"Cyclic air-steam injection (CASI) is emerging as a promising method for producing hydrogen directly from heavy oil and bitumen reservoirs, offering a potentially low-cost and low-emission alternative to conventional hydrogen production technologies. In this study, a Lloydminster heavy oil reservoir model was developed in CMG STARS to simulate in-situ hydrogen production using CASI. The process involved alternating air and steam injections in cycles over a 20-year operational period. To optimize key engineering parameters, a sub-model optimization was performed using a differential evolution algorithm, and the optimal injection parameters were subsequently scaled up for field-scale simulations. A techno-economic analysis (TEA) was also conducted to estimate hydrogen production costs and carbon emissions. Optimization results revealed significant variability in cumulative hydrogen production across different parameter sets, underscoring the sensitivity of hydrogen yield to engineering design and the necessity of precise process control. At the field scale, the simulation predicted a cumulative hydrogen production of approximately 7,000 metric tonnes over 20 years. The TEA estimated a hydrogen production cost of $2.32/kg H2, with a carbon emission intensity of only 1.62 kg CO2/kg H2—both lower than conventional steam methane reforming (SMR) combined with carbon capture, utilization, and storage (CCUS). These findings highlight CASI as a viable and economical alternative for hydrogen production, offering both reduced carbon emissions and competitive costs. This research provides a strong foundation for advancing CASI as a clean and cost-effective in-situ hydrogen production method, paving the way for future development and field implementation in heavy oil and bitumen reservoirs."
 

Unconventional play drilling and completion are pushing for longer laterals and more aggressive fracturing to maximize reservoir contact. On the other hand, there is no one-size-fits-all solution for artificial lift. This study characterizes artificial lift trends in the Midland and Delaware Basins using a dataset of well completions, production performance, and lift methods. Results show distinct variations in lift selection driven by geological differences, gas-oil ratio, well depth, and lateral length. The Midland Basin is skewed toward ESPs and rod pumps, with lower GOR and shallower depths, while the Delaware Basin presents a higher preponderance of gas lift due to deeper wells and higher GOR. Second, the concept of lift has been in a stage of evolution: from changing reservoir conditions to changes in completion design. Though the dataset does not provide in-depth operational details the observed trends shed light on artificial lift practices, highlighting industry preferences and areas where optimization may be possible.
 

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.

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.

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.
 

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.

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 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.  
 

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.

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. 
 

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.
 

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

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.

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.

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.

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.

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.

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.
 

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.

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.

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.

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.

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.
 

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.