Technology Conference Research Articles

Machine-Learning Approach PredictsGel Strength of Drilling Fluid While Drilling

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35433, “Novel Machine-Learning Approach for Predicting the Gel Strength of the Drilling Fluid While Drilling,” by Ahmed Gowida, SPE, and Salaheldin Elkatatny, SPE, King Fahd University of Petroleum and Minerals. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ Accurately estimating gel strength is paramount for optimizing drilling operations and preventing cuttings from settling at the wellbore’s bottom. Traditional methods rely on rotational viscometers, which are time-intensive, equipment-dependent, and lack real-time monitoring capabilities. This study underscores the feasibility of leveraging machine learning (ML) as a practical tool for predicting drilling-fluid gel strength, offering real-time monitoring and precise predictions to enhance drilling efficiency, safety, and automation initiatives. Background The gel strength of drilling fluid is assessed using a viscometer, focusing on the 3-rev/min reading obtained after agitating the fluid at 600 rev/min to disrupt any gel formation. Initially, the measurement is taken when the mud reaches a static state for 10 seconds. Subsequent readings are conducted at 10- and 30-minute intervals. The rationale behind the 30-minute reading lies in its ability to indicate whether the mud forms a substantial gel during prolonged static periods, such as when tripping out a bottomhole assembly. Elevated gel strength may result in increased pump pressure required to restore circulation after extended static conditions. Additionally, a consistent upward trend in the 30-minute gel strength suggests the accumulation of ultrafine solids. Consequently, appropriate measures such as chemical treatments or dilution with fresh base fluid are necessary to address this issue. The frequency of measuring various fluid properties is tailored to their respective effects on well-control and drilling operations. These frequent evaluations allow for timely adjustments and monitoring of rheological measurements, offering valuable insights into rock sensitivity and the performance of mud activity and stability after exposure to drilled formations. On the other hand, a complete mud test (including all mud rheological properties) is performed twice a day because it consumes considerable time. It has been observed that mud rheological properties exhibit a significant correlation with two fundamental mud properties: mud weight and Marsh funnel (MF) viscosity. To the best of the authors’ knowledge, a dearth of research exists in the literature aimed at predicting the gel strength of drilling fluid using ML techniques. Consequently, this research endeavor introduces a novel ML model designed specifically for forecasting the gel strength of synthetic oil-based mud systems. Such predictive models are poised to enhance drilling performance by optimizing mud functions. Leveraging MF and mud-density measurements, the developed models aim to forecast the rheological properties of drilling fluid, thereby facilitating improved monitoring of mud functionality during drilling operations at the rig site.

Locally Produced Sustainable and Resilient Surfactants for Enhanced Oil Recovery

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 24518, “Locally Produced Sustainable and Resilient Surfactants for Enhanced Oil Recovery,” by Syed Muhammad Shakil Hussain, SPE, Muhammad Shahzad Kamal, SPE, and Afeez Gbadamosi, King Fahd University of Petroleum and Minerals, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ Chemical flooding is a major enhanced oil recovery (EOR) method for recovering residual oil within rock pores. Injected chemicals such as surfactant, however, must be soluble in low- and high-salinity brine, compatible with reservoir ions, and stable at elevated temperatures. The main objective of the study described in the complete paper is to explore the potential of locally produced surfactants for EOR in high-temperature and high-salinity reservoir environments. Design and synthesis of the new surfactants were achieved using green or no solvents. Importance of Chemical EOR Because only 15–20% of hydrocarbons can be extracted in the primary recovery stage, the waterflooding or gas-injection techniques usually are applied in the secondary recovery stage to extract 15–20% more oil and maintain the oilfield’s original pressure. After the application of these two techniques, however, a large amount of oil remains, the extraction of which requires the use of EOR, which can include thermal, gas, or chemical techniques. In thermal EOR, hot water or steamflooding are usually used to recover heavy oil. Currently, other thermal EOR methods such as in-situ combustion or steam-assisted gravity drainage receive considerable attention, especially in reservoirs containing heavy to extra-heavy crude oil. Gas methods normally are used in reservoirs featuring light and volatile oil. CO2 flooding is perhaps the most extensively applied gas EOR method for light oil extraction. Other gases such as nitrogen, hydrocarbon gas, acid gas, and air also are used for oil recovery. Chemical EOR involves the injection of chemicals including surfactants, polymers, alkali, and mixtures thereof. The polymer tends to increase the viscosity of the aqueous phase and lower the permeability of reservoir rocks. Surfactants minimize the interfacial tension (IFT), cause emulsification, and alter the wettability of the reservoir rocks. Alkali flooding generates in-situ surfactant by reacting with organic acid and ultimately reducing the IFT. Surfactants are organic compounds having both lipophilic and lipophobic parts. The lipophilic part is called a nonpolar compound and is soluble in the oil phase. The lipophobic part is termed a polar group and is soluble in the aqueous phase. Because of the availability of both lipophilic and lipophobic compounds in the same chemical structure, the surfactant stays on the interface ­of the water and oil phase and reduces the IFT. Based on the charge of the lipophobic head, the surfactants can be classified as nonionic, cationic, anionic, and zwitterionic (Fig. 1). Each class of surfactants possesses unique properties. For example, anionic surfactants are the material of choice in sandstone reservoirs because of their low adsorption into reservoir rocks. Similarly, the cationic surfactants exhibit minimum adsorption in carbonate rocks because of charge repulsion. Zwitterionic surfactants (ZS) show high heat-stability and salt-tolerance properties, and nonionic surfactants are known for their use as cosurfactants or solvents.

President’s Column: SPE Finances

_ Editor’s Note: The November edition is a written column only, with the vodcast set to resume next month. _ SPE finances are not the most interesting or exciting topic for most members, and you will be forgiven if you pass this column. You may not be interested at all if you only want to know what SPE does. However, you may be interested in this column to understand how SPE functions financially. SPE is not a commercial business, but it has an events business that de facto finances most of its other services to members—direct membership fees are a relatively small part of SPE’s revenue. In the current model, if the events business fails, SPE collapses. Finances are always important, but they have become critical in the current context, including the 2015 downturn and the 2020 COVID-19 pandemic, especially the latter, which have brought an existential threat to our Society. As shown in Fig. 1, between 2014 and 2023, we lost 65% of our revenue, 200% of our profit (Net Operating Income), and 50% of our net assets. Even last year, 3 years after the pandemic, we still had an operational deficit of $3.6 million, and this was expected to be a “good year” with Offshore Europe and two Offshore Technology Conference events. Operationally, we are still hemorrhaging money. SPE’s finances are public, but I thought it would be good to present this information in plain English and with illustrative graphs to explain how we operate financially and how SPE can prevail while its traditional business model is being challenged. I have occasionally heard and read severe statements about SPE’s financial management, allusions to staff being oversized and overpaid, our lack of willingness to adapt, etc. So, it is also a good opportunity to clear up some of these misunderstandings. Conventions and Definitions Until 2024, SPE’s fiscal year (FY) started in April and ended in March. For example, FY24 started on 1 April 2023 and ended on 31 March 2024. This has recently changed and will be explained below. The numbers presented in this document are consolidated in USD (SPE has several offices handling different currencies) and corrected for US inflation using factors listed in Fig. 2. The reference is the USD from the middle of FY24, i.e., October 2023. One important result to gauge our operational results is our Net Operating Income (NOI), which would be equivalent to profit if SPE were a commercial venture.

ANALYSIS OF MARKETING CAPABILITIES, COMPETITIVE ADVANTAGE AND ORGANIZATIONAL CULTURE IN IMPROVING SME PERFORMANCE(SMALL AND MEDIUM ENTERPRISES)

Small and Medium Enterprises (SMEs) face significant challenges in maintaining performance amidst increasingly tight market competition, especially in utilizing marketing capabilities, competitive advantages, and organizational culture. This study aims to explore the impact of investment in training and technology, participation in industry conferences, and collaboration with technology partners on SME performance. Qualitative research methods were used, including in-depth interviews and thematic analysis, to identify key factors influencing the success of these strategies. The results show that investments in training and technology significantly increase employee competency and technology adoption, while participation in technology conferences and collaborations expands innovation opportunities and market access. The implications of these findings underscore the importance of an integrative approach that combines training, technology and strategic partnerships to enhance the competitiveness and long-term success of SMEs. This research provides new contributions to the SME management literature as well as practical recommendations for industry players and policy makers.

Special Issue: Selected Papers from IDETC-CIE 2023

Abstract This special issue of the ASME Journal of Mechanisms and Robotics (JMR) draws on papers presented at the 47th Mechanisms and Robotics Conference (MR), held as part of the 2023 International Design and Engineering Technical Conferences & Computers and Information in Engineering Conference (IDETC/CIE 2023), held in Boston, Massachusetts, August 20-23, 2023.

Special Section: Manufacturing Science Engineering Conference 2024

Special Section: Manufacturing Science Engineering Conference 2024

Preface

These proceedings contain the peer-reviewed full papers presented at the joint conference ICMASS (the 6th International Conference on Maritime Autonomous Surface Ships) and MTEC (International Maritime Port Technology and Development Conference), held October 29th – 30th, 2024, in Trondheim, Norway. MTEC and ICMASS bring together academia and industry from around the world showcasing cutting-edge research and development within maritime technology, autonomous ships and port operations. https://www.ntnu.edu/mtec-icmass2024/home Trondheim, Norway’s hub for technological innovation, has utilized its rich maritime heritage to position itself at the forefront of maritime innovation. With the world’s first test area for autonomous ships, its strong position within academia and research, Trondheim has gained a leading position in the field of maritime innovation through collaboration between maritime stakeholders. This year’s conference topics include: • Green shipping and ports • Smart and autonomous ship and port operations • Maritime safety • Maritime digitalization, connectivity and cybersecurity The theme of this year’s conference, featuring contributions covering topics such as AI & autonomy, cybersecurity, onboard control, remote & shore control, smart ships as part of smart logistics, green shipping, safety evaluations, collision avoidance, regulatory & legal frameworks, as well as discussions on liability, etc. The papers, published in these proceedings contain theoretical contributions as well as reports on practical implementations in field labs and industry, and the conference will also have oral only presentation. Totally there will be more than 90 presentations, where more than 60 papers are invited. A conference such as this can only succeed as a team effort, and, as such, we thank the International Program Committee and the Reviewers for their excellent work in reviewing the papers as well as their invaluable input and advice. On behalf of the organizing committee, List of MTEC/ICMASS-24 Organizing Committee, International Programme and Management Committee and International Reviewers are available in this Pdf.

Application for Predicting Vessel Motion Enhances Operability in Offshore Drilling

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35341, “Enhancing Energy Efficiency and Operability in Offshore Drilling Operations: Validation and Benefits of a Machine-Learning-Based Vessel-Motion-Prediction Application,” by Daniel A.C. Canache, Massimiliano Russo, and Rune Haakonsen, Kongsberg Maritime, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ This paper delves into the framework of a new application that leverages advanced machine-learning (ML) techniques in conjunction with metocean forecasts to predict vessel motions and thruster loads. The discussion encompasses the key role of diverse input factors in shaping prediction accuracy and outlines strategies to address inherent uncertainties associated with methods, weather forecasts, and the stochastic nature of the underlying problem. Methods, Procedures, and Process Traditional Physics-Based Vessel Model. A physics-based model of the vessel is used to train the ML model. As such, the accuracy of the physics-based model is critical to the success of the ML model. The model is built using vessel-specific hydrodynamic data, mass data, and thruster-control software. The thruster-control software is extracted from the actual vessel to ensure that the same settings are being used in the model. The model is used to execute time-domain simulations, which include second-order effects, from which prediction targets [six degrees-of-freedom (DOF) motions and thruster usage] are extracted. As shown in Fig. 1, four environmental components are typically considered: wind waves, swell waves, wind, and current. To train an ML model capable of predicting in any given weather condition, environmental parameters are varied over thousands of simulations. Physics-Informed Neural Network (PINN) Architecture. The adopted architecture for the ML model is a PINN, a model architecture that offers several advantages. By integrating vessel-specific hydrodynamic data, the model becomes grounded firmly in the underlying physical phenomena. Furthermore, the architecture facilitates the model’s comprehension and assessment of the environment by enabling the compilation of individual loads into an overall load acting on the vessel. Ultimately, the analysis of resultant loads on the vessel provides a means to compare various environmental load cases directly in relation to the vessel’s response. Optimizing the Training Matrix. The optimal training matrix should span the environmental parameter space up to the vessel’s station-keeping capacity while minimizing the number of necessary load cases. Given the computational expense and prolonged execution times associated with time-domain simulations, it is important to maintain a manageable number of cases. While resultant loads facilitate the comparison across different environment load cases, a systematic algorithm is needed for case selection. To address this requirement, a similarity metric incorporating cosine similarity and Euclidean distance was implemented. The downside to the Euclidean distance is that, at low magnitudes, the distance will be low regardless of direction. This is mitigated to some extent by combining the measure with the cosine similarity. The cosine similarity will be high if two vectors are close in direction regardless of their magnitudes. For the specific problem described in the complete paper (vessel responses), it is desirable that the similarities at low loads stay high because the response also will likely be low.

Remedial Conformable Sand-Control Technology Deployed Offshore Colombia

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23690, “First Horizontal Deployment of Remedial Conformable Sand-Control Technology in Colombia: Qualification and Case Study,” by Suzanne Stewart, SPE, TAQA, and Jose M. Bermudez, SPE, and Camilo Mazo, Hocol, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ The challenge of remedial sand control lies in the fact that the system must pass through restrictions in the upper completion before ideally conforming to the inner diameter (ID) of the zone requiring sand control. The complete paper describes the qualification of a multilayer, open-cell matrix polymer (OCMP) system for the first horizontal deployment in an offshore gas well. The system is capable of being deployed remedially through tight tubing restrictions while providing conformant sand control in a horizontal wellbore without the need for gravel packing, making the approach particularly valuable for scenarios where surface space is limited. Background During 2006, gas Wells CH-20, CH-19, and CH-18 were originally drilled and completed in the B2 zone in the Chuchupa field offshore Colombia. Wells CH-20, CH-19, and CH-18 experienced water breakthrough from the aquifer in late 2016, 2018, and 2020, respectively. The first workover operation in these wells was performed in 2021. The aim was to isolate the B2 zone with a packer and to perforate the slightly shallower B1 zone to access attic gas. In Well CH-18, an inflatable packer between Zones B2 and B1 was installed successfully, resulting in the ability to produce at full potential, while Wells CH-19 and CH-20 recovered their potential partially but below the calculated target rate. A new operation for the three wells was planned in 2022 to set a mechanical packer to isolate Zone B2 and reperforate Zone B1 to increase flow area, reduce drawdown at the sandface, and diminish the risk of sand production. However, because produced sand had accumulated in front of the perforations in all wells, removing the sand and setting the mechanical packer was impossible. At present, Wells CH-19 and CH-20 are not producing and Well CH-18 is on lower-than-calculated target production. Given the production difficulties, the plan is to isolate Zone B2 successfully in all wells, clean the wells, and install effective remedial sand control with significant surface-space constraints. OCMP: Conformant Remedial Through-Tubing Sand Control The OCMP system evaluated and subsequently selected for this application consists of multiple layers of highly porous (up to 85%) and permeable (40 darcies or greater) OCMP bonded to a specially designed base pipe. The compressibility of the system enables it to be run in hole compressed within a sleeve to allow passage through tight restrictions in the upper completion; then, once in place, the sleeve can be removed, allowing a return to the original shape and conformance to the ID of the sand-producing section. The system can be run on slickline, braided line, coiled tubing, or pipe. If deployed with a hydraulic conduit, it has the capability to perform sand cleanout during deployment and can incorporate an integral hydraulic-set, high-expansion anchor. If run with slickline or braided line, it is necessary to run an anchoring device on a separate trip; then, the first OCMP system can be anchored in place.

Geothermal Power, and a Battery as Well

One of geothermal energy’s key advantages is that it’s always on. But making money selling power increasingly requires being able to react to shifts in electric prices by adjusting production up and down. The fact this is a concern now is an indication of the ambition of a new generation of companies that have shown it is possible to use horizontal drilling and fracturing to build subsurface heat exchangers to harvest large amounts of geothermal energy. The geologic potential is huge—there are a lot of places with hot rock at a drillable depth. But monetizing that potential will require grabbing a sizeable share of the market in big states such as California and Texas where the price of electricity can sink toward zero when sunny conditions allow maximum solar power production, and then rebound as the sun sets. This is a pressing concern for Houston-based Fervo Energy because it is one of the first firms in a small pack of innovators to reach the point where it is building a large scale power plant using this emerging technology. Unlike wind and solar, it can deliver power on demand, similar to coal, gas, and nuclear-powered plants that supply baseload power to the electric market. Fervo’s founders play up its ability to deliver power on demand, but they resist the label baseload power provider because, as Jack Norbeck, chief technology officer and cofounder of Fervo, said, “In the future, baseload power will be a thing of the past.” Baseload power plants are not yet an endangered species. There are still large, mostly old fossil-fueled plants providing baseload power that are still around because they were paid for long ago. However, their numbers are declining as they wear out and are hit with demands for costly emission reductions. The initial sales by Fervo’s Cape Station project in Utah will provide baseload power to southern California power suppliers, complying with a unique California rule that requires them to source low-carbon power supplies that are available 24/7. But for new geothermal companies to sell enough power to become significant players in US power markets, they will need to provide what the electricity business describes as “more flexible, dispatchable power.” Big baseload plants ruled the power universe back when regulators set rates high enough to maintain a sizable surplus of generating capacity—ensuring the lights stayed on. Now, in markets such as Texas and California, power pricing rises and falls based on supply and demand, with selling at all times sometimes resulting in very low payments during peak production periods for solar and wind. This is particularly true during seasons where days tend to be sunny and windy with moderate temperatures. “If you are consuming electricity, particularly in the spring and fall, it is an extremely clean grid you are pulling from,” said Christian Gradl, vice president of operations for Fervo during a panel at this year’s Offshore Technology Conference.

Drilling Automation Serves as Engine of Change for Risk Prevention Offshore

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35137, “Drilling Automation: An Engine of Change for Risk Prevention Offshore,” by Brennan Goodkey, SPE, Andrew Fabo, and Francois Le Buhan, SLB, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ This paper delves into the evolving landscape of drilling automation, emphasizing the imperative for these systems to go beyond novelty and deliver quantifiable financial value. The complete paper presents an examination of several offshore drilling operations that exemplify the successful implementation of a closed-loop drilling-automation solution and the positive effect these technologies can have on the bottom line. Introduction In the dynamic landscape of drilling technologies, the conventional discourse on rig mechanization, robotics, and drilling automation is no longer a new topic, having nearly a decade of active discussion, development, and deployment. However, these systems, despite their longstanding presence, are still working toward substantiating their anticipated value. To navigate this challenge successfully, a clear understanding of where and how exactly the deployed solution will deliver value is required. The criteria of success inevitably will vary based on the customer, region, and objective. One of the clearest examples is obvious in the dichotomy between the priorities of high-volume drilling in onshore operations compared with offshore drilling. While the overarching goal of automation remains consistent—maintain safety while maximizing production and minimizing operational expenditures—the path to delivery in these spaces looks quite different. Offshore drilling introduces a myriad of complexities and must prioritize not only efficiency but also risk reduction and the minimization of nonproductive time. The complete paper examines the collaborative journey of several oil and gas organizations to deploy and improve a drilling-automation system aimed at the priorities and challenges of offshore drilling. Definitions The authors offer the following definitions to delineate scope as they describe an integrated system that combines domain drilling automation, rig-floor mechanization, and directional-drilling automation into a cohesive and comprehensive solution: - Domain Drilling Automation—This refers to the process of leveraging sensor data to interpret downhole conditions and react with the appropriate domain response, mimicking an experienced driller’s expertise with high accuracy and precision. - Rig-Floor Mechanization—This is the implementation of automated technologies and robotic systems on the rig floor to limit manual human involvement in tasks situated within the hazardous red zone. - Directional-Drilling Automation—This term refers to the use of automated systems and technologies to control and navigate precisely the trajectory of a drilling borehole, enhancing accuracy and efficiency in achieving specific wellbore paths and target zones. - Planning Drilling Automation—The use of advanced technologies and automated systems during office-based well planning is leveraged to optimize resources, enabling precise and efficient decision-making for the entire drilling process. - Real-Time-Monitoring Drilling Automation—The use of advanced automation technologies can monitor and analyze drilling operations continuously in real time, providing instantaneous feedback and adjustments to optimize performance, efficiency, and safety.

Study Evaluates Long-Term Corrosion Risk of Load-Bearing, High-Power ESP Cable

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34898, “Long-Term Corrosion-Risk Evaluation of Load-Bearing, High-Power Electrical Submersible Pump Cable,” by Serko A. Sarian, SPE, Alkhorayef Petroleum, and Hattan Banjar, SPE, and Chidirim Ejim, SPE, Saudi Aramco, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ In this study, a fit-for-purpose electrical submersible pump (ESP) load-bearing power cable was deployed inside the production tubing of a sour oil well for an extended period of service. Project economics required the power-cable metallurgy to survive long-term exposure reliably for up to 15% hydrogen sulfide (H2S) and high-salinity production fluids. Laboratory tests simulating varying sour well and extended galvanic corrosion conditions have been performed to determine the adequacy of the selected armor metallurgy in downhole corrosive environments. Introduction In recent years, various types of load-bearing power cable-deployed ESP (CDESP) systems have been introduced, eliminating the need to install or remove a conventional ESP along with the completion and reducing ESP changeover time by more than 80%. More recently, live-well CDESP systems have been developed and tested to eliminate the need for a well-kill operation. The most-critical and costly component of such a system is the load-bearing power cable. The cable has the dual purpose of conveyance and long-term powering-up of the ESP. In a conventional artificial lift operation, the ESP is conveyed using the production tubing with a non-load-bearing power cable strapped to the outside of the tubing. This operation requires a workover rig to remove and reinstall the entire completion and a killed-well operation that might permanently damage the reservoir. The main advantages of a CDESP system include operational efficiency gain and cost reduction, no reservoir skin damage, and production-loss minimization. However, a few challenges exist with the use of CDESP. These cables must have significantly different structures from commercial oil and gas power cables. These differences are detailed in the complete paper. Cable-Design Requirements CDESP system criteria include multiple-year continued service in adverse oilwell and reservoir conditions such as sour fluids, high gas/oil ratios (GOR) and temperatures, and abrasion caused by solids production. The following product acceptance requirements were set in advance: - Three redeployments or retrievals after the initial deployment - Single deployment continued runtime to meet or exceed the regional conventional ESP system runtime Based on regional statistics, a conventional ESP system single-deployment average run time is 2.5 years. The effective CDESP power-cable service life target then becomes 2.5 years × four total deployments = 10 years, which served as the basis for all cable-associated testing and reliability metrics.

Fiber-Reinforced Thermoplastic Sucker Rods Provide Artificial Lift Efficiencies

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23949, “Fiber-Reinforced Thermoplastic Sucker Rods Providing High-Strength, Lightweight, Low-Cost, and Environmentally Responsible Artificial Lift Efficiencies,” by Jeff Saponja, SPE, Oilify, and Corbin Coyes, SPE, and Michael Conner, SPE, Q2 Artificial Lift Services. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ The complete paper focuses on the development of fiber-reinforced thermoplastic (FRTP) sucker rods, highlighting their potential advantages and challenges, for rod pumping (in general) and for offering an earlier transition from electrical submersible pump (ESP) pumping or gas lifting to reliable deep high-rate rod pumping. A unique feature of an FRTP composite rod is its remarkably high shear failure resistance compared with that of a thermoset composite rod. A high shear-failure resistance means the rods have compressional loading tolerance and that an entire sucker rod string could be comprised of FRTP sucker rods. Introduction Sucker rods made from steel are relatively heavy. Extensive well-specific designs require tapering of rod strings to optimize the overall sucker rod string weight relative to the strength and fatigue requirements and consideration of the dynamic loadings from accelerations and decelerations of the rods and fluids, frictional effects, and structural or power limitations of the pump jack or unit at surface. Steels suffer from corrosion risks. Corrosion, which rapidly can accelerate fatigue failure, often is the root cause of sucker rod failure. Fiber-reinforced composites (i.e., fibers surrounded by or wetted by a resin matrix) have gained considerable popularity because they can be tailored to have outstanding mechanical, thermal, and physical properties, and have superior material mechanical properties to metal. The fatigue behavior of composite materials and structures is complex because composites fail by a series of, or collection of, damage mechanisms, including fiber breakage, matrix cracking, fiber/matrix debonding, delamination, and the effect of shear-induced damage on cracks. Cracking can be slowed somewhat if the reinforced fibers are of high stiffness. Composite materials can offer a lower environmental footprint over their entire life cycle. They can require less energy to manufacture, thereby reducing CO2 emissions. A high strength/weight ratio offers less energy consumption during operational use, further reducing CO2 emissions. Composite materials can be recycled and reused. Composite sucker rods, in the form of thermoset fiberglass sucker rods, have offered a high strength/weight ratio with greater corrosion tolerance, but they are too stretchy from a low glass fiber tensile modulus of elasticity for deep high-rate rod pumping and when a high production-rate decline is likely. This limitation results in a large bottomhole pump-stroke variability as operating conditions change. Such rods have low tolerance to compressional and impact loads, forcing a larger proportion of a sucker string to remain as steel. They are also more costly than steel rods. For sucker rod pumping, an ideal composite rod should tolerate compressional loads and feature high impact resistance and high fatigue endurance with an ability to limit or control crack formation. A composite material that potentially offers these important sucker rod properties is FRTP.

Autonomous Inflow Control Devices Help Maximize Life of Wells in Deepwater West Africa

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35418, “Design Execution and Evaluation of Advanced Completions in Deepwater West Africa,” by Piyush Pankaj, SPE, Matthew S. Jackson, and Lokesh, ExxonMobil, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ Deepwater wells offshore West Africa traverse a complicated faulted block with sand bodies that can feature thicknesses of tens of meters. The study described in the complete paper provides insight into designing advanced well completions under various challenging reservoir conditions with autonomous inflow control devices (AICDs) that enable maximizing the producing life of the wells. Introduction The study area for this paper has been a challenging brownfield. Wells have been drilled in difficult deepwater conditions, and the target reservoirs have been lenticular sands with interbedded shale layers. To further complicate production, the sand bodies are poorly consolidated. Openhole wells with standalone screen and gravel packs have become a common approach to address sand control. Water- and gas-injection programs have been used actively in the field during the past 25 years, which further augments production and reservoir management challenges. Water and gas breakthrough in the infill wells has been a major concern for reservoir management. To address the gas buildup in the near-wellbore region and early water production, AICDs have become a popular feature in the lower well-completion designs in high-angled wells that intersect multiple sand bodies along the lateral completion interval. Two case studies are provided in the complete paper; one is included in this synopsis. Flow-Control Technology Although technology that empowers the ability to control the flow of unwanted fluids from zones in the well has been in use since the 1990s, flow-control technology has rapidly evolved, with advancement fueled by the need for long, complex well designs. The two broad categories of these approaches include active and passive flow control. The decision to use inflow-control technologies can be driven by the following economic values: - Balance drawdown along the wellbore - Increase recovery factor and reserves - Improve well cleanup - Reduces risk of erosion or hot-spotting of sandface completion Choice of Inflow Control for West Africa Field of Study Fluidic-diode AICDs were chosen because of their applicability to encountered fluid properties and reservoir conditions and their robustness of design in providing reliable long-term solutions. The reliability is prolonged in such AICDs because they work without any moving parts. Upon changes in viscosity, density, and rate, the fluid flow path will vary to gain the required control of flow rates. This AICD design, with its special geometry, alters the flow path or pattern for preferential fluid restriction. Operational Execution Ultimately, the AICDs were deployed on an inner string. This allowed the standard wire-wrapped screens and gravel pack to function as the traditional sand-control mechanism, while the inner string, deployed inside the lower completion, provides resistance to flow from unwanted gas production.

2024 Tianmulake Advanced Anode Materials Innovation Forum and Sixth National Conference of Advanced Battery Failure Analysis and Testing Technology concluded successfully

2024 Tianmulake Advanced Anode Materials Innovation Forum and Sixth National Conference of Advanced Battery Failure Analysis and Testing Technology concluded successfully

Employee Awareness and Attitudes Towards Cybersecurity Technologies

This study explores employee awareness and attitudes towards cybersecurity technologies. As organizations strive to improve their cybersecurity measures, the human element remains a critical yet often overlooked factor. This research investigates the correlation between employee awareness and the adoption of emerging cybersecurity technologies, the impact of these technologies on cybersecurity incident rates, and the relationship between employee satisfaction and cybersecurity awareness. A qualitative exploration approach was employed, utilizing data from peer-reviewed publications, technology conference proceedings, and industry reports. Surveys of cybersecurity experts and organizational executives were conducted to identify recurring themes and concerns. The findings reveal that increased employee awareness significantly enhances the effectiveness of cybersecurity measures and reduces security incidents. Furthermore, the study highlights the necessity of continuous training and education for employees to maintain a robust cybersecurity posture. The research also emphasizes the importance of integrating cybersecurity technologies into daily operations to enhance their efficacy. This comprehensive examination aims to assist organizations in developing resilient cybersecurity strategies that address both technological and human factors.

Multidisciplinary Approach Underpins Development of Marginal Presalt Reservoir

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35273, “Sururu Central: Appraisal and Development Plan for a Marginal Presalt Reservoir,” by Thiago E.S. Azevedo, L.M. Hayashi, and Rodrigo R.S. Leal, SPE, Petrobras, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ The complete paper presents a multidisciplinary view of the evolution of the concept of a development project for the central area of the Sururu reservoir and the method applied to address challenges and propose solutions. The central area presents distinct characteristics from typical Brazilian presalt fields, with low permeabilities despite high porosity. Sururu Reservoir The reservoir is in the Santos Basin 230 km offshore Rio de Janeiro at water depths ranging from 2000 to 2300 m. The wildcat in the reservoir, 1-BRSA-618-RJS (1-RJS-656), is in the central area of the field, which is the main subject of the present work. The well exhibited reasonably high average porosity while presenting low permeabilities and low productivity when compared with other presalt wells. The second well, 3-BRSA-891A-RJS (3-RJS-682A), was drilled in 2011 in an area known as Iara Horst, also in the central area of the Sururu reservoir and presenting the same challenges faced by the wildcat. The third well, 3-BRSA-1181D-RJS (3-RJS-715D), was drilled in 2013 as a high-angle multifractured well consisting of an alternative architecture. Productivity results, however, were similar to the ones obtained in the previous wells. Investments were made in acquiring and reprocessing seismic data, ultimately leading to the drilling of the fourth well, 9-BRSA-1212-RJS (9-RJS-726). This well, in the Sururu Oeste area, revealed characteristics more similar to other Brazilian presalt fields and cleared the path to the later drilling of other Sururu Oeste wells. These good results paved the way for floating production, storage, and offloading (FPSO) vessel Petrobras 68 (P-68), which has produced both the Berbigão and Sururu reservoirs since November of 2019. P-68 is a 150,000-BOPD, 6-million std m³/d gas processing “replicant” FPSO that includes 10 producers (five from Berbigão and five from Sururu) and seven injectors (four in Berbigão and three in Sururu). However, the idea of developing an alternative for producing the Sururu Central area was never abandoned. In 2020, the ninth Sururu well and the fourth well in the central area, 9-SRR-5-RJS, was drilled near some of the main Sururu Central faults, aiming to test the existence of better reservoir quality or the presence of conductive in-situ fractures. The results from the well were in line with the results from the previous three wells drilled in the area, confirming the challenging nature of Sururu Central productivity. A suitable development strategy for the area was increasingly dependent on the attainment of long-term dynamic data that could support a modeling hypothesis for this unique presalt reservoir.

Hess’ ‘Drainage’ Wells Show Strong Production but Face Cost and Spacing Challenges

A new kind of horizontal well has emerged from an experiment in North Dakota’s Bakken and Three Forks shales. It uses an uncemented slotted liner to produce hydrocarbons by intercepting fractures that originate from offset wells. Hess Corp. revealed the concept over 2 years ago, confirming at an SPE conference that crude was flowing from the pilot well. The New York City-headquartered oil company also announced that additional trials were in progress, though it withheld specific production figures. The wait for those key details is now over. At the recent Unconventional Resources Technology Conference (URTeC) in Houston, Hess presented its first technical paper on the augmented drainage development (ADD) pilots which it claims have proven the approach to be, at the very least, a technical success. In URTeC 4044110, the company’s authors underlined their optimism in noting that ADD wells “could lead to a step change in productivity and recovery in unconventional developments.” Hess acknowledges that economic and technical hurdles currently stand in the way of that vision. But the upbeat assessment is backed by impressive production data from its inaugural pilot launched in 2021. Placed about 240 ft between two actively stimulated Middle Bakken wells, the first drainage well exceeded expectations, averaging nearly 1,700 B/D of crude in the first 8 days of flowback. Output fell to about 1,500 B/D over the next few days as the nearest actively stimulated well—called a “standard well” by Hess—began its flowback. This was one of several confirmations that the wells were in direct communication. “A lot of bets were lost on this well—maybe not by me, but by a lot of people,” remarked Craig Cipolla, a principle completions engineering advisor for Hess. Cipolla presented the company’s findings at the conference this past summer. He said the ADD well also pumped out about as much frac sand as is seen in a typical shale well, which in addition to tracer data, verified that it was well propped. During the initial production period, the first ADD well achieved about 85% of the output of the offsetting standard wells on the pad. Although this figure eventually dropped to just over 40% over the next 2 years, it was enough for Hess to consider the concept validated. Based on the results from all three pilots, Hess estimates ADD wells in the Bakken can be expected to achieve 10 to 45% of the output of typical hydraulically fractured horizontal wells. On the low end, the oil recovered from distant and low-conductivity fractures likely won’t justify drilling even a wellbore as barebones as the ADD concept calls for. Conversely, if a drainage well produces too much oil it is a sign that well spacing is too tight and that it is overly competing for resources with more-expensive offsets. This is likely the story of why the first ADD well came on so strong.

Study Finds Compact Carbon-Capture Modules Feasible on Offshore Production Facilities

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34825, “Implementation of Compact Carbon-Capture Modules on Offshore Hydrocarbon Production Facilities,” by Jaime H. Tan and Rizal A. Hassan, Technip Energies, and Umberto Cornelis, KANFA, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ Carbon capture and storage has been implemented onshore successfully by different industries, including utilities and waste treatment, to capture CO2 from flue gases after the combustion of fossil fuels. Duplicating this success for offshore hydrocarbon processing facilities can be challenging because of deck-space constraints and marine environmental conditions. The complete paper describes the development of a compact carbon-capture module design for post-combustion carbon capture and its potential implementation on typical offshore hydrocarbon production facilities. Solvent Absorption Technology for Post-Combustion Carbon Capture The process technology at the core of the compact carbon-capture module is based on a solvent-absorption technique and a proprietary amine-based solvent. First, feed gas is quenched and saturated in a circulated water prescrubber. The gas contacts the lean amine solution in a countercurrent mass-transfer packed absorption column, and CO2 is absorbed while the treated gas exits to the atmosphere. Midway through the column, partially loaded amine is removed from the tower, cooled, and reintroduced over a layer of mass-transfer packing. CO2-rich amine from the absorption column is pumped through a lean-rich amine heat exchanger and then to the regeneration column. The rising, low-pressure saturated steam in the column regenerates the lean amine solution. CO2 is recovered as a pure, water-saturated product. Lean amine is pumped from the stripper reboiler to the absorption column for reuse in capturing CO2. Finally, the CO2 is directed to byproduct-management systems. The pure CO2 streams produced from the system may be sequestrated or used for applications such as enhanced oil recovery. Design of Offshore Carbon-Capture Modules For offshore applications, the carbon-capture modules must be more compact and lighter compared with carbon-capture systems developed for onshore applications. The absorber column is the critical component of the carbon-capture module because of its weight, footprint, and height. To reduce the overall height of the absorber for offshore application, an innovative configuration has been adopted: The bottom section of the absorber is placed on top of the prescrubber/direct contact cooler (DCC), and the top section of the absorber and the wash-water section comprise the second column. With this arrangement, the maximum height of the columns is limited to approximately 25 m. Because the lower absorber section is placed on top of the prescrubber/DCC, the in-between chimney tray is designed to be totally leakage-free to avoid losses of amines into the DCC water loop. A patent-pending compact absorber column design has been developed. The column wall construction will be a part of the overall module support structure, with cantilevered platforms for supporting carbon-capture equipment. The equipment for compression, injection, and treatment of CO2 is placed on a separate submodule. This module design benefits from footprint and weight savings of potentially more than 20% compared with typical cylindrical absorber column designs.

Shear-Wave Velocity Data Assists Modeling for Offshore Windfarm Development

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35354, “Pseudo-3D Underwater Multichannel Analysis of Surface Waves for Offshore Windfarm Development,” by Stephan Unterseh and Luis McArthur, TotalEnergies, and Edouard Mouton, SismOcean. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ In the course of a research and development (R&D) project dedicated to quantitative ground modeling, underwater multichannel analysis surface-wave (UMASW) data were acquired within an offshore windfarm area currently in development in the North Sea. The goal of the project described in the complete paper was to test the added value of the shear wave velocity (Vs) interpreted from the UMASW, particularly as a propagation tool of geotechnical information. While UMASW, together with seismic refraction, is regularly used to characterize the ground for burial or trenching purposes, it appears also to bring valuable design parameters for offshore wind turbine foundations. Introduction To investigate the value of Vs in the performance of quantitative ground modeling studies, an internal R&D initiative was launched aimed at acquiring Vs data and the associated uncertainties of foundation depth of an offshore windfarm currently in development. These data will be tested at a later stage for the propagation of geotechnical parameters used in foundation design. The acquisition consisted of obtaining Vs data through UMASW methodologies around two distinct geotechnical boreholes and along a corridor tying the two areas. The UMASW commonly is used in combination with seismic refraction to perform burial assessment analysis of cable or pipeline or to characterize ground conditions before performance of horizontal deviated drilling. Thus, the data acquisition did not require extensive hardware development. A unique pseudo-3D processing technique nevertheless was implemented to allow for 3D data visualization and ground characterization. Site Conditions The selected site lies in the North Sea in water depths ranging from 20 to 30 m. The area was first investigated with standard geophysical techniques. Preliminary geotechnical investigation included 6-m-deep vibrocores and 60-m-deep drilled boreholes, with alternating cone penetration tests and push sampling and coring. P-S logging also was performed at key geotechnical locations to gather 1D primary wave velocities (Vp) and Vs. The seabed generally consists of a thin cover of Holocene dense sand, occasionally with boulders, overlying quaternary subglacial formation deposits, including moraine, gravelly sand, and clays of variable thicknesses. The bedrock is generally Jurassic and includes dense sand; hard clay; weak claystone; and, locally, strong limestone bands. The test locations were selected within the coverage of the geophysical data set in areas where variable lithologies occur and where the seabed was found free of boulders and outcrops because these are detrimental to UMASW acquisition. The lithology of the two boreholes performed within the test area is indicated in Table 1 of the complete paper.