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.
 

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.

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.
 

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.

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.

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.
 

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.

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%.

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.

Sand production is widely recognized as one of the most significant challenges affecting the operation, efficiency, and longevity of 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.

PetroQuip’s SandMaze SRP reduces the total cost of operating a rod-pumped system by being specifically engineered as a self-cleaning downhole solution to address these challenges. By preventing solids fallback during shutdowns and leading to incident-free start-ups, the SandMaze SRP protects not only the pump but also the associated rod and tubing string from excessive wear, which helps to maintain optimal volumetric efficiency. This results in an operation with diminished friction, reduced maintenance requirements, and extended equipment life. The SandMaze SRP also prevents sand and other solids from migrating down the outside of the pump barrel and accumulating, reducing the risk of blockages and operational issues. By mitigating this sand buildup, it minimizes the likelihood of unplanned tubing pulls during rod part or pump failure workovers.

This paper provides an in-depth look at the SandMaze SRP’s operating mechanism, highlights the operational benefits delivered, and presents field-proven performance data that demonstrates its effectiveness as a cornerstone in modern sand management strategies. Oxy recently completed a six-well study evaluating the SandMaze SRP as a downhole fallback solution to extend rod pump run life. Across the trial, the SandMaze SRP demonstrated consistent protection against sand and solids returning to the pump, which is one of the leading causes of premature pump failure. Wells equipped with the SandMaze SRP showed notable reductions in pump and rod wear, fewer workovers, and longer, more stable production intervals compared to historical performance.

PetroQuip’s SandMaze SRP is ideal for operators seeking a solution that not only minimizes pump wear but also helps avoid costly unplanned tubing pulls during workovers. Operators incorporating this technology have seen measurable results, demonstrating that it significantly mitigates the risks associated with sand production while improving overall rod-pump reliability. Alone with Oxy’s six-well trial, we can account for an overall increase of 181% of the run life.

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.

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.

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.

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.

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.

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.

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.
 

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.

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.

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.

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.

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.

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.

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.