Drilling operations depend not only on controlling surface parameters but also on keeping bottom-hole assembly (BHA) components structurally sound. The BHA is the lower portion of the drill string in a drilling operation – the part that actually contacts the wellbore and guides the drilling process. Failures, especially at the connection between the flow diverter and the drive shaft behind the mud-motor power section, can cause major non-productive time (NPT), high costs, and poor performance. These failures are often linked to combined surface and downhole rotational speeds and high bending moments, which are common during directional drilling. To reduce this risk, we present a new method for real-time health monitoring and remaining useful life (RUL) estimation of these connections. The method combines physics-based fatigue modeling with machine-learning estimators, making it possible to track connector use across time and jobs using serialized component data. The system processes real-time drilling parameters to estimate downhole rotational speed (RPM) and bending moment. When measurement-while-drilling (MWD) data are available, direct RPM values are used; otherwise, a predictive model based on temperature, flow rate, and differential pressure is applied. Bending moment is inferred from drilling parameters and BHA design. The framework then calculates fatigue damage with connector-specific S–N (stress–number of cycles) curves and updates both current and cumulative RUL values. This helps operators make proactive decisions and lowers the risk of expensive failures. Tests with historical drilling data show strong agreement between predicted damage and observed connector failures, proving that the approach works in the field. The solution is already integrated into a commercial platform and used by field teams. Case studies show it reduces unexpected failures, cuts non-productive time, and improves the efficiency of directional drilling.

With the frequent occurrence of stuck pipe incidents during the ultra-deep well drilling operation, the hydraulic-while-drilling (HWD) jar has become a critical component of the bottom hole assembly (BHA). However, during jarring operations for stuck pipe release, the drill string experiences severe vibrations induced by the impact loads from the jar, which significantly alter the stress state and dynamic response of the threaded connections—the structurally weakest elements—under cyclic dynamic loading, often leading to fracture failures. here, a thread failure incident of a hydraulic jar in an ultra-deep well in the Tarim Basin, Xinjiang, is investigated. A drill string dynamic impact model incorporating the actual three-dimensional wellbore trajectory is established to capture the time-history characteristics of multi-axial loads at the threaded connection during up and down jarring. Meanwhile, a three-dimensional finite element model of a double-shouldered threaded connection with helix angle is developed, and the stress distribution of the joint thread is analyzed on the boundary condition acquired from the time-history characteristics of multi-axial loads. Numerical results indicate that the axial compression induces local bending of the drill string during down jarring, resulting in significantly greater bending moment fluctuations than in up jarring and a correspondingly higher amplitude of circumferential acceleration at the thread location. Among all thread positions, the first thread root at the pin end consistently experiences the highest average stress and stress variation, rendering it most susceptible to fatigue failure. This study provides theoretical and practical insights for optimizing drill string design and enhancing the reliability of threaded connections in deep and ultra-deep well drilling.

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 224044, “The Evolution of Riserless Wireline Subsea Intervention in Deepwater Gulf of Mexico: Doing More With Less,” by Strethen E. Townsend, Jose Duenas, SPE, and Lawrence W. Ramnath, BP. The paper has not been peer reviewed. _ Riserless light well interventions (RLWIs) were conducted within the deepwater subsea environment of the Gulf of Mexico. The main drivers for RLWI were cost reduction and acceleration of intervention scopes in order to improve well productivity and prevent production deferrals. During the period 2020–24, target wells for interventions were challenged by low margins. However, per the original objectives of RLWI, financial metrics for the candidate wells were still found to be attractive, yielding double-digit net present value and internal rate of return values. A heuristic payback period of 1 to 2 years also was consistently achieved. While the complete paper is divided into two major sections, the first concentrating on capabilities and lessons learned during 2020–21, this synopsis emphasizes the period during 2022–24. Capabilities: 2022–24 The latter part of the deepwater RLWI campaign saw an increase in conveyance through wireline (electric line) leading to more mechanical capabilities such as high-accuracy plug setting for water shutoffs, reperforating, manipulation of downhole flow-control completion equipment, and installation of subsurface safety valves. In addition to added capabilities, the use of wireline also provided alternative means to disconnect from bottomhole assemblies (BHAs). In situations where tools needed to be released downhole, slickline typically only provided single mechanical-release mechanisms without the use of memory timers. For deepwater RLWI, reliance on a single mechanical downhole release or a timed-release device is a significant risk. Wireline allowed electronic release devices to be included in the toolstring. Some emergency release devices also incorporated a secondary release logic that would disconnect after a set time if communication to the tools were lost. This capability was particularly beneficial in the deeper, high-pressure wells. In addition to an enhanced downhole toolbox and improved options for stuck-tool recovery, deepwater RLWI was expanded to harsher well environments during the latter campaigns. These included an additional 13 wells undergoing mechanical intervention. Challenges, Solutions, and Lessons Learned: 2022–24 Loss of Grease Seal. This phenomenon was experienced primarily on the cased and perforated wells in Asset 1. On-the-job troubleshooting and post-job investigations identified inadequate grease delivery as the root cause of the loss-of-grease-seal events. Several improvements to the grease-management and pressure-control system led to a solution that resulted in jobs after Well 11 no longer experiencing loss of grease seal. Some improvements in the grease-management system and pressure control included the following: - A conservative approach was taken to specify grease-injection pressure at the pressure-control head based on absolute shut-in tubing pressure without accounting for the approximately 2,500-psi hydrostatic pressure caused by the water column. To help monitor the grease-injection pressure, subsea pressure gauges were added at the grease-injection points for accurate measurements. - In addition to the subsea pressure gauges, grease-supply flowmeters were added to the surface grease-injection system. - Specific flow-tube configurations and grease-injection points were defined for positive and subambient wells. - Flow-tube sizing was aligned and clarified to resolve conflicts in operators’ and suppliers’ requirements. - Hoses used to deliver grease to the pressure-control head were replaced with larger-diameter hoses. - Manual-control grease regulators and controls were replaced with automatic models. A less-viscous grease was implemented during Well 11 and for all subsequent wells.

Summary Positive displacement motor (PDM) bottomhole assemblies (BHAs) are widely used in horizontal drilling due to their low cost and high rate of penetration (ROP) under rotary conditions. However, their limited-trajectory control ability often requires switching to sliding drilling for sharp corrections, which significantly reduces efficiency. Moreover, the quantitative relationship between build up rate (BUR) and controllable parameters such as revolutions per minute (RPM) and mud flow rate (MFR) remains unclear under rotary conditions. To address these issues, we propose a machine learning (ML)–based model predictive control (MPC) framework that regulates trajectory solely through real-time optimization of drilling parameters. A hybrid prediction model, integrating mechanical principles and ML, is developed to map weight on bit (WOB), RPM, and MFR to BUR, with a Lipschitz continuity constraint enhancing stability and robustness. The MPC objective function is improved by incorporating adaptive weighting, which accelerates convergence, reduces overshoot, and improves control consistency. The proposed method is evaluated across five simulation scenarios, which are analysis of control behavior, objective function enhancement, piecewise setpoint tracking, comparison with classical controllers, and robustness testing. The approach is validated using field data from a horizontal well in the Junggar Basin, northwest China. The results show that the ML-MPC strategy achieves accurate setpoint tracking under various conditions, maintains strong robustness to input noise, initialization variations, and measurement disturbances (with steady-state error < 0.2°/30 m), and meets real-time computation requirements (<20 seconds per control step). Analysis of the optimized control parameters provides data-driven insights into how WOB, RPM, and MFR influence BUR. Notably, a control inertia effect is observed: When the control objective aligns with the existing trend of variation, the system responds more efficiently; when it opposes the trend, the response becomes slower and more prone to overshoot. Overall, this work presents a practical framework for real-time trajectory control and contributes to the automation and intelligent drilling technologies in the oil and gas industry.

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 219627, “Use of Along-String Measurements and High-Speed Telemetry for Geohazard Mitigation and Improved Risk Management Delivers Enhanced Operational Efficiency and Enables Optimal Well Placement in Challenging Offshore and Onshore Applications,” by Stephen Pink, SPE, NOV, and Dale Bradley and Johnathan Rice, DCOR, et al. The paper has not been peer reviewed. _ Wired drillpipe (WDP; high-speed telemetry), along-string measurements (ASMs), and advanced logging-while-drilling (LWD) tools have been deployed in multiple wells worldwide to address specific challenges that typically have been either insurmountable with other techniques or likely to experience suboptimal results with alternative technologies. The complete paper discusses use cases in which high-fidelity pressure and dynamics measurements, combined with high-speed telemetry, were used to address complex geotechnical challenges such as low overburden, shale reactivity, and karstified reservoirs. Introduction Across global operations with multiple operators, several modern and very simple rigs have been equipped with surface interfaces and a high-speed wired network. Key components in the system include the wired bottomhole assembly, including LWD and an interface sub. This allows streaming of formation evaluation data at approximately memory quality, depending on tool firmware. The wired network itself is made up of wired double-shouldered tubulars and wired tools such as jars, network boosters for managing the downhole network, and distributed measurements in the form of ASMs, which enable the acquisition of dynamics and pressure data along the drillstring independent of flow. In addition, a high-resolution drilling-mechanics tool can be run to obtain downhole weight on bit and downhole torque. At the surface, a swivel assembly pulls data from the network while rotating and a device mounted on the bales enables the acquisition of all downhole data while tripping on elevators. This device is referred to as “data while tripping.” The data is decoded at the network controller, distributed to either the technology provider or service company, and shared with the operator’s drilling and subsurface teams. Now that this data is available at surface, it must be converted into actionable intelligence for well placement or for improved understanding of wellbore conditions and system dynamics. Much of the complete paper discusses how this technology, partnered with others, was an enabler for the successful completion of uniquely challenging wells. The complete paper includes four case studies, with two included in this synopsis. The case studies not included in this synopsis involve offshore California (ultralow-overburden, geologically complex extended-reach-drilling wells) and offshore Norway (need to manage shale reactivity).

Stick–slip vibration is a common phenomenon in ultra-deep drilling that significantly impacts the failure of both drill bits and drill tools. The most direct and efficacious approach to alleviating the stick–slip vibration of the drill string in the downhole is to modify its external excitation. In recent years, the composite impact tools that can simultaneously offer axial and torsional excitation in the downhole have been applied, effectively reducing the stick–slip vibration of the drill string. However, the mechanical mechanism thereof remains undefined. In order to understand the nature of this phenomenon, A dynamic model of the drill string taking into account multi-directional excitations is presented. The governing nonlinear equations are obtained by using the Lagrangian approach, which take the work done by the multidirectional excitation into consider. The Hertz contact model is introduced considering the constraints of the wellbore, and the finite element node iteration method is employed to solve the dynamics equation of drill string. The axial vibration, torsion vibration and phase trajectory characteristics of the drill string under multidirectional excitation are analyzed, and the inhibitory effect of the excitations on stick–slip vibration is clarified. The results show that the vibration characteristics of the bottom hole assembly can be significantly altered through periodic axial and torsional excitations at higher frequencies, resulting in the emergence of high-frequency vibration responses. These responses exhibit a pronounced inhibitory effect on stick–slip suppressed.

With the in-depth application of digital transformation in the oil industry, data-driven methods provide a new technical path for drilling engineering safety evaluation. In this paper, a data-driven drilling safety level evaluation system is proposed. By integrating the three-dimensional visualization technology of wellbore trajectory and the prediction model of friction torque, a dynamic and intelligent drilling risk evaluation framework is constructed. The Python platform is used to integrate geomechanical parameters, real-time drilling data, and historical working condition records, and the machine learning algorithm is used to train the friction torque prediction model to improve prediction accuracy. Based on the K-means clustering evaluation method, a three-tier drilling safety classification standard is established: Grade I (low risk) for friction (0–100 kN) and torque (0–10 kN·m), Grade II (medium risk) for friction (100–200 kN) and torque (10–20 kN·m), and Grade III (high risk) for friction (>200 kN) and torque (>20 kN·m). This enables intelligent quantitative evaluation of drilling difficulty. The system not only dynamically optimizes bottom-hole assembly (BHA) and drilling parameters but also continuously refines the evaluation model’s accuracy through a data backtracking mechanism. This provides a reliable theoretical foundation and technical support for risk early warning, parameter optimization, and intelligent decision-making in drilling engineering.

Oil and gas operators’ pursuit of speed and efficiency when it comes to more-complex, long lateral wells has given rise to vibrations events that can sideline drilling operations by damaging vital downhole tools. One of the costly phenomena is called torsional vibration, which is caused by a twisting motion because of fluctuating torques. The key to smoothing out the drilling experience is to keep the bit and drillpipe above the bottomhole assembly (BHA), spinning in unison. If they start spinning at different speeds, a torsional event can occur that can take the drilling experience from the The Beach Boys’ “Good Vibrations” to Jerry Lee Lewis’ “A Whole Lotta Shakin’ Going On” faster than you can trip out of the hole. Have you ever wrung out a wet towel? That’s an instance of applied torsional vibration. You applied opposing twisting forces to the towel’s ends, causing it to twist and vibrate. Have you ever been sitting in your den and loud thumps start emanating from the laundry room? It’s a good bet that it is due to an unbalanced load during your washing machine’s spin cycle. That can cause the drum and other components to experience torsional vibrations leading to the machine shaking excessively. Data on high-frequency torsional oscillations (HFTO)—a specific subset of the event—when drilling oil and gas wells dates back several years, but early on it was dismissed as electronics noise, according to Danny Perez, product line manager at NOV. “The frequencies were very high (approximately 1,000 Hz) and, for many, it didn’t make sense for it to be an actual mechanical event,” he said. “It wasn’t until around 2017 when some companies started actively recording it, analyzing the data, and realizing it was to blame for a lot of fatigue and even failure of certain electronic components downhole.” At that time, Norway’s Tomax was really the only game in town when it came to combating HFTO. Their Anti Stick-Slip Tool (AST) had been around since the early 2000s, developed to combat an increasing frequency of tool-joint problems and instances of over-torqued threads that caused power tongs to fail when drilling with polycrystalline diamond cutter (PDC) bits. Stick/slip occurs when the bit sticks then slips as it moves through a formation and leads to erratic drilling performance and unwanted torsional vibrations. While not specifically designed to address HFTO, the AST is effective for suppressing root oscillations in the lower-frequency ranges and thus has a strong effect on HFTO. According to the company, the tool is known to repeatedly have cut HFTO as much as 70% in advanced, 3D drilling operations. “Unlike dampeners or absorbers, the Tomax AST tool is a regulator designed to actively manage downhole drilling forces,” said Tomax founder Nils Reimers. “Its primary role is to prevent the self-exciting vibrations that frequently occur when drilling torque and weight on bit ‘couples’ at the bit-rock interface. This phenomenon is almost unavoidable when using a PDC bit at the bottom of a long drillstring, even in uniform rock formations.”

Abstract Oil and gas exploration uses a variety of drilling fluids during the drilling process. The drilling fluid serves to protect the wells and maintain the stability of the borehole. One type of drilling fluid currently used is the so-called mixed metal oxide (MMO) mud. This is a type of drilling mud that is environmentally friendly, biodegradable, non-toxic, and low cost. MMO also provides other functions such as hole cleaning, lubrication, cooling, hydraulic lifting, and borehole stabilizing. However, some effects of this type of fluid on the drilling process are still unknown, such as the effect of MMO on the borehole size. This research evaluates the impact of MMO mud on borehole sizes. To understand this effect, a case study was performed using two wells/sections, one drilled with MMO mud and the other with conventional polymer mud. The case study has been performed, including wells located in the same field and with the same formation layers, to isolate the other factors that affect the borehole size, including formation types, local field stresses, and drilling techniques. The results can improve calculations for borehole size in case using MMO mud instead of the conventional polymer mud. The results showed an 11% increase from the theoretical calculation. This important finding is essential for drilling-related calculations, including but not limited to cement calculations and bottom hole assembly (BHA) performance.

Summary Reliably predicting directional tendencies of downhole drilling assemblies has been an interest of researchers for decades. Initial efforts focused primarily on accuracy in calculation, attempting to account for the various nonlinearities that exist downhole (geometric coupling, wellbore contact, friction, etc.). As bottomhole assembly (BHA) mechanics models have improved to capture these inherently nonlinear behaviors of the downhole system, focus has naturally shifted to improving calculation efficiency and reducing the time required to obtain results. With the continued adoption of automated technology, a fast and reliable method for performing these calculations is even more critical. A directional prediction algorithm is developed, in combination with a new efficient drillstring-wellbore contact model, which drastically reduces these calculation times and helps address the challenge of balancing accuracy and efficiency. The algorithm uses a secant iteration approach to estimate the equilibrium curvature that the BHA can achieve at specific operational parameters. Bit steerability and bit-walk angle are used as calibration variables within the model to account for the bit/formation interface, which prevents the need for specific bit or formation details for accurate modeling. Validation of the new directional estimation method is performed via comparisons to an established nonlinear finite element model (FEM) as well as actual directional performance data from both rotary-steerable systems (RSS) and steerable mud motors. The resulting modeling algorithm shows a drastic improvement in the calculation time of directional sensitivity analysis, obtaining results 50–100x faster than previous methods. This comparison also shows a strong agreement between the calculated values of the two modeling methods, establishing confidence that the approach adequately accounts for the various intricacies and nonlinearities that exist downhole. The reliability of the directional model is further highlighted via a direct comparison with actual directional performance data. The use of this new drillstring-wellbore contact model, in combination with a direct integration of drillstring deflections, provides an efficient alternative to calculating the directional behavior of BHAs in realistic wellbores. The developed algorithm shows a significant improvement in calculation time compared with traditional nonlinear finite element approaches, while maintaining accuracy for complex scenarios. This method lays the foundation for real-time drilling optimization, trajectory prediction, and integration into automated drilling guidance systems. Keywords Directional Estimation, Directional Automation, Real-Time Analysis, Drilling Optimization, Efficient Drillstring Contact

Summary As the global energy transition accelerates, coiled tubing (CT) operations face the challenge of delivering increasingly sustainable well interventions. This can be achieved by reducing operational time and optimizing pumping strategies without compromising operational integrity and safety. This challenge is compounded in depleted fields, where more complex interventions requiring longer operating times and facing high levels of operational uncertainty, such as underbalanced coiled tubing cleanouts (CTCOs), are increasingly needed. CTCOs in low-pressure wells rely on establishing a slight underbalance to maximize annular velocity and the carrying capacity of solids to the surface. Equivalent circulation density (ECD)—traditionally used in underbalanced drilling—and flowing reservoir pressure (FRP) are estimated in real time using a CT acquisition digital solution. The CT operation’s crew use the ECD and FRP to optimize the underbalanced environment. FRP helps define drawdown, for which there is a fine optimal operating window. An increase in ECD may incur losses, which can result in a stuck CT pipe, extend intervention time, and impact overall efficiency. A decrease in ECD may result in exceeding critical drawdown and produce unwanted solids. Real-time ECD and FRP provide the CTCO operator with the necessary information to fine-tune the pumping schedule for an efficient and sustainable CT intervention. The CT acquisition digital solution uses real-time downhole data from sensors on the CT bottomhole assembly (BHA), surface data from CT equipment, and a priori information such as the wellbore geometry to estimate critical parameters of CTCOs, including ECD and FRP. These parameters are estimated, aggregated, and plotted in real time. The underbalanced CTCO has been successfully executed in live-well conditions in gas wells with heavy inorganic scale and mixed deposits across the production tubulars, averting losses to reactivate gas production while achieving safe handling of liquid, heavy solids, and gas. Visualization of ECD and FRP enabled the underbalanced operating condition and facilitated optimizing aspects of the CTCO: CT speed, bite size, bottoms-up frequency, and frequency of solids flushing in the flowback setup. The solution and workflow optimized the cleanout interventions by eliminating nearly 24 working hours, 1,500 bbl of cleanout fluids, and 12,000 gal of liquid nitrogen as compared to the CTCO using the traditional, underbalanced approach. When compared to the traditional overbalanced approach—one that may not even be viable in highly depleted wells—the solution and workflow yield an effective reduction of 66.7% in carbon dioxide emissions (CO2e). Novel digital solutions play a fundamental role in achieving more efficient and sustainable CT interventions in underbalanced conditions by enabling on-the-fly optimizations, which reduce operational time and fluids consumed. In some cases, when downhole conditions are adverse and at the operating limit, they even make such operations possible in the first place. These underbalanced cleanouts are among the earliest implementations that leverage a CT digital solution that can be tailored to guide and enhance CTCOs amid narrow operating envelopes. The work paves the way for the development of additional execution advisors, using the same acquisition architecture, and facilitates the delivery of other CT downhole applications.

Impact Drilling Technology is one of the most effective methods for enhancing the penetration rate and efficiency in hard rock formations. Downhole axial vibration impact tools can provide a stable impact load, but they also increase the complexity of the Bottom Hole Assembly (BHA) motion. Addressing the problem of vibration fatigue in the lower BHA when subjected to high-frequency impact stresses during impact drilling, this study utilizes finite-element impact modules and Design-Life fatigue analysis software to establish a nonlinear dynamic model of the drill string assembly under axial excitation. It investigates the influence patterns of control parameters, such as the impact energy and impact frequency, on BHA vibration damage and rock-breaking efficiency. The results show that the vibration characteristics of the BHA are significantly affected by the impact tool’s control parameters. Increasing the input impact energy intensifies the amplitude of alternating stress in the drill string system. Meanwhile, the equivalent stress fluctuation of the drill string tends to stabilize at high frequencies above 100 Hz, indicating that high-frequency impacts are beneficial for mitigating vibration damage and prolonging the service life of the BHA. This study provides a theoretical basis for reducing the drill string fatigue damage and optimizing the drilling parameters for an improved performance.

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 224032, “Riserless Coiled Tubing Services From Light Well Intervention Vessel: First Operation in a Live Subsea Well,” by Per Buset, SPE, Bernt Gramstad, and Mark Howitt, TechnipFMC, et al. The paper has not been peer reviewed. _ Riserless light well intervention (RLWI) offers several advantages over riser-based intervention. Traditionally, only wireline and slickline services could be performed in riserless mode. Thus, if coiled tubing (CT) were required, typically it was necessary to switch to a riser-based intervention. The introduction of riserless coiled tubing (RLCT) addresses this issue, enhancing capabilities for a wide range of operations. This paper describes the first RLCT operation performed in a live subsea well. RLCT Technology Overview The RLCT capability has been developed as an add-on service to existing RLWI capabilities. The complete paper provides examples of its successful deployment in various applications. The system uses the standard RLWI stack. The pressure control head used for normal cable operations is replaced by a subsea stripper and subsea injector. The subsea stripper includes three CT sealing elements like the ones used for surface applications. The sealing elements provide redundancy and help ensure effective sealing around the CT. The sealing elements can be replaced at surface in between runs because the stripper and injector are retrieved to surface when changing the bottomhole assembly (BHA), but they cannot be changed subsea in the middle of a run. The main function of the subsea injector is to inject the CT into the well, overcoming the stripper friction and the extrusion force caused by the borehole pressure acting on the CT cross section. The subsea injector operates in combination with the surface injector to maintain the CT in tension between surface and seabed. At surface, a standard CT injector mounted on a heave-compensated platform runs on the rails of the tower cursor system. The CT injector and cursor system hang in the tower active heave-compensation winch together with a passive heave compensator. The rest of the CT spread is standard and can be configured according to specific project requirements. Preparation In 2021, it was decided to develop the RLCT system further for use in live wells, integrating a subsea injector and subsea stripper onto the existing RLWI stack. Several oil companies joined forces to progress qualification and system development. A subsea stripper was designed, built, tested, and qualified. In 2023 and 2024, the same design, testing, and qualification process was performed for a lighter version of the subsea injector used in previous projects. Extended system testing was performed in 2024, including training and familiarization of offshore personnel. A surface test facility was built for system testing, control-software development and debugging, and hands-on training of personnel. In June 2024, a wet test of the stripper and injector was performed. The associated procedures and remotely operated vehicle interfaces and operations also were tested before performing a full test program on a test well. The well identified for the first operation of the new RLCT system was in the central North Sea, equipped with a 4-in.×2-in. vertical tree in a water depth of 130 m. The well had been shut in for many years and had been temporarily suspended with the installation of a temperature-activated suspension plug. To gain access to the well, a parted safety valve would have to be fished with 7/32-in.braided line.

Rotary drilling systems with PDC bits, commonly used for drilling deep wells in the production and exploration of oil and natural gas, frequently encounter severe vibrations. These vibrations can cause significant damage to the drilling system, particularly its downhole components, leading to drilling performance inefficiencies, notably reducing the rate of penetration and incurring high costs. This paper presents a parametric study on a proposed new axial semi-active tool designed to mitigate these unwanted vibrations. The tool, an axial absorber with tunable stiffness and damping coefficients over a wide range, composed of a hybrid magnetorheological elastomer-fluid (MRE-F), is installed above the PDC bit. In this study, the lumped parameter model considering axial and torsional vibrations is followed to assess the effectiveness of including the proposed absorber in the drill-string system’s behavior and to estimate the optimal coefficient values for achieving high-efficiency drilling. The drilling system response shown in this study indicates that, with optimal axial absorber coefficient values, the bit dynamically stabilizes, and unwanted vibrations are minimized, effectively eliminating the occurrence of bit-bounce and stick–slip, even when operating at critical frequencies. The proposed semi-active control tool has been proven to significantly reduce maintenance time, reduce the costs associated with severe vibrations, extend the lifespan of bottom-hole assembly components, and achieve smoother drilling with a simple addition to the drilling system.

The rate of penetration (ROP) is the key parameter to enhance drilling processes as it is inversely proportional to the overall cost of drilling operations. Maximizing the ROP without any limitation can induce drilling dysfunctions such as downhole vibrations. These vibrations are the main reason for bottom hole assembly (BHA) tool failure or excessive wear. This paper aims to maximize the ROP while managing the torque to keep the depth of cut within an acceptable range during the cutting process. To achieve this, machine learning algorithms are applied to build ROP and drilling torque models. Then, a metaheuristic algorithm is used to determine the optimal technical control parameters, the weight on bit (WOB) and revolutions per minute (RPM), that simultaneously enhance the ROP and mitigate excessive vibrations. This paper introduces a new methodology for mitigating drill string vibrations, improving the rate of penetration (ROP), minimizing BHA failures, and reducing drilling costs.

During the drilling process, stick–slip vibrations are one of the critical causes of bottom-hole assembly (BHA) failure and reduced drilling efficiency. To address this, this study first proposes a drill-string model based on a three-dimensional nonlinear finite beam element, combined with Hamilton’s principle of virtual work, to comprehensively describe the nonlinear behavior of the drill-string system. Next, to improve computational efficiency, the model is reduced using the modal truncation method, which retains the key modes of drill-string vibrations. Based on this, a model predictive control (MPC) method is designed to eliminate stick–slip vibrations. Furthermore, the robustness of the MPC method under parameter uncertainties is also investigated. In particular, the impact of the weight on bit (WOB) on the drill bit’s torsional velocity is further considered, and an MPC angular velocity comprehensive control scheme based on the dynamic WOB (DWOB-MPC) is proposed. This scheme stabilizes the velocity of the drill bit by dynamically adjusting the WOB, thereby eliminating stick–slip vibrations. Simulation results demonstrate that both the proposed MPC and DWOB-MPC methods effectively suppress stick–slip vibrations. Notably, the DWOB-MPC method further reduces the settling time and overshoot, exhibiting superior dynamic performance.

The development system of the Al-Sama field (oil and gas bearing basin Sab'atayn, Republic of Yemen) is implemented using vertical and directional wells. The project of additional development of the field involves drilling new directional wells with horizontal completions and the same type of sidetracks from already operated wells. The completions are planned to be located in oil-producing terrigenous deposits of the Madbi suite (Late Jurassic) in zones with high residual oil reserves. The experience gained in drilling vertical and directional wells does not allow for trouble-free drilling of horizontal completions of wells, which is confirmed by the occurrence of complications in 30 % of cases of construction of mine workings. A quantitative assessment of complications during drilling of new sixty wells shows that most of them are stuck bottom hole assembly and collapse of well walls. Collapses most often occur in sidetracks drilled from old well stock, and stuck drill pipes, in turn, occur during process downtime.A preliminary study of rocks from the intervals where complications occur showed the absence of physical and chemical activity of the reservoir systems. Petrographic analysis confirmed the fractured-brittle nature of argillite with the presence of open, partially healed microcracks in the layers along the bedding.Modeling the mechanical properties of rocks made it possible to determine the optimal range of the specific gravity of the drilling fluid for drilling horizontal well endings depending on the azimuth of the direction. Construction of horizontal well endings using the same range of drilling mud weight made it possible to create a mathematical model for predicting wellbore instability and identifying various types of complications. In the future, these models will be used as a basis for designing the drilling of new horizontal wellbores in the conditions of the Marib uplift, which will help in selecting and justifying the optimal values of drilling mud density to minimize the risk of accidents during well construction.

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 220770, “Managing Well-Collision Risk by Disruptive Ranging Technology Without Impacting Rig Time,” by Mahmoud ElGizawy, SPE, and Rustam Rakhmangulov, SPE, SLB, and William T. Allen, SPE, BP, et al. The paper has not been peer reviewed. _ Drilling a surface section from an offshore platform or a multiwell pad increases the risk of well collision. Managing well collision is currently performed by taking stationary surveys and projecting ahead of the bit to calculate the minimum allowable separation distance from the offset well. This approach, however, does not possess any means of confirming the distance and direction of the offset well. The complete paper presents a continuous passive magnetic ranging technique that can provide real-time distance and direction to the offset well while drilling without interrupting the drilling operation. Introduction The deployment of the ranging technique using definitive dynamic surveys (DDS) took place in Thunder Horse field, the largest offshore field in the Gulf of Mexico. The well was drilled in Thunder Horse North, where the subject Well A path came closer to two offset wells (Well B and Well C). Offset Well B’s center-to-center separation was closer to the subject Well A in the 26-in. section. The section interval is 4,068 ft (between 5,982 and 10,050 ft), where the equivalent center-to-center distance from offset Well B is closer to the subject well for more than one-third of the section, thus presenting a well-collision risk. DDS, in comparison with legacy stationary surveys to execute passive magnetic ranging (PMR), eliminate the added operational rig cost of taking static surveys that also could add drilling risk to operations. Adding to the complexity of the section, the bottomhole assembly already had a main measurement-while-drilling (MWD) service provider that was incompatible with the DDS MWD platform to demodulate on the same carrier. This complexity was overcome, however, by the ability of the DDS MWD platform to demodulate at higher frequencies. The technique permits dual-provider MWD survey services because of its independent telemetry frequency that does not affect the objectives of the section. Methodology PMR is a method of determining the relative distance and direction between the drilled well and a cased offset well. It uses magnetometer measurements within any traditional MWD or enhanced-measurement-system tool to detect external magnetic interference from the offset well casing. This method was first developed in the 1970s for a relief well drilling application. MWD technology featuring DDS was used in this case study. The ability of the MWD tool to take continuous six-axis dynamic surveys is not the only requirement for a successful real-time PMR job. Additionally, the tool should be able to provide sufficient surveying data density, an acceptable signal/noise ratio, and advanced ranging processing to interpret data in real time.

_ Reelwell’s DualLink wired drillpipe is heading offshore for the first time, set to make its debut later this year in a campaign with Vår Energi on the Norwegian Continental Shelf. The Stavanger-based technology developer sees the project as more than a milestone—it’s a chance to shift the narrative around wired pipe, a technology first brought to the market by NOV more than 2 decades ago. Challenged by high costs and integration hurdles, earlier generations of wired pipe never quite found widespread adoption. But Reelwell says it’s ready to change that. The DualLink system delivers real-time telemetry and, in a notable evolution, brings high-wattage downhole power into play for the first time. In this Q&A with JPT, Svein Strømberg, Reelwell’s newly appointed CEO and 31-year veteran of Baker Hughes, unpacks the company’s strategy as it prepares to put its most advanced technology to work offshore Norway. Editor’s note: This interview has been edited for length and clarity. JPT: What does Reelwell bring to the table that the industry hasn’t seen before? SS: DualLink delivers high-speed data from the bottomhole assembly (BHA) to surface and high power from surface to the downhole BHA, enabling real-time transmission of both data and electrical power. It transmits at rates up to 56 kilobits per second (kbps), which is a significant leap compared to conventional mud pulse systems that typically operate between 1 and 30 bps. That level of bandwidth opens the door to much more detailed and frequent tool updates. But the real differentiator is electrical power. Our wired pipe can deliver up to 500 W downhole at present, enabling tools and functionality that simply are not possible with telemetry alone. Whether it’s active flow control, tool actuation, or high-power sensors, having a reliable power source changes what’s technically feasible today. Right now, surface certification standards place some limits on how much power can be supplied, but the system itself is built to scale. It is fully redundant and engineered to support greater capacity as requirements evolve. And for many current applications, 500 W is already more than enough to drive meaningful gains in capability. In our conversations with leading exploration and production companies, both in Norway and the US, the data speed was compelling, but what really stood out was the power. That’s what they saw as the key to enabling the next generation of downhole tools, and it has played a major role in recent contract awards. DualLink isn’t just about faster data, it’s about unlocking a smarter, more capable downhole environment. More broadly, we’re entering a market that has long been defined by a single legacy provider. That kind of landscape can limit innovation. With new players emerging, including Reelwell, we believe the increased competition will help accelerate the adoption of wired-pipe technologies and expand what’s possible in drilling operations. JPT: Considering the industry’s historical reluctance to invest in wired drillpipe, how is Reelwell overcoming legacy obstacles and advancing the case for wider use? SS: There’s been hesitation in the past as wired pipe was often seen as expensive, complex, and difficult to plan for, especially when decisions had to be made a year in advance. And for some, the value wasn’t clearly understood. But I’m confident our upcoming work offshore in Norway will demonstrate that the landscape is changing. The benefits are becoming too significant to ignore.

Summary High-frequency torsional oscillations (HFTO) continue to be a challenge for rotary steerable system (RSS) performance. While ruggedization of downhole tools has improved significantly over the years and has enabled tools to survive these violent events, excessive vibrations can still lead to drilling inefficiencies, shortened lifespans of components (increased replacement rates during tool servicing), or occasionally errors in sensor readings. This study shares some key observations during HFTO events including relationships between other vibration modes, behavior with other commercially available vibration mitigation tools, mitigation strategies, and practical limitations. Case histories are presented highlighting HFTO behavior and what this vibration mode looks like within drilling data. Real-time, log, and high-frequency data are all examined to illustrate the differences and variability of each. Mitigation strategies are addressed in detail, looking at parameter adjustments, changes to the bottomhole assembly (BHA), and different types of dedicated vibration mitigation tools. Benefits and shortcomings are shown for each. The results show the benefit of planning for this type of vibration event and illustrate how the specific drilling application can impact the dynamic response of the BHA. Some unique dynamic characteristics have been observed and are discussed. One such behavior that has been noted is the presence of a torsional beating phenomenon when utilizing a torsional spring-like type of vibration mitigation tool. The physics of this behavior is further examined through detailed modeling and simulation, accurately replicating the observed field measurements. General HFTO observations over the years have also led to the development and implementation of a new at-bit viscous damper type of HFTO mitigation device. Due to the success of this at-bit mitigation device, it has been integrated directly into the rotary-steerable system (RSS), removing the need for additional tools or connections in the BHA, and is now a standard technology on all RSS deployments. The data presented in this study is the first documented case of a torsional beating phenomenon during an HFTO event. In addition to this, general HFTO observations are shown in a concise format to share the knowledge gained thus far with this type of vibration. The success resulting from the implementation of the only at-bit HFTO mitigation device is also highlighted.