bluuebunny/crossref_metadata_2025_split huggingface dataset:
Near-Bit HFTO Damper Enables Significant Drilling Performance Increase in Global Case Study
Authors: Hohl Andreas , Mihajlovic Saša , Fawaz Hassan 
Published: February 2025

Abstract
The drilling performance of rotary steerable systems is defined by the capabilities of the surface and downhole system, the bit, the formation, different functional aspects such as hydraulics, and is limited by dysfunctions that constrain the operational parameter envelope. One such constraint is vibrations that limit the drilling efficiency and can result in premature damage of the bottom-hole assembly (BHA). High-frequency torsional oscillations (HFTO) are a particularly damaging vibration mode that cause failures at sensitive electrical and mechanical components through high acceleration and dynamic torque values. To prevent these damages, the operational parameter envelope and the bit and BHA design options are constrained which compromises the drilling performance.
The paper introduces a steering unit with HFTO-damping capability which was designed to overcome these limitations. The inertia-based damper is implemented in a component of the steering unit close to the bit. The placement close to the source of the vibration enables an effective mitigation of HFTO, as suggested by theoretical considerations, simulations, and lab testing. A worldwide case study with &gt;50 deployments covers representative applications/BHAs, environments and formations.
In the case study a reduction of damaging HFTO of typically 100 % (and at least by 99 %) compared to offset runs was achieved. Third party vibration mitigation tools were significantly outperformed regarding HFTO reduction. The data confirms a significant improvement in reliability and re-run capability of the deployed BHAs. After proving the HFTO mitigation capability, the weight on bit and bit rotary speed limits were increased resulting in a significant increase of the rate of penetration (ROP). The drilling parameter increase enabled record runs in specific applications discussed in the paper.
In summary, HFTO effectively disappeared with the introduced steering unit. This in turn allowed for an increase in Weight on Bit (WOB) and bit rotary speed, opening the operating parameter envelope, resulting in achieving an even higher rate of penetration. The early study proves a significant cost saving potential enabled by higher reliability, lower non-productive time, and increased drilling efficiency and ROP. The results create opportunities for the introduction of new rotary steerable designs that were previously unattainable.
Drill Pipe Connection Inspection Optimization
Authors: Plessis G. , Delcambre D. , Tumlinson J. , Cunningham K. 
Published: February 2025

Abstract
The latest generation of drill pipe connections was designed to bring a low cost of ownership, which was confirmed by monitoring the inspection data of hundreds of thousands of connections over the last few years. It established that the 4th generation of double-shouldered connection offers a lower percentage of connection recut, typically half that of other connection designs. However, some users sporadically reported seeing a very different picture, with recut percentages in excess of 50%.
This started a reinspection project by the original equipment manufacturer's (OEM) field personnel, using its procedure and taking advantage of the connection design's tolerance for damage. The project included performing minor field repairs on surfaces that qualified. The focus was specifically on the connections marked for recut and ignoring those marked for reface or passed.
the same principle of reinspection according to the OEM criteria was used by a major rental company, using an independent source to determine whether the initial inspection data accurately reflected the reality of a string that suffered hard drilling conditions or was being over-inspected.
In both cases, we found reinspection numbers showing a very different picture, with cases where the number of connections needing recut fell by more than 90%. A need for fast inspection turnaround drives this practice of over-inspection as the rig moves to the next pad. It also provides comfort by removing the risk of making a bad decision. Marking the connection for repair is fast and safe and requires minimal effort. However, it pushes, on average, two to three times the volume of connections toward a workshop repair.
And this massive swing in numbers impacts the cost of asset ownership. More drill pipe may be needed on-site to cope with the volume that is out for repair, or some may need to be rented to top up the string. This process involves more transportation. A bottleneck may form at repair shops where additional cost is incurred to recut these connections. Finally, some asset life is lost as connections can only be repaired a limited number of times before tool joints are too short to be clamped on.
For the first time, a thorough study of connection repairs will be shared, with a focus on connection recut numbers. It shows how a reclassification of the inspection can greatly save time, money, and asset life.
As a result of the study, a new service has been created to correct, when needed, possible situations of over-inspection. Its objective is to gently push the industry to adopt the new inspection criteria set by the OEM.
Towards Johan Sverdrup Field Development Optimization and Concept Robustness Using AI Assistance
Authors: Les B. , Tjøstheim B. P. , Sørbel J. , Ulvedal L. , Dolle N. 
Published: February 2025

Abstract
This paper introduces an artificial intelligence (AI)-assisted methodology for rapidly screening multitude field development concepts across cost and risk domains. The methodology, matured over the last years, has been applied to the early-phase Johan Sverdrup Phase 3 Field Development Project (FDP), the company's digital frontrunner, with aim to improve the project's economy while ensuring robust infrastructure placement and expedited CAPEX screening.
The methodology integrates evolutionary algorithms to generate sets of possible and feasible well trajectories for considered development targets. Feasibility is ensured adopting the field-specific well concept and associated drilling rules, whereas all possible solutions are evaluated through greedy exploration of a large option space. This is combined with a second solver that optimizes well- to-template allocation and subsea template placement, ensuring that subsurface hazards are avoided and either the total project cost or drilling risk is minimized. Simulated results are presented in an online user interface and analyzed through a digital data report, facilitating evaluation of multiple concepts and the associated cost-risk trade-offs.
The study demonstrates a novel fast-track methodology for screening tens of thousands of drilling and surface combinations, significantly accelerating concept comparison and identifying new, relevant FDP solutions. Data generated by this methodology was used for internal validation of project assumptions and refinement of concept selection as the project matures towards the final investment decision. Results of study highlighted data-driven concept improvements, sensitivity analysis of reference concept sensitivities, and benefits of human-centered evaluation of solution space. Extracted learning resulted in more efficient use of engineering resources and time, channeling them towards the subset of most promising FDP solutions.
This case study represents the first application of an AI-driven approach to field development optimization in this context, replacing traditionally manual, discipline-specific processes. The proposed methodology enables a more efficient and streamlined insight retrieval, thus facilitating resource-allocation and improving decision-making for future field development projects.
Openhole Logging Utilizing a Statically Underbalanced Mud Weight in a Narrow-Windowed Extended Reach Well: A Case for Closed-Loop Dynamic Annular Pressure Control in Logging Operations
Authors: Khalid Ali , Ruiz Carlos 
Published: February 2025

Abstract
An operator was performing reentry operations in existing vertical wells to drill an extended lateral section across the reservoir formation. The carbonate reservoir exhibited faults and fracture networks and, with pressure depletion over time, presented a narrow operating margin for drilling and all subsequent operations.
Despite the operator’s intention to perform openhole logging across the complete openhole interval, the use of conventional drilling fluid and pressure management plans proved to be severely limiting. These methods, when attempting to navigate through tight operating windows, often led to issues such as total circulation losses, influxes from the reservoir, hole instability, and stuck pipe events. This underscored the need for a more effective and efficient approach.
To reduce operational complexity, the conventional practice is to have a balanced mud weight inside the wellbore while logging operations are being conducted. However, in the case of a narrow-windowed well, displacing a sufficiently heavy kill fluid can cause the equivalent circulating density (ECD) to exceed the minimum fracture gradient of the section, and displacing to a lighter kill fluid will potentially result in an underbalanced condition as a sufficient trip margin will not be maintained. Therefore, a proposal was made to utilize a statically underbalanced mud weight in the section and maneuver the annular pressure profile just above the pore pressure line by utilizing a closed-loop managed pressure setup.
A managed pressure engineering design was performed to optimize the ECD management plan, and a specialized logging string was designed to contain two specialized barriers that would allow for the logging tools to be passed and deployed outside of the string. The logging string was to be stripped out of the hole through a rotating control device, closing the loop on the annulus, while the managed pressure system maintained the required equivalent mud weight profile at the targeted depths across the openhole.
The openhole logs were conducted as per plan, stabilizing the statically underbalanced wellbore by actively managing the annular pressure profile across the target section. Contributions to the industry include the design methodology, the sequence of execution at the wellsite, and documentation of the results achieved in the application of managed pressure openhole logging on the subject well.
Well Construction Difficulty Index – A Modern Benchmarking Tool for Drilling
Authors: Dow Blaine , Manescu Gabe , Haq Shahid Azizul , Escalera Hernan Melgares , Rodas Mauricio Pena , Dhaher Karam Sulaiman , Abuelaish Ahmed Rami 
Published: February 2025

Abstract
In 2000, Oag and Williams (IADC/SPE 59196) introduced Directional Difficulty Index (DDI) as a benchmarking tool aimed at normalizing trajectory complexities across wells. The tool was designed to establish expectations of directional drilling performance from well to well, and serve as a planning tool for optimizing projects. Equally, where drilling teams desired, it served as a means of leveling performance incentives from well to well. In the interest of simplicity, DDI focused exclusively on trajectory, wellbore length, TVD and tortuosity. The uptake of DDI has been successful, yet the original authors acknowledged future work could broaden the application. This body of work is intended to expand the concept of DDI to incorporate additional complexity factors.
Items within the control of the planning team will include wellbore architecture, drilling rig capabilities, drillstring, bit and BHA selection, drilling fluid, casing and cementing plan. It will also include in-situ factors such as rock characteristics (homogeneity, rock strength, abrasiveness) borehole pressure and temperature challenges, and the location and environment of the drilling location. Consideration for well characterization and reservoir steering objectives, while drilling, coring or post drilling will be incorporated. The completion method will also be considered, in context of how it pertains to drilling. Less conventional well constructions methods such as casing while drilling, multi-lateral drilling, MPD and coiled tubing drilling, will also factor.
This document is intended to be a first iteration of Well Construction Difficulty Index (WCDI). The desired outcome will be an industry tool that offers a means of normalizing technical challenges for a given hole section, in as simple a form as possible, to drive project decision making. It will help drilling teams more effectively select and prioritize technical solutions for their wells during the design phase and measure relative execution performance across many wells. Applied correctly, WCDI will help rand risk and set appropriate expectations, while also facilitating mechanisms that can appropriately drive incentive contracts.
A Probabilistic Framework for the Risk-Based Evaluation of Drilling Plans
Authors: Daireaux B. , Ambrus A. , Moi S. , Cayeux E. 
Published: February 2025

Abstract
During the well planning stage, several alternative designs are considered, and a team of experts then has to identify the optimum one according to possible contradicting criteria such as performance, cost, logistics, or safety.
This selection can be challenging, and several key aspects may be ignored to simplify and accelerate the process. In particular, the impact of uncertainties on the main criteria is notoriously difficult to measure and include in the analyses.
The objective of the presented work is to develop a software platform that facilitates the analyses involved and enables the end-user to make informed decisions at the planning stage. The developed system has to cope with the presence of uncertainties, the possible occurrence of incidents that may affect overall drilling performance, and a large variety of possible scenarios. The analysis of a given well plan relies on Monte-Carlo simulations of the drilling process, including potential malfunctions or incidents and their impact on the operations. The propagated uncertainties can subsequently be analyzed through a dedicated logging mechanism that enables the user to specify drilling metrics of interest.
The combination of modern software architectures and advanced numerical models makes it possible to obtain detailed evaluations of a given well plan. We provide examples of such analyses and show how our probabilistic simulation framework can capture a large variety of relevant metrics. The end-user is then free to select the most appropriate one to finally assess the quality of the proposed plan and compare it to alternatives. Additionally, it becomes possible to incorporate learning mechanisms to optimize several operational procedures during the planning stage: this may in the future form the basis for a direct connection between well planning and automated execution.
A simulation framework is presented that aims at capturing the effects of uncertainties early at the planning stage. By quantifying risks and performance metrics, it provides the end-user with realistic estimates of the plan's quality, helping them make informed choices among the available alternatives.
Limiter Redesign Workflow Yields Positive Results in Deep Geothermal Drilling in Switzerland
Authors: Garcia A. , El-Alfy A. , Noynaert S. , Centala P. , Wojaczek D. , Moldoveanu S. 
Published: February 2025

Abstract
As companies are considerably increasing geothermal energy as a crucial element in their decarbonization strategies, the need to reduce costs and increase efficiency in hot hard rock drilling is gaining significant importance.
The lessons from FORGE (Frontier Observatory for Research in Geothermal Energy), a U.S. Department of Energy (DOE) geothermal project in Utah that started in 2020 over a 5-well program, were implemented using the same physics-based practices workflows developed by a group in Texas A&M University, aimed to reduce flat time generated from key performance limiters such as BHA whirl, lack of weight transfer, resonant RPM, and other parameters that accelerate drilling dysfunctions.
To reduce the drillability uncertainty into hard rock in the Switzerland project, evaluation of core samples extracted from 3 different offset wells yielded conclusive results. The lithologies included Monzonite, Metapelite and Granite, representing different grain structures. These were analyzed in the laboratory for single PDC cutter testing at different depths of cut. One of the three samples required 10-15% higher forces both axially and tangentially, suggesting a higher compressive strength compared to the granite found at FORGE.
Rapid bit iterations were critical to extend the cutting structure longevity and rate of penetration based on dull conditions seen in each run. These included different body configurations and PDC cutter grades and shapes that would perform optimally under typical higher weight on bit using high torque motor and rotary assemblies.
The combination of a good BHA design, the use of aggressive bits with shaped cutters and maximizing WOB resulted in reduced vibration levels as recorded in the MSE (Mechanical Specific Energy) trends and bit dulls led to better drilling performance. Physics- based practices training and re-training for all people involved played a significant role in achieving such results.
ORCHYD: Combination of High-Pressure Water Jet and Percussion to Improve Drilling Performance in Hard Rocks
Authors: Gerbaud L. , Velmurugan N. , Jahangir E. , Sellami H. , Cazenave F. , Latham J. P. , Xiang J. , Naderi S. , Kane P. A. , Dumoulin S. 
Published: February 2025

Abstract
Drilling through hard crystalline rocks like granites is challenging and taxing on the overall performance due to reduced rate of penetration (ROP). While efforts have been made in improving polycrystalline diamond compact (PDC) bits to increase ROP in hard rocks, the evidence of their field performance is currently restricted to only a few sites. There exists scope for alternative drilling technology where a significant fraction of hard rocks are present, such as in deep geothermal wells for electricity generation.
In the ORCHYD project, two mature technologies – high pressure water jetting (HPWJ) and percussion drilling - were combined. A combination of bit profile and peripherical groove (slotted by HPWJ) creates a stress-relief effect releasing the rock from surrounding geological stresses, requiring lower energy to break the rock using a mud hammer. Furthermore, pressure waves due to percussion are reflected by free surfaces at the groove aiding in rock breakage. In this project, an experimental study on the influence of operating conditions such as HPWJ pressure, bottom hole pressure and surrounding geological stresses on the drilling performance was conducted.
Several tests were performed at a dedicated drilling laboratory where the operational parameters can be varied to emulate drilling conditions for depths up to 4 km. As compared to tricone roller bits, ORCHYD technology guaranteed at least 4 times increase in the drilling performance. The performance of HPWJ in slotting a peripheral groove and mud hammer in rock breakage were strongly influenced by the operational conditions, e.g., for a given jet pressure the groove depth decreased significantly with increased bottom hole pressure. In this work, effects of such operating conditions on drilling performance were tested for different types of rocks such as Sidobre, Kuru Grey and Red Bohus. A sensitivity analysis of the influencing parameters on drilling performance of this technology is presented in this work. With increasing geological stresses, the proposed drilling technique is more effective in increasing ROP due to the stress relief effect.
A novel technique combining HPWJ and percussion drilling using a mud hammer prototype was developed to show improved drilling performance in deep, hard rocks as compared to conventional drilling technique. Through this work, the performance of this method under different realistic drilling conditions was studied to optimize ROP, especially when drilling hard abrasive formations in deep oil and gas or geothermal wells.
The Automation Advantage: Efficiency Improvements in Offshore Drilling
Authors: Millward B. , Kabi B. , Marck J. , Laing M. , Welmer M. , Reber R. , Kjøsnes I. 
Published: February 2025

Abstract
Automation has progressively taken over various manual drilling subprocesses on selected rigs for one Norwegian operator. In the past year, notable advancements in automation have been achieved, which orchestrate automation procedures across disparate surface and subsurface systems into a unified platform for control. This paper presents the tangible benefits these initiatives have yielded, notably enhanced operational efficiency and safety as well as improved efficiency of workflows for the drilling crews.
This paper will detail the technological innovations employed in this project, the verification and validation steps that preceded full-scale implementation, and the practical impact the automation solution is having on operations. The paper will elaborate on how the solution enables orchestration across multiple engineering solutions in conjunction with the rig control system to ensure a state-managed set of critical drilling parameters is utilized to deliver precise actuation aligned with the current rig process. It will also discuss the process of establishing connectivity between the parties involved in both a technical and operational capacity.
This project represents a revolutionary step in offshore drilling, showcasing the successful collaboration, integration, and orchestration of automated technologies in a complex operational environment involving multiple actors. We will provide a detailed review of the project’s objectives, which centered on demonstrating the feasibility of autonomous drilling operations to function over an extended period.
The project demonstrated successful interoperability of processes aligned with best practices between downhole and surface controls across multiple partners, on a robust system for exchange platform. In addition to reviewing what worked well, the paper highlights several learnings on the relevance of integrated process boundaries for lower-bounds management in system control.
The paper will explore the implications of these results for future offshore drilling operations, emphasizing the potential for widespread adoption of autonomous drilling technologies. It will reflect on the project’s contribution to the field of automated drilling and its alignment with industry goals of safer, more efficient, and consistent practices.