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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Determining BHP is key when optimizing production in oil wells. Inclusion of intermittent gas lift or plunger lift causes a change in BHP at specified intervals, typically at a set pressure. In turn, these artificial lift systems create an additional factor when determining BHP and must be accounted for accordingly. This project will explore one of these topics. 
 

S curve wells and high kickoff wells pose great challenges to artificial lift, specifically, wells drilled with gas lift in mind and needing to be changed to ESP or rod lift in the future. This poster examines operational constraints of these wells, including complications in installation, pump performance, and bottom hole pressure.
 

This project focuses on the impact that VFD can have on sucker rod pumps regarding fluid production, power consumption, rod loads, among other possible effects. 
 

Using permanent magnet motors to power electrical submersible pumps provides a more enhanced performance in terms of electrical consumption, efficiency and the type of challenging and unconventional wells that it can operate in. Therefore, industry professionals, through laboratory testing, find PMMs to be a superior alternative for induction motors due to their practical and economical benefits. 
 

Study of corrosion fatigue and its effects on sucker rods. Study of the effects and applications of corrosion inhibitors. 
 

"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."