bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Drill Bit Forensics Through a Hybrid Analysis of Smartphone-Captured Videos and Operational Time Series Data
Authors: Safarov A. , Ashok P. , van Oort E. 
Published: February 2025

Abstract
Drill bit photos/videos can be used as primary data sources for bit forensics. However, photos/videos only provide the final state of the drill bit, and there is still uncertainty with respect to how the damaged state was reached. The purpose of this work is to automate drill bit damage forensics using a video recording of the bit with time series data of drilling operation, thereby providing better generalization of bit forensics and a timeline of damage progression. Through the combination of 3D mesh building and custom-trained damage classification models, the algorithm was able to accurately classify drill bit damage, with the 3D mesh precisely capturing the cutter's shape and the object recognition model consistently recognizing the cutter's position throughout frames. This is then combined with damage evaluation models based on time series data to arrive at the damage timeline.
This study introduces two different techniques of conducting drill bit forensics, one using videos and the other using operational time-series data. The video analysis provides a visual evaluation of cutter damage, whereas the analysis of time series data helps to understand the mechanism of cutter damage using trends indicating drill bit vibrations. The integration of the time series analysis can improve forensics by providing a timeline for damage evolution. The hybrid approach using time series provides a parallel analysis of cutter damage, allowing an improved understanding of the damage progression to be obtained. It is also expected to significantly accelerate dull grade assessment, leading to quicker operational responsiveness and improved drilling performance.
A Case Study on Setting Up an Auto-Driller to Prevent Instability
Authors: Chhantyal K. , Padir A. G. 
Published: February 2025

Abstract
Auto-drillers are widely used in the drilling industry to regulate the process by maintaining key drilling parameters such as Weight On Bit (WOB) and Rate Of Penetration (ROP). A lack of understanding of an auto-driller and its control parameters can result in drilling dysfunctions and process instability. This paper is a case study on how to properly setup and apply an auto-driller presented with offshore drilling data. Most common auto-drillers have two main modes namely WOB and ROP. An operator can select the desired mode of operation, or in some auto-drillers, the mode switches automatically based on setpoints or limits. Inappropriate setpoint(s) and/or controller gains for the given formation coupled with the process limits can result in instabilities. This paper highlights the importance of understanding the auto-driller's functionality, setup, and its application for achieving good regulation. In the event of varying formation or the presence of heave, it is difficult to achieve good WOB regulation using an auto-driller in ROP mode. The case study shows that ROP is highly influenced by the rig heave and WOB oscillates with the heave motion when ROP mode is applied. In WOB mode, an auto-driller adjusts block speed to regulate WOB. If the resulting block speed is limited by the operator set process limits, WOB regulation is lost. Therefore, an operator needs to understand the interrelation between WOB setpoint, resulting block speed, process limits, and controller gains. An auto-driller with extreme controller gains against a formation and/or in combination with a heave can also result in irregular WOB regulations. Non optimal controller gains can sometimes be suitable for given conditions and still give satisfactory regulation. The study highlights different scenarios where an auto-driller can be limited due to improper settings resulting in instability, inefficient drilling, increasing probability of bit damage, axial vibrations, and thereby stick-slips. The paper suggests the correct practice of using an auto-driller.
Understand and Apply PDC Bit-Rock Interaction Model Towards Directional Response of Drill Bit
Authors: Valbuena F. , Savage M. , Belloso A. , Bomidi J. 
Published: February 2025

Abstract
Performing directional work with Polycrystalline Diamond Compact (PDC) bits have been a constant challenge since their introduction. As well trajectories continuously get more complex, more scrutiny is placed upon the drill bit design than ever before. Historically, there have been successful design philosophies that can be employed to improve PDC bit responses to steering inputs. How those philosophies can be tailored to meet the needs of particular applications, has proven a challenge. Computational models allow the engineer to better understand the effect of forces (rock-bit interaction) and responses of a given PDC bit, accelerate the iteration of concepts, and improve the cutting structure to promote bit response to directional assembly requirements.
This paper will discuss the method used to tune the directional response of a PDC bit based on the concept of bit imbalance force through advanced computational simulation as well as the validation process, through in lab testing and field cases. Drilling environments ranging from vertical versus build drilling, with specific deflection parameters, in addition to general drilling parameters such as Revolutions Per Minute (RPM), Weight On Bit (WOB), Rate of Penetration (ROP), can be prescribed in the model. The model calculates the forces from both the PDC cutting structure and bit body-rock interaction for that prescribed situation and allow the engineer to evaluate the imbalance force present in that situation.
A PDC drill bit's total imbalance force can significantly impact its responsiveness to inputs from a given steering assembly. This force changes with the bit design as well as the environment in which the bit is currently in; vertical versus a build, for example, but also in the amount of deflection that the steering assembly is applied to the drill bit. The ability of the simulation program to take these various factors into consideration and deliver insight into how this force changes in these environments, allows for more accurate assessment of what the steerability is within a given drill bit design. This is shown to be particularly important on Rotary Steerable System (RSS) assemblies, where it has been found that design steps taken to engineer the total imbalance force of a drill bit design can lead to improved steering responses.
The novelty of this paper will be providing insight into how the computational model for bit-rock interaction can be utilized to assess the forces of different bit design iterations in various operating environments. This includes varying operating scenarios such as while being deflected by a directional assembly and while operating at different parameter sets. These varying conditions generate varying forces. Visualizing the responses in these different conditions allows for more accurate assessment and ability to apply design concepts proven over the years to arrive at a drill bit design that is more responsive to directional assembly inputs.
Revealing Time-Dependent Mud Properties Needed for Predicting Gel Breaking Pressure
Authors: Gjerstad K. 
Published: February 2025

Abstract
Gel strength measurements are routinely conducted on the drilling fluid on most drilling rigs today. They provide peak shear stress values during stress-overshoot measurements performed on a rotational viscometer, and they are among the few near-real-time metrics available to update drilling mud properties during drilling. Updated knowledge about the mud is crucial for predicting wellbore hydraulics and transient pressure surges during pump and string startup. However, although the gel strength measurements in a simplified way can be related to the yield stress of the mud, such correlations will in general not give correct pressure calculations. The reason for this is that both the gel strength and the pressure spikes are in addition dependent on the viscoelastic properties of the fluid and the acceleration of the fluid. This leaves a gap in how to utilize these measurements in the real-time prediction of the wellbore hydraulics. This paper contributes to fill this gap by providing simple formulas that can be used to estimate properties that are important for predicting transient downhole pressures for water-based fluids where bentonite is the dominating viscosifier. The inputs to these formulas are the standard gel strength measurements taken regularly on most rigs, and some parameters that are close to constants for the analyzed groups of drilling fluids. These constants are identified and quantified.
Novel High Temperature Water-Based Reservoir Drilling Fluid to Access Depleted Deepwater Reserves
Authors: King Conan , Rodrigue Kevin 
Published: February 2025

Abstract
High overbalances in high temperature-high pressure (HTHP) environments creates an unprecedented challenge for water-based reservoir drilling fluids (RDIF). Historically, oil-based systems have effectively controlled fluid losses at such extreme pressures. A novel high-temperature divalent brine-based reservoir drilling fluid (HT-RDIF) has been successfully deployed twice on HTHP wells for a Gulf of Mexico (GOM) operator, directly addressing this scenario. With ongoing depletion in the field, a redesign of the fluid was necessary to meet this new condition. Aqueous fluid solutions for highly depleted HTHP reservoirs have been a gap in the industry for many years. This paper describes the redesign process along with the qualifications and application on two reservoirs close to 7,000 psi depletion at temperatures above 320°F.
A HT-RDIF designed for standard overbalance between 1,000 – 2,000 psi was redesigned utilizing the same novel synthetic polymer technology as earlier wells in the field. Calcium bromide was selected as the base brine to minimize the amount of acid soluble solids in the drilling fluid as one of the wells would be an injector. A through qualification process was conducted to evaluate parameters such as rheological performance across a range of temperatures, long-term stability, fluid loss under elevated pressure of 5,000 psi overbalance and stress conditions (16 hours at 365°F), production screen tests (PST), and various fluid-fluid compatibility tests. Formation response tests (FRT) were performed on the final formulation to validate suitability for use.
At this time, there were limited commercially available Particle Plugging Apparatus (PPA) capable of greater than 5,000 psi. The operator had equipment capable of 10,000 psi. Halliburton commenced the building of a similar unit as the operator's PPA but capable of 12,500 psi. As well conditions continue to increase with pressure and temperature its critical to be able to test at near reservoir conditions as possible. At the time of this paper, an oil field testing equipment manufacture now offers a 10,000 psi PPA; however, a critical piece to high depletion wells is the extended duration testing and data acquisition capability of the equipment.
Determining Drilling and Positive Displacement Motor Dynamics Including Spectral Information With a Low Cost Sensor Package Integrated Into a Standard MWD Tool
Authors: Jeffryes Ben , Yang Libo , Bonderover Eitan , Weng Hans , Lesso Bill 
Published: February 2025

Abstract
Downhole dynamics and mechanics data have been acquired during drilling operations for at least forty years, but beyond simple shock counts and stick-slip estimation are still not routinely used to aid the driller either in real-time control of the drilling process or post-well analysis. The barriers to doing this include equipment cost and reliability, telemetry bandwidth from downhole to surface, and availability of expertise in data interpretation. In this paper it is shown how valuable drilling dynamics information can be acquired using accelerometers and magnetometers integrated into a standard mandrel D&I tool, as used in most directional drilling operations. In addition to time-domain statistics, high frequency accelerometer data is processed downhole to provide frequency-domain spectral information, which in combination with rotation speed information derived from magnetometers can be used to monitor the performance of downhole tools such as drilling-motors and friction-reducing vibration tools, as well as detecting drilling dysfunctions such as bit-bounce, bit-sticking, and whirl.
After describing a new drilling dynamics module (DDM) used to acquire the data, case studies of data and its analysis are shown. Firstly, in monitoring of motor and friction-reduction tool behaviour using data acquired above the motor in a standard directional drilling configuration. Secondly, in applications where a motor is combined with a rotary steerable tool, and the DDM is between the motor and the bit, showing how damaging dysfunctions such as bit-stopping, bit bouncing and forward-whirl can be reliably detected.
Comparing Polycrystalline Diamond Compact Cutter Stress to its Structural Integrity When Drilling Interbedded Formations
Authors: Cherry M. M. , Pastusek P. E. , Payette G. S. , Bijai R. R. , Gjertsen O. J. , Durairajan B. , Gan X. , LeBaron A. M. 
Published: February 2025

Abstract
Measurement of the strength of materials and calculation of applied and residual stress are fundamental to mechanical engineering design and the continuous improvement of mechanical systems and processes. This paper uses these fundamental principles to establish an enhanced engineering framework and workflow for drill bit design, application, and drilling process improvements. It also highlights improvements in modeling and experimental data collection that are needed to continue to improve the drilling process.
Transient rock-cutting models are used to calculate the contact stress on the face of polycrystalline diamond compact (PDC) cutters on drill bits. This is applied to finite element models (FEM) of the cutters to calculate the maximum principal stresses. This process can be used to study the effects of bit profile, blade count, and cutter density on the maximum principal stress while drilling at different penetration per revolution (PPR) in various formation hardnesses. These stresses are compared with a forensics study to find instances of tangential overload-induced fractures to determine the maximum PPR a given PDC bit design can withstand for a given rock strength and application.
When drilling homogeneous or interbedded formations, it is necessary to control the PDC cutter stress below its structural limit. One method to do this is to create roadmaps of the acceptable parameters (particularly PPR) to reduce unwanted tool failures and trips. Roadmap creation is often experimental and fine-tuned with field development. With the outlined workflow, digital data from offset wells and forensics observations can be used to calculate stress for specific designs and applications. Along with estimations of a particular cutter's tangentially loaded structural integrity, this can be used to create much more accurate roadmaps of the drilling system's capabilities.
Computation of the dynamic stress required to fail cutters is a major improvement for the industry. It makes the design process and parameter recommendations based on well-established engineering principles. This process is continuously improved as the experimental and modeling capabilities are upgraded.
Specific guidance on maximum allowable PPR as a function of confined compressive rock strength can now be given to reduce uncertainties in roadmap creation. Bit designers can study the effects of bit profile, blade count, cutter density, and depth of cut (DOC) elements on the peak cutter stress while drilling interbedded formations, and bit selection of existing designs is now put on a firm engineering basis. This is a significant improvement over the maximum weight on bit (WOB) recommendations used today.
Digitalization of Connection Practices to Prevent Transient Drilling Dysfunctions
Authors: Li D. , Shen Y. , Tang K. H. , Chen W. , Zhang J. , Al Jarad C. , Simon A. , Converset J. 
Published: February 2025

Abstract
Total well delivery time is becoming the primary performance metric in well construction. This drives operators to increase on-bottom penetration rate and reduce time spent performing off-bottom operational steps, such as connections. This paper introduces a new method to digitalize each connection, define optimal practices, and ultimately avoid costly transient drilling dysfunctions. The method combines an advanced physics-based simulation package with cutting-edge digital and data science tools.
Multiple failures, such as twist-off events, overtorqued connections, and back-off events, were investigated across various applications. Many of these failures were caused by transient downhole dynamic events when transitioning between operational steps. Picking up off-bottom, tagging bottom, starting rotation, and starting flow are the main examples of the critical steps during connections.
A comprehensive physics-based model was developed to replicate these transient dysfunctions. The model revealed what attributes of the connection process cause dysfunctions. Performance indices were computed from those relevant attributes to characterize each connection in digital form. A new computation engine was developed to automatically compute these indices. The engine was deployed both in real time for drilling monitoring purposes and in the cloud for deeper big data studies in the future.
Unlock the Potential of High-Resolution Ultrasonic Imaging and Caliper Measurements for Large Borehole Sections
Authors: Carrilero S. Gutierrez , Hinz D. , Wong S. M. , Jin J. 
Published: February 2025

Abstract
Obtaining high-resolution ultrasonic caliper measurements and amplitude images in oil-based and water-based mud from logging-while-drilling (LWD) tools has become a common practice for hole sizes up to 14.75-in. in diameter. This paper introduces a new LWD high-resolution ultrasonic caliper/imager tool designed for hole sizes up to 19 in. in diameter.
The insight gained with smaller ultrasonic tools has revealed that a 9.5-in. tool would require a distinct ultrasonic transducer to account for larger standoff distances in larger boreholes. The new 9.5-in. tool utilizes an ultrasonic transducer with a lower nominal frequency than the smaller tools. Laboratory and field trials confirmed the 9.5-in. tool's capability to capture high-resolution borehole images and caliper measurements in boreholes up to 19 in. with varying mud weights. The tool's eccentricity-corrected amplitudes and radius images improved borehole geometry analysis and geological feature identification. The high firing rate of the transducers and four-transducer design allows for obtaining an average caliper size while tripping out of the hole without rotation and enables accurate cement volume calculation. Additionally, while reaming out of the hole, the borehole shape can be evaluated to understand its behavior over time after drilling, providing valuable information for the operator.
The data collected during field trials was analyzed and compared with wireline ultrasonic tools from the same area to validate the results. The interpretation of the borehole images (amplitude and travel time) for both borehole geometry and geologic features confirmed a spot resolution of 0.2-in. while drilling with different logging and rotary speed combinations. The development of a new 9.5-in. LWD high-resolution ultrasonic caliper/imager tool has resolved the challenge of obtaining caliper measurements and borehole images in larger borehole sections. This innovative tool will significantly enhance operators' ability to perform cement volume calculations and accurately identify unstable formations in larger boreholes.
Casing Swivel: A Key Enabler in Aiding the Longest Liner Deployment in Offshore Umm Shaif Field, UAE
Authors: Wong C. , Fomekong F. , Prasetyo B. , Al-Hajri S. S. 
Published: February 2025

Abstract
With the growing trend of drilling 30,000+ ft horizontal wells from an offshore WHT slot, a new level and specific approach are required to enable successful liner deployment to well TD. This paper describes the well challenges and the use of a casing swivel application in liner deployment that helped complete the longest liner in the deepest drilled well in the Offshore Umm Shaif field, UAE.
The recent well design of a 30,000+ ft well rendered the operator's previous approach of using the drill pipe swivel irrelevant. While the market offers casing swivel technology to reduce drag force and aid liner deployment, the optimum intervals where the casing swivel should be placed along the liner must be thoroughly assessed as both compression and tension force acting on each specific placement depth may compromise the casing swivel bearing lifetime and performance. A series of torque and drag simulations were run with a variance of casing swivel placement depth to achieve this optimum value.
By optimizing the placement of the casing swivel at 3,485ft below the liner setting sleeve, enabled a large section of the string to be rotated while decoupling torque to be transferred down below the casing swivel. The swiveling effect resulting in axial frictional drag reduction, alleviates buckling risks and provides more weight at the surface to push the liner to TD. In this case, the collaboration between the operator and technology provider yielded a successful deployment of 17,678 ft of 6-5/8" liner on a 30,000 ft MD horizontal well.
The liner was stalled and could not be deployed under the conventional deployment at 28,100 ft MD due to drag and buckling events. After attempting to wash down without any progression, rotation was then initiated with the help of the casing swivel at 20 RPM and 4 BPM circulating rate, which successfully completed the existing stand. Subsequently, the rotation continued for the last 1,892ft at a controlled tripping speed where it finally landed at well TD.
The casing swivel saved approximately 5 days of rig time, avoided NPT and completed the jobs efficiently and safely. It also enabled the operator to complete a long lateral section, maximizing and extending beyond the boundaries of typical offshore wells. Proper placement of the casing swivel technology enabled the liner string to be deployed in the challenging offshore jack-up rigs, increasing the success rate of liner deployment, and saving overall cost and time, avoiding the need to POOH the failed liner string and run an additional wiper trip.