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Abstract Rod and tubing wear, caused by the relative motion between these components under dynamic loading and harsh downhole conditions, is a major challenge in rod-lifted wells, particularly in corrosive environments. In U.S. unconventional operations, this issue represents a significant portion of rod-lift OPEX. This paper presents an integrated approach—combining laboratory testing, material innovation, optimized string design, and operational practices—developed over three years of collaborative research and field implementation. Root Cause Analysis identified wear driven by rod-tubing interaction. To replicate these conditions, two full-scale laboratory protocols—Tribocorrosion Sliding Test and Abrasive Sliding Test—were developed, enabling controlled variation of environmental factors, loads, and fluid or abrasive constituents. The program included a wide range of products and materials commonly used in oil-producing wells to establish performance benchmarks. Insights guided the design of a new sucker rod material, introduced to the market and validated through field trials in the Williston Basin, complemented by optimized string configurations and operational adjustments. Laboratory testing demonstrated significant reductions in wear compared to conventional materials across multiple product categories. Field trials confirmed these findings, showing measurable improvements in run life and reductions in wear-related failures. Beyond material performance, results indicate that combining advanced materials with optimized string design and operational practices—such as load balancing and stroke adjustments—provides a holistic strategy for mitigating wear. This integrated approach, developed through three years of coordinated R&D and field validation, demonstrates that system-level optimization is critical for reducing OPEX and improving reliability in unconventional environments. The paper will detail comparative wear data, operational adjustments implemented during trials, and lessons learned for future applications in similar operating conditions. This work introduces a commercially available sucker rod material specifically designed to mitigate wear caused by rod-tubing interaction, supported by full-scale laboratory testing and field validation. It also proposes a comprehensive strategy for rod-lift systems that integrates material selection, string design, and operational practices, offering a replicable framework for future developments in challenging environments.

Inflow control devices (ICDs) are increasingly used in steam-assisted gravity drainage (SAGD) operations to improve steam chamber conformance, delay steam breakthrough, and enhance bitumen recovery. More recently, ICDs incorporating internal flashing—a phenomenon during which water vaporizes due to localized pressure drops inside the ICD tool, mostly at the vena contracta—have gained attention for their potential to further optimize steam and fluid control. Industry designs often aim to increase the extent of flashing, assuming that this leads to improved performance. However, this approach may result in overchoking, which restricts flow unnecessarily and can negatively impact oil production. In this paper, we introduce a novel steam-sensitive flow control device designed to restrict the production of steam and low-subcool liquids while allowing higher mobility of oil-phase fluids. By preferentially limiting flow from zones with high steam saturation or low subcool, the new ICD (branded as EQUALIZER Dart) helps retain steam energy within the reservoir, directs heat to colder regions, minimizes sandface erosion, and supports the growth of a more uniform steam chamber. This approach enhances thermal efficiency, promotes bitumen mobilization, and may accelerate overall production rates. A central concept presented is sandface subcool, defined as the temperature difference between actual reservoir temperature and saturation temperature at the sandface, based on localized pressure. When the sandface subcool approaches zero, the likelihood of steam flashing increases, which may lead to steam coning and early steam breakthrough. The ICD contributes by increasing upstream backpressure, thereby raising sandface subcool to just above zero. Importantly, this study challenges some operators’ practice of maximizing subcool (to combat vapor returns), showing that excessive increases can be counterproductive and reduce flow performance. In this paper, we present the first field implementation of this new ICD in the Athabasca McMurray oil sands reservoir, specifically within the Surmont I SAGD operation. Field production data were analyzed using a newly developed modeling tool, which captures both micro- and macroscale flow behavior. At the micro scale, the model was calibrated using nozzle-level pressure drop data matched against flow loop experiments. This calibration was then integrated into full well-pair simulations to evaluate field-scale performance. Results demonstrated improved well conformance; however, early oil production was impacted by cold-toe conditions. To mitigate this issue, alternative ICD configurations and completion strategies are proposed for future brownfield applications. Additionally, a novel diagnostic chart is introduced, leveraging distributed temperature sensing data to monitor ICD performance and steam chamber development throughout the production life cycle.

Through recent advancements in Rayleigh Frequency Shift Distributed Strain Sensing (RFS-DSS), the ability to derive cluster level production insights has improved significantly. This study focuses on two horizontal wells in the Delaware Basin, each landed in different layers. The objective is to compare in-well production strain during shut-in to understand differences in effective fracture geometry and identify how variations in completion design and geology contribute to these differences. This study conducts a comprehensive analysis that compares in-well production strain attributes, such as mechanical strain magnitude, widths and depth alignment with perforation clusters, between two horizontal wells in the Delaware Basin. Using these strain attributes to further characterize the effective fracture geometry, a coupled fluid flow and geomechanics model was employed to simulate and calibrate strain change behaviors. Additionally, the study systematically examines completion design and operational history to identify key factors driving the observed differences between the wells. Key findings from analysis showed that attributes such as average strain peak, notably differed by as much as 400%. Additionally, the mechanical strain change peaks in the Well 3H often showed misalignment with the perforation cluster depths, indicative of higher frac tortuosity. In contrast, Well B4H shows that strain peaks align exactly with perforation locations. Completion design in B4H has a significant impact on both the strain peak magnitude and zero-strain width, whereas these effects were less of an influence in the 3H. Furthermore, the calibration of the coupled flow/geomechanics model indicated that the fracture conductivity was lower in the 3H when compared to the B4H. The difference in proppant amount has been identified and may contribute to the reduced conductivity observed in 3H. Additionally, the wells are located in different geological layers, which may be another reason for the observed variation. This study reveals differences in calibrated fracture geometry across geological layers in the Delaware Basin and highlights the impact of completion designs, using high-resolution in-well strain measurements from fiber-based monitoring during the production phase. The findings provide practical guidance to obtain information for optimizing horizontal well landing depths and improving completion designs in future wells.

Abstract Mineral scale formation remains one of the most encountered flow assurance challenges in upstream operations. Despite more than 70 years of efforts, the oil and gas industry still lacks a universally accepted framework for combining field measurements, scale modelling, and risk evaluation into coherent field management decisions. While individual operators and service providers have developed their own policies and practices, the absence of standardized guidance creates inconsistency in how scale threats are assessed and risk mitigation strategies are addressed across the industry. This paper proposes a comprehensive methodology to standardize inorganic scale risk evaluation and provide a structured foundation for scale management strategies. The approach is based on three pillars: Pillar 1. Fluid sampling and chemistry fundamentals. High-quality sample collection and preservation are the foundation for reliably determining scale threat. This paper outlines what defines a good-quality sample, summarizes the most widely used guidance on fluid sampling, preservation, handling and analysis, and describes how compromised samples can still yield valuable information. In doing so, it highlights the critical role of accurate water characterization for both asset integrity management and effective hydrocarbon production. Pillar 2. Scale prediction workflow. Once gas, oil, and water compositions, as well as operating conditions (temperature, pressure, and rates), are defined, thermodynamic modelling can be used to calculate saturation ratios and excess solute values for minerals such as carbonates, sulfates, sulfides, and others. This paper outlines common procedures for conducting robust scale prediction calculations across a wide range of operating conditions and includes a general discussion on the impact of kinetics and fluid dynamics on prediction accuracy. The goal is to provide predictions that are reliable—meaning representative of observed field outcomes—and to frame how such calculations can be used to guide proactive rather than reactive mitigation strategies. Pillar 3. Scale risk assessment guidelines. The third and final pillar links predicted saturation ratios and excess solute values to operational risk in different environments. This is arguably the most debated aspect, as classification ranges often reflect field-specific experience and production portfolio. This paper argues that while such classifications vary, consolidating existing knowledge into common guidelines allow operators to make better informed decisions. This information is also valuable to chemical suppliers, enabling them to predict scale formation more accurately, design better qualification tests, and develop more effective products. By integrating rigorous thermodynamic predictions with standardized practices and professional judgment, the proposed methodology builds a foundation for consistent, effective scale risk management across the industry.

ABSTRACT: Wellbore instability remains a major challenge when drilling weak, shale-dominated formations at high inclinations, and stress anisotropy combined with prolonged exposure time only increases the likelihood of failure. This study develops a comprehensive one-dimensional (1D) geomechanical model to investigate time-dependent wellbore failure mechanisms and to optimize drilling strategies for improved well integrity and operational efficiency. Wellbore breakouts and drilling-induced tensile fractures were analyzed using Logging While Drilling (LWD) ultrasonic imaging to constrain in-situ stresses and rock strength parameters. Multiple post-drill geomechanical models were constructed and iteratively refined using well logs, ultrasonic image data, geological interpretations, and field observations. Model calibration was achieved using drilling experience and formation integrity test results to capture the stress state and failure behavior of the formation. The integration of LWD ultrasonic imaging provided highresolution insight into borehole wall conditions, enabling accurate identification of breakout geometry, azimuthal persistence, and stress orientation. Comparison of up-pass image runs revealed progressive time-dependent deformation within shale intervals under constant drilling conditions. Analysis of failure evolution under Water-Based Mud (WBM) versus Oil-Based Mud (OBM) demonstrated the dominant influence of drilling fluid type on wellbore stability, confirming that replacing WBM with OBM effectively mitigates delayed shear failure and improves drilling performance in complex shale formations.