bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanical Specific Energy: Derivation, Understanding and Relationship to Formation Strength
Authors: Macpherson John D. 
Published: February 2025

Abstract
The Mechanical Specific Energy (MSE) model is used widely in the drilling industry. However, its use has been questioned in a two-part series in the SPE-IADC Drilling Conference, "Mechanical Specific Energy (MSE): Claims and Implications – Facts, Fallacies, and Pitfalls" (Samuel and Mensa-Wilmot, 2023 SPE 212508, 2024 SPE 217727). This paper will independently develop the theory of the MSE, leading to an improved understanding and an appraisal of the conclusions in the two papers.
This paper develops the theory underlying the MSE from fundamentals and explains its applications and constraints. The theoretical development uses the concept of instantaneous mechanical power, which it transitions to drilling energy and then to drilling energy per a specific volume of rock, the MSE. The development pays particular attention to physical units. Of special interest is the relationship of the MSE to rock parameters, and its use in defining mechanical efficiency, and limits, of the drill bit. The paper further examines the validity of the Samuel and Mensa-Wilmot claims.
The MSE is a valid method for describing the amount of energy delivered by the drilling system to the drill bit to destroy rock. It is calculated as specific to a certain volume of rock, which in physics relates to the strain energy density (SED) of the formation. That is, the concentration of mechanical energy required to catastrophically fail (destroy) a volume of rock.
Comparison between the MSE and the SED of the formation describes the mechanical efficiency of the drill bit in converting input mechanical energy to output energy. Hydraulic energy applied at the drilling workface can both improve (e.g., clean, kerf) or impede (e.g., increase pressure overbalance) energy transfer at the workface. It is, therefore, considered separately.
Current oilfield measurement capabilities, and theoretical misunderstandings, introduce simplifications and errors in the MSE. It is important to understand this when using the MSE. Several of Samuel's and Mensa-Wilmot's deprecating claims about the MSE are questionable. The paper examines these claims and describes why they are incorrect. However, they do advocate a holistic approach to drilling process management—essentially an operational approach—which has merit. Understanding of the MSE is important in that approach.
This paper details the theoretical development of the MSE from a concept of instantaneous drilling power. This places the MSE on a firm theoretical basis and leads to an understanding of its limitations, and valid application. The relationship of the MSE to the energy density of the formation shows that the MSE should not be compared to the compressive strength of the formation, which leads to an improved understanding of drill bit mechanical efficiency.
Model of Rotary Drilling Dynamics for Rig Automation
Authors: Whitlow Z. W. , Paikoff B. , Auld S. , Kern S. 
Published: February 2025

Abstract
Drilling automation is critical for improving efficiency and consistency in drilling operations. Using a combination of models and data helps build an understanding of system dynamics and uncertainties used to develop effective automation systems. Autodrillers serve a critical role in drilling automation by regulating surface weight on bit (SWOB), top drive torque, or standpipe pressure. The model of rotary drilling dynamics presented here provides a simple tool that describes the dynamic relationships between surface inputs block velocity, top drive velocity, and flow rate; and outputs such as weight on bit (WOB), torque, and differential pressure.
Model development is based on simple mechanical relationships coupled with a simplified hydraulics model. Dominant rotary dynamics relevant to autodriller control are captured while neglecting complex high frequency dynamics which are beyond the autodriller control bandwidth. The simplicity and frequency range covered makes the model appropriate for autodriller control design and analysis.
Model parameters were estimated and the model was compared to data for several wells to demonstrate fidelity. Linearization and frequency domain analysis shows the difference in dynamics from block velocity input to WOB and pressure outputs and demonstrates the challenges of pressure regulation compared to SWOB regulation. The model shows that dynamics from block velocity input to WOB output behaves as dominant first-order. However, dynamics from block velocity input to differential pressure output is dominant second-order with a significant phase lag between WOB output and differential pressure output. This explains the delay in pressure signal relative to SWOB commonly observed while drilling and shows that the delay is frequency dependent. Sensitivity analysis shows a wide range in dynamics with respect to drillability and motor volume.
Comparison of Supervised and Unsupervised Machine Learning for Well-Log Depth Alignment
Authors: Acharya S. , Fabian K. , Westeng K. 
Published: February 2025

Abstract
Well logs, crucial for drilling and post-drilling analysis, provide continuous measurements of subsurface formations as a function of depth. Logging while drilling (LWD) and electrical wireline logs (EWL) are commonly used techniques for well-log acquisition. Both methods are prone to depth measurement errors due to various factors, which need to be aligned to a common depth-scale for subsequent analysis. This study compares two automated machine learning approaches for aligning repeated measurements of the same parameters from LWD and EWL logs of the same well. The first approach is based on supervised learning and the second on unsupervised learning. The supervised approach trains a 1D convolutional neural network (1D CNN) classification model on actual well-log data from the Norwegian North Sea, using LWD-EWL pairs of log slices. A specific depth discrepancy is introduced for each pair, and the logs are divided into various classes based on the depth error between them. The unsupervised method combines autoencoders and K-means clustering to identify potential lithological boundaries in EWL and LWD multiparameter log data. These predicted boundaries are validated by requesting a maximal Pearson correlation. The performance of the classification model is evaluated using metrics such as accuracy, precision, and recall. The optimal number of clusters for K-means clustering is identified using silhouette scores and the elbow method. Depth alignment is verified through visual inspection, correlation analysis, and Euclidean distances between logs. Supervised and unsupervised approaches significantly improve the alignment of various logs, such as bulk density, deep resistivity, sonic compressional, and neutron porosity. Both methods outperform maximization of cross-correlation for specific logs, such as deep resistivity and neutron porosity. These results highlight the potential of machine learning for efficient and accurate depth alignment of well logs, with promising implications for enhancing drilling and post-drilling analysis in the oil and gas industry.
Kvitebjørn Evolution: Driving Excellence in HPHT Project Management
Authors: Beeh Hany , Paulus Steven L. , Færo Erlend , Caycedo Alberto , Moldekleiv Rune , Mohanova Yelena , Egar Caroline E. , Zahoor Syed , Svenningsen Sondre , Naley Helge M. , Azher Mohammed , Reese Lasse 
Published: February 2025

Abstract
Kvitebjørn is a gas and condensate field in the Norwegian sector of the North Sea which was discovered in 1994. Kvitebjørn produces from Middle Jurassic sandstone in the Brent Group with secondary reservoirs on the Lower Jurassic Cook formation and Upper Triassic Statfjord group. The reservoirs lie at a depth of 4000 mTVD-RKB (meter True Vertical Depth – Rotary Kelly Bushing) with initial HPHT (High Pressure High Temperature) conditions. The field started production in 2004 and have experienced several drilling campaigns to access different areas of the field and maintain production.
In the recent campaign, the targets were further away from the platform. This resulted in well design and construction that is outside the originally established drilling scope at the time of designing the drilling module on the platform. Moreover, the improvement of subsurface understanding resulted in uncertainties regarding overburden flow units and barrier requirements for well integrity aspects. These pose challenges in the project which resulted in cost overruns and high Non-Productive Time (NPT) at the start of the campaign.
The Kvitebjørn One Team implemented structured improvement plans to overcome the various challenges in the current drilling campaign. The improvement plans covered one run strategy in all sections, using drill-bit and cutters technology for specific section challenges, thorough fluids strategy during execution, use of stage cementing equipment to replace long cement job, use of spacer with particles to mitigate risk of gas entering wellbore during wait-on-cement, enhancing the BHA (bottom hole assembly) with fit-for-purpose FPWD (Formation Pressure While Drilling) logging tool, continuous evaluation of wellbore strengthening materials to manage depletion, and several others. This publication covers the main improvements and the One Team organizational perspectives.
The Kvitebjørn project were able to turn around the NPT trend and deliver the longest well (A-16 B) successfully. Resulting in +/- 36 days ahead of budget (20% budget time reduction) and significant NPT reduction (from 46% to 16%) while managing an increasingly more complex well design and operations. The improved performance significantly increased well delivery efficiency by 50-80% compared to project's historical average and it was achieved with zero HSE (Health, Safety and Environment) and well control incidents.
The paper serves as an experience sharing of a successful organizational learning process and well construction deliveries in a mature HPHT field with complex challenges. The recent success provided opportunities in the field to access previously unfeasible targets. The key improvements that are presented with context of the background challenges could serve as a suggestion towards the industry for implementation in other projects.
Analysis of the Efficiency of a Vibration Mitigation Tool Using Modeling and Downhole Measurements
Authors: Nguyen K. L. , Mahjoub M. , Dao N. H. , Menand S. , Bonstaff W. , Servaes L. 
Published: February 2025

Abstract
When drilling complex wells, excessive vibrations can lead to damages of the bottom-hole assembly (BHA) and increase non-productive time. Employing a vibration reduction downhole tool to the BHA can help overcome this issue. We focus in this paper on a particular vibration reduction tool (VRT) composed of multiple parts designed to absorb and dissipate lateral shocks and vibrations. The upper and lower bodies of this tool are interconnected in such a way which allows relative deflection. The connection between these two parts is protected by a bladed sleeve for stabilization and is equipped with anti-vibration rings for damping.
The behavior of the vibration reduction tool is simplified for modeling purposes by a reduced stiffness combined with a distributed damping coefficient. This model is implemented for numerical simulation using the finite element method (FEM) both in frequency and time domains. The modeling results are validated against downhole data where the tool was equipped with two sensors in its upper and lower bodies. Lateral and axial accelerations as well as bending velocities acquired at a high frequency rate are used for the comparisons.
The numerical simulation predictions show an agreement with the downhole data. Based on that, new simulations are conducted where the VRT is replaced by a standard stabilizer with the same dimensions and where all the other parameters are kept the same. The comparison with the baseline simulations shows the level of vibration reduction gained by the VRT and allows us to better understand its vibration mitigation mechanisms. Moreover, a parametric study is conducted by varying the position of the VRT's within the BHA to investigate the optimal placement and operating conditions of the tool for a given BHA without completely changing its directional tendencies.
The novelty of this work lies in demonstrating a reliable model of a vibration reduction tool to predict its effectiveness in mitigating BHA vibrations, which could subsequently be employed to optimize the VRT position along the BHA and determine optimal drilling parameters.
Controlled Mud Level (CML) Modeling: Dual MPD with Combined CML and Surface Backpressure (SBP)
Authors: Callerio S. , Yoon D. , Ashok P. , van Oort E. , Hariharan P. , Tuckwell N. , Van Noort R. 
Published: February 2025

Abstract
Controlled Mud Level (CML) offers enabling managed pressure drilling (MPD) technology for drilling deepwater wells with narrow pressure windows. CML technology is now being extended with the addition of Surface Back Pressure (SBP) technology, creating a "dual MPD" technology. However, modeling CML operations in combination with SBP functionality and control has been difficult due to the lack of robust hydraulic models. This study presents a CML multi-phase drift-flux model with added SBP functionality, incorporating such features as the subsea pump module (SPM) operation, mud return line (MRL), SBP choke, and an active control device (ACD) placed in the marine riser.
The developed hydraulic model significantly extends an existing model for SBP Managed Pressure Drilling (MPD) operations to include CML operations. In this model, the riser is subdivided into a lower riser section below the ACD, an upper riser section located above the ACD, and the section associated with the mud return line (MRL). The SPM, which features automatic speed control, acts as a sink upon the lower riser, adjusting the riser level to regulate the target bottom hole pressure PBHP. The built-in ACD can be used to restrict flow between riser sections and can be used to regulate pressure from the lower riser section for SBP application and influx management. A surface choke connected to the MRL outlet allows the system to adjust PBHP by adding SBP. Future work will extend the model to kick management.
The use of SPM and MRL sub models in the hydraulic model have resulted in accurate replication of CML and CML+SBP drilling operations under both dynamic and static conditions. Simulations furthermore show that switching to CML with SBP application during static periods optimizes connection procedures, thus reducing connection time and enhancing overall operational efficiency. These results showcase the model's potential to significantly enhance the planning and execution of deepwater dual MPD operations, expanding opportunities for drilling deeper, lower-margin wells.
This work represents the first integrated multi-phase hydraulic model that seamlessly integrates CML and CML+SBP modes, with the capability to transition seamlessly between them. Furthermore, it is the first to fully integrate and reflect the performance of a CML+SBP MPD system, with the integration of the SPM, the MRL, the surface choke, and an ACD.
Dynamic Pressure Management for Well Integrity in Subsea Wells: Defining Safe Operating Limits Through the Annulus Operating Envelope
Authors: Kalil I. A. , Fischer R. , Foote C. , Trevisan R. , Howard J. A. 
Published: February 2025

Abstract
Ensuring well integrity in subsea wells is vital to preventing the escape of wellbore fluids into the environment, necessitating the presence of two effective pressure barriers. The evaluation of key components, including the production tubing string, production casing, and downhole production packer, is critical to avoiding issues such as casing burst, tubing collapse, and ensuring the reliable operation of the downhole packer.
This methodology defines the maximum and minimum allowable pressures for both the tubing annulus ("A" annulus) and tubing head, considering the highest pressures expected during the well’s life cycle—such as those encountered during production, shut-in of hydrocarbons, fluid injection, or kill operations—and the lowest pressures, such as zero pressure or a depleted production state. The approach accounts for the dynamic nature of the well’s life cycle, with early life characterized by higher pressures and late life marked by high water cut and potentially higher temperatures. The maximum allowable wellhead operating pressure (MAWOP), as defined by the American Petroleum Institute (API) in API RP 90-1, is referenced to ensure safe operation, while the minimum "A" annulus pressure is determined to prevent failures in the well barrier elements. These pressure limits, combined and compared against the operating limits of the production packer, potentially restrict the "A" annulus pressure below the calculated MAWOP in specific scenarios. The resulting annulus operating envelope (AOE) is graphically represented with tubing head pressure on the x-axis and "A" annulus pressure on the y-axis, providing a clear visualization of the safe operating window. The final envelope, typically rectangular, may become trapezoidal in cases where the packer’s operating constraints alter the shape of the AOE.
This dynamic approach, which adapts to the well’s life cycle and varying pressure conditions, serves as a practical tool for operations teams to visualize and manage safe operating limits in subsea wells.
Robust Mitigation of Axial-Torsional Drilling Vibrations Through Distributed Downhole WOB-RPM Control
Authors: Zhang Yifan , Ashok Pradeepkumar , Chen Dongmei , Oort Eric van 
Published: February 2025

Abstract
Coupled tri-axial drillstring vibrations are widely recognized as major causes of compromised drilling efficiency and safety. Excessive and self-sustaining drillstring oscillations, occurring at different frequencies, can result in premature drilling system failures, bit wear/damage, compromised hole quality, reduced rate-of-penetration (ROP), and non-productive time (NPT). In this study, a novel distributed in-bottom-hole-assembly (in-BHA) drilling vibration control system is proposed to robustly and efficiently suppress coupled drilling vibrations once they are detected. Multi-input-multi-output (MIMO) in-BHA controllers with local state-/output-feedback were designed following robust and optimal control theories. Lower drillstring dynamics and downhole drilling parameters are utilized to simultaneously control the at-bit weight-on-bit (WOB) and rotation speed (RPM). Ideally, the proposed control system requires no communication with surface once deployed, which significantly accelerates system control response action and expands the control bandwidth. Comprehensive simulations are performed to illustrate that the proposed controllers outperform existing drilling vibration mitigation technologies in terms of robustness, stabilization time, energy consumption, and actuation requirements.
The Benefits of Real-Time Drilling Dynamics Measurements from a Mud Motor Designed for U.S. Shale Drilling
Authors: Jones Steve , Sugiura Junichi , Ference Zachary 
Published: February 2025

Abstract
Embedded high-frequency drilling dynamics data recorders have become commonplace in U.S. shale drilling applications. The benefits of these data recorders are that they are small enough to place at the drill bit and mud motor top sub. These recorded measurements provide drilling dynamics information that cannot be seen from measurement-while-drilling (MWD) shock and vibration measurements; hence they provide post-run information that can be used throughout the pad to optimize the drilling process.
A new mud motor has been developed that can transmit real-time drilling dynamics data. The real-time mud motor data is just like embedded drilling dynamics data placed in the mud motor. The advantage is that the drilling dynamics data from the motor can be used in real-time to optimize drilling parameters and rig operations. This allows for fine-turning of parameters on-the-fly to optimize drill bit life and power-section performance/life.
Transplanting drilling dynamics measurements into the rotor catch of the drilling motor, along with a short-hop transmitter to be received at the MWD, enabled measurements to flow in real-time to surface. The measurement placements were critical to provide similar drilling dynamics readings as would be seen from the drill bit.
The advantage of placing the measurements in the rotor catch is that the devices do not interfere with the general construction and strength of the drilling motor. Field tests have successfully proven that the real-time mud motor measurements deliver results very similar to what can be seen from embedded dynamics data recorders post-run. Using the real-time data allows for monitoring of dynamics results as soon as changes are made, providing instant feedback to the operator while drilling.
This paper will compare the mud motor rotor catch measurements and MWD short-hop receiver measurements with the embedded high-frequency data recorder measurements at the bit and motor top sub. The data will clearly demonstrate how the measurements compare to each other, and how the real-time measurements can be used to optimize drilling parameters for longer and more repeatable runs.
Conclusions will be drawn to show the operational advantages of real-time mud motor dynamics versus standard MWD shock and vibration measurements.