod lift systems are extended to greater depths and tasked with higher production rates, operators face increasing complexity in maintaining reliability and cost-effectiveness. Elevated loads, deeper pump landings, and aggressive environments introduce compounded risks, including rod and tubing wear, bending fatigue failures, corrosion fatigue, and connection reliability issues, among others. Simultaneously, business strategies demand earlier conversion to rod lift and compatibility both with large size (long stroke) and mid-size pumping units such as 912 and 640 to deliver more production and deeper.
To address these challenges, a structured development program was initiated in 2016, aimed at expanding the operational envelope of rod lift through a portfolio of engineered solutions. This effort progressed from proof-of-concept designs to full integration by 2024, incorporating advanced materials, optimized geometries, finishing technologies and string design optimization to mitigate the challenges and enhance system performance.
Field validation across diverse environments demonstrated measurable improvements in runtime, reliability, and production capacity. The 1K @ 10K framework reflects a systematic approach to design and integration, enabling rod lift systems to meet the demands of modern high-value wells while maintaining operational integrity.

Examine the structured development and implementation of the Quality Assurance and Quality Control (QAQC) Team at Oxy, emphasizing the team's strategic impact on reducing operational expenditures (OPEX). The QAQC team delivers targeted training in sucker rod maintenance and handling to more than 100 workover crews, conducts systematic audits of pump shops across Oxy's U.S. assets, and actively manages warranty claims to recover costs from equipment failures. The team is also responsible for managing the region's most advanced reclamation programs for production tubing and sucker rods in the Permian Basin. Each month, over 800,000 feet of tubing are systematically processed through three centralized hubs, utilizing rigorous inspection and quality assurance protocols to ensure operational integrity and maximize asset recovery.

Serving as a crucial link between field operations and suppliers, the team's responsibilities include performing detailed root cause analyses of failures, organizing independent laboratory testing and assessments, and working closely with Oxy's Supply Chain Management (SCM) to strengthen contract terms. These efforts help limit Oxy's risk exposure from poor-quality materials and manufacturing flaws.

Insights gained from failure analyses often lead to the creation of Standard Operating Procedures (SOPs) that are embedded into commercial agreements, enabling enforceable quality standards. The QAQC team also leverages warranty clauses to recover funds, ensuring that wells with working interest partners maintain transparent and accurate financial records. Ensuring adherence to both industry standards and Oxy-specific requirements at tubing reclamation facilities is a primary mandate for the QAQC team. The implementation and oversight of Oxy's proprietary inspection protocols at these plants have resulted in substantial annual cost savings, amounting to millions of dollars for the organization. Routine pump shop audits at each site enable ongoing vendor performance monitoring, supporting the identification and resolution of recurring issues.

This paper explores how the QAQC team's audit processes have transformed business operations and supplier qualification criteria. By presenting real-world case studies and detailed failure analysis reports, we demonstrate how these practices have enhanced Oxy's artificial lift systems and offer practical recommendations for implementing similar value-driven strategies in your own organization.
 

The efficient management of gas lift systems is pivotal in minimizing operational costs and maximizing production for a large majority of unconventional wells. By leveraging automated workflows to efficiently build and tune physics based nodal analysis models, operators can optimize well performance and gas injection rates thus reducing operational expenses. A cornerstone of effective gas lift optimization is the seamless integration of real-time data with physics-based models. Automated assisted workflows streamline this process which enables continuous optimization of gas lift injection rates to compensate for changing production rates, gas liquid ratios, and reservoir pressures.

The author emphasizes the value of having an evergreen tuned well model to optimize every gas lifted well. Optimization can be realized in some cases by increasing or decreasing gas injection, as the model often shows over injection can reduce production. The challenges in realizing the value from a physics based well model for every well include staff time to build and maintain the models, time to tune the models, and time to make gas injection rate adjustments. The gas lift optimization workflow presented requires significantly reduced engineering staff time by letting automated processes continuously complete the majority of the workflow.

Automated Model Building
In order to efficiently build physics based well models for hundreds of wells, a unique data loader was developed through a collaborative effort between various teams. This process merges wellbore, completion, and production data from multiple databases into a centralized staging table used to create the model. Any missing model data such as fluid gravities, reservoir pressures, and pipe roughness factors are manually entered by the engineer to complete the well model generation. This workflow dramatically reduced the time required by engineering staff to build well models. In addition to building the initial model, the data loader automatically updates the model with any changes made to a well following workover activities.

Automatic Model Tuning
To keep the model evergreen, software automatically tunes the model using every well test. The Inflow performance relationship (IPR) and Vertical lift performance (VLP) variables are derived from the nodal well model, while Injection Rate, Tubing Head Pressure (THP), Casing Head Pressure (CHP), Water Cut (%) and GOR are extracted from production test data to construct an updated gas lift well performance curve. This performance curve facilitates the gas lift optimization process by ascertaining whether there is an under- or over-injection.

Autonomous Control Logic (ACL) through Enterprise
ACL, which was created through a collaborative effort of subject matter experts and computer programmers, was designed to use the tuned model’s performance curve to determine optimum injection rates for each well. The ACL accomplishes this by running solutions at rates above and below current injection rates and solving for total fluid rates and oil production. Based on these results, and parameters set by the Operator within the ACL control interface, the system automatically suggests an optimum injection rate. The frequency of optimization runs can be easily defined by the Operator but is typically done every 4 hrs as the ACL continuously adjusts to optimize the gas injection rate.

Results, Observations, Conclusions
As a result of this automated workflow, Operators can much more efficiently have all gas lift wells modeled, automatically tuned, and automatically optimized for production and associated gas injection rates. As a result of applying this workflow, Operators can realize either reductions in gas injection rates with no loss in production or incremental oil production associated with incremental gas injection.

In conclusion, the deployment of this highly automated workflow can create significant value for Operators by allowing them to efficiently utilize physics-based models to continuously optimize their gas lifted wells. Future improvements include enabling full ACL logic to continuously adjust gas injection rates via automated control valves without human intervention.

Jet lift systems have earned a strong reputation as an effective artificial lift method for unconventional oil well production across the most prolific hydrocarbon-producing regions in the United States of America. In prolific reservoirs such as the Permian Basin, Eagle Ford, and Bakken, operators have successfully utilized jet lift as the primary lifting method for challenging oil wells. Additionally, operators in the Eagle Ford Basin have consistently employed jet lift as the main production technique for their wells.

Like any other artificial lift system used in unconventional oil well production, jet lift has its strengths and weaknesses. Its most notable advantage over other powered production methods is its ability to handle a wide range of flow rates, from 10 barrels of fluid per day (bfpd) up to 5,000 bfpd, using the same jet pump size. The jet pump “free pump” feature, which allows the operator to hydraulically retrieve and reinstall the jet pump without the need for workover or wireline using only reverse power fluid circulation; and is also widely recognized as critically important in the artificial lift selection matrix.

The most common problems that need to be addressed during the implementation of jet lift systems typically include: uncertainty regarding the placement of the jet pump cavity or the optimal depth for the deviation seating point; determining the right moment to start producing the well using the jet pump after the early flowing-well production stage; identifying the most effective initial nozzle-throat combination; selecting the most cost-effective surface equipment capacity (horsepower) for the user; managing the well's transient behavior by resizing the jet pump nozzle-throat combination; preventing cavitation in the jet pump during both early and late production stages; and, finally, developing a properly designed strategy to convert from jet lift to rod lift.

This paper provides a clear discussion of the issues and challenges associated with jet lift operations, along with field-proven solutions successfully implemented in the Eagle Ford formation across approximately 150 jet-pumped wells.
 

Objective/Scope
Optimizing production across unconventional assets requires rapid identification of well performance anomalies, efficient artificial lift optimization, and scalable evaluation of intervention opportunities such as acid jobs and lift-system transitions. Traditional surveillance workflows struggle to keep pace with high well counts, changing lift designs, and evolving reservoir conditions. This pilot study focuses on a digital production optimization system deployed on 441 wells equipped with Gas Lift and ESPs in Permian basin. The scope includes daily surveillance for production optimization, evaluation of artificial-lift transition scenarios, defining surface injection-pressure management criteria for multi-well gas-lift systems, and systematically assessing acid-job performance to determine optimal implementation conditions.

Methodology
A web-based production optimization platform, integrating comprehensive physics-based modeling with advanced AI-driven analytics, was used to continuously process historical and daily production data. The system employs a novel transient reservoir pressure estimation based on dynamic drainage volume computation with multiphase well modeling to characterize reservoir inflow performance, artificial-lift behavior, and deviations from design operating envelopes. Daily computations include productivity-index forecasting, bottomhole pressure tracking, and opportunity identification for lift adjustments (e.g., gas-lift injection tuning, ESP frequency optimization). Statistical analysis of historical acid-job interventions was conducted to correlate treatment success with inflow performance constraints identified and the chemical composition of produced fluids, particularly indicators of solids-related deposition risk. Multi-well gas lift modeling was used to evaluate injection-pressure requirements across groups of wells sharing same compressors and determine suitable transitions between high-pressure gas lift (HPGL) and low-pressure gas lift (LPGL) across shared facilities.

Case Study Results and Observations
Implementation of the platform’s daily optimization recommendations yielded a measurable and repeatable impact across the 441-well asset. Those wells in which recommendations were adopted delivered an average of 6% incremental oil production, primarily driven by optimized gas-lift injection rates and ESP operating frequencies. Concurrently, the field achieved over 20% reduction in average gas-lift usage, reflecting more efficient allocation of lift gas. The acid-job evaluation workflow identified the most favorable PI opportunities by tracking the PI trends associated to inflow issues for treatment success, providing operators with predictive criteria to avoid treatments likely to result in insufficient inflow improvement. Multi-well gas lift network analysis produced a clear guideline for managing surface injection-pressure constraints, including the timing and operational triggers for transitioning wells from HPGL to LPGL compressors to maximize field-wide lift efficiency.

Novelty and Significance
This work demonstrates how an integrated hybrid modeling system—combining physics-based flow dynamics with data-driven techniques, can transform daily surveillance and optimization workflows into unconventional asset management. Unlike traditional manual review processes, the platform delivers continuous, scalable, and objective recommendations for lift-control adjustments and conversions, well interventions, and facility-level gas-lift management. The structured analysis of acid-job performance provides a reliable framework for diagnosing treatment potential from both reservoir productivity and fluid-chemistry perspectives, minimizing ineffective interventions. The simultaneous optimization of ESPs, gas lift, and multi-well injection pressure management highlights the system’s ability to coordinate decisions across diverse lift systems and facility bottlenecks. The pilot results confirm the value of deploying automated, physics-informed digital solutions that enhance operational efficiency, reduce resource consumption, and support proactive field-wide production management.

Operators of marginal plunger lift wells face significant challenges in optimizing performance while managing tight economic constraints. These wells, characterized by lower flow rates, are often highly sensitive to operational costs, making it difficult to justify investments in advanced digital automation and control systems. Yet, these wells represent a substantial portion of production assets and have the potential to benefit greatly from enhanced efficiency, reduced operational expenses, and extended productive lifespans.

To address these challenges, a new solution has been developed to provide advanced digital capabilities tailored to the unique needs of marginal plunger lift wells. This system offers fully automated operations, high-resolution data analysis, and real-time diagnostics, enabling operators to make informed, data-driven decisions. 

The control systems programmable and upgradable architecture enables operators to develop unique algorithms tailored to each wells specific operational situation. This flexibility addresses a wide range of challenges and makes it possible to optimize performance regardless of changing conditions, production goals, or economic constraints. With additional features such as remote monitoring, local Wi-Fi connectivity, and IoT integration, the solution ensures operators can oversee and optimize well performance from virtually anywhere, reducing the need for frequent site visits and minimizing equipment wear.

Designed with affordability and scalability in mind, the system bridges the gap between high-end SCADA controllers and standalone devices, delivering the sophistication and connectivity of advanced automation at a cost that aligns with the financial realities of marginal wells. Its upgradable architecture and plug-and-play simplicity make it an accessible and practical choice for operators looking to enhance profitability, fully recover reserves, and streamline operations. 

By empowering operators with actionable insights and seamless control, this solution transforms marginal plunger lift wells into efficient, productive assets, bringing them into the digital age without compromising on cost-effectiveness.
 

For decades, VRUs have been deployed as compliance equipment and treated as commodity hardware – sized on rough estimates, lightly engineered, and minimally monitored. The results have been predictable: inconsistent runtime, chronic loading instability, ever-increasing maintenance costs, and a long-standing belief that VRUs simply “don’t work.” This paper examines why that legacy persists and outlines a modern engineering and measurement framework that significantly changes VRU performance, economics, and reliability.

The approach centers on precise sizing, real-time operational data, and flexible deployment strategies designed to match dynamic vapor loads. A comprehensive operational dataset – including pressures, temperatures, load signatures, runtime behavior, oil level, and measured vapor flow – enables predictive maintenance, drift detection, and stable runtime across a wider range of operating conditions. Rather than relying on a single indicator, this data ecosystem provides the analytical foundation for a proactive VRU program. The same infrastructure also supports accurate emissions accounting, turning VRUs into valuable compliance assets as regulators move toward measurement-based methane reporting and as operators work to reduce the significant financial exposure tied to modern methane enforcement.

Field deployments in the Permian Basin show significant improvements in uptime, maintenance cost, and equipment longevity, with operators experiencing fewer cycling events, reduced downtime, and lower LOE. These results indicate that a measurement-driven VRU program can prevent both oversized and vapor-constrained installations, significantly reducing risk while improving economic return.

This paper will present the engineering principles, measurement insights, and early field learnings behind this next-generation approach – and why solving the long-standing VRU problem ultimately turns vapor recovery from a perceived liability into a measurable, high-value asset.

Beneath the Surface: Data-Driven Analysis Illuminates Well Performance
Artificial lift decisions directly influence production sustainability and operating costs across thousands of unconventional wells. Yet despite the volume of data surrounding rod-lift systems, the information that should guide performance improvement often remains scattered across departments and disconnected from the equipment responsible for delivering results. Without visibility into what is happening beneath the surface, operators are left to make equipment decisions based on assumptions, delayed diagnostics, and after-the-fact interpretation.
This paper introduces an Integrated Well Tracking System (IWTS), a platform designed to close this visibility gap by linking production behavior with equipment configuration and documented failure mechanisms throughout run life. Instead of waiting until a pump is pulled to learn whether a specialty component performed as intended, IWTS allows operators to monitor its impact while the well continues producing.
A field analysis in the Permian Basin demonstrates how this shift in visibility alters operational outcomes. Across 1,811 cage installations, wells equipped with vortex flow one-piece cages exhibited a reversal in declining production behavior. In addition, these wells showed reduced rates of cage and valve related issues compared to common conventional designs. These results, made possible by data integration rather than delayed teardown evaluation, highlight how component geometry can significantly improve production efficiency and durability under real-world operating conditions.
By bringing equipment performance into view while wells remain online, IWTS provides earlier and more actionable insight into what is working, and what is not. This enables clearer justification for equipment investment, reduces uncertainty in optimization decisions, and supports more proactive rod-lift management. As the system continues to evolve, expanded automation and AI-assisted analytics will further strengthen performance benchmarking and operational judgement. Training and support will ensure operators can fully leverage these capabilities to drive continuous improvement across their wells. Together, these advancements redefine artificial-lift performance, illuminating a future guided by data-driven insight.
 

The Oxy Texas Delaware North Business Unit (TXDN) experiences frequent premature failures from severe downhole corrosion due to reservoir conditions and chemical undertreatment in wells with <1yr operating life. Typical damage occurs on undertreated annular gas lift wells near cap-string clamps/bands. Turbulent flow occurs on these components from high velocity flowrates, stripping chemical protection for corrosion to develop. From Jan 2022 to May 2025, ~28% of rig work addressed corrosion-induced tubing failures, costing $63.7MM cumulatively. In TXDN, ~15% of wells are chemically undertreated, decreasing runtimes and increasing failures.

TXDN is trialing three solutions to mitigate downhole tubing corrosion: 1) Externally coated tubing, 2) Internal capillary strings for chemical injection, and 3) Automated chemical injection. Since Oct 2024, 13 resin-coated tubing strings from BondCoat have been ran without failure at an economically incremental cost $6/ft. Since Nov 2024, two internal cap strings have been installed successfully for $13M per install incrementally. Both methods eliminate external clamps/bands--the main corrosion induced failure locations. To address undertreatment, TXDN implemented automated injection logic using NEXUS well test data, enabling daily rate adjustments and real-time monitoring, reducing reliance on weekly vendor changes, and keeping chemical treatments consistently on target.

While still in the trial stages, TXDN has successfully implemented automated chemical injection logic, external tubing coatings and internal capillary strings as methods for corrosion prevention. The measure of success will be if the tubing strings can last long enough for the wells to require conversion from annular flow to tubing flow gas lift, indicating the elimination of a premature failure and costly workover. This would deliver approximately $18.6MM/year in savings due to unnecessary workovers being eliminated. Measuring treatment targets from automated chemical injection is done in real time through Cygnet and Pi trends. With the automated chemical trials scaled up, the team is projecting a discounted cash flow of ~$610M across new drills for EOY 2025 through 2026.

Looking forward, automated chemical logic is in the process of scaling up all existing wells with DC3 controllers and installed for all future wedge wells. Cygnet and Pi screen surveillance are being built out in tandem to controller logic implementation. 
The internal cap string tool has been redesigned so that it can accommodate 2-3/8", 2-7/8", and 3-1/2", tubing and trials for 2-3/8" tubing during first lift installs will begin in Aug 2025. Along with externally coating tubing, these technologies will be considered for TXDN "One Lift" Trials including Hybrid and/or EC Mandrel gas lift designs. 
 

Oil and gas operators face growing expectations to improve operational performance, manage risk, and demonstrate responsible emissions management. Finalized New Source Performance Standards (NSPS) rules for OOOOa and OOOOb sites enable a more efficient, data-driven approach to Leak Detection and Repair (LDAR) compliance. Under these regulations, operators can use traditional Optical Gas Imaging (OGI) surveys or new technologies approved under the advanced Alternative Test Methods (ATMs). Continuous, real-time monitoring qualifies as an ATM for periodic screening and improves operational efficiency while maintaining regulatory compliance.
This paper focuses on how continuous monitoring supports advanced emission management and operational excellence. Continuous monitoring shifts LDAR programs from reactive, survey-based to a proactive, risk-based approach. By utilizing real-time data and actionable alerts, operators can locate, quantify and repair leaks in near real time. Operational teams can also prioritize field visits to remote locations based on actual site conditions instead of fixed LDAR schedules. This approach conserves both time and personnel.
Continuous emissions data enables robust desktop diagnostics. Operators validate equipment setpoint adjustments, confirm successful repairs without additional site visits, and quantify known operational activities. These efficiencies improve scheduling, reduce windshield time, and lower operational burden. We present a periodic screening program that leverages continuous monitoring to help operators meet or exceed compliance requirements and maintain constant visibility into site emissions. This approach minimizes the likelihood of undetected leaks and captures intermittent emission events that quarterly OGI inspections may miss.
Real-world implementation of a strategic periodic screening program has reduced required OGI inspection costs by 10 to 25 percent. Emissions trend data, combined with SCADA data, improves root-cause investigations and supports repair verifications. These results provide strong evidence of assurance for corporate sustainability initiatives and commitments. Participants will gain a clear understanding of periodic screening requirements and practical guidance on program design and execution. They will also learn methods for conducting investigative analyses.
Continuous monitoring is an established enterprise-level strategic tool. Its multi-faceted value proposition includes operational efficiencies through real-time data and historical trending, stronger regulatory compliance assurance for informed decision making, and greater confidence for operational teams and leaders in delivering sustainable, responsible energy.

Large-scale plunger lift operations demand surveillance methods that can balance proactive optimization with targeted field intervention. To replace route-based monitoring, Occidental Petroleum developed an integrated closed loop control program as well as SCADA based exceptions for its 2,000+ plunger lift wells. Plunger Lift Artificial Intelligence (PLAI) delivers proactive plunger lift optimization by blending real time well data with machine learning and decision logic, enabling timely alerts and automated setpoint updates. By leveraging JSON-based logging, every data point and automated setting change is documented in a structured format, enabling personnel to clearly understand each system action. SCADA is utilized for manual setpoint changes, tracking plunger components and categorizes various alarm types to enable targeted responses. When actions from either remote system prove insufficient, the system allows company personnel to send field callouts for specific well maintenance issues. Implementation challenges include the continued redistribution of stakeholder responsibilities, keeping PLAI’s algorithms and capabilities current and managing automation equipment and reliability. This paper outlines the surveillance framework, discusses implementation challenges, and presents a case study showing efficiency gains from shifting to a combined automated and exception-driven strategy.

Oil wells utilizing Electric Submersible Pump (ESP) systems require substantial electrical power for continuous operation leading to large operation electrical expenses and inefficiencies in traditional induction motor (IM) setups. This paper presents a comprehensive analysis of integrating Permanent Magnet Motors (PMMs) into ESP configurations to achieve superior power densities and operational efficiencies. By leveraging unique motor construction and advanced variable speed drive (VSD) controls, PMM-powered ESPs demonstrate up to 95% energy conversion efficiency which can significantly outperform IMs through minimized rotor slippage, reduced excitation losses, and precise torque delivery under variable downhole conditions. Field trials across multiple wells in the Permian Basin demonstrate real power savings of 10-25% due to lower losses and optimized load matching, while total input power (real + reactive) reductions of 20-30% stem from power factor improvements exceeding 0.95 eliminating the need for larger surface equipment typically required for IM applications. For larger ESP applications in 7 inch and 9-5/8 inch casing sizes that can accommodate larger 500 and 700 series motor selections, this paper provides a comprehensive review of ESP design analysis, surface equipment selection and optimization, and fundamental design challenges and integration covering the uniqueness of PMM drive ESPs

Unconventional reservoirs have accelerated the need for artificial lift strategies that recognize the fundamentally multiphase nature of modern well production. Traditional classifications of wells as strictly “oil” or “gas” producers—and the corresponding artificial lift systems historically assigned to each—no longer reflect operational reality, particularly in liquids-rich plays where substantial formation gas is routinely present. This disconnect often results in sub-optimal lift selection, unnecessary interventions, and elevated operating costs. To address these challenges, the authors introduce Applied Multi-Phase Pneumatic Lift (AMPL), a unified, “Life of Well” methodology that fully leverages the pneumatic contribution of produced and injected gas from initial flowback through end-of-life operations.

AMPL integrates the physics of multiphase flow—including bubble, slug, churn, and annular regimes—into every stage of production planning and optimization. By acknowledging that produced gas immediately imparts a pneumatic component to the system, engineers can more accurately predict fluid-column behavior, manage gradient reduction, and enhance liquid lifting through mechanisms such as micro-bubble generation, foam-assisted flow, gas-lift, and hybrid systems including PAGL and GAPL. This approach requires collaboration across reservoir, production, and midstream teams to align well design, facility constraints, and artificial lift sequencing.
At the core of AMPL is the coordinated application of NODAL analysis, decades of field experience, and continuous operational surveillance. Real-time monitoring provides the feedback loop necessary to adapt to rapid changes in reservoir contribution, gas-oil ratio, flowing pressures, and multiphase flow transitions. These insights support proactive decision-making, minimizing unplanned downtime while enabling responsive optimization of gas injection rates, plunger cycle strategies, and flowback protocols. The result is a systematic reduction of unnecessary workovers, minimized equipment breakdowns, and a meaningful decrease in production engineering workload through automated analytics and 24/7 expert support.

The paper highlights design considerations for pneumatic-lift configurations, performance limits related to flow-regime instability, and operational risks such as gas lift valve chatter under slugging or stratified conditions. The authors demonstrate how integrated data management, predictive analytics, and condition monitoring enhance system stability and overall production efficiency. Importantly, AMPL presents a scalable, sustainable framework that preserves well productivity while reducing operational footprints, extending lift system life, and improving stewardship of the reservoir resource.
AMPL represents a new production paradigm—one that combines science, experience, and real-time intelligence to optimize well performance consistently from day one through plug and abandonment.

Downhole separation is a critical process for proper sucker rod pump operation. This technology has been successfully applied in vertical wells, providing a solution for gas interference. New horizontal wells present a new challenge to this technology, since slug flow is a predominant flow pattern when sucker rod pumps are implemented. Many experimental studies have been conducted in the past that consider the continuous injection of gas and liquid near the separator inlet. For these cases, separators are operated continuously, and the separation efficiency is primarily measured in terms of vertical position. Thus, there is a need to develop an experimental procedure that considers the intermittent action of the sucker rod pump, as well as the inclination effect.

This paper presents a novel experimental procedure to characterize the performance of donwhole separators under the periodic behavior of a sucker rod pump. The paper describes the facility and the measurements. Computer vision algorithms are used to measure the gas void fraction entering the pump, as well as the bubble size distribution. Results for a poor boy are also presented and compared with the case of a single deep tube.

Intermittent gas wells frequently suffer production losses due to liquid loading and the limitations of manual or SCADA-driven cycling. This work introduces an edge-native autonomous control system that optimizes liquid unloading and flowback behavior using a hybrid physics-based and machine-learning (ML) framework. Deployed directly at the wellsite on rugged IIoT gateways, the system continuously ingests surface pressure, temperature, and flow data to compute real-time gas velocity, critical velocity, and inferred liquid-column dynamics. These insights are used to automatically determine optimal shut-in timing and choke-actuation decisions without requiring cloud connectivity or operator oversight.

To enhance unloading efficiency, shut-in duration is predicted by a cloud-hosted ML workflow trained on pressure-buildup trends, cycle outcomes, and historical production behavior, producing tailored per-well recommendations that are executed autonomously at the edge. The combination of deterministic modeling, adaptive ML forecasts, and closed-loop decision logic eliminates reactive, calendar-based operation and reduces unnecessary downtime.

Field deployment across nine Haynesville wells demonstrated significant production uplift, with cumulative gas increases of 70–139% and average daily gains reaching 350 MCFD. The approach delivered over 80 MMCF of incremental gas per well annually while requiring minimal infrastructure changes. Results confirm that hybrid edge-cloud intelligence provides a scalable, low-cost pathway to modernizing intermittent well management, enabling production optimization, reduced emissions, and improved operational consistency across diverse asset conditions.

Compressor downtime remains one of the primary causes of lost production, unstable injection performance, and fugitive methane emissions in gas lift operations. This paper reviews a zero-methane emission compression optimization system designed to stabilize gas lift performance by mitigating gas lift compressor issues, reducing shutdown frequency, and capturing methane emissions. The closed-loop system incorporates autonomous recirculation, real-time pressure control, and high-resolution monitoring to maintain steady gas-injection conditions and prevent scrubber-related malfunctions that commonly lead to compressor failures.

A large-scale field study was conducted across 77 gas compressors supporting 281 gas-lifted wells in the Permian Basin to evaluate the impact of deploying this optimization technology. The study compares compressor performance with and without the optimization skid in operation. Key performance indicators included shutdown frequency, downtime duration, under-injection events, scrubber liquid-level freeze-up incidents, methanol consumption associated with freeze-up mitigation, and methane emissions generated during disruption periods.

Results show that deploying the optimization system reduces compressor downtime by up to 90% compared with traditional mitigation methods by improving liquid handling and preventing liquid-level and dump-valve freeze-ups caused by the Joule Thomson cooling effect under high differential pressure. These improvements result in a more stable and consistent gas-injection process. Operators reported a substantial decline in shutdown events and improved production consistency, leading to increased oil output and higher cash flow. Field data also confirmed complete methane capture during gas compression, including emissions from rod-packing vents and blowdowns, providing a clear environmental advantage in gas-lift operations.

Overall, the compression optimization system offers a practical and scalable solution for operators seeking to reduce downtime, lower operational costs, maximize oil production, improve gas-lift stability, and meet evolving environmental expectations. This field study provides a framework for integrating an automated optimization skid into field development strategies as operators target both operational reliability and environmental compliance.
 

Jefferson Ogbuka, Texas Tech University, Petroleum Engineering - Multiphase Flow Metering Approaches: Physics, Field Performance and Test-Separator Comparisons

Seth Fitter, Texas Tech University, Petroleum Engineering - The Application of Sinker Rods vs Sinker Bars in Horizontal Wells

Adkham Izbassar, Texas Tech University, Petroleum Engineering - Experimental Evaluation of Pressure and Fatigue Performance of Cellulose Acetate Butyrate (CAB) Piping for Multiphase Flow Applications

This paper explores the High Pressure Gas Lift Upper Completion Design Strategy in the Delaware Basin, focusing on optimizing gas lift design for a life-of-well approach that ensures optimal economics. Various design options are assessed to balance cost savings, reliability, and operational efficiency. A comparative analysis of different gas lift designs, including Single Point (no GLV), Side-Pocket Mandrels (SPM), High Pressure GLV, Hybrid Gas Lift Designs, Traditional GLV with 10k Check Valve, and Traditional GLV with Burst Disc, was conducted. The study evaluated economic performance, reliability, and operational feasibility. Field data from wells with annular flow periods ranging from 18 to 30 months were analyzed to determine the most cost-effective and reliable gas lift strategy. The study involved simulating production scenarios for different gas lift configurations and analyzing their performance under various well conditions. Failure rates, reliability, and overall well performance were key factors considered in the evaluation. While Single Point installations provide the highest OPEX savings, reliability concerns must be addressed. SPM designs present a competitive and balanced solution, particularly for long-term production scenarios. Strategic planning based on annular flow duration and operational constraints is critical for maximizing efficiency and cost savings. Additionally, leveraging shared compression infrastructure can further enhance cost-effectiveness and operational flexibility.

Development of AI controllers has allowed abnormal pumping conditions to be accurately identified remotely. Due to the geometry of most rod lifting systems corrective actions need to be undertaken manually at the well location. This paper introduces an automated approach to implementing corrective actions with the use of a non-fixed stroke length rod pumping system. The focus includes case studies where manipulating the stroke length is used to rectify the abnormal pumping condition without the use of additional equipment or service rig intervention.

The method is derived from the experience of field operators who manually manipulate stroke lengths onsite with external lifting equipment or service rigs to rectify the abnormal pumping conditions. Procedures have now been implemented for operators to utilize the non fixed stroke length capabilities of the surface pumping unit to eliminate the need for a service rig or additional equipment. Case studies focus on spacing rods, tagging pumps, freeing stuck pumps and avoiding damaged sections of the downhole pump without the use of additional equipment. Preprogrammed solutions can now be implemented to automate the process and avoid the requirement for human intervention completely.

In each case study the abnormal pumping condition was rectified through manipulation of the stroke length. Wells report a significant reduction in downtime and lost production due to immediate correction of the abnormal pumping conditions. AI POCs coupled with variable stroke length allow automated sequence solutions to be implemented for identifiable abnormal conditions. The geometry of most surface rod pumping units significantly reduce the capability of AI POCs to implement corrective actions autonomously. This technology allows the PLC to bridge the gap from AI identification of abnormal pumping conditions and implementing the corrective actions needed to rectify the condition.

As industry moves further towards AI control it is important to emphasize the mechanical limitations of the surface equipment. Powerful AI programs without the ability to implement solutions erode the value of the AI technology. When designing wells or selecting artificial lift systems it is important to consider the overall efficiency of the system, specifically whether we are limiting the AI with the mechanical geometry of the surface unit.

In the Delaware Basin, traditional well control during high-pressure annular gas lift installations often introduced risks of formation damage, restricted wellbore access, costly interventions, and extended non-productive time. A dissolvable packer eliminated these drawbacks by delivering reliable pressure isolation without kill fluids, snubbing, or retrieval operations, enabling day-one gas lift. Validated across more than 100 wells, the technology consistently lowered costs, accelerated production onset, and became Devon Energy’s well control standard for gas lift installation in high-pressure wells.

The oil and gas industry has used Variable Frequency Drives (VFDs) for decades to match production to inflow. In sucker rod pump applications, it is well understood that optimizing pumping speed dramatically improves pump efficiency and failure rate. However, the same technology provides the opportunity to make multiple speed changes in a pumping cycle.
The effects of speed changes within a pumping cycle were analysed using predictive modeling, advanced rod stress and sideload calculations. A 5-year long trial was conducted on a population of 28 wells. A speed profile was selected to reduce rod failures, while maintaining production and pump efficiency. 19 of wells saw a fall in failure rate, improving the average time between failures by over 35%.

Intermittent gas lift (IGL) is emerging as a key late-life artificial lift method for the growing number of aging horizontal wells in the Permian Basin. With more than 20,000 wells on continuous gas lift, operators face challenges in converting to IGL and operating it effectively. This study synthesizes lessons gathered from controlled IGL experiments at the Texas Tech Oilfield Technology Center (OTC) and multiple Permian Basin wells. 

1. Tubing integrity presents a major barrier to successful IGL implementation. Perforation sealers and tubing patch systems offer a temporary fix. However, the corroded tubing strings left in a well for a long time can turn into expensive fishing jobs.
2. Proper IGL conversion depends on the liquid fallback factor, tubing size, and depth of the gas lift valve.
3. Flaws in the deployment method of standing valves affect their performance in IGL.
4. Reservoir depletion must be considered in the initial IGL design since the gas lift valve behavior alters with declining tubing pressures. The gas lift valve mechanics depend on the tubing pressure, so the valve opening pressure and spread change with declining tubing pressure.
5. High-frequency bottomhole pressure sensor data is essential for diagnostics and effective optimization of IGL.
6. Identified the operational similarities between sucker rod pumping and IGL.
These insights provide a practical framework to improve candidate selection, system design, and long-term intermittent gas lift success in unconventional reservoirs.

The Polished Rod Transducer (PRT) is a practical and effective tool for well analysis, offering the ability to acquire dynamometer data quickly with minimal disruption to pumping operations. This paper provides guidance on best practices for obtaining reliable PRT readings and improving diagnostic accuracy.
The paper begins with a brief overview of how the PRT measures load through polished rod diameter change. It then addresses key factors that can affect data quality, including transducer temperature equalization, PRT orientation, and polished rod alignment. Practical recommendations are provided for field application, such as installing the PRT early to allow temperature stabilization before data acquisition.
A key finding presented in this paper is that thermal drift, particularly from sun exposure during acquisition, can produce data trends that may be misinterpreted as polished rod bending if a rod rotator is present and operational during acquisition. These thermal effects are visually distinguishable from actual mechanical issues once the operator knows what to look for. Recognizing this distinction adds a valuable diagnostic skill to the operator's toolkit.
This paper will help operators and engineers get more value from PRT analysis by understanding both its capabilities and the conditions that influence its readings.

This study evaluates a 3-1/2 in. tubing well converted from continuous gas lift to plunger-assisted gas lift (PAGL) using a bypass plunger that initially failed to complete cycles under flowing conditions. The objective is to diagnose the root cause, determine operational boundaries for PAGL in 3-1/2 in. tubing, and assess the feasibility of PAGL relative to tubing replacement and higher gas-injection strategies using field data and plunger lift mechanistic models.

Steady-state multiphase flow simulations and drag-based mechanistic models were used to estimate plunger fall and upstroke velocities along the well, cycle durations, and kinetic energy at impact. Model results indicated that a 14-in. bypass plunger should be able to fall against flow rates exceeding 2 mmscf/d for this well. However, field data showed that the custom 3-1/2 in. tubing plunger had an undersized inner orifice, making it too restrictive to fall against flow. Consequently, prolonged shut-in times were required, which increased bottomhole pressure and reduced production. After deploying a proportionally designed bypass plunger with a larger inner orifice, PAGL operation stabilized with a 2-minute shut-in and production increased.

This paper presents a comparative study demonstrating that continuous-flow plunger deployment in larger tubing can provide a cost-effective alternative to tubing replacement, enabling operators to reduce gas injection while avoiding liquid loading.

Mechanical components used in artificial lift face significant environmental and functional challenges, primarily caused by factors such as corrosion, abrasion, erosion, and stress corrosion cracking in downhole conditions. To ensure a component remains operational, the material not only needs to meet mechanical requirements but also needs surface properties capable of withstanding the corrosive and abrasive downhole environment.
To address these challenges, various coatings, metallurgies and surface treatments have been developed and utilized since the inception of the oil and gas industry. Over the past two decades, advancements in material engineering across industries have driven innovation in surface protection, meeting the increasing demands to reduce costs and extend service life.
This study offers a thorough evaluation of existing coatings and metallurgies, along with Harbison-Fischer’s Deka Diamond coating for rod pumping applications. It reviews both traditional and innovative materials, surface treatments, and coatings currently being used by operators to improve the durability of their equipment. By applying advanced wear and abrasion testing methods, these metallurgies have undergone rigorous assessment to enable detailed analysis of their surface characteristics before and after testing. The focus of the analysis is on the quantitative results of metallurgical testing while introducing HF’s advanced coating technology and quantifying its benefits in improving overall run-life. The findings of this study will support operators in selecting appropriate materials—such as Diamond, Boronized, Chrome, Nickel-Carbide, and Spray Metal—for their Rod Lift equipment, with the objective of maximizing run-life and minimizing mean time before failures.

Objectives/Scope:
Fracture-driven interactions (FDIs), commonly known as frac hits, are becoming an increasing concern as hydraulic fracturing operations intensify in mature basins. These interactions can introduce foreign solids, crosslinked gels, and formation fines into existing wellbores, significantly impairing well productivity. Traditional mechanical clean-outs, while effective, are costly and may not fully restore well performance. This paper presents a series of field case studies highlighting the application of advanced chemical remediation strategies designed to address these complex challenges, providing operators with a cost-effective alternative to conventional methods.

Methods, Procedures, Process:
Two novel chemical systems were developed to eliminate the need for solvent preflushes, utilizing multifunctional chemistries in combination with either fresh water or 15% NEFE HCl. Treatment designs targeted the dissolution of precipitated scales, removal of chemical residues, dispersion of fines, restoration of near-wellbore relative permeability, re-establishment of water-wet conditions, and reduction of capillary pressures to aid fluid recovery. Simple field deployment methods, such as bullheading, were selected for ease of execution and cost efficiency.
A comprehensive suite of laboratory tests, including dispersibility analysis, contact angle measurement, and fluid compatibility assessments, was conducted to validate the effectiveness of these multifunctional chemistries in mitigating frac hit damage. These tests provided critical insights into the interaction mechanisms and optimal treatment parameters for various damage profiles.

Results, Observations, Conclusions:
Field trials demonstrated consistent and sustained improvements in post-treatment well performance, with some wells achieving production rates exceeding pre-frac hit baselines. Recovery outcomes ranged from 50% to over 100% relative to pre-hit decline curves, confirming the efficacy of the selected chemistries. Lessons learned from these deployments, including the importance of intervention timing and chemical compatibility, are also discussed.

Novel/Additive Information:
This work introduces a novel chemical formulation that eliminates the need for traditional solvent preflushes, offering a more efficient and cost-effective approach to frac hit remediation. The integration of multifunctional chemistries with simple operational techniques provides a practical framework for operators seeking to maximize production recovery while minimizing downtime and extending asset life.

OBJECTIVES/SCOPE:
The presentation will review a new modeling workflow utilizing dynamic, iterative nodal analysis  with cumulative-based IPR indexing to generate production profiles for different operating scenarios for a given base-case production forecast. Output profiles can be tested for value in an
economic model. This workflow has been used to rebase the high-pressure gas lift strategy in Delaware Basin and evaluate production impacts of other initiatives (surface-controlled gas lift and smaller annular areas).

METHODS, PROCEDURES, PROCESS:
The workflow starts with a production profile reflecting a base-case operating mode (type curve or production forecast). A reservoir pressure profile is generated based on EUR, cumulative production, and initial pressure. A flowing bottomhole pressure (FBHP) profile is calculated. The
combination of reservoir pressure and FBHP profiles provides IPRs at each point in cumulative production. A parallel profile is then calculated for the alternative case: for each point, IPR is consistent with the base profile at the same cumulative production. Injection depth and production rates are calculated for each day of the alternative case.

RESULTS, OBSERVATIONS, CONCLUSIONS:
Direct comparisons of offset well performance are often obscured by differences in well characteristics (depletion, drilling quality, completion execution, operations). Reservoir simulation, an alternative, is time-intensive and not typically performed outside specific cases. An evaluation
technique was needed to fill the gap between offset comparison and reservoir simulation. This new workflow was first utilized to assess production impact of high-pressure gas lift in Delaware Basin, and found that the value of high-pressure gas lift is more dependent on fluid composition and productivity than on oil EUR (prior metric for selecting high vs. low pressure). Application of the workflow catalyzed a pivot in strategy: high-pressure gas lift was removed from scope on new wells where it was found not to be value accretive, resulting in cost savings. On a smaller set of new wells, the workflow affirmed that high pressure gas lift was value accretive and was maintained in scope. The workflow was also utilized to support field development by assessing production impacts of other initiatives (surface-controlled gas lift and smaller annular area during annular gas lift).

NOVEL/ADDITIVE INFORMATION:
The workflow has been a valuable tool to assess early-life production acceleration opportunities. These opportunities, by definition, do not lead to incremental EUR (no change to late life artificial lift method and terminal FBHP), but rather serve only to accelerate barrels from later years into
earlier years. In evaluation of such opportunities, the time-value of the production acceleration must justify the additional cost (which is usually not an acceleration but is additive to existing cost structures). This workflow has provided insight into which factors have larger impacts on
production acceleration, and which have lower impacts.
 

Electric Submersible Pumps (ESPs) remain one of the most widely deployed artificial lift technologies for maximizing production from Permian wells. Operating companies often find themselves installing ESPs between multiple producing zones or even below the perforated intervals for several reasons, including the goal of maximizing production by setting the pump as deep as possible and increasing natural gas separation to help stabilize operating trends. 
Shroud and recirculation systems are the two primary technologies used for ESP motor cooling. In this paper, the performance of both techniques was evaluated, and the main challenges, limitations, and lessons learned are discussed.

A dataset comprising hundreds of ESP installations equipped with motor cooling systems was analyzed to evaluate the performance of both techniques. Survivability curves were used to compare the reliability of these systems, while several Dismantle Inspection and Failure Analysis (DIFA) reports were reviewed to identify the main failure mechanisms and root causes. Numerical simulation was conducted to better understand the physics underlying the recirculation system performance. Operating trends and production data were also examined to further assess the challenges, limitations, and efficiencies of these technologies.

Based on survivability curves, ESPs equipped with cooling systems demonstrated a 45% higher average runtime compared to standard ESPs. Over 400 ESPs with recirculation systems have been installed in the Permian Basin, with an average run life of 982 days and several wells exceeding 4,000 run days. Numerical simulation indicates that setting the pump below the perforations can achieve up to 95% natural gas separation, ensuring reliable and stable operation. In contrast, pull and DIFA reports show that units installed with shroud systems experienced several critical challenges and failures. These include incidents of holes in the shroud preventing proper cooling, scale and sand deposition inside the shroud reducing production rates, and in many cases causing complete blockage. Additionally, the pump stack inside the shroud often contributes to reliability concerns, making the shroud a less dependable option compared to the recirculation system.  

The standardized industry practice for deploying ESP systems below perforations requires the use of a motor cooling system. This study demonstrates the superior reliability of the recirculation system compared to the shroud, providing the industry with best-practice guidance for future ESP installations.

This paper presents the Gas Release System Bypass, the latest advancement in gas regulation and separation technologies for Electric Submersible Pump systems operating in high-GLR and gas-slugging environments. The GRSB enhances conventional gas-handling methods by integrating the principles of gas regulation, pressurization, centrifugal dispersion, and controlled gas venting through a dedicated bypass system. This design ensures that fluids delivered to the pump intake are properly conditioned, enabling stable ESP performance, improved drawdown, and reduced motor temperature, while mitigating shutdowns associated with gas interference. The system serves as a high-efficiency solution for wells nearing the limits of ESP operability and as an intermediate step before transitioning to alternative artificial lift systems.
The GRSB integrates four major components a Triple Seal Packer, Pressurization Chamber, Centrifugal Regulator, and Gas Release Bypass section, working sequentially to homogenize fluid and efficiently vent free gas. Large gas slugs are first dispersed into smaller bubbles, then reabsorbed through pressure increases generated within an oversized chamber. Centrifugal forces further break remaining bubbles, and any unrecombined gas is vented through a one-way valve above the ESP discharge. The result is a stable, homogenized liquid stream that promotes efficient motor cooling and consistent pump operation

Three field applications in the Midland Basin demonstrate the system’s impact. In Case Study 1, installing a downsized pump with a GRSB reduced PIP from historical levels to 390 PSI at only 52 Hz performance previously unattainable. Case Study 2 achieved a drawdown to 420 PSI at 63 Hz, improving on prior limits of 630 PSI at similar frequencies. In Case Study 3, GRSB deployment increased total fluid production by 55% and boosted oil output from 85.7 to 118 BOPD, highlighting improved flow stability and gas-handling capacity. Across all cases, sensor data indicated lower motor temperatures, fewer shutdowns, enhanced pump efficiency, and reduced NPT.

Overall, the Gas Release System Bypass provides a robust and innovative approach to transforming slug flow into a manageable, homogenized stream, optimizing ESP performance in challenging gas-prone wells. Its ability to regulate, separate, and release gas before reaching the pump intake establishes the GRSB as a transformative technology for modern artificial lift operations.
 

In response to rising demands for operational efficiency, power challenges, environmental responsibility, and workplace safety, this paper presents a case study on the integration of high-efficiency Permanent Magnet Motors (PMMs) and Power Regenerative Variable Speed Drive systems on long-stroke and conventional pumping units. This initiative was the result of a strategic collaboration between Weatherford and the operators, aimed at optimizing artificial lift operations while reducing energy consumption and enhancing safety performance.

The technical approach involved retrofitting existing rod lift systems with Weatherford’s Permanent Magnetic Motor’s and the Power Regenerative (PRSi) Variable Speed Drive system. Unlike conventional induction motor systems that dissipate regenerative energy as heat, the PRSi system captures and stores excess energy using ultra-capacitor technology and redistributes it during peak load demand. This dual-technology integration provides a more efficient energy management process and improves motor control during both acceleration and deceleration cycles of the pumping unit. While conventional regenerative drive technology pushes excess power back into the grid, the PRSi system is a closed loop approach that ensures its viability for greenfield applications running on genset power.

A field implementation for a Bakken operator demonstrated up to 49% reduction of power consumption, resulting in an estimated annual reduction of 106,230 kg of COâ‚‚ emissions and a field implementation for a Permian operator demonstrated 37% reduction of power consumption. Additionally, the system enhanced operational safety by decreasing the need for manual intervention, thereby keeping personnel out of high-risk zones. Operational performance data is presented to validate improvements in energy utilization, equipment longevity, and process control.
This paper offers novel insights into how existing rod lift assets can be transformed into highly efficient, regenerative systems through advanced motor technology and intelligent energy capture. The results support a broader industry shift toward sustainable production practices while delivering tangible value in operational cost savings and safety enhancements.
 

The plunger lift process can be divided into four distinct cycles: buildup, upstroke, after flow, and liquid discharge. One key parameter that can be measured for optimizing oil production is the total gas flow rate produced during the liquid discharge cycle. Typically, the only known parameters are the controller’s on and off time, so post-processing is required to identify the liquid discharge period and quantify the observed flow rate.
Human analysis is enough to identify when the liquid discharge happens, which is characterized by the sudden increase in the gas flow rate. Analyzing one single well is feasible, however, the evaluation of tens or hundreds of wells becomes an unfeasible task.

This work proposes a machine-learning approach based on neural networks to automatically split plunger lift cycles. The model employs a long-short term memory (LSTM) neural-network, commonly used for time series data, with a classification head to identify and classify each stage. The model’s input is a time window containing casing, flowline, and tubing pressures, along with gas flow rate data; its output consists of probabilities corresponding to each plunger cycle. After the cycle automatic splitting, the cumulative gas flow rate produced during the liquid discharge period is quantified and recorded.

To train the model, field data must be acquired and manually labeled by a subject-matter expert. To automatize this part, a graphical-user interface (GUI) was developed to load well data and interactively select the correspondent plunger stage. The model was trained using data from five different wells and tested on a different well, achieving an accuracy of 98% for the cycle’s prediction.
This study presents an efficient and automated method to address a common challenge in production monitoring - quantifying well performance. Once trained, the proposed neural network can rapidly classify real-time data, enabling improved troubleshooting, production optimization, and performance tracking.

Electrical Resistance (ER) probes offer a continuous, high-resolution method for measuring corrosion rates in oilfield systems. This study demonstrates how ER data can be used to establish baseline corrosion, evaluate corrosion inhibitor performance, and guide product selection under varying produced-water and multiphase conditions. Results show that ER data can quickly distinguish between inhibitor chemistries, quantify treatment effectiveness in a short period, and guide the selection of the most effective corrosion control products for specific fluid chemistries and operating conditions. Overall, ER probes proved to be a practical and sensitive tool for corrosion inhibitor performance verification and product selection, supporting more efficient chemical programs and stronger asset integrity management.

The thermal behavior of Electrical Submersible Pump (ESP) systems deployed in unconventional wells is poorly characterized, particularly when exposed to elevated gas volume fractions and transient flow regimes. Traditional point temperature measurements provide limited spatial resolution and do not capture how gas interference influences heat distribution along pump stages, seal sections, and motors. To address this knowledge gap, an experimental R&D deployment of distributed fiber-optic temperature sensing (DTS) was performed in a gassy unconventional well to observe continuous downhole temperature profiles along the entire ESP assembly.

The DTS system was encapsulated in a stainless-steel tube and installed externally along the ESP string, from the sensor to above discharge. The acquired data showed distinct temperature changes associated with gas-entrainment regions, as well as deviations in cooling performance from values typically assumed in ESP selection and modeling.

The intent of this work is not to propose a scalable field monitoring method, but to present rare empirical insight into actual ESP thermal profiles in gassy unconventional wells. The findings can help refine operating envelope interpretation, improve cooling-related design assumptions, and enhance diagnostic understanding using existing surveillance signals.

While the west Texas natural gas industry has been on life support since 2008 with low prices and inadequate takeaway capacity it is on the verge of a major revival in order to meet upcoming major LNG and data center demand increases.   These plants and data centers will require 18-24 BCFD of incremental supply over current levels in the US by 2030.  Based on EIA projections it is expected that the Permian will provide up to 45% of this incremental demand.  For the first time since 2018 West Texas pipeline investors saw this demand coming well in advance and are responding in force to put in enough takeaway capacity to help meet the need for incremental production.  The expected additions to the Waha system in 2026 are staggering with 6.6 BCFD of additional takeaway capacity increasing to over 10 BCFD by 2028.  On the supply side the latest expected incremental supply growth from West Texas is less than 1.4 BCFD in 2026 and 0.6 BCFD in 2027 and 2028.   When this is combined with an expected 32 GW of incremental demand from Texas data centers alone by 2028 the demand for gas looks pretty strong.  Each GW of generating capacity requires 160 MMCFD of feed gas for the turbines or an incremental 5.1 BCF of demand by 2028 that will not be heading to the LNG plants.  Between the newly added capacity expansions and huge expected demand growth West Texas gas has the potential to be the next $100 oil at a time when oil prices are struggling to stay above $60.  At a minimum Waha should be on par or better than Henry Hub which was the case prior to the capacity bottleneck pricing disaster of 2018-2026.  With virtually zero drilling and recompletion activity in Permian basin dry gas reservoirs since 2008 this represents a major ramp up of gas production from legacy fields that have had little or no activity for the last 18 years.  The bulk of the current expected increase comes from associated gas from horizontal oil wells which is the most of the 1.4 BCFD expected 2026 West Texas supply growth expectation.  Significant volumes of incremental gas supply from dedicated gas wells must be added to meet the expected demand growth without focusing on dedicated gas wells.  The oil focused shales in the Permian would need a significant increase in rig and frac crew count to meet this demand with oil well associated gas alone.   Prior to the price spikes from the Iran conflict the EIA was forecasting +/- $55 oil in 2026.  Once this temporary increase in prices ends it is unlikely that this will forecast change significantly.  Without a significant sustained increase in oil prices the oil focused rig and frac crew count will not follow and thus significant additional supply is probably not going to come from associated gas.  The bulk of the incremental gas must come from 100% gas producing wells in the Permian Basin.   

Traditional metal-to-metal seal rings have long struggled with down hole sealing issues due to a functional lack of interchangeability among manufacturers, particulate contamination on the seal face, and a possible designed-in lack of precise control of the sealing angle on mating parts. These issues drive costly interventions and decrease pump performance. The hybrid seal introduces a solution by combining precision machined metal elements with a high-performance, compression molded elastomeric component, forming a dual sealing system that unites structural rigidity with adaptive sealing behavior. A step towards superior sealing integrity under these conditions.

Experiments confirm the hybrid seal’s ability to maintain a leak-free barrier under pressures up to 5000 psi without deformation or degradation. The elastomeric compound, Hydrogenated Nitrile Butadiene Rubber (HNBR), delivers exceptional hardness, tensile strength, chemical resistance, and gas embolism resistance. Its elastic deformation capacity ensures consistent sealing across repeated stress cycles, pump unseating and flush-back operations.

Due to its technical performance, the hybrid seal offers significant operational advantages, including reduced downtime, extended equipment life, and decreased intervention costs. Research into this technology will continue through field trials and additional experimentations with expanded operating parameters.

More than 200,000 horizontal multifractured wells are currently active across multiple unconventional basins in continental United States. The first completion designs relied on completion practices that had been utilized in conventional reservoirs, and the early wells completed with low proppant/fluid intensity and in many cases cluster/fracture spacing greater than 100 ft. Chlorine Dioxide (ClO₂) was field trialed as a Restimulation/EOR chemistry in a well D&C in 2015 as an alternative to traditional Refrac operations.
Well R is a well D&C in 2015 in Culberson County, Texas with a lateral of 7,058 ft. At the first 4,300 ft, the well was completed with a perforation design of 6 clusters 8 ft apart, followed by 183 ft of spacing to the next group of clusters. For the remaining part of the lateral, a perforation design with clusters ~38 ft apart was used. The pumping schedule was a hybrid design of slickwater/X-link gel. A Chlorine Dioxide (ClO₂) EOR Re-stimulation treatment was engineered and pumped in 01/2025, and the well, which had been shut-in since 11/2017, was returned to production
Initial production rates IP30 of ~ 230 bopd and 1,700 Mscfd were recorded (01/2025), approximately 65% of the initial production rates when the well was first put in production in 10/2015. The well demonstrates better cumulative oil/gas production and EUR when compared to the well’s initial production after 12 months of flow back. The ClO₂ re-stimulation treatment providing better economics and NPV without posing the mechanical/engineering risk of a traditional restimulation method (bull head Refrac or liner re-frac). Realized production data and performance of Well R further validated the theory presented by Dalamarinis et al . (2023, 2025) that production degradation is not exclusively related to depletion, but mainly to skin damage mechanisms developed inside the fracture system. It also expanded the range/criteria of wells at which Chlorine Dioxide (ClO₂) EOR treatments can be applied (fracture system spacing ~ 180 ft) with similar success to the cases previously presented to the industry.
Re-stimulation with Chlorine Dioxide (ClO₂) proved to be an effective method to restore production and reservoir conductivity in a well that traditionally would be considered a Refrac or Plug and Abandoned (P&A) candidate. Without the need to invest millions of dollars and operational risk in bull head or liner refrac operations, operators can utilize Chlorine Dioxide (ClO₂) as an alternative restimulation strategy that offers better economics and efficiencies.

Electric Submersible Pumps (ESPs) face significant performance challenges when free gas enters the system, and bubbles obstruct fluid flow through the pump impellers–a phenomenon known as gas locking, which can induce premature failure. This complication is amplified during gas slug events, which are inevitable in unconventional reservoirs common to the Permian Basin. This paper presents compelling results from real field deployments that highlight superior recovery capabilities achieved through the CENesis PHASE™ Multiphase Encapsulated System. The CENesis PHASE™ solution fully encapsulates the ESP system to naturally separate gas from the fluid, preventing the gas from entering the ESP. This optimized ESP system overcomes challenging well conditions such as high gas-liquid ratios by greatly improving gas separation efficiency through enhanced system geometry. For numerous cases where ESPs previously underperformed in gassy applications, the systems were upgraded to the CENesis PHASE™ solution and closely observed. Performance data before and after the transition were analyzed with emphasis on production trends and operational improvements.

This solution has proven to be successful in more than 500 ESP installations in the USA land by mitigating gas slugs, increasing oil production, and reducing ESP motor temperature shutdowns. The study will present more than 30 CENesis PHASE™ systems across multiple fields since 2022 with a Delaware basin operator. Results of the phase system demonstrate increased run life of the population ESPs, achieved by the configuration’s ability to maximize the well draw down and eliminate gas related shutdowns. By reducing downtime, the operator improved oil production and avoided inescapable costly failures. Evident through the analysis of production and ESP operational data before and after implementation of the optimized ESP, it is clear the approach to find a remedy to gas complications was successful.

This paper will present the key enabling technologies of the CENesis PHASE™ system including the novel encapsulation concept in combination with unique flow management. There will be a strong focus on quantitative production enhancements in Permian’s challenging gas-saturated wells. The study will provide valuable insight for operators by exposing them to world-class solutions aimed to overcome this common production obstacle.

Leveraging advancements in material science, a comprehensive pilot study of the effectiveness of vibrational-energy tools to inhibit asphaltene and paraffin was conducted involving over 40 wells throughout the Permian Basin, encompassing both conventional and unconventional reservoirs. This technical paper provides an in-depth analysis of the tool, which operates on the interaction of specially formulated solid materials that passively emit vibrational energy at targeted frequencies. This energy alters the physical behavior of hydrocarbon molecules, producing lasting changes in fluid properties.
Raman spectrometry provides solid, quantitative proof for how these modifications work, backing up the scientific foundation of the tool. The vibrational energy it creates interferes with the van der Waals forces that normally cause paraffin to clump together, which helps keep hydrocarbons stable right at the source. In addition, this resonant energy not only helps prevent further aggregation but also lowers viscosity and density. It also makes it easier to separate oil and water by reducing their interfacial tension. Altogether, these effects lead to more efficient production.
For the pilot, comprehensive candidate well selection criteria were established. The chosen wells were systematically excluded from all existing chemical treatment regimens targeting paraffin and asphaltenes. This case study presents empirical evidence of the tool’s performance, utilizing production metrics and operational monitoring data to demonstrate its effectiveness. The findings illustrate the tool's ability to significantly reduce chemical spend, extend operational runtime in wells historically susceptible to solids-related issues, and achieve substantial production uplift.
 

Electric Submersible Pumps (ESPs) are commonly known in the Artificial Lift Systems for high flowrates capabilities; however, it’s been limited on tight casing application due to not only HP constrains, but also for presenting restriction in terms of chemical treatment all the way down to the bottom of the equipment and reliability concern on tandem motor applications. Recently an operating company in the Permian Basin was experiencing production limitation on one of their wells with an unusual completion with 5” 18# production casing where a conventional slimline ESP was originally installed with 375 tandem induction motors. The described system was not able to draw the well down, minimum pump intake pressure was above the 2000psi, with the unit running at high motor loads and total fluid rates only averaging ~720BPD. After proposal was presented, the operator decided to proactively pull the system and successfully installed the Reynolds Permanent Magnet 399 Series Motor in less risk associated with fishing jobs with significant lower operating costs. New HP capability allowed to upsize the ESP which resulted in an increased production of 4 times in oil, 8 times in gas and over 2 times in total fluid ~1850BPD, with a drawdown of ~60psi/day for the first 2 weeks taking the pump intake pressure down to ~1100psi after just 20 days of start up, and now after 80~days by the time the abstract is being written pump intake pressure is down to ~850psi exceeding customer expectations and production targets, being able to operate the unit on steady conditions at a more reliable motor load  and improving operational performance and maintaining stable production of the well. Moreover, similar results have been observed in 5.5” casing applications with extended laterals, where operators are targeting flowrates exceeding 6500–7000 BFPD. These scenarios demand significantly higher HP levels that are not achievable with conventional induction motors, further highlighting the performance advantages and broader applicability of Permanent Magnet Motor technology in modern high-demand ESP environments.

A major Bakken operator repeatedly experienced insufficient pump fillage and lower-than-anticipated production volumes in rod-pumped horizontal wells due to poor gas and sand separation. Unable to achieve the desired results after deploying a variety of different gas- and sand-mitigation techniques, the operator partnered with Endurance Lift Solutions to deploy the patented ELS Guardian™ separator in combination with the Triple Bypass tubing-anchor catcher.

This presentation describes an extensive, 138-well project that resulted in significant gains in pump fillage and production volumes versus prior configurations. In collaboration with the operator, Don Crane, ELS Product Line Director for Downhole Rod Pumps, will share before-and-after data, key lessons learned, and advancements in gas- and sand-separation technologies.

Oil and gas operators increasingly face difficulties optimizing production from wells characterized by variable flow regimes and dynamic pressure conditions. Conventional gas lift systems are often unable to respond effectively to these fluctuations, resulting in inefficiencies, elevated downtime, and reduced hydrocarbon recovery. These challenges are compounded by the need to control costs, particularly in marginal or complex well environments.
 
A newly developed surface-controlled gas lift technology addresses these limitations by enabling dynamic, precise adjustment of gas lift performance. The system integrates coordinated surface and downhole components to allow real-time modification of valve setpoints in response to changing well conditions. Using a hydraulically actuated mechanism, the technology provides accurate valve control independent of injection pressure, minimizing pressure losses and enhancing production rates.
 
Constructed with robust, industry-standard materials, the system is designed for reliability and seamless integration with existing infrastructure. Its ability to continuously optimize valve setpoints allows operators to "shoot the gaps" across a broad range of flow rates and pressures. Additional capabilities such as reversing injection flow or over-pressuring valves to clear obstructions further improve operability and reduce downtime.
 
Field deployments have validated the systems performance in annular, conventional, intermittent, and high-pressure gas lift applications. Demonstrating more than 8,500 open/close cycles over a one-year period, the technology offers durable, cost-effective production enhancement and reduced operating expenses.
 
By resolving the fundamental constraints of traditional gas lift designs, the surface-controlled system provides improved efficiency, operational flexibility, real-time visibility, and consistent repeatability under a wide range of well conditions.
 

Building upon the successes of cathodically protected rod strings in rotary applications, this study extends the evaluation to reciprocating sucker rod pump operations using anode-coated coiled rod strings. The paper presents results from a pilot project involving four wells for a major California oil and gas producer, achieving a remarkable 11-fold improvement in Mean Time to Failure (MTF) compared to historical performance. Prior to the trial, wells with high water-cut and elevated CO₂ content experienced frequent failures—typically within six months—despite optimized rod compositions, use of both rod and tubing rotators, and corrosion inhibition treatments. These conditions had led to wells being classified as non-viable. The introduction of anode-coated rod strings combined with lined tubing reversed this trend, revitalizing field operations and prompting the deployment of over 20 additional installations.

Mechanical components used in artificial lift face significant environmental and functional challenges, primarily caused by factors such as corrosion, abrasion, erosion, and stress corrosion cracking in downhole conditions. To ensure a component remains operational, the material not only needs to meet mechanical requirements but also needs surface properties capable of withstanding the corrosive and abrasive downhole environment.
To address these challenges, various coatings, metallurgies and surface treatments have been developed and utilized since the inception of the oil and gas industry. Over the past two decades, advancements in material engineering across industries have driven innovation in surface protection, meeting the increasing demands to reduce costs and extend service life.
This study offers a thorough evaluation of existing coatings and metallurgies, along with Harbison-Fischer’s Deka Diamond coating for rod pumping applications. It reviews both traditional and innovative materials, surface treatments, and coatings currently being used by operators to improve the durability of their equipment. By applying advanced wear and abrasion testing methods, these metallurgies have undergone rigorous assessment to enable detailed analysis of their surface characteristics before and after testing. The focus of the analysis is on the quantitative results of metallurgical testing while introducing HF’s advanced coating technology and quantifying its benefits in improving overall run-life. The findings of this study will support operators in selecting appropriate materials—such as Diamond, Boronized, Chrome, Nickel-Carbide, and Spray Metal—for their Rod Lift equipment, with the objective of maximizing run-life and minimizing mean time before failures.

While the west Texas natural gas industry has been on life support since 2008 with low prices and inadequate takeaway capacity it is on the verge of a major revival in order to meet upcoming major LNG and data center demand increases.   These plants and data centers will require 18-24 BCFD of incremental supply over current levels in the US by 2030.  Based on EIA projections it is expected that the Permian will provide up to 45% of this incremental demand.  For the first time since 2018 West Texas pipeline investors saw this demand coming well in advance and are responding in force to put in enough takeaway capacity to help meet the need for incremental production.  The expected additions to the Waha system in 2026 are staggering with 6.6 BCFD of additional takeaway capacity increasing to over 10 BCFD by 2028.  On the supply side the latest expected incremental supply growth from West Texas is less than 1.4 BCFD in 2026 and 0.6 BCFD in 2027 and 2028.   When this is combined with an expected 32 GW of incremental demand from Texas data centers alone by 2028 the demand for gas looks pretty strong.  Each GW of generating capacity requires 160 MMCFD of feed gas for the turbines or an incremental 5.1 BCF of demand by 2028 that will not be heading to the LNG plants.  Between the newly added capacity expansions and huge expected demand growth West Texas gas has the potential to be the next $100 oil at a time when oil prices are struggling to stay above $60.  At a minimum Waha should be on par or better than Henry Hub which was the case prior to the capacity bottleneck pricing disaster of 2018-2026.  With virtually zero drilling and recompletion activity in Permian basin dry gas reservoirs since 2008 this represents a major ramp up of gas production from legacy fields that have had little or no activity for the last 18 years.  The bulk of the current expected increase comes from associated gas from horizontal oil wells which is the most of the 1.4 BCFD expected 2026 West Texas supply growth expectation.  Significant volumes of incremental gas supply from dedicated gas wells must be added to meet the expected demand growth without focusing on dedicated gas wells.  The oil focused shales in the Permian would need a significant increase in rig and frac crew count to meet this demand with oil well associated gas alone.   Prior to the price spikes from the Iran conflict the EIA was forecasting +/- $55 oil in 2026.  Once this temporary increase in prices ends it is unlikely that this will forecast change significantly.  Without a significant sustained increase in oil prices the oil focused rig and frac crew count will not follow and thus significant additional supply is probably not going to come from associated gas.  The bulk of the incremental gas must come from 100% gas producing wells in the Permian Basin.   

Traditional metal-to-metal seal rings have long struggled with down hole sealing issues due to a functional lack of interchangeability among manufacturers, particulate contamination on the seal face, and a possible designed-in lack of precise control of the sealing angle on mating parts. These issues drive costly interventions and decrease pump performance. The hybrid seal introduces a solution by combining precision machined metal elements with a high-performance, compression molded elastomeric component, forming a dual sealing system that unites structural rigidity with adaptive sealing behavior. A step towards superior sealing integrity under these conditions.

Experiments confirm the hybrid seal’s ability to maintain a leak-free barrier under pressures up to 5000 psi without deformation or degradation. The elastomeric compound, Hydrogenated Nitrile Butadiene Rubber (HNBR), delivers exceptional hardness, tensile strength, chemical resistance, and gas embolism resistance. Its elastic deformation capacity ensures consistent sealing across repeated stress cycles, pump unseating and flush-back operations.

Due to its technical performance, the hybrid seal offers significant operational advantages, including reduced downtime, extended equipment life, and decreased intervention costs. Research into this technology will continue through field trials and additional experimentations with expanded operating parameters.

More than 200,000 horizontal multifractured wells are currently active across multiple unconventional basins in continental United States. The first completion designs relied on completion practices that had been utilized in conventional reservoirs, and the early wells completed with low proppant/fluid intensity and in many cases cluster/fracture spacing greater than 100 ft. Chlorine Dioxide (ClO₂) was field trialed as a Restimulation/EOR chemistry in a well D&C in 2015 as an alternative to traditional Refrac operations.
Well R is a well D&C in 2015 in Culberson County, Texas with a lateral of 7,058 ft. At the first 4,300 ft, the well was completed with a perforation design of 6 clusters 8 ft apart, followed by 183 ft of spacing to the next group of clusters. For the remaining part of the lateral, a perforation design with clusters ~38 ft apart was used. The pumping schedule was a hybrid design of slickwater/X-link gel. A Chlorine Dioxide (ClO₂) EOR Re-stimulation treatment was engineered and pumped in 01/2025, and the well, which had been shut-in since 11/2017, was returned to production
Initial production rates IP30 of ~ 230 bopd and 1,700 Mscfd were recorded (01/2025), approximately 65% of the initial production rates when the well was first put in production in 10/2015. The well demonstrates better cumulative oil/gas production and EUR when compared to the well’s initial production after 12 months of flow back. The ClO₂ re-stimulation treatment providing better economics and NPV without posing the mechanical/engineering risk of a traditional restimulation method (bull head Refrac or liner re-frac). Realized production data and performance of Well R further validated the theory presented by Dalamarinis et al . (2023, 2025) that production degradation is not exclusively related to depletion, but mainly to skin damage mechanisms developed inside the fracture system. It also expanded the range/criteria of wells at which Chlorine Dioxide (ClO₂) EOR treatments can be applied (fracture system spacing ~ 180 ft) with similar success to the cases previously presented to the industry.
Re-stimulation with Chlorine Dioxide (ClO₂) proved to be an effective method to restore production and reservoir conductivity in a well that traditionally would be considered a Refrac or Plug and Abandoned (P&A) candidate. Without the need to invest millions of dollars and operational risk in bull head or liner refrac operations, operators can utilize Chlorine Dioxide (ClO₂) as an alternative restimulation strategy that offers better economics and efficiencies.

Development of AI controllers has allowed abnormal pumping conditions to be accurately identified remotely. Due to the geometry of most rod lifting systems corrective actions need to be undertaken manually at the well location. This paper introduces an automated approach to implementing corrective actions with the use of a non-fixed stroke length rod pumping system. The focus includes case studies where manipulating the stroke length is used to rectify the abnormal pumping condition without the use of additional equipment or service rig intervention.

The method is derived from the experience of field operators who manually manipulate stroke lengths onsite with external lifting equipment or service rigs to rectify the abnormal pumping conditions. Procedures have now been implemented for operators to utilize the non fixed stroke length capabilities of the surface pumping unit to eliminate the need for a service rig or additional equipment. Case studies focus on spacing rods, tagging pumps, freeing stuck pumps and avoiding damaged sections of the downhole pump without the use of additional equipment. Preprogrammed solutions can now be implemented to automate the process and avoid the requirement for human intervention completely.

In each case study the abnormal pumping condition was rectified through manipulation of the stroke length. Wells report a significant reduction in downtime and lost production due to immediate correction of the abnormal pumping conditions. AI POCs coupled with variable stroke length allow automated sequence solutions to be implemented for identifiable abnormal conditions. The geometry of most surface rod pumping units significantly reduce the capability of AI POCs to implement corrective actions autonomously. This technology allows the PLC to bridge the gap from AI identification of abnormal pumping conditions and implementing the corrective actions needed to rectify the condition.

As industry moves further towards AI control it is important to emphasize the mechanical limitations of the surface equipment. Powerful AI programs without the ability to implement solutions erode the value of the AI technology. When designing wells or selecting artificial lift systems it is important to consider the overall efficiency of the system, specifically whether we are limiting the AI with the mechanical geometry of the surface unit.

In the Delaware Basin, traditional well control during high-pressure annular gas lift installations often introduced risks of formation damage, restricted wellbore access, costly interventions, and extended non-productive time. A dissolvable packer eliminated these drawbacks by delivering reliable pressure isolation without kill fluids, snubbing, or retrieval operations, enabling day-one gas lift. Validated across more than 100 wells, the technology consistently lowered costs, accelerated production onset, and became Devon Energy’s well control standard for gas lift installation in high-pressure wells.

In response to rising demands for operational efficiency, power challenges, environmental responsibility, and workplace safety, this paper presents a case study on the integration of high-efficiency Permanent Magnet Motors (PMMs) and Power Regenerative Variable Speed Drive systems on long-stroke and conventional pumping units. This initiative was the result of a strategic collaboration between Weatherford and the operators, aimed at optimizing artificial lift operations while reducing energy consumption and enhancing safety performance.

The technical approach involved retrofitting existing rod lift systems with Weatherford’s Permanent Magnetic Motor’s and the Power Regenerative (PRSi) Variable Speed Drive system. Unlike conventional induction motor systems that dissipate regenerative energy as heat, the PRSi system captures and stores excess energy using ultra-capacitor technology and redistributes it during peak load demand. This dual-technology integration provides a more efficient energy management process and improves motor control during both acceleration and deceleration cycles of the pumping unit. While conventional regenerative drive technology pushes excess power back into the grid, the PRSi system is a closed loop approach that ensures its viability for greenfield applications running on genset power.

A field implementation for a Bakken operator demonstrated up to 49% reduction of power consumption, resulting in an estimated annual reduction of 106,230 kg of COâ‚‚ emissions and a field implementation for a Permian operator demonstrated 37% reduction of power consumption. Additionally, the system enhanced operational safety by decreasing the need for manual intervention, thereby keeping personnel out of high-risk zones. Operational performance data is presented to validate improvements in energy utilization, equipment longevity, and process control.
This paper offers novel insights into how existing rod lift assets can be transformed into highly efficient, regenerative systems through advanced motor technology and intelligent energy capture. The results support a broader industry shift toward sustainable production practices while delivering tangible value in operational cost savings and safety enhancements.
 

A major Bakken operator repeatedly experienced insufficient pump fillage and lower-than-anticipated production volumes in rod-pumped horizontal wells due to poor gas and sand separation. Unable to achieve the desired results after deploying a variety of different gas- and sand-mitigation techniques, the operator partnered with Endurance Lift Solutions to deploy the patented ELS Guardian™ separator in combination with the Triple Bypass tubing-anchor catcher.

This presentation describes an extensive, 138-well project that resulted in significant gains in pump fillage and production volumes versus prior configurations. In collaboration with the operator, Don Crane, ELS Product Line Director for Downhole Rod Pumps, will share before-and-after data, key lessons learned, and advancements in gas- and sand-separation technologies.

Electrical Resistance (ER) probes offer a continuous, high-resolution method for measuring corrosion rates in oilfield systems. This study demonstrates how ER data can be used to establish baseline corrosion, evaluate corrosion inhibitor performance, and guide product selection under varying produced-water and multiphase conditions. Results show that ER data can quickly distinguish between inhibitor chemistries, quantify treatment effectiveness in a short period, and guide the selection of the most effective corrosion control products for specific fluid chemistries and operating conditions. Overall, ER probes proved to be a practical and sensitive tool for corrosion inhibitor performance verification and product selection, supporting more efficient chemical programs and stronger asset integrity management.

Building upon the successes of cathodically protected rod strings in rotary applications, this study extends the evaluation to reciprocating sucker rod pump operations using anode-coated coiled rod strings. The paper presents results from a pilot project involving four wells for a major California oil and gas producer, achieving a remarkable 11-fold improvement in Mean Time to Failure (MTF) compared to historical performance. Prior to the trial, wells with high water-cut and elevated CO₂ content experienced frequent failures—typically within six months—despite optimized rod compositions, use of both rod and tubing rotators, and corrosion inhibition treatments. These conditions had led to wells being classified as non-viable. The introduction of anode-coated rod strings combined with lined tubing reversed this trend, revitalizing field operations and prompting the deployment of over 20 additional installations.

Intermittent gas wells frequently suffer production losses due to liquid loading and the limitations of manual or SCADA-driven cycling. This work introduces an edge-native autonomous control system that optimizes liquid unloading and flowback behavior using a hybrid physics-based and machine-learning (ML) framework. Deployed directly at the wellsite on rugged IIoT gateways, the system continuously ingests surface pressure, temperature, and flow data to compute real-time gas velocity, critical velocity, and inferred liquid-column dynamics. These insights are used to automatically determine optimal shut-in timing and choke-actuation decisions without requiring cloud connectivity or operator oversight.

To enhance unloading efficiency, shut-in duration is predicted by a cloud-hosted ML workflow trained on pressure-buildup trends, cycle outcomes, and historical production behavior, producing tailored per-well recommendations that are executed autonomously at the edge. The combination of deterministic modeling, adaptive ML forecasts, and closed-loop decision logic eliminates reactive, calendar-based operation and reduces unnecessary downtime.

Field deployment across nine Haynesville wells demonstrated significant production uplift, with cumulative gas increases of 70–139% and average daily gains reaching 350 MCFD. The approach delivered over 80 MMCF of incremental gas per well annually while requiring minimal infrastructure changes. Results confirm that hybrid edge-cloud intelligence provides a scalable, low-cost pathway to modernizing intermittent well management, enabling production optimization, reduced emissions, and improved operational consistency across diverse asset conditions.

Compressor downtime remains one of the primary causes of lost production, unstable injection performance, and fugitive methane emissions in gas lift operations. This paper reviews a zero-methane emission compression optimization system designed to stabilize gas lift performance by mitigating gas lift compressor issues, reducing shutdown frequency, and capturing methane emissions. The closed-loop system incorporates autonomous recirculation, real-time pressure control, and high-resolution monitoring to maintain steady gas-injection conditions and prevent scrubber-related malfunctions that commonly lead to compressor failures.

A large-scale field study was conducted across 77 gas compressors supporting 281 gas-lifted wells in the Permian Basin to evaluate the impact of deploying this optimization technology. The study compares compressor performance with and without the optimization skid in operation. Key performance indicators included shutdown frequency, downtime duration, under-injection events, scrubber liquid-level freeze-up incidents, methanol consumption associated with freeze-up mitigation, and methane emissions generated during disruption periods.

Results show that deploying the optimization system reduces compressor downtime by up to 90% compared with traditional mitigation methods by improving liquid handling and preventing liquid-level and dump-valve freeze-ups caused by the Joule Thomson cooling effect under high differential pressure. These improvements result in a more stable and consistent gas-injection process. Operators reported a substantial decline in shutdown events and improved production consistency, leading to increased oil output and higher cash flow. Field data also confirmed complete methane capture during gas compression, including emissions from rod-packing vents and blowdowns, providing a clear environmental advantage in gas-lift operations.

Overall, the compression optimization system offers a practical and scalable solution for operators seeking to reduce downtime, lower operational costs, maximize oil production, improve gas-lift stability, and meet evolving environmental expectations. This field study provides a framework for integrating an automated optimization skid into field development strategies as operators target both operational reliability and environmental compliance.
 

Ayann Tiam, Texas Tech University, Petroleum Engineering - Produced-Water Management in the Permian Basin: Historical Production, Forecast, Water Quality, and Screening-Level Constituent Valorization for Beneficial Reuse in West Texas

Luke Elbel, Texas Tech University, Petroleum Engineering - Optimizing Horizontal Well Pumping and BHA Design to Reduce Bottomhole Flowing Pressure

Abdul Rehman, Texas Tech University, Petroleum Engineering - Production Optimization Through Simulated Multiphase Pumping: A Case Study in the Delaware Basin.

OBJECTIVES/SCOPE:
The presentation will review a new modeling workflow utilizing dynamic, iterative nodal analysis  with cumulative-based IPR indexing to generate production profiles for different operating scenarios for a given base-case production forecast. Output profiles can be tested for value in an
economic model. This workflow has been used to rebase the high-pressure gas lift strategy in Delaware Basin and evaluate production impacts of other initiatives (surface-controlled gas lift and smaller annular areas).

METHODS, PROCEDURES, PROCESS:
The workflow starts with a production profile reflecting a base-case operating mode (type curve or production forecast). A reservoir pressure profile is generated based on EUR, cumulative production, and initial pressure. A flowing bottomhole pressure (FBHP) profile is calculated. The
combination of reservoir pressure and FBHP profiles provides IPRs at each point in cumulative production. A parallel profile is then calculated for the alternative case: for each point, IPR is consistent with the base profile at the same cumulative production. Injection depth and production rates are calculated for each day of the alternative case.

RESULTS, OBSERVATIONS, CONCLUSIONS:
Direct comparisons of offset well performance are often obscured by differences in well characteristics (depletion, drilling quality, completion execution, operations). Reservoir simulation, an alternative, is time-intensive and not typically performed outside specific cases. An evaluation
technique was needed to fill the gap between offset comparison and reservoir simulation. This new workflow was first utilized to assess production impact of high-pressure gas lift in Delaware Basin, and found that the value of high-pressure gas lift is more dependent on fluid composition and productivity than on oil EUR (prior metric for selecting high vs. low pressure). Application of the workflow catalyzed a pivot in strategy: high-pressure gas lift was removed from scope on new wells where it was found not to be value accretive, resulting in cost savings. On a smaller set of new wells, the workflow affirmed that high pressure gas lift was value accretive and was maintained in scope. The workflow was also utilized to support field development by assessing production impacts of other initiatives (surface-controlled gas lift and smaller annular area during annular gas lift).

NOVEL/ADDITIVE INFORMATION:
The workflow has been a valuable tool to assess early-life production acceleration opportunities. These opportunities, by definition, do not lead to incremental EUR (no change to late life artificial lift method and terminal FBHP), but rather serve only to accelerate barrels from later years into
earlier years. In evaluation of such opportunities, the time-value of the production acceleration must justify the additional cost (which is usually not an acceleration but is additive to existing cost structures). This workflow has provided insight into which factors have larger impacts on
production acceleration, and which have lower impacts.
 

Electric Submersible Pumps (ESPs) face significant performance challenges when free gas enters the system, and bubbles obstruct fluid flow through the pump impellers–a phenomenon known as gas locking, which can induce premature failure. This complication is amplified during gas slug events, which are inevitable in unconventional reservoirs common to the Permian Basin. This paper presents compelling results from real field deployments that highlight superior recovery capabilities achieved through the CENesis PHASE™ Multiphase Encapsulated System. The CENesis PHASE™ solution fully encapsulates the ESP system to naturally separate gas from the fluid, preventing the gas from entering the ESP. This optimized ESP system overcomes challenging well conditions such as high gas-liquid ratios by greatly improving gas separation efficiency through enhanced system geometry. For numerous cases where ESPs previously underperformed in gassy applications, the systems were upgraded to the CENesis PHASE™ solution and closely observed. Performance data before and after the transition were analyzed with emphasis on production trends and operational improvements.

This solution has proven to be successful in more than 500 ESP installations in the USA land by mitigating gas slugs, increasing oil production, and reducing ESP motor temperature shutdowns. The study will present more than 30 CENesis PHASE™ systems across multiple fields since 2022 with a Delaware basin operator. Results of the phase system demonstrate increased run life of the population ESPs, achieved by the configuration’s ability to maximize the well draw down and eliminate gas related shutdowns. By reducing downtime, the operator improved oil production and avoided inescapable costly failures. Evident through the analysis of production and ESP operational data before and after implementation of the optimized ESP, it is clear the approach to find a remedy to gas complications was successful.

This paper will present the key enabling technologies of the CENesis PHASE™ system including the novel encapsulation concept in combination with unique flow management. There will be a strong focus on quantitative production enhancements in Permian’s challenging gas-saturated wells. The study will provide valuable insight for operators by exposing them to world-class solutions aimed to overcome this common production obstacle.

This paper presents the Gas Release System Bypass, the latest advancement in gas regulation and separation technologies for Electric Submersible Pump systems operating in high-GLR and gas-slugging environments. The GRSB enhances conventional gas-handling methods by integrating the principles of gas regulation, pressurization, centrifugal dispersion, and controlled gas venting through a dedicated bypass system. This design ensures that fluids delivered to the pump intake are properly conditioned, enabling stable ESP performance, improved drawdown, and reduced motor temperature, while mitigating shutdowns associated with gas interference. The system serves as a high-efficiency solution for wells nearing the limits of ESP operability and as an intermediate step before transitioning to alternative artificial lift systems.
The GRSB integrates four major components a Triple Seal Packer, Pressurization Chamber, Centrifugal Regulator, and Gas Release Bypass section, working sequentially to homogenize fluid and efficiently vent free gas. Large gas slugs are first dispersed into smaller bubbles, then reabsorbed through pressure increases generated within an oversized chamber. Centrifugal forces further break remaining bubbles, and any unrecombined gas is vented through a one-way valve above the ESP discharge. The result is a stable, homogenized liquid stream that promotes efficient motor cooling and consistent pump operation

Three field applications in the Midland Basin demonstrate the system’s impact. In Case Study 1, installing a downsized pump with a GRSB reduced PIP from historical levels to 390 PSI at only 52 Hz performance previously unattainable. Case Study 2 achieved a drawdown to 420 PSI at 63 Hz, improving on prior limits of 630 PSI at similar frequencies. In Case Study 3, GRSB deployment increased total fluid production by 55% and boosted oil output from 85.7 to 118 BOPD, highlighting improved flow stability and gas-handling capacity. Across all cases, sensor data indicated lower motor temperatures, fewer shutdowns, enhanced pump efficiency, and reduced NPT.

Overall, the Gas Release System Bypass provides a robust and innovative approach to transforming slug flow into a manageable, homogenized stream, optimizing ESP performance in challenging gas-prone wells. Its ability to regulate, separate, and release gas before reaching the pump intake establishes the GRSB as a transformative technology for modern artificial lift operations.
 

The oil and gas industry has used Variable Frequency Drives (VFDs) for decades to match production to inflow. In sucker rod pump applications, it is well understood that optimizing pumping speed dramatically improves pump efficiency and failure rate. However, the same technology provides the opportunity to make multiple speed changes in a pumping cycle.
The effects of speed changes within a pumping cycle were analysed using predictive modeling, advanced rod stress and sideload calculations. A 5-year long trial was conducted on a population of 28 wells. A speed profile was selected to reduce rod failures, while maintaining production and pump efficiency. 19 of wells saw a fall in failure rate, improving the average time between failures by over 35%.

The plunger lift process can be divided into four distinct cycles: buildup, upstroke, after flow, and liquid discharge. One key parameter that can be measured for optimizing oil production is the total gas flow rate produced during the liquid discharge cycle. Typically, the only known parameters are the controller’s on and off time, so post-processing is required to identify the liquid discharge period and quantify the observed flow rate.
Human analysis is enough to identify when the liquid discharge happens, which is characterized by the sudden increase in the gas flow rate. Analyzing one single well is feasible, however, the evaluation of tens or hundreds of wells becomes an unfeasible task.

This work proposes a machine-learning approach based on neural networks to automatically split plunger lift cycles. The model employs a long-short term memory (LSTM) neural-network, commonly used for time series data, with a classification head to identify and classify each stage. The model’s input is a time window containing casing, flowline, and tubing pressures, along with gas flow rate data; its output consists of probabilities corresponding to each plunger cycle. After the cycle automatic splitting, the cumulative gas flow rate produced during the liquid discharge period is quantified and recorded.

To train the model, field data must be acquired and manually labeled by a subject-matter expert. To automatize this part, a graphical-user interface (GUI) was developed to load well data and interactively select the correspondent plunger stage. The model was trained using data from five different wells and tested on a different well, achieving an accuracy of 98% for the cycle’s prediction.
This study presents an efficient and automated method to address a common challenge in production monitoring - quantifying well performance. Once trained, the proposed neural network can rapidly classify real-time data, enabling improved troubleshooting, production optimization, and performance tracking.

The Polished Rod Transducer (PRT) is a practical and effective tool for well analysis, offering the ability to acquire dynamometer data quickly with minimal disruption to pumping operations. This paper provides guidance on best practices for obtaining reliable PRT readings and improving diagnostic accuracy.
The paper begins with a brief overview of how the PRT measures load through polished rod diameter change. It then addresses key factors that can affect data quality, including transducer temperature equalization, PRT orientation, and polished rod alignment. Practical recommendations are provided for field application, such as installing the PRT early to allow temperature stabilization before data acquisition.
A key finding presented in this paper is that thermal drift, particularly from sun exposure during acquisition, can produce data trends that may be misinterpreted as polished rod bending if a rod rotator is present and operational during acquisition. These thermal effects are visually distinguishable from actual mechanical issues once the operator knows what to look for. Recognizing this distinction adds a valuable diagnostic skill to the operator's toolkit.
This paper will help operators and engineers get more value from PRT analysis by understanding both its capabilities and the conditions that influence its readings.

The thermal behavior of Electrical Submersible Pump (ESP) systems deployed in unconventional wells is poorly characterized, particularly when exposed to elevated gas volume fractions and transient flow regimes. Traditional point temperature measurements provide limited spatial resolution and do not capture how gas interference influences heat distribution along pump stages, seal sections, and motors. To address this knowledge gap, an experimental R&D deployment of distributed fiber-optic temperature sensing (DTS) was performed in a gassy unconventional well to observe continuous downhole temperature profiles along the entire ESP assembly.

The DTS system was encapsulated in a stainless-steel tube and installed externally along the ESP string, from the sensor to above discharge. The acquired data showed distinct temperature changes associated with gas-entrainment regions, as well as deviations in cooling performance from values typically assumed in ESP selection and modeling.

The intent of this work is not to propose a scalable field monitoring method, but to present rare empirical insight into actual ESP thermal profiles in gassy unconventional wells. The findings can help refine operating envelope interpretation, improve cooling-related design assumptions, and enhance diagnostic understanding using existing surveillance signals.

Objectives/Scope:
Fracture-driven interactions (FDIs), commonly known as frac hits, are becoming an increasing concern as hydraulic fracturing operations intensify in mature basins. These interactions can introduce foreign solids, crosslinked gels, and formation fines into existing wellbores, significantly impairing well productivity. Traditional mechanical clean-outs, while effective, are costly and may not fully restore well performance. This paper presents a series of field case studies highlighting the application of advanced chemical remediation strategies designed to address these complex challenges, providing operators with a cost-effective alternative to conventional methods.

Methods, Procedures, Process:
Two novel chemical systems were developed to eliminate the need for solvent preflushes, utilizing multifunctional chemistries in combination with either fresh water or 15% NEFE HCl. Treatment designs targeted the dissolution of precipitated scales, removal of chemical residues, dispersion of fines, restoration of near-wellbore relative permeability, re-establishment of water-wet conditions, and reduction of capillary pressures to aid fluid recovery. Simple field deployment methods, such as bullheading, were selected for ease of execution and cost efficiency.
A comprehensive suite of laboratory tests, including dispersibility analysis, contact angle measurement, and fluid compatibility assessments, was conducted to validate the effectiveness of these multifunctional chemistries in mitigating frac hit damage. These tests provided critical insights into the interaction mechanisms and optimal treatment parameters for various damage profiles.

Results, Observations, Conclusions:
Field trials demonstrated consistent and sustained improvements in post-treatment well performance, with some wells achieving production rates exceeding pre-frac hit baselines. Recovery outcomes ranged from 50% to over 100% relative to pre-hit decline curves, confirming the efficacy of the selected chemistries. Lessons learned from these deployments, including the importance of intervention timing and chemical compatibility, are also discussed.

Novel/Additive Information:
This work introduces a novel chemical formulation that eliminates the need for traditional solvent preflushes, offering a more efficient and cost-effective approach to frac hit remediation. The integration of multifunctional chemistries with simple operational techniques provides a practical framework for operators seeking to maximize production recovery while minimizing downtime and extending asset life.

The Resin-in-Cement (RIC) system is a hybrid technology that merges thermosetting epoxy resin emulsions with traditional Portland cement systems, creating a stable emulsion for superior wellbore sealing and bond-adhesion in oil and gas wells. It solves key integrity issues like micro-annuli , and debonding in harsh downhole conditions. Conventional resin-cement mixes often fail due to density-driven separation, causing incompatibility and a non-homogeneous slurry. RIC counters this with proprietary chemistry of dry and liquid additives, ensuring uniform resin dispersion, additive compatibility, and strong adhesion to casing and formations.
RIC excels over traditional cement in flexibility and durability. Portland cement is economical but rigid—high Young's modulus, low toughness, moderate bonds, and permeable set cement sheath—leading to stress-induced cracks. RIC cuts Young's modulus while boosting flexibility against temperature, pressure, and mechanical loads. The RIC system shows an increase in modulus of toughness against conventional cement blends, absorbing energy to resist fracture. In cyclic pressure wells such as injection wells, it adapts to expansions/contractions, preventing fatigue cracks and prolonging life. In mobile formations such as highly mobile salts, lower stiffness allows elastic deformation, easing shear stress and avoiding debonding or isolation failures. Shear bonding to casing and formation shows formidable adhesion, curbing migration; permeability falls, compressive strength rises, fluid loss drops, and free fluid is non-existent. Typical temperature profile of this system can range from Surface ambient to 200oF+, and density of the systems can be run from a conventional 10 ppg up to a heavyweight 18 ppg slurry.
Economically, RIC delivers resin's premium traits—impermeability, resilience—through bulk cement, using 15-30% resin to cut costs dramatically versus pure resin. This system is ideal for P&A, HPHT wells, and injection applications.
Ultimately, RIC transforms zonal isolation: cement strength plus resin agility, affordably, for enduring well integrity.

This paper explores the High Pressure Gas Lift Upper Completion Design Strategy in the Delaware Basin, focusing on optimizing gas lift design for a life-of-well approach that ensures optimal economics. Various design options are assessed to balance cost savings, reliability, and operational efficiency. A comparative analysis of different gas lift designs, including Single Point (no GLV), Side-Pocket Mandrels (SPM), High Pressure GLV, Hybrid Gas Lift Designs, Traditional GLV with 10k Check Valve, and Traditional GLV with Burst Disc, was conducted. The study evaluated economic performance, reliability, and operational feasibility. Field data from wells with annular flow periods ranging from 18 to 30 months were analyzed to determine the most cost-effective and reliable gas lift strategy. The study involved simulating production scenarios for different gas lift configurations and analyzing their performance under various well conditions. Failure rates, reliability, and overall well performance were key factors considered in the evaluation. While Single Point installations provide the highest OPEX savings, reliability concerns must be addressed. SPM designs present a competitive and balanced solution, particularly for long-term production scenarios. Strategic planning based on annular flow duration and operational constraints is critical for maximizing efficiency and cost savings. Additionally, leveraging shared compression infrastructure can further enhance cost-effectiveness and operational flexibility.

Electric Submersible Pumps (ESPs) remain one of the most widely deployed artificial lift technologies for maximizing production from Permian wells. Operating companies often find themselves installing ESPs between multiple producing zones or even below the perforated intervals for several reasons, including the goal of maximizing production by setting the pump as deep as possible and increasing natural gas separation to help stabilize operating trends. 
Shroud and recirculation systems are the two primary technologies used for ESP motor cooling. In this paper, the performance of both techniques was evaluated, and the main challenges, limitations, and lessons learned are discussed.

A dataset comprising hundreds of ESP installations equipped with motor cooling systems was analyzed to evaluate the performance of both techniques. Survivability curves were used to compare the reliability of these systems, while several Dismantle Inspection and Failure Analysis (DIFA) reports were reviewed to identify the main failure mechanisms and root causes. Numerical simulation was conducted to better understand the physics underlying the recirculation system performance. Operating trends and production data were also examined to further assess the challenges, limitations, and efficiencies of these technologies.

Based on survivability curves, ESPs equipped with cooling systems demonstrated a 45% higher average runtime compared to standard ESPs. Over 400 ESPs with recirculation systems have been installed in the Permian Basin, with an average run life of 982 days and several wells exceeding 4,000 run days. Numerical simulation indicates that setting the pump below the perforations can achieve up to 95% natural gas separation, ensuring reliable and stable operation. In contrast, pull and DIFA reports show that units installed with shroud systems experienced several critical challenges and failures. These include incidents of holes in the shroud preventing proper cooling, scale and sand deposition inside the shroud reducing production rates, and in many cases causing complete blockage. Additionally, the pump stack inside the shroud often contributes to reliability concerns, making the shroud a less dependable option compared to the recirculation system.  

The standardized industry practice for deploying ESP systems below perforations requires the use of a motor cooling system. This study demonstrates the superior reliability of the recirculation system compared to the shroud, providing the industry with best-practice guidance for future ESP installations.

Leveraging advancements in material science, a comprehensive pilot study of the effectiveness of vibrational-energy tools to inhibit asphaltene and paraffin was conducted involving over 40 wells throughout the Permian Basin, encompassing both conventional and unconventional reservoirs. This technical paper provides an in-depth analysis of the tool, which operates on the interaction of specially formulated solid materials that passively emit vibrational energy at targeted frequencies. This energy alters the physical behavior of hydrocarbon molecules, producing lasting changes in fluid properties.
Raman spectrometry provides solid, quantitative proof for how these modifications work, backing up the scientific foundation of the tool. The vibrational energy it creates interferes with the van der Waals forces that normally cause paraffin to clump together, which helps keep hydrocarbons stable right at the source. In addition, this resonant energy not only helps prevent further aggregation but also lowers viscosity and density. It also makes it easier to separate oil and water by reducing their interfacial tension. Altogether, these effects lead to more efficient production.
For the pilot, comprehensive candidate well selection criteria were established. The chosen wells were systematically excluded from all existing chemical treatment regimens targeting paraffin and asphaltenes. This case study presents empirical evidence of the tool’s performance, utilizing production metrics and operational monitoring data to demonstrate its effectiveness. The findings illustrate the tool's ability to significantly reduce chemical spend, extend operational runtime in wells historically susceptible to solids-related issues, and achieve substantial production uplift.
 

Electric Submersible Pumps (ESPs) are commonly known in the Artificial Lift Systems for high flowrates capabilities; however, it’s been limited on tight casing application due to not only HP constrains, but also for presenting restriction in terms of chemical treatment all the way down to the bottom of the equipment and reliability concern on tandem motor applications. Recently an operating company in the Permian Basin was experiencing production limitation on one of their wells with an unusual completion with 5” 18# production casing where a conventional slimline ESP was originally installed with 375 tandem induction motors. The described system was not able to draw the well down, minimum pump intake pressure was above the 2000psi, with the unit running at high motor loads and total fluid rates only averaging ~720BPD. After proposal was presented, the operator decided to proactively pull the system and successfully installed the Reynolds Permanent Magnet 399 Series Motor in less risk associated with fishing jobs with significant lower operating costs. New HP capability allowed to upsize the ESP which resulted in an increased production of 4 times in oil, 8 times in gas and over 2 times in total fluid ~1850BPD, with a drawdown of ~60psi/day for the first 2 weeks taking the pump intake pressure down to ~1100psi after just 20 days of start up, and now after 80~days by the time the abstract is being written pump intake pressure is down to ~850psi exceeding customer expectations and production targets, being able to operate the unit on steady conditions at a more reliable motor load  and improving operational performance and maintaining stable production of the well. Moreover, similar results have been observed in 5.5” casing applications with extended laterals, where operators are targeting flowrates exceeding 6500–7000 BFPD. These scenarios demand significantly higher HP levels that are not achievable with conventional induction motors, further highlighting the performance advantages and broader applicability of Permanent Magnet Motor technology in modern high-demand ESP environments.

Intermittent gas lift (IGL) is emerging as a key late-life artificial lift method for the growing number of aging horizontal wells in the Permian Basin. With more than 20,000 wells on continuous gas lift, operators face challenges in converting to IGL and operating it effectively. This study synthesizes lessons gathered from controlled IGL experiments at the Texas Tech Oilfield Technology Center (OTC) and multiple Permian Basin wells. 

1. Tubing integrity presents a major barrier to successful IGL implementation. Perforation sealers and tubing patch systems offer a temporary fix. However, the corroded tubing strings left in a well for a long time can turn into expensive fishing jobs.
2. Proper IGL conversion depends on the liquid fallback factor, tubing size, and depth of the gas lift valve.
3. Flaws in the deployment method of standing valves affect their performance in IGL.
4. Reservoir depletion must be considered in the initial IGL design since the gas lift valve behavior alters with declining tubing pressures. The gas lift valve mechanics depend on the tubing pressure, so the valve opening pressure and spread change with declining tubing pressure.
5. High-frequency bottomhole pressure sensor data is essential for diagnostics and effective optimization of IGL.
6. Identified the operational similarities between sucker rod pumping and IGL.
These insights provide a practical framework to improve candidate selection, system design, and long-term intermittent gas lift success in unconventional reservoirs.

Oil and gas operators increasingly face difficulties optimizing production from wells characterized by variable flow regimes and dynamic pressure conditions. Conventional gas lift systems are often unable to respond effectively to these fluctuations, resulting in inefficiencies, elevated downtime, and reduced hydrocarbon recovery. These challenges are compounded by the need to control costs, particularly in marginal or complex well environments.
 
A newly developed surface-controlled gas lift technology addresses these limitations by enabling dynamic, precise adjustment of gas lift performance. The system integrates coordinated surface and downhole components to allow real-time modification of valve setpoints in response to changing well conditions. Using a hydraulically actuated mechanism, the technology provides accurate valve control independent of injection pressure, minimizing pressure losses and enhancing production rates.
 
Constructed with robust, industry-standard materials, the system is designed for reliability and seamless integration with existing infrastructure. Its ability to continuously optimize valve setpoints allows operators to "shoot the gaps" across a broad range of flow rates and pressures. Additional capabilities such as reversing injection flow or over-pressuring valves to clear obstructions further improve operability and reduce downtime.
 
Field deployments have validated the systems performance in annular, conventional, intermittent, and high-pressure gas lift applications. Demonstrating more than 8,500 open/close cycles over a one-year period, the technology offers durable, cost-effective production enhancement and reduced operating expenses.
 
By resolving the fundamental constraints of traditional gas lift designs, the surface-controlled system provides improved efficiency, operational flexibility, real-time visibility, and consistent repeatability under a wide range of well conditions.
 

This study evaluates a 3-1/2 in. tubing well converted from continuous gas lift to plunger-assisted gas lift (PAGL) using a bypass plunger that initially failed to complete cycles under flowing conditions. The objective is to diagnose the root cause, determine operational boundaries for PAGL in 3-1/2 in. tubing, and assess the feasibility of PAGL relative to tubing replacement and higher gas-injection strategies using field data and plunger lift mechanistic models.

Steady-state multiphase flow simulations and drag-based mechanistic models were used to estimate plunger fall and upstroke velocities along the well, cycle durations, and kinetic energy at impact. Model results indicated that a 14-in. bypass plunger should be able to fall against flow rates exceeding 2 mmscf/d for this well. However, field data showed that the custom 3-1/2 in. tubing plunger had an undersized inner orifice, making it too restrictive to fall against flow. Consequently, prolonged shut-in times were required, which increased bottomhole pressure and reduced production. After deploying a proportionally designed bypass plunger with a larger inner orifice, PAGL operation stabilized with a 2-minute shut-in and production increased.

This paper presents a comparative study demonstrating that continuous-flow plunger deployment in larger tubing can provide a cost-effective alternative to tubing replacement, enabling operators to reduce gas injection while avoiding liquid loading.

This case study presents a comprehensive evaluation of how the integration of advanced electric submersible pump (ESP) technologies, efficient gas handling devices, high-efficiency induction motors, and continuous real-time digital surveillance can drive both operational efficiency and sustainability in upstream oil production. The focus is on 22 wells operated by SOGC, Inc. in the Williston Basin, USA, between June 2024 and May 2025. The primary objective of this study is to illustrate how these technological advancements, combined with proactive remote operations, can minimize downtime, extend ESP run life, and significantly reduce the carbon footprint associated with oilfield operations. 
The methodology involved a comparative analysis of production data and downtime before and after the digital service center assumed full control of remote interventions for the operator. The study meticulously tracked ESP performance indicators, such as mean time to failure (MTTF), average run life, and uptime, to assess the impact of digitalization and proactive interventions. Environmental impact was quantified by translating operational improvements into tons of Co2 emissions reductions, directly linked to the prevention of field trips and workovers. The analysis also considered the broader implications of these operational changes on safety and labor efficiency, including the reduction of nonessential field visits and the prevention of potential ESP failures. 
Results from the study demonstrate a substantial improvement in ESP performance and a marked reduction in environmental impact. The adoption of high-performance ESPs and digital operations led to a mean time to failure of 249 days, a significant increase in average run life from 225 days (with standard ESPs) to over 249 days, and ESP uptime consistently exceeding 90%. Real-time surveillance and remote interventions played a critical role in achieving these outcomes by enabling early identification of critical events and minimizing downtime. The adoption of advanced ESP technology and digital operations led to a substantial reduction in carbon footprint by 6% per well per year (approximately 194 TCo2e), achieved through reduced field trips, fewer workovers, and remote interventions that saved over 18,000 km (over 11,322 miles) in driving, reducing emissions by about 5 TCo2e. Three critical remote interventions prevented ESP failures, eliminating additional workover jobs and further reducing emissions by almost 1 TCo2e, for a total reduction of approximately 6 TCo2e. 
This case study offers novel, real-world data on the environmental and operational benefits of enhancing ESP survivability and leveraging digital solutions, an area not previously addressed in the existing literature. By minimizing production loss and nonessential field trips, the operator not only improved operational efficiency but also made a positive impact on the environment. The findings provide actionable insights for practicing engineers seeking to improve both operational and environmental performance in oilfield operations. This work demonstrates that the strategic deployment of advanced ESP technology, combined with digital optimization and proactive remote management, can serve as a model for sustainable practices in the oil and gas industry.

Production operations have traditionally relied on routine well checks and daily to weekly trips to verify well performance and status. While this ensures coverage, it consumes significant field time, fuel, and labor on wells that are already performing as expected.
With the vision to transition from a schedule-based to exception-based well management and with the goal to empower operators to focus their expertise on wells that truly needed attention, while letting data and AI-ML powered automation handle wells that are running smoothly, a small footprint digital ecosystem was deployed on a remote producing facility in West Texas. This facility consisted in six producing wells, one injection well and their respective surface facilities.
The digital ecosystem is designed to enable pump-by-exception operations, and it includes smart controllers and sensors on each well, providing real-time production and equipment data; a centralized analytics platform powered by AI/ML algorithms that identify anomalies, pump-off events, or mechanical issues automatically; automated alerts and dashboards that highlight wells needing attention and suppress noise from normal operations; and mobile tools that allowing field technicians to view pump cards, alarms, history and control wells from anywhere.
This enabled a shift from “checking every well every day” to “checking the wells that need it today.”
This paper shows how next generation technologies that use , small footprint and quick deployment micro controllers powered by AI and ML algorithms can boost operational efficiencies and maximize well’s profitability in all types of wells, including those wells with marginal economics.

1. OBJECTIVES/SCOPE
Modern wellhead inspection systems depend largely on operators interpreting electromagnetic signal graphs displayed on their laptops. Because this task demands both extensive training and unwavering focus, results can vary or be inconsistent due to the subjective nature of human judgment.
This work seeks to present an approach based on intelligent algorithms to reduce such dependency, standardize the results and improve the reliability of the scanning process of production pipes and rods directly at the wellhead.
The current technical and regulatory framework includes the API 5CT standards, with guidelines applicable to EMI (Electromagnetic Inspection). Although these inspections are derived from standards designed for workshops or plants, their adaptation to the field environment presents additional challenges due to the variability of conditions for example the speed of the pipe pulling is not controlled by the EMI inspector, but depends on the capacity of the rig, well conditions and safety concerns on everyday operations of workover rigs.
After completing the testing period in March 2025, the results have been highly satisfactory. To this date ending 2025 approximately 50,000 tubing joints between 2 3/8 and 4 1/2", have been scanned using the algorithm, no errors attributable to the implemented algorithm have been identified. In addition to fulfilling its main objective – to support and improve the interpretation of EMI signals – there has been evidence of significant standardization of results between operators with different levels of technical expertise.
The use of intelligent algorithms has been well received by users, to the point that some operators have begun to require the integration of this type of system in scanning processes. This trend has also aroused the interest of service companies that seek to integrate technologies based on artificial intelligence into their services, as a tool to improve the quality of the results delivered to their clients.
The software significantly reduces the time required to train new operators, allowing them to generate reliable results in less time. The algorithm incorporates a sequence of steps which allow large volumes of data to be evaluated and interpreted in real time.
Programmed logic automates technical decisions based on set parameters and historical defect patterns. Studies show the system's results match or surpass human expert accuracy. This automation is designed to boost operator efficiency and reduce errors, not eliminate human input.

3. RESULTS, OBSERVATIONS AND CONCLUSIONS
The implemented software has proven to be an effective and reliable tool in real field conditions. It can be installed on any Windows operating system and is currently compatible with EMI inspection platforms for tubing and rods.
Among its main functionalities are:
• Elimination of interference and noise typical of the operating environment.
• Real-time processing of electromagnetic signals from MFL (Magnetic Flux Leakage) and MFD (Magnetic Field Detection) systems.
• Generation of automatic classifications based on technical criteria defined by regulations.
The algorithm significantly enhances signal amplitude quality, based on the interplay between tubular velocity, the electromagnetic field within the coil, and the gains applied to digitized signals. This advancement enables more precise classification of tubulars, including in areas that are typically challenging, such as near coupling where signal distortion frequently occurs.

4. NOVEL/ADDITIONAL INFORMATION
This technology represents an evolution in wellhead inspection processes, integrating intelligent analysis tools to reduce human error and standardize results. The algorithm allows for precise filtering and processing of signals, improving the interpretation of defects in production tubulars.
Wellhead scanning is a technically and economically efficient alternative that eliminates the need to transport components to inspection plants, reduces operating time, minimizes environmental impacts from cleaning agents, and lowers costs related to tubular replacement and inventory.
This innovation has significantly enhanced operational efficiency and delivered substantial economic advantages to workover operations.

This study analyzes a comprehensive dataset of mid-to-late life Electric Submersible Pump (ESP) designs deployed in Delaware Basin wells to identify the most effective configurations for high Gas Volume Fraction (GVF) environments. Downhole GVFs are normalized across wells, and ESP designs are categorized by pump stage count, gas-handling pump type, gas separator configuration, and casing size. Cumulative distribution functions (CDFs) are used to evaluate statistical performance differences among these design groups, highlighting which configurations best accommodate elevated GVF conditions. Additionally, run life statistics are assessed using CDFs to determine the optimal ESP design for each installation scenario. Final, relative recommendations are made to balance reliability and produce at maximized GVFs for multiple well conditions.

Oil and gas operators face growing expectations to improve operational performance, manage risk, and demonstrate responsible emissions management. Finalized New Source Performance Standards (NSPS) rules for OOOOa and OOOOb sites enable a more efficient, data-driven approach to Leak Detection and Repair (LDAR) compliance. Under these regulations, operators can use traditional Optical Gas Imaging (OGI) surveys or new technologies approved under the advanced Alternative Test Methods (ATMs). Continuous, real-time monitoring qualifies as an ATM for periodic screening and improves operational efficiency while maintaining regulatory compliance.
This paper focuses on how continuous monitoring supports advanced emission management and operational excellence. Continuous monitoring shifts LDAR programs from reactive, survey-based to a proactive, risk-based approach. By utilizing real-time data and actionable alerts, operators can locate, quantify and repair leaks in near real time. Operational teams can also prioritize field visits to remote locations based on actual site conditions instead of fixed LDAR schedules. This approach conserves both time and personnel.
Continuous emissions data enables robust desktop diagnostics. Operators validate equipment setpoint adjustments, confirm successful repairs without additional site visits, and quantify known operational activities. These efficiencies improve scheduling, reduce windshield time, and lower operational burden. We present a periodic screening program that leverages continuous monitoring to help operators meet or exceed compliance requirements and maintain constant visibility into site emissions. This approach minimizes the likelihood of undetected leaks and captures intermittent emission events that quarterly OGI inspections may miss.
Real-world implementation of a strategic periodic screening program has reduced required OGI inspection costs by 10 to 25 percent. Emissions trend data, combined with SCADA data, improves root-cause investigations and supports repair verifications. These results provide strong evidence of assurance for corporate sustainability initiatives and commitments. Participants will gain a clear understanding of periodic screening requirements and practical guidance on program design and execution. They will also learn methods for conducting investigative analyses.
Continuous monitoring is an established enterprise-level strategic tool. Its multi-faceted value proposition includes operational efficiencies through real-time data and historical trending, stronger regulatory compliance assurance for informed decision making, and greater confidence for operational teams and leaders in delivering sustainable, responsible energy.

Examine the structured development and implementation of the Quality Assurance and Quality Control (QAQC) Team at Oxy, emphasizing the team's strategic impact on reducing operational expenditures (OPEX). The QAQC team delivers targeted training in sucker rod maintenance and handling to more than 100 workover crews, conducts systematic audits of pump shops across Oxy's U.S. assets, and actively manages warranty claims to recover costs from equipment failures. The team is also responsible for managing the region's most advanced reclamation programs for production tubing and sucker rods in the Permian Basin. Each month, over 800,000 feet of tubing are systematically processed through three centralized hubs, utilizing rigorous inspection and quality assurance protocols to ensure operational integrity and maximize asset recovery.

Serving as a crucial link between field operations and suppliers, the team's responsibilities include performing detailed root cause analyses of failures, organizing independent laboratory testing and assessments, and working closely with Oxy's Supply Chain Management (SCM) to strengthen contract terms. These efforts help limit Oxy's risk exposure from poor-quality materials and manufacturing flaws.

Insights gained from failure analyses often lead to the creation of Standard Operating Procedures (SOPs) that are embedded into commercial agreements, enabling enforceable quality standards. The QAQC team also leverages warranty clauses to recover funds, ensuring that wells with working interest partners maintain transparent and accurate financial records. Ensuring adherence to both industry standards and Oxy-specific requirements at tubing reclamation facilities is a primary mandate for the QAQC team. The implementation and oversight of Oxy's proprietary inspection protocols at these plants have resulted in substantial annual cost savings, amounting to millions of dollars for the organization. Routine pump shop audits at each site enable ongoing vendor performance monitoring, supporting the identification and resolution of recurring issues.

This paper explores how the QAQC team's audit processes have transformed business operations and supplier qualification criteria. By presenting real-world case studies and detailed failure analysis reports, we demonstrate how these practices have enhanced Oxy's artificial lift systems and offer practical recommendations for implementing similar value-driven strategies in your own organization.
 

Sand production has been recognized by the oil and gas industry as one of the most significant challenges affecting the operation, efficiency, and longevity of unconventional rod-pumped wells. As sand and other solid particles migrate into the pump assembly, they create abrasive conditions that accelerate wear on critical components. This abrasion not only reduces pump efficiency but also increases the risk of premature equipment failure, unplanned downtime, and costly maintenance interventions. 

Given these challenges, operators have expressed the need for sand fallback protection for wells produced on Sucker Rod Pump (SRP) lift.  The industry has responded to this challenge by developing tools that trap sand above the rod pump during a shutdown state. These tools have proven to reduce the total cost of operating a rod pump system by reducing pump plugging and wear. Rod pump sand management tools have improved economics by increasing run life and reducing operational costs.

This paper provides an in-depth look at a commercially available SRP sand management tool. PetroQuip has shared the operating mechanism and operational benefits of the Sand Maze SRP. The operator will share a seven-well study that evaluates the use of this tool on unconventional wells within the Midland Basin.  The operator’s data shows that SRP sand management tools extend run life and reduce the need to pull tubing on standard rod pump failures.

Effective back-check performance is critical in gas-lift systems to prevent reverse flow during injection shut-in. As well-integrity requirements strengthen, operators require barrier solutions that do not impede unloading efficiency or gas-lift performance.

This paper presents a Patented, barrier-qualified 1-inch back-check system engineered to maximize flow capacity while delivering reliable reverse flow isolation. The design increases flow area and positions the check mechanism outside the primary flow stream during injection, protecting it from solids and erosive flow while maintaining low pressure drop and high injection efficiency.

Performance verification using CFD-based flow path optimization, HPHT qualification testing, erosion and solids-tolerance testing, extended cycling and flow endurance trials, and successful field runs. Achieved all acceptance criteria for seal integrity, pressure-drop performance, and actuation reliability.

This technology builds on the proven 1.500-inch platform originally developed for wireline retrievable applications and further development with double-barrier mandrel systems, which established the benchmark for redundant well-integrity protection in gas-lift completions. The 1-inch design utilizes that barrier-qualified back-check technology, delivering high flow efficiency and reliable isolation performance without reliance on a dual-valve mandrel configuration.

This development sets a new standard for flow-efficient, barrier-qualified gas-lift performance in modern completions.

Unconventional reservoirs have accelerated the need for artificial lift strategies that recognize the fundamentally multiphase nature of modern well production. Traditional classifications of wells as strictly “oil” or “gas” producers—and the corresponding artificial lift systems historically assigned to each—no longer reflect operational reality, particularly in liquids-rich plays where substantial formation gas is routinely present. This disconnect often results in sub-optimal lift selection, unnecessary interventions, and elevated operating costs. To address these challenges, the authors introduce Applied Multi-Phase Pneumatic Lift (AMPL), a unified, “Life of Well” methodology that fully leverages the pneumatic contribution of produced and injected gas from initial flowback through end-of-life operations.

AMPL integrates the physics of multiphase flow—including bubble, slug, churn, and annular regimes—into every stage of production planning and optimization. By acknowledging that produced gas immediately imparts a pneumatic component to the system, engineers can more accurately predict fluid-column behavior, manage gradient reduction, and enhance liquid lifting through mechanisms such as micro-bubble generation, foam-assisted flow, gas-lift, and hybrid systems including PAGL and GAPL. This approach requires collaboration across reservoir, production, and midstream teams to align well design, facility constraints, and artificial lift sequencing.
At the core of AMPL is the coordinated application of NODAL analysis, decades of field experience, and continuous operational surveillance. Real-time monitoring provides the feedback loop necessary to adapt to rapid changes in reservoir contribution, gas-oil ratio, flowing pressures, and multiphase flow transitions. These insights support proactive decision-making, minimizing unplanned downtime while enabling responsive optimization of gas injection rates, plunger cycle strategies, and flowback protocols. The result is a systematic reduction of unnecessary workovers, minimized equipment breakdowns, and a meaningful decrease in production engineering workload through automated analytics and 24/7 expert support.

The paper highlights design considerations for pneumatic-lift configurations, performance limits related to flow-regime instability, and operational risks such as gas lift valve chatter under slugging or stratified conditions. The authors demonstrate how integrated data management, predictive analytics, and condition monitoring enhance system stability and overall production efficiency. Importantly, AMPL presents a scalable, sustainable framework that preserves well productivity while reducing operational footprints, extending lift system life, and improving stewardship of the reservoir resource.
AMPL represents a new production paradigm—one that combines science, experience, and real-time intelligence to optimize well performance consistently from day one through plug and abandonment.

Objective/Scope
Optimizing production across unconventional assets requires rapid identification of well performance anomalies, efficient artificial lift optimization, and scalable evaluation of intervention opportunities such as acid jobs and lift-system transitions. Traditional surveillance workflows struggle to keep pace with high well counts, changing lift designs, and evolving reservoir conditions. This pilot study focuses on a digital production optimization system deployed on 441 wells equipped with Gas Lift and ESPs in Permian basin. The scope includes daily surveillance for production optimization, evaluation of artificial-lift transition scenarios, defining surface injection-pressure management criteria for multi-well gas-lift systems, and systematically assessing acid-job performance to determine optimal implementation conditions.

Methodology
A web-based production optimization platform, integrating comprehensive physics-based modeling with advanced AI-driven analytics, was used to continuously process historical and daily production data. The system employs a novel transient reservoir pressure estimation based on dynamic drainage volume computation with multiphase well modeling to characterize reservoir inflow performance, artificial-lift behavior, and deviations from design operating envelopes. Daily computations include productivity-index forecasting, bottomhole pressure tracking, and opportunity identification for lift adjustments (e.g., gas-lift injection tuning, ESP frequency optimization). Statistical analysis of historical acid-job interventions was conducted to correlate treatment success with inflow performance constraints identified and the chemical composition of produced fluids, particularly indicators of solids-related deposition risk. Multi-well gas lift modeling was used to evaluate injection-pressure requirements across groups of wells sharing same compressors and determine suitable transitions between high-pressure gas lift (HPGL) and low-pressure gas lift (LPGL) across shared facilities.

Case Study Results and Observations
Implementation of the platform’s daily optimization recommendations yielded a measurable and repeatable impact across the 441-well asset. Those wells in which recommendations were adopted delivered an average of 6% incremental oil production, primarily driven by optimized gas-lift injection rates and ESP operating frequencies. Concurrently, the field achieved over 20% reduction in average gas-lift usage, reflecting more efficient allocation of lift gas. The acid-job evaluation workflow identified the most favorable PI opportunities by tracking the PI trends associated to inflow issues for treatment success, providing operators with predictive criteria to avoid treatments likely to result in insufficient inflow improvement. Multi-well gas lift network analysis produced a clear guideline for managing surface injection-pressure constraints, including the timing and operational triggers for transitioning wells from HPGL to LPGL compressors to maximize field-wide lift efficiency.

Novelty and Significance
This work demonstrates how an integrated hybrid modeling system—combining physics-based flow dynamics with data-driven techniques, can transform daily surveillance and optimization workflows into unconventional asset management. Unlike traditional manual review processes, the platform delivers continuous, scalable, and objective recommendations for lift-control adjustments and conversions, well interventions, and facility-level gas-lift management. The structured analysis of acid-job performance provides a reliable framework for diagnosing treatment potential from both reservoir productivity and fluid-chemistry perspectives, minimizing ineffective interventions. The simultaneous optimization of ESPs, gas lift, and multi-well injection pressure management highlights the system’s ability to coordinate decisions across diverse lift systems and facility bottlenecks. The pilot results confirm the value of deploying automated, physics-informed digital solutions that enhance operational efficiency, reduce resource consumption, and support proactive field-wide production management.

As the global oil industry increasingly relies on unconventional and marginal assets, operators face a complex array of production challenges. These include high viscosity fluids, significant solid content, gas interference, and the need for deployment in deviated wellbores. Traditional lift methods, such as beam pumping and conventional rotary electric submersible pumps (ESPs), often reach their mechanical or economic limits under these conditions. This paper introduces a next-generation Linear Electric Submersible Pump (LESP) system that integrates advanced permanent magnet linear motor technology with intelligent control algorithms to address these specific downhole complexities.

The discussion focuses on the system's unique mechanical architecture, including a modular motor design and a plug-in power cable connection that significantly reduces rig time and maintenance complexity. Furthermore, the paper details specific proprietary software algorithms designed to manage "stuck" conditions and gas slugs autonomously. These include "Jogging" and "Swing" modes for freeing wedged pumps and gas plug removal logic that prevents underload faults. By combining robust hardware options—such as magnetic flow cleaners for paraffin control—with smart surface control, this technology offers a comprehensive solution for extending run life and optimizing production in challenging well environments.

For decades, VRUs have been deployed as compliance equipment and treated as commodity hardware – sized on rough estimates, lightly engineered, and minimally monitored. The results have been predictable: inconsistent runtime, chronic loading instability, ever-increasing maintenance costs, and a long-standing belief that VRUs simply “don’t work.” This paper examines why that legacy persists and outlines a modern engineering and measurement framework that significantly changes VRU performance, economics, and reliability.

The approach centers on precise sizing, real-time operational data, and flexible deployment strategies designed to match dynamic vapor loads. A comprehensive operational dataset – including pressures, temperatures, load signatures, runtime behavior, oil level, and measured vapor flow – enables predictive maintenance, drift detection, and stable runtime across a wider range of operating conditions. Rather than relying on a single indicator, this data ecosystem provides the analytical foundation for a proactive VRU program. The same infrastructure also supports accurate emissions accounting, turning VRUs into valuable compliance assets as regulators move toward measurement-based methane reporting and as operators work to reduce the significant financial exposure tied to modern methane enforcement.

Field deployments in the Permian Basin show significant improvements in uptime, maintenance cost, and equipment longevity, with operators experiencing fewer cycling events, reduced downtime, and lower LOE. These results indicate that a measurement-driven VRU program can prevent both oversized and vapor-constrained installations, significantly reducing risk while improving economic return.

This paper will present the engineering principles, measurement insights, and early field learnings behind this next-generation approach – and why solving the long-standing VRU problem ultimately turns vapor recovery from a perceived liability into a measurable, high-value asset.

Beneath the Surface: Data-Driven Analysis Illuminates Well Performance
Artificial lift decisions directly influence production sustainability and operating costs across thousands of unconventional wells. Yet despite the volume of data surrounding rod-lift systems, the information that should guide performance improvement often remains scattered across departments and disconnected from the equipment responsible for delivering results. Without visibility into what is happening beneath the surface, operators are left to make equipment decisions based on assumptions, delayed diagnostics, and after-the-fact interpretation.
This paper introduces an Integrated Well Tracking System (IWTS), a platform designed to close this visibility gap by linking production behavior with equipment configuration and documented failure mechanisms throughout run life. Instead of waiting until a pump is pulled to learn whether a specialty component performed as intended, IWTS allows operators to monitor its impact while the well continues producing.
A field analysis in the Permian Basin demonstrates how this shift in visibility alters operational outcomes. Across 1,811 cage installations, wells equipped with vortex flow one-piece cages exhibited a reversal in declining production behavior. In addition, these wells showed reduced rates of cage and valve related issues compared to common conventional designs. These results, made possible by data integration rather than delayed teardown evaluation, highlight how component geometry can significantly improve production efficiency and durability under real-world operating conditions.
By bringing equipment performance into view while wells remain online, IWTS provides earlier and more actionable insight into what is working, and what is not. This enables clearer justification for equipment investment, reduces uncertainty in optimization decisions, and supports more proactive rod-lift management. As the system continues to evolve, expanded automation and AI-assisted analytics will further strengthen performance benchmarking and operational judgement. Training and support will ensure operators can fully leverage these capabilities to drive continuous improvement across their wells. Together, these advancements redefine artificial-lift performance, illuminating a future guided by data-driven insight.
 

The Oxy Texas Delaware North Business Unit (TXDN) experiences frequent premature failures from severe downhole corrosion due to reservoir conditions and chemical undertreatment in wells with <1yr operating life. Typical damage occurs on undertreated annular gas lift wells near cap-string clamps/bands. Turbulent flow occurs on these components from high velocity flowrates, stripping chemical protection for corrosion to develop. From Jan 2022 to May 2025, ~28% of rig work addressed corrosion-induced tubing failures, costing $63.7MM cumulatively. In TXDN, ~15% of wells are chemically undertreated, decreasing runtimes and increasing failures.

TXDN is trialing three solutions to mitigate downhole tubing corrosion: 1) Externally coated tubing, 2) Internal capillary strings for chemical injection, and 3) Automated chemical injection. Since Oct 2024, 13 resin-coated tubing strings from BondCoat have been ran without failure at an economically incremental cost $6/ft. Since Nov 2024, two internal cap strings have been installed successfully for $13M per install incrementally. Both methods eliminate external clamps/bands--the main corrosion induced failure locations. To address undertreatment, TXDN implemented automated injection logic using NEXUS well test data, enabling daily rate adjustments and real-time monitoring, reducing reliance on weekly vendor changes, and keeping chemical treatments consistently on target.

While still in the trial stages, TXDN has successfully implemented automated chemical injection logic, external tubing coatings and internal capillary strings as methods for corrosion prevention. The measure of success will be if the tubing strings can last long enough for the wells to require conversion from annular flow to tubing flow gas lift, indicating the elimination of a premature failure and costly workover. This would deliver approximately $18.6MM/year in savings due to unnecessary workovers being eliminated. Measuring treatment targets from automated chemical injection is done in real time through Cygnet and Pi trends. With the automated chemical trials scaled up, the team is projecting a discounted cash flow of ~$610M across new drills for EOY 2025 through 2026.

Looking forward, automated chemical logic is in the process of scaling up all existing wells with DC3 controllers and installed for all future wedge wells. Cygnet and Pi screen surveillance are being built out in tandem to controller logic implementation. 
The internal cap string tool has been redesigned so that it can accommodate 2-3/8", 2-7/8", and 3-1/2", tubing and trials for 2-3/8" tubing during first lift installs will begin in Aug 2025. Along with externally coating tubing, these technologies will be considered for TXDN "One Lift" Trials including Hybrid and/or EC Mandrel gas lift designs. 
 

1. OBJECTIVES/SCOPE: 
Horizontal drilling is an essential technology for exploiting unconventional resources. However, wellbores often include zones with high Dog Leg Severity (DLS), which can limit the installation of Electrical Submersible Pumping (ESP) systems at the deepest possible setting depth. Placing the ESP as deep as possible is critical to maximizing recovery and cash flow. This work highlights the successful application of curve ESP systems in Permian Basin wells with DLS values of 17°/100 ft, and discusses both the challenges encountered and the potential benefits of this technology.

2. METHODS PROCEDURES, PROCESS: 
The industry standard tolerance for deviation is approximately 6° per 100 ft for a conventional ESP system to reliably pass through the curved section of a wellbore. In this study, deviation surveys from several wells were carefully evaluated, and stress analysis was performed to assess mechanical stresses and the potential risk of equipment failure when navigating high-DLS zones. A group of wells with elevated DLS values was selected as pilot candidates for deployment of the new curve ESP system. Well models were developed, and sensitivity analyses were conducted to evaluate the impact of pump setting depth on production performance. The ESP systems were subsequently designed and installed, with production data collected and operating parameters closely monitored.

3. RESULTS, OBSERVATIONS, CONCLUSIONS: 
Based on stress analysis simulations, a standard ESP system wouldn’t be able to pass through zones with high DLS. In the first install a conventional ESP was installed and the system setting depth was shallow. The unit was subsequently pulled and replaced with a curve ESP system, allowing for a deeper setting depth while passing through zones with DLS of 12°/100 ft. The pump setting depth was increased from 6,660 ft to 7,800 ft—an additional 1,100 ft. As a result, production increased by 75%, adding 550 BOPD and generating approximately USD 1 million in the first 30 days of operation. The unit has since demonstrated stable operating trends with minimal X- and Y-axis vibration, indicating limited mechanical wear.
In a separate case study, two curve ESP systems were deployed in a well with DLS of 17°/100 ft consecutively. The first unit achieved a run life of 802 days, while the second operated for 551 days, further demonstrating the reliability and field-proven performance of this technology.

4. The standardized industry practice for deploying ESP systems in wells with high DLS is to avoid traversing the curved section by setting the pump at a shallower depth. Alternatively, operators may attempt to pass through by reducing pump length, which typically requires decreasing the number of stages, thus limiting lift capacity and selecting smaller motors, which reduces available power. Both approaches compromise system performance and production potential. The curve ESP system provides a viable solution to these mechanical and hydraulic limitations, enabling reliable installation at greater depths and unlocking the full production capacity.
In short, the post is important because it demonstrates Baker Hughes’ thought leadership, technical expertise, and investment in the next generation of engineers, while also reinforcing their role in delivering measurable value to the energy industry.

Objective/Scope:
Presentation will review design, installation, and results of recent novel artificial lift pilot in the DJ Basin.
GALLOP (Gas Assisted Liquid Lift Oscillating Pressure) is a new variant of gas-lift, designed to unload
horizontal wells from the lateral. Unloading from the lateral can add years to a well’s life by preventing
heel loading when reservoir pressure drops too low to keep a well unloaded between the lateral and the
end of tubing.
Methods/Procedures/Process:
GALLOP system pilot was meticulously planned over multiple years prior to execution, in close collaboration with Scott Wilson (patent holder), Well Master / VaultPC (manufacturers), PETEX, and internal Oxy teams. Detailed system modelling was performed prior to install to ensure success (GAP
Transient, CFD modelling of downhole valve assembly, etc). Custom wellhead and downhole equipment were designed and manufactured to meet project scope. Candidate well was identified (low reservoirpressure well with existing gas lift infrastructure). GALLOP was successfully installed (workover / surface construction) following extensive planning with the Well Intervention and Surface Construction teams.

Results/Observations/Conclusions:
GALLOP pilot has successfully extended the life of the candidate well, which otherwise would have beena P&A candidate. Initial production with GALLOP proved that the system is capable of moving the target outflow – 20 BLPD flowrate for the pilot well, and modeling indicates the system is capable of producing rates up to ~40 BLPD if inflow will permit. Pilot well rates have fallen off faster than expected due to productivity being below expectation (well-quality inflow issue as opposed to artificial lift outflow issue). Even with inflow-related drop in production, GALLOP system has proven that it can stably produce rates as low as ~3 BLPD from the lateral, and potentially lower. Due to low rate nature of late life production,
GALLOP system will be most economically attractive on wells with existing gas lift infrastructure, and is potentially broadly applicable across US Onshore assets.

Novel/Additive Information:
GALLOP is a new type of gas lift that utilizes concentric tubing to produce from the lateral. Fluid enters into the tubing system through a downhole check valve during the ‘fill’ phase. Injection is intermittently applied down the annulus between the concentric tubing strings, which closes the check valve and lifts fluid that has entered the tubing system to surface. The Oxy pilot in the DJ Basin was installed and kicked off in early 2022, and is the first and only pilot of this system in industry to date. A review of the system with the wider SPE audience could unlock late life production from wells that would otherwise be candidates only for P&A.

The efficient management of gas lift systems is pivotal in minimizing operational costs and maximizing production for a large majority of unconventional wells. By leveraging automated workflows to efficiently build and tune physics based nodal analysis models, operators can optimize well performance and gas injection rates thus reducing operational expenses. A cornerstone of effective gas lift optimization is the seamless integration of real-time data with physics-based models. Automated assisted workflows streamline this process which enables continuous optimization of gas lift injection rates to compensate for changing production rates, gas liquid ratios, and reservoir pressures.

The author emphasizes the value of having an evergreen tuned well model to optimize every gas lifted well. Optimization can be realized in some cases by increasing or decreasing gas injection, as the model often shows over injection can reduce production. The challenges in realizing the value from a physics based well model for every well include staff time to build and maintain the models, time to tune the models, and time to make gas injection rate adjustments. The gas lift optimization workflow presented requires significantly reduced engineering staff time by letting automated processes continuously complete the majority of the workflow.

Automated Model Building
In order to efficiently build physics based well models for hundreds of wells, a unique data loader was developed through a collaborative effort between various teams. This process merges wellbore, completion, and production data from multiple databases into a centralized staging table used to create the model. Any missing model data such as fluid gravities, reservoir pressures, and pipe roughness factors are manually entered by the engineer to complete the well model generation. This workflow dramatically reduced the time required by engineering staff to build well models. In addition to building the initial model, the data loader automatically updates the model with any changes made to a well following workover activities.

Automatic Model Tuning
To keep the model evergreen, software automatically tunes the model using every well test. The Inflow performance relationship (IPR) and Vertical lift performance (VLP) variables are derived from the nodal well model, while Injection Rate, Tubing Head Pressure (THP), Casing Head Pressure (CHP), Water Cut (%) and GOR are extracted from production test data to construct an updated gas lift well performance curve. This performance curve facilitates the gas lift optimization process by ascertaining whether there is an under- or over-injection.

Autonomous Control Logic (ACL) through Enterprise
ACL, which was created through a collaborative effort of subject matter experts and computer programmers, was designed to use the tuned model’s performance curve to determine optimum injection rates for each well. The ACL accomplishes this by running solutions at rates above and below current injection rates and solving for total fluid rates and oil production. Based on these results, and parameters set by the Operator within the ACL control interface, the system automatically suggests an optimum injection rate. The frequency of optimization runs can be easily defined by the Operator but is typically done every 4 hrs as the ACL continuously adjusts to optimize the gas injection rate.

Results, Observations, Conclusions
As a result of this automated workflow, Operators can much more efficiently have all gas lift wells modeled, automatically tuned, and automatically optimized for production and associated gas injection rates. As a result of applying this workflow, Operators can realize either reductions in gas injection rates with no loss in production or incremental oil production associated with incremental gas injection.

In conclusion, the deployment of this highly automated workflow can create significant value for Operators by allowing them to efficiently utilize physics-based models to continuously optimize their gas lifted wells. Future improvements include enabling full ACL logic to continuously adjust gas injection rates via automated control valves without human intervention.

Jet lift systems have earned a strong reputation as an effective artificial lift method for unconventional oil well production across the most prolific hydrocarbon-producing regions in the United States of America. In prolific reservoirs such as the Permian Basin, Eagle Ford, and Bakken, operators have successfully utilized jet lift as the primary lifting method for challenging oil wells. Additionally, operators in the Eagle Ford Basin have consistently employed jet lift as the main production technique for their wells.

Like any other artificial lift system used in unconventional oil well production, jet lift has its strengths and weaknesses. Its most notable advantage over other powered production methods is its ability to handle a wide range of flow rates, from 10 barrels of fluid per day (bfpd) up to 5,000 bfpd, using the same jet pump size. The jet pump “free pump” feature, which allows the operator to hydraulically retrieve and reinstall the jet pump without the need for workover or wireline using only reverse power fluid circulation; and is also widely recognized as critically important in the artificial lift selection matrix.

The most common problems that need to be addressed during the implementation of jet lift systems typically include: uncertainty regarding the placement of the jet pump cavity or the optimal depth for the deviation seating point; determining the right moment to start producing the well using the jet pump after the early flowing-well production stage; identifying the most effective initial nozzle-throat combination; selecting the most cost-effective surface equipment capacity (horsepower) for the user; managing the well's transient behavior by resizing the jet pump nozzle-throat combination; preventing cavitation in the jet pump during both early and late production stages; and, finally, developing a properly designed strategy to convert from jet lift to rod lift.

This paper provides a clear discussion of the issues and challenges associated with jet lift operations, along with field-proven solutions successfully implemented in the Eagle Ford formation across approximately 150 jet-pumped wells.
 

Frac hits in unconventional developments often cause persistent liquid loading, increased flowing pressures, and reduced lift efficiency in offset gas-lift wells. These effects are largely driven by trapped frac fluids, elevated water saturation, and unstable multiphase flow, all of which delay production recovery. This paper evaluates the use of targeted surfactant treatments to accelerate post–frac-hit cleanup and restore gas-lift performance.

Laboratory screening—including foam height, foam break test, and emulsion tendency test on fluid samples collected from candidate wells. The results confirmed the efficacy of the surfactant and showed no adverse effects on oil emulsion or water quality. The surfactant was then tested for compatibility with the combination corrosion/scale inhibitor to verify no adverse effects. Field applications in impacted gas-lift wells showed improved unloading, lower flowing bottomhole pressures, and faster stabilization compared to conventional lift optimization alone. Several wells achieved earlier return to pre-hit production trends and incremental oil uplift.

Results demonstrate that surfactant-assisted recovery provides a low-cost, low-intervention method to mitigate frac-hit impacts and enhance gas-lift effectiveness in tightly spaced unconventional developments.

The Appalachian Basin, specifically the Marcellus and Utica shales, are known for their initial low water-to-gas ratios and appealing high gas rates.  This, however, leaves operators with establishing phase of life flow paths as the well declines.  Installing production tubing too early leaves the asset producing at a constrained rate due to frictional losses downhole.  These constraints have been observed to be as much as 30% - 40% depending on flowing conditions.  Installing production tubing too late; leaves the asset vulnerable to slug flow and deviation from natural decline impacting cash flows.  Utilizing a Production Engineer to run nodal analysis to understand exact timing of tubing install can be unrealistic and logistically challenging for procuring material and resources for large-scale tubing programs.    
  
Through engineering efforts along with automation of field devices, an evolution of previously deployed plunger lift optimization efforts traditionally leveraged for optimization of depleted wells and assets resulted in the successful implementation of a unique artificial lift technique called Plunger Assisted Annulus Flow (PAAF).  PAAF is targeted to be installed in combination with the installation of production tubing which is approximately 30% above the calculated Turner critical rate in 5-1/2” production casing.  PAAF allows for bottom hole pressure to be drawn down until the full well stream can be diverted up tubing without any constraints.  This is achieved by simultaneously flowing the annulus and tubing while cycling a continuous-style plunger in the tubing.  Each plunger cycle is initiated when flow rates drop below annulus critical rate and is needed to help evacuate fluid hold up that starts to occur in the annulus.  

PAAF allows Production Engineers to focus on evolving their business, provide a smooth decline to aid in more accurate forecast generation, and support more predictable cashflows in volatile market conditions.  
 

Operators of marginal plunger lift wells face significant challenges in optimizing performance while managing tight economic constraints. These wells, characterized by lower flow rates, are often highly sensitive to operational costs, making it difficult to justify investments in advanced digital automation and control systems. Yet, these wells represent a substantial portion of production assets and have the potential to benefit greatly from enhanced efficiency, reduced operational expenses, and extended productive lifespans.

To address these challenges, a new solution has been developed to provide advanced digital capabilities tailored to the unique needs of marginal plunger lift wells. This system offers fully automated operations, high-resolution data analysis, and real-time diagnostics, enabling operators to make informed, data-driven decisions. 

The control systems programmable and upgradable architecture enables operators to develop unique algorithms tailored to each wells specific operational situation. This flexibility addresses a wide range of challenges and makes it possible to optimize performance regardless of changing conditions, production goals, or economic constraints. With additional features such as remote monitoring, local Wi-Fi connectivity, and IoT integration, the solution ensures operators can oversee and optimize well performance from virtually anywhere, reducing the need for frequent site visits and minimizing equipment wear.

Designed with affordability and scalability in mind, the system bridges the gap between high-end SCADA controllers and standalone devices, delivering the sophistication and connectivity of advanced automation at a cost that aligns with the financial realities of marginal wells. Its upgradable architecture and plug-and-play simplicity make it an accessible and practical choice for operators looking to enhance profitability, fully recover reserves, and streamline operations. 

By empowering operators with actionable insights and seamless control, this solution transforms marginal plunger lift wells into efficient, productive assets, bringing them into the digital age without compromising on cost-effectiveness.
 

With an estimated 46,000 producing horizontal wells in the Permian Basin currently yielding less than 200 BOPD, operators are facing a growing inventory of declining wells. This base production decline must be continually offset by new well additions—an increasingly costly and resource-intensive strategy. As a result, the industry is experiencing a resurgence of acidizing treatments in horizontal wells as a means to restore productivity and extend asset life.

Transitioning from traditional acid treatments applied to short vertical pay zones to long horizontal laterals introduces new complexities in treatment design and execution. Achieving consistent production uplift and sustained well performance requires innovation across multiple technical dimensions. Advances have emerged in candidate selection methodologies, surfactant chemistry, diversion techniques, equipment design, stage optimization, and scale management practices following acid stimulation.

This paper presents the latest strategies and innovations driving the effective revitalization of horizontal wells through acid stimulation. Emphasis is placed on integrating modern chemical systems, operational best practices, and field-proven designs to maximize production gains while maintaining long-term well integrity.

Sucker rod pumping for horizontal wells has advanced considerably over the past few years. Advancements in sucker rod pump technologies and bottomhole assembly (BHA) components/configurations have allowed for more efficient downhole gas separation and greater production drawdowns. The unintended consequence has been an escalation of solids in the produced fluids with increased failure frequencies.
Solids control while sucker rod pumping horizontal wells is risky, complex and tricky, especially for when lowering a pump into the curve or using Extended Dip Tube systems in the curve. Extended Dip Tube systems position the pump in the vertical or near vertical and place the gas separator deeper in the curve.
Lab and field studies confirm that gassy-slug flow moves solids as migrating dunes/beds. These dunes accumulate (over weeks and months during steady production) in the lower portion of the wellbore’s curve section where gravity starts limiting dune migration. The risk is any surge in gas rate, flow interruption, or shutdown instantly mobilizes the accumulation of solids as high-concentration solids slugs—overwhelming BHA’s and causing stuck/failed pumps.
A comprehensive systems solution was essential: advanced BHA’s paired with targeted operating practices to defeat solids slugging. The following solution has proved effective:
1. Apply operational practices to control and limit formation high concentration solids slugs:
a. Invoke a preventative maintenance casing flush program, especially after shutdowns
b. Employ operational practices that avoid gas rate surging and spiking
c. Employ rod pump controller logic that reduces slug flows
2. Design the BHA with technologies and configurations that limit slug flows.
3. Design the BHA with technologies that firstly “bust up” solids slugs and then separate solids for containment out of harm’s way. This includes a slug busting solids separator that operates at high inclinations (such as 90 degrees).
4. Design the pump to efficient convey solids through itself.
Results from implementation of this comprehensive approach with innovative solids control and separation technologies will be shared and discussed.

As rod lift systems are extended to greater depths and tasked with higher production rates, operators face increasing complexity in maintaining reliability and cost-effectiveness. Elevated loads, deeper pump landings, and aggressive environments introduce compounded risks, including rod and tubing wear, bending fatigue failures, corrosion fatigue, and connection reliability issues, among others. Simultaneously, business strategies demand earlier conversion to rod lift and compatibility both with large size (long stroke) and mid-size pumping units such as 912 and 640 to deliver more production and deeper.
To address these challenges, a structured development program was initiated in 2016, aimed at expanding the operational envelope of rod lift through a portfolio of engineered solutions. This effort progressed from proof-of-concept designs to full integration by 2024, incorporating advanced materials, optimized geometries, finishing technologies and string design optimization to mitigate the challenges and enhance system performance.
Field validation across diverse environments demonstrated measurable improvements in runtime, reliability, and production capacity. The 1K @ 10K framework reflects a systematic approach to design and integration, enabling rod lift systems to meet the demands of modern high-value wells while maintaining operational integrity.

Large-scale plunger lift operations demand surveillance methods that can balance proactive optimization with targeted field intervention. To replace route-based monitoring, Occidental Petroleum developed an integrated closed loop control program as well as SCADA based exceptions for its 2,000+ plunger lift wells. Plunger Lift Artificial Intelligence (PLAI) delivers proactive plunger lift optimization by blending real time well data with machine learning and decision logic, enabling timely alerts and automated setpoint updates. By leveraging JSON-based logging, every data point and automated setting change is documented in a structured format, enabling personnel to clearly understand each system action. SCADA is utilized for manual setpoint changes, tracking plunger components and categorizes various alarm types to enable targeted responses. When actions from either remote system prove insufficient, the system allows company personnel to send field callouts for specific well maintenance issues. Implementation challenges include the continued redistribution of stakeholder responsibilities, keeping PLAI’s algorithms and capabilities current and managing automation equipment and reliability. This paper outlines the surveillance framework, discusses implementation challenges, and presents a case study showing efficiency gains from shifting to a combined automated and exception-driven strategy.

Oil wells utilizing Electric Submersible Pump (ESP) systems require substantial electrical power for continuous operation leading to large operation electrical expenses and inefficiencies in traditional induction motor (IM) setups. This paper presents a comprehensive analysis of integrating Permanent Magnet Motors (PMMs) into ESP configurations to achieve superior power densities and operational efficiencies. By leveraging unique motor construction and advanced variable speed drive (VSD) controls, PMM-powered ESPs demonstrate up to 95% energy conversion efficiency which can significantly outperform IMs through minimized rotor slippage, reduced excitation losses, and precise torque delivery under variable downhole conditions. Field trials across multiple wells in the Permian Basin demonstrate real power savings of 10-25% due to lower losses and optimized load matching, while total input power (real + reactive) reductions of 20-30% stem from power factor improvements exceeding 0.95 eliminating the need for larger surface equipment typically required for IM applications. For larger ESP applications in 7 inch and 9-5/8 inch casing sizes that can accommodate larger 500 and 700 series motor selections, this paper provides a comprehensive review of ESP design analysis, surface equipment selection and optimization, and fundamental design challenges and integration covering the uniqueness of PMM drive ESPs

Downhole separation is a critical process for proper sucker rod pump operation. This technology has been successfully applied in vertical wells, providing a solution for gas interference. New horizontal wells present a new challenge to this technology, since slug flow is a predominant flow pattern when sucker rod pumps are implemented. Many experimental studies have been conducted in the past that consider the continuous injection of gas and liquid near the separator inlet. For these cases, separators are operated continuously, and the separation efficiency is primarily measured in terms of vertical position. Thus, there is a need to develop an experimental procedure that considers the intermittent action of the sucker rod pump, as well as the inclination effect.

This paper presents a novel experimental procedure to characterize the performance of donwhole separators under the periodic behavior of a sucker rod pump. The paper describes the facility and the measurements. Computer vision algorithms are used to measure the gas void fraction entering the pump, as well as the bubble size distribution. Results for a poor boy are also presented and compared with the case of a single deep tube.