bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cuttings Return Analysis by Visual Imaging: Novel Technology to Support Drilling Automation
Authors: Grossi Caroline D , Hummels Yuri H , Meleiros Luiz Augusto da Cruz , Scheid Claudia Miriam , Calçada Luís Américo , Waldmann Alex Tadeu Almeida , De Sa Carlos , Martins André Leibsohn 
Published: March 2023

Abstract
In recent years, image acquisition of process variables has become a common practice as an essential monitoring tool for industrial systems. The rise of data analysis models and high performance computers enables the development of systems to support real time decision and automation initiatives. This work aimed to develop a comprehensive methodology to acquire, process and interpret shale shaker video images to support detection of problems associated with poor hole cleaning and wellbore instability. To achieve this goal, experiments in different operational conditions were performed in a pilot-scale vibrating screen using a sand suspension with xanthan gum at 0.1% to emulate the slurry flow in actual sieves. Such experiments aimed to evaluate how some of the main operational variables influence the area of the sieve filled with solids, the moisture content of the solids, and their flow velocity. The proposed methodology used a U-Net convolutional neural network to perform the semantic segmentation of the sieve’s images to estimate the percentual area filled with solids in the shale shaker. An image database with 11,140 pictures and their respective templates was created from 26 experiments. The templates were built using image processing techniques, and 75% of them were used for training, 10% for validation, and 15% for testing. The neural network evaluation metrics were accuracy for training, F1-Score, and MeanIoU for testing. In addition, the estimated values were compared to the experimental data. The estimated velocity, expressed in cm/s, was further compared to experimental data. The results obtained using the U-Net showed high segmentation ability, with an average accuracy of 97%, mean F1-Score of 92%, and mean IoU of 91%. According to these results, it can be concluded that the proposed image-based technique is a promising tool for monitoring important process variables in drilling operations. Additional experiments with different shape particles result in effective guidelines to detect wellbore instability events. In future work, the authors expect to improve the segmentation technique to obtain better estimations of the process variables and the implementation of the procedure in integrated real time diagnosis systems. This work shows an innovative approach to support the drilling process, allowing to evaluate, quantify and characterize the drilling cuttings that returns to the surface. This initiative is committed to helping to reduce the well construction costs, non-productive times (NPTs) and to guarantee drilling operations more efficient and safer. Besides, provides additional relevant information to support the future views of autonomous drilling and unmanned rigs.
Becoming an HPHT World Class Project, the Valemon experience 2012-2017
Authors: Paulus Steven Leonardus , Shen Hendry , Beeh Hany Ahmed 
Published: March 2023

Abstract
The objective of this case study is to share essential learnings from the planning and execution of the first drilling and completion campaign in the Valemon field throughout the period of 2012-2017 with a total delivery of 17 wells. The case study will give an overview of the Valemon field, geology of the area and well design. The development of well trajectory became longer and more challenging as the geology targets moved farther away from the platform. Several major challenges and learnings were experienced during execution such as enabling one run strategy in 17-1/2" section, updating well path strategy to improve borehole stability, managing overburden gas responses in 12-1/4" section, and section target depth strategy for 12-1/4" section.
Continuous learnings from sessions such as Improve Well on Paper (IWOP), Drill Well on Paper (DWOP), Subsurface Action Review (SAR), Subsurface After-Action Review (SAAR), operational procedures after action review, experience reports, and post well meetings enabled the project to reduce the time and cost per well. It took 160, 111, and 166 days respectively to complete the first three wells. The last well was delivered in 62 days. By the end of the campaign in November 2017, the Valemon project delivered four (4) extra wells compared to the original plan of thirteen (13) wells, while spending 500 million NOK-2017 (Norwegian Kroner with 2017 currency) or 60 million USD-2017 (United States Dollar with 2017 currency) less than the planned budget. Moreover, the entire drilling campaign was completed without any well control incidents.
Improving the Accuracy of a Kick-detection System by Reducing Effects of Rig Operational Practices
Authors: Joshi Deep R. , Yalamarty Sai Sharan , Cheatham Curtis A. , Kamyab Mohammadreza , Winklmann Kelly , Ross Trish , McCormack Patrick 
Published: March 2023

Abstract
Novel methods are presented that update a real-time cloud-based kick-detection system introduced in SPE-208770-MS to handle false kick identifications caused by rig operations. A common weakness in kick-detection systems is false indications of kicks due to rig operations and drilling practices that cause changes in tank volumes. In this work, we will discuss the modifications made to the existing real-time kick-detection system to handle rig operational practices and reduce false positives.
The existing kick-detection system analyzes the trends in the drilling data such as tank volumes, flow rates, and pump rates to detect well control events. Extensive field use of this system showed that the rig operations such as transfers between tanks, tank swaps, and adding material to the active tanks have a severe impact on the false-positive rates. Two approaches were developed to handle such operational practices: - Transfer identification: identify transfers between monitored tanks - Comment watcher: Evaluate the rig-memos to check if they might identify an operation that explains the variation in the tank volumes.
These approaches were tested with historical wells and live wells. Transfers were identified in several historical wells with help from the operator subject matter experts (SMEs). Thresholds such as the rate of transfer and the window size were tuned to optimally identify transfers. The tuned algorithms correctly identified transfers between monitored tanks with more than 85% accuracy. This workflow was added to the existing kick-detection framework. The efficiency of the kick detection logic depends on dynamically adjusting various thresholds. If any transfers were identified, the thresholds were reset which helped further reduce the false positives by 20% - 25%. For the comment watcher, a keyword library was developed with help from the operator SMEs. This library contained a list of keywords that the rig crew frequently uses in the rig memos to describe the operations. Each keyword from the library was mapped to an alarm type to be suppressed. A workflow was implemented to identify if a rig memo contains a keyword and suppress the respective alarm. The comment watcher feature was then implemented on historical wells along with the transfer identification. These updates resulted in a 40% reduction in false positives while maintaining a 100% true positive identification rate.
This work improves the accuracy and efficacy of a previously presented (SPE 208770) real-time cloud- based kick-identification system by detecting and avoiding the impact of rig operations. Features such as transfer identification and comment watcher are added to determine if the changes in the tank volumes can be attributed to rig operations. This update was tested on historical wells and live wells. Working together, these features helped reduce the false positives by up to 40%.
A Control-Oriented Lumped Parameter Drillstring Dynamic Model for Real-Time Vibration Mitigation and Drilling Optimization
Authors: Zhang Yifan , Ashok Pradeepkumar , Chen Dongmei , van Oort Eric 
Published: March 2023

Abstract
Drilling is an essential operation for subsurface hydrocarbon/geothermal energy extraction or underground waste fluid/gas storage. Efficient drilling is the key to an economically viable operation. Axial, torsional, and lateral oscillations that are excited in the drillstring by various surface/downhole sources (like the application of the weight-on-bit (WOB), rock cutting process, bottom-hole-assembly (BHA) resonance, downhole tool operation, drilling fluid dynamics, etc.), are the prime causes of downhole tool failure, material fatigue, bit wear/damage, and insufficient surface-to-bottom energy transfer. Since the 1960s, a wide variety of models have been developed to analyze drillstring dynamics and optimize the well/drillstring design. With the advance of drilling engineering, sensor technology, and data science, a fast and comprehensive drilling system dynamic model is in need for real-time drilling optimization and automation.
In this study, a control-oriented physics-based lumped parameter model (LPM) is developed to investigate the fully coupled drillstring dynamics in all three directions. Various boundary conditions (wellbore-drillstring interaction, bit-rock interaction, presence of stabilizers/centralizers) and system input actuations (surface WOB/hookload, surface rotational speed (RPM)/torque, mud motor operational parameters, etc.) are defined in the modeling framework. Simulations are run for different drillstring scenarios in a vertical and an actual L-shaped wellbore configuration. System dynamic responses illustrate various amplitudes, frequencies, and modes of fully coupled drillstring vibrations at different depths when simulated with different drilling parameters. Another significant observation is the emergence, propagation, and transition of lateral vibration modes between forward, backward, and chaotic whirl patterns. Based on the tradeoff between accuracy and complexity, the proposed dynamic model can be adapted for real-time model-based control, and can also be deployed for well design purposes or digital twinning applications.
Design and Calculation of Process Parameters in Bullheading and Pressurized Mud Cap Drilling
Authors: Liu Yaxin , Upchurch Eric R. , Ozbayoglu Evren M. , Baldino Silvio , Wang Junzhe , Zheng Danzhu 
Published: March 2023

Abstract
This study aims to provide the design and calculation method of key parameters in bullheading/PMCD operations. An improved gas migration velocity model in closed well conditions was developed based on the combination of the equation of motion (bubble flow) and Taylor bubble correlation (slug flow). A detailed derivation of the model can be found in our companion work (Liu et al. 2023). Experiments of Taylor bubble countercurrent behavior in an eccentric 6 in. × 4 in. annulus were conducted. Fluid rheology, annulus inclination, and internal pipe rotational speed were varied to provide a clearer understanding of Taylor bubble physics under non-Newtonian countercurrent flow and its implications for effectively managing upward gas migration that can occur in a wellbore during drilling operations in fractured or vugular rock formations. Computational Fluid Dynamics (CFD) simulations were performed to estimate the velocity of Taylor bubble in vertical annuli with downward fluid flow and a new closure relation for distribution parameter, C0, was proposed. The drift flux model embedded in the new gas migration velocity model was applied to simulate the dynamics of bullheading/PMCD. Good agreement between the model and published data was obtained. The effect of different bullheading rates on surface pressure and gas fraction in PMCD operation was examined.
Automated Offsets for Drill Bit Performance Evaluation, Analysis, and Monitoring At-Scale
Authors: Skoff Gregory , Fink Dave , Poor Andrew , Gjertsen Ole , Wolfram Preston , Santana Roberta , Ford Robert 
Published: March 2023

Abstract
Utilizing big drilling data requires an innovative approach. The service company’s drill bits business is largely based upon an in-house drilling record system (DRS) that captures global bit record performance data. The DRS contains over 1.8 million wells drilled worldwide since 1980 with nearly 5.4 million total BHA runs from over 100 countries. In the last 10 years alone, over 1.4 million bit runs drilling over 2.8 billion ft of formation have been recorded. To utilize this vast amount of data for drill bit performance evaluation, analysis, and monitoring, the innovative approach described in this paper was developed and implemented.
Traditionally, the performance of a drill bit run–often measured in terms of drilled footage and ROP–has been evaluated versus similar offset runs. Offset runs are chosen in various ways, but are typically done manually by bit engineers, meaning that offset run selection is subjective based on personal experience and bias. Furthermore, people often only evaluate the performance of test bit designs. Instead, we wanted to analyze and monitor the performance of all drill bit runs. To alleviate these biases and enable a wider breadth of considered runs, an objective offset run selection workflow was developed and implemented within DRS. Offset runs are selected based on a sophisticated filtering and scoring routine that considers many characteristics such as geographic location, time, wellbore and drilling system design, along with lithology. As new data enters DRS continuously, this workflow runs on a regular basis using an automated pipeline.
The performance evaluation results of the automated offset selection workflow are available to all data analysts (engineers and salespeople) both inside DRS and extensible applications to aid in performance monitoring and new product development target-setting. Product performance is now objectively evaluated at-scale across geographies and always utilizing apples-to-apples comparisons. The workflow has proven itself quite useful and delivered business value already but also exemplifies the need for both enhanced data quality and improved bit record data capture rate. These are ongoing efforts to further enhance and improve this workflow.
Automated workflows like this one can help our industry by eliminating repetitive biased tasks and allowing people to focus on more creative processes leveraging objective data. Developing new drill bit designs, material selections, or component selections to overcome new challenges are creative processes which contribute to increased drilling performance and lower costs for the industry.
Drilling Three-Mile Laterals Tighter and Safer with a New Magnetic Reference Technique
Authors: Pare Andrew , Cosca Nico , Berarducci Alec , Crookston Glenna , Paynter Ryan 
Published: March 2023

Abstract
Three-mile laterals have become more common over the last five years of onshore US drilling. They are especially commonplace in the Appalachian and Permian basins and are used to overcome limited surface access for drill pads and for economic reasons. These long laterals pose significant wellbore positioning and anti-collision challenges. Horizontal position error grows at 2% (or more) of the lateral length per degree of wellbore azimuth error. This work addresses these wellbore positioning challenges with a new and significant improvement in magnetic field determination. With this procedure, multi-well pads with tightly spaced three-mile laterals can be drilled without compromising anti-collision standards or horizontal placement goals.
Most commonly in the US land market, tightly spaced laterals are 1-2 miles in length and make use of In-Field Referencing (IFR-1) magnetic models built from airborne geophysical surveys to ensure proper positioning and avoid well collisions. For more challenging pad designs, such as three-mile laterals, a new method has been developed to combine an IFR-1 magnetic model with a near-well magnetic theodolite measurement to build a more precise magnetic model and positioning tool code. Specifically, the declination error terms in the ISCWSA (Industry Steering Committee on Wellbore Survey Accuracy) Error Model can shrink beyond the IFR-1 tool code specifications. This reduces the horizontal uncertainty in the ellipse of uncertainty (EOU) by upwards of 40% when compared to the MWD tool code standard.
A study was conducted on a typical well and pad design for three-mile laterals in the Marcellus Shale in Pennsylvania. We find that the horizontal uncertainty with the MWD tool code at two and three miles of reach to be 206 feet and 303 feet, respectively. With the new tool code enabled by this body of work, we calculate the horizontal uncertainty at two and three miles of reach to be 120 feet and 174 feet, respectively. These results clearly show that this technique enables three-mile laterals to be drilled more safely and more tightly together. It is preferable for well pad design and lateral spacing to be determined by drilling and reservoir economics rather than collision concerns. Well planners and reservoir engineers can now safely access more of the reservoir from a single pad with longer laterals.
This work is novel because it combines a ground based, near-well, magnetic measurement with an airborne derived IFR-1 model. This allows for a greater reduction in positioning uncertainty than has been available in the past. The application of this method to three-mile laterals is also new and has a profound impact on being able to plan optimally spaced wells and avoiding collisions.
Gas Migration Model for Non-Newtonian Fluids Under Shut-In Well Conditions
Authors: Liu Yaxin , Upchurch Eric R. , Ozbayoglu Evren M. , Baldino Silvio , Zheng Danzhu , Wang Junzhe 
Published: March 2023

Abstract
Addressing gas migration in a static mud column during the shut-in period is a major concern in Pressurized Mud Cap Drilling (PMCD). Significant discrepancies have been found between the field data and existing correlations for gas migration velocity, since the latter are based on either small-scale experiments or overly simplified assumptions, resulting in overly conservative estimations. To meet the Light Annular Mud (LAM) requirement for managing gas migration and to monitor the transient pressure experienced throughout the PMCD operation, an improved gas migration velocity model was developed by combining the equation of motion (bubble flow) and Taylor-bubble correlation (slug flow). In the bubble flow model, the effects of non-Newtonian fluid properties and drill pipe rotation are considered through a modified drag coefficient (CD) that incorporates the bubble Reynolds number (Reb) and dimensionless shear rate (Sr). The effect of bubble swarm is taken into account through a void fraction (αg) term. The slug flow model is based on a Taylor bubble correlation in terms of Eötvös number (Eo) and inverse viscosity number (Nf). For the first time, the dependence of Taylor bubble velocity on drill pipe rotation has been shown and correlated as a function of Sr. Predictions of the gas migration velocities in PMCD operations are made and successfully compared with the existing models and test-well experimental data. The drift flux model embedded in the new gas migration velocity model was applied to simulate the gas migration in a test well. Good agreement between the model and measured pressure results in the full-scale test-well experiments can be obtained. Its companion work (Liu et al., 2023) provides the design and calculation method of key parameters in bullheading/PMCD operations.
Rotary Steerable Drilling Dynamics and Associated BHA Changes to Improve Overall BHA Performance and Reliability
Authors: Jones Steve , Sugiura Junichi , Johnson D. Wayne 
Published: March 2023

Abstract
During the advanced development phase of a push-the-bit rotary steerable system (RSS), downhole drilling dynamics were captured utilizing high-frequency embedded drilling dynamics sensors distributed throughout the bottom-hole assembly (BHA).
The RSS development testing was conducted in a challenging pocket of the Delaware Basin in the Permian Region of North America. This specific Delaware area has proven difficult to drill with conventional steerable motors due to rapid shoulder wear on the bit and sliding difficulties (Sugiura et al. 2022).
The initial RSS BHAs were designed based on the directional objectives of the well. As the runs and wells progressed, the multiple embedded drilling dynamics sensor data, BHA/bit component wear and reliability, and drilling performance were all analyzed. From these learnings, systematic BHA changes were implemented and measured. This process continued until the drilling pace, reliability and repeatability were at an acceptable level for the project.
This paper details the drilling dynamics, drilling parameters, BHA configurations, formations, and logic for BHA/drilling parameter changes in the 12 ¼-in. intermediate section.
Case Study of the World's First Offshore Implementation of a Drilling Automation Platform with Multiple Closed-Loop Applications
Authors: Ronquillo Nahum , Birgisson Kjartan , Ørevik Morten , M Zurhan M Syahmi , A Murad M Syazwan , Khazali-Rosli Khairul Amir , Abd Mokhti M Ridzuan , Jamal Jasrudin , Bailey Jason , McEwan Doug , Ng Damien 
Published: March 2023

Abstract
Drilling automation technology has been successfully deployed and in operation for several years. While the technologies covered in this paper had already been deployed separately in other regions, this case study is not only Malaysia's first drilling automation project but also the world's first deployment that includes the automation platform combined with two third-party closed-loop control applications (Apps). The study details the technologies, their implementation approach, and key performance indicators (KPIs) to measure the success of the project.
Technical and procedural measures necessary to ensure the safe and efficient use of the system are explained. The project's measured KPIs were collected and analyzed throughout multiple wells and are presented in the paper to measure the performance and success of the project.
Throughout the execution of the project, the automation platform successfully coordinated control ownership of the two Apps. A comparison by the drilling contractor of KPIs with and without the automation technology successfully validates the benefits in performance and consistency.
Cloud-Based Real-Time Well Engineering: Coupling Torque-And-Drag and Uncertainty Modeling
Authors: Chi Yuandao , Kemajou Vanessa , Rajan Anil , Samuel Robello 
Published: March 2023

Abstract
Surface hookload and torque values serve as good indicators for some undesirable scenarios or anomalies during drilling, such as stuck pipe, buckling, and inadequate hole cleaning. However, to detect these risks, it requires drilling engineers to perform the friction factor calibration manually and regularly, which costs more effort and poses significant uncertainties on the detection. In this paper, a cloud-based real-time well engineering webapp has been developed to monitor and forecast tripping frictions and drilling performance. Results of field tests were presented to prove the successful testing of this cloud- based real-time workflow. Real-time hookload and torque values were streamed smoothly to the web application interface. Rig activity, friction factor, and mechanical specific energy (MSE) were also evaluated and displayed in real-time with predicted uncertainty zone. It has been demonstrated that this cloud-based web application supports a multi-tenancy architecture and multiple wells can stream simultaneously with no down time. This new workflow made it possible for drilling engineers to monitor live drilling wells anywhere and anytime while enabling the rig personnel to make significant improvements to operations and make timely and accurate decisions.