bluuebunny/crossref_metadata_2025_split huggingface dataset:
First Integrated Robotics Pilot Offshore West Africa
Authors: Munoz Jean Michel , Collin Gildas , Herrera Ronald , Grenier Philippe , Baconnais Olivier 
Published: November 2024

Abstract
The Oil and Gas industry is still in the early stages of adopting autonomous robots. To build trust among operational teams regarding this groundbreaking approach, TotalEnergies initiated an extensive testing program in 2020, which has seen seven pilots to date. In 2023, an ambitious pilot started off the coast of Angola, showcasing a more integrated approach. This paper offers insights from the Pazflor FPSO pilot, during which two robots were operational for a six-month period.
The pilot project lasted almost two years, encompassing various phases from preparation and preliminary tests to training, commissioning, and the final 6-month deployment. Throughout each phase, various actors played critical roles, including robot manufacturer, Robot Supervision System developers and many other specialists from different disciplines.
Given the complex integration of all the pilot components, collaboration was essential to mitigate challenges related to remote site conditions and ensure a reasonable chance of successful trials.
Only after extensive testing in our robotics playground in France, configured to match the Angola environment, the project did receive the green light for shipment and deployment.
Throughout the project's duration, especially in the operational stages, significant knowledge was acquired. Initially, the on-site team was skeptical about the technology. However, their views shifted as they witnessed the robot consistently executing time-consuming tasks. The pilot project underscored the technology's potential in a significant asset environment and demonstrated the scalability of the robotics ecosystem, with site personnel solely in charge, with only occasional remote assistance from robot experts.
The robots successfully performed routine monitoring tasks as planned by the initial engineering study. This indicated that the robot's operating envelope was well-calibrated, and they achieved approximately 2,300 man-hours annually across the two oil separation modules where they were deployed. A notable accomplishment was the successful integration of various technological components within an affiliate configuration, including adherence to cybersecurity rules.
Nevertheless, there were areas that required improvement. The robots did not achieve the anticipated reliability targets, resulting in a lower mission success rate. Consequently, although the robots were capable of collecting the data as planned, they could not do so at the expected frequency.
In conclusion, the pilot project was a success since we are now on the verge of showcasing a Minimum Viable Product, especially for manned facilities.
Autonomous robotics could potentially be a game-changer and a crucial element of Industry 5.0. This paper provides valuable insights into the large-scale implementation of robotics, considering the comprehensive integration and challenging conditions encountered during the Pazflor FPSO pilot.
Mapping of Karst Using Deep Learning Method: A Case Study in Central Luconia, Sarawak
Authors: Anis Amalina N. N. , Hassan N. M. , Jamaludin S. N. Fathiyah , Izzatie Salman Nurul Fatin , Babikir Ismailalwali , Mat Daud M. Fahmi 
Published: November 2024

Abstract
This study focuses on leveraging deep learning method, specifically Convolutional Neural Network (CNN), to enhance seismic data interpretation for mapping karst bodies in Central Luconia carbonate platform, offshore Sarawak, Malaysia. The research aims to improve the accuracy of seismic data interpretation through detailed mapping of karst geobodies and evaluate the risks associated with karsts. The CNN architecture is designed to effectively capture spatial patterns and features pertinent to karst detection. The model undergoes supervised learning process, wherein it is trained using a labeled dataset. Throughout the training phase, the model learns to discern characteristics patterns and textures associated with karst features by iteratively adjusting its parameters to minimize prediction errors. The model is validated using a separate dataset to evaluate its performance and generalization ability. Hyperparameters of the model are then fine-tuned based on the validation results to enhance its accuracy and robustness. The CNN accurately identifies and maps sinkholes and dendritic karsts, significantly reducing manual interpretation time and effort. The results are validated in 3D cube but it is presented on map view in this paper. The maps provide insights into the distribution, density, and morphology of the karst features which are essential for assessing drilling risks. By highlighting the different types of karst within a carbonate platform, the CNN aids in planning and mitigating risks associated with drilling, such as collapses and fluid loss, ensuring safer and more efficient operations. This advanced approach enhances the understanding of the geological significance of karst formations and supports effective scanning for hydrocarbon reservoirs as well as future planning in CO2 storage selection, if needed.
A Method for Detecting and Solving Auto Driller Instability: A Real-Time Control System Solution
Authors: Chatar Crispin , Pastusek Paul , Converset Julien , Wicks Nathan , Payette Gregory. S. , Quarles Tyler , Barajas Pablo 
Published: November 2024

Abstract
Multiple tool failures on projects across the globe led a multidomain team to collaborate with an operator to explore unconventional sources for causes and solutions. This is the narrative of the development, implementation, validation, and deployment of a novel solution to reduce auto driller instability. These systems are prone to "hidden" instability where large variations in parameters such as penetration rate, WOB, differential pressure, torque, and rotary speed are observed. The main roles of an auto driller are to control drilling parameters, reduce operational variations, and optimize drilling. System instability reduces drilling performance and the lifespan of surface and downhole tools. Service company and operator subject matter experts worked together to develop a method to detect instability. The resulting algorithm is used to monitor all the parameters affected by the auto driller system. Data from multiple sources, such as surface, downhole, and control system settings are aggregated and passed to a software plugin that enables system dysfunction to be identified. The user is presented with a wide range of alarms, flags, and key performance indicators (KPIs).
Multiple wells were monitored in real time using this algorithm. Potential dysfunction flags were passed to the operator's and service company's real-time operations centers (ROCs) to validate the output before suggestions were sent to the rig. This workflow identified multiple cases of instability and system shutdowns that went unnoticed for several minutes on the rig. In some cases, as much as 10% of drilling time per stand could be recovered from the system inefficiency. The deployment results were reviewed by a team of domain experts to validate the events that were caught and those that were missed, and then the algorithms were improved iteratively.
The system worked well with a fit-for-purpose real-time monitoring workflow producing near perfect results. Because it would be distracting to send the raw signals directly to the drillers at this point, more work needs to be done to make the interface available to the drill teams directly at the wellsite. It was found that reducing peak stress on components contributed to fewer downhole failures. The first trials were too short to quantify the effect on rig equipment life but reducing the peak torque on the top drive and motor current on the drawworks should lead to reduced failure rates for these tools. This information can also be sent to the rig contractor to quantify the value of upgraded control systems.
Advanced Electric Submersible Pump Technology Implementation in the Challenging Waterflood Field of Indonesia's Largest Oil Block
Authors: Alkahfi Sayid Habibi , Tejotriarso Satrio Hadi , Indhiarto P. Andri , Yulianto Bangun , Khairi Raihan Naufal , Allo Sakti Andi Lolo , Pasaribu Rinaldi , Anggaraini Hanny , Abadi Faiz Alfarisi 
Published: November 2024

Abstract
The primary objective of this paper is to evaluate the impact of advanced Electrical Submersible Pump (ESP) technologies on improving well performance in the BS Field, one of the most challenging operational environments in Indonesia's largest oil block. Specifically, the study aims to address the persistent issues of low permeability, poor sand connectivity, low reservoir pressure and high gas interference that have historically contributed to high failure rates and diminished oil recovery. Through the deployment of innovative ESP solutions tailored to these conditions, the research seeks to significantly enhance the operational efficiency and economic viability of the oil extraction processes.
Our study employed a comprehensive approach to assess the efficacy of advanced ESP technologies in the BS Field. Initially, a detailed field analysis was conducted to identify specific operational challenges. Subsequently, we implemented three distinct ESP technologies: modern low-rate ESPs, wide-range ESPs, and slim ESPs with motor shrouds, tailored to meet the unique needs of the field. The performance of these technologies was monitored through continuous data collection, including well test, sonolog, amp chart readings, and sensor outputs for pressure and temperature. This data was analyzed to evaluate improvements in operational efficiency and reliability, correlating technology deployment with changes in oil and fluid production rates
The implementation of advanced ESP technologies in the BS Field yielded significant improvements in well performance and operational efficiency. The deployment of modern low-rate ESPs extended the average run life of wells from 103 to 306 days, significantly reducing downtime and operational costs. Wide-range pumps demonstrated their efficacy in managing reservoir variability without the need for frequent resizing, thereby maintaining stable production rates and minimizing oil production losses. The slim ESP setups, equipped with motor shrouds and positioned below perforations, led to a notable increase in oil and fluid rates, achieving up to a 212% increase in oil production and increase more than 100% of fluid above pump (submergence fluid level). These setups also stabilized gas handling and maintained optimal motor temperatures, effectively mitigating risks such as gas locking and motor overheating. Our study concludes that these advanced ESP technologies are crucial for overcoming the unique challenges of high gas interference and poor sand connectivity in waterflood fields, offering significant operational and economic benefits to the oil extraction industry
Flare Recovery Successful Case Study
Authors: Gaber Mohamed Kamal 
Published: November 2024

Abstract
A stream of 2 up to 4 Million Standard Cubic Feet Per Day (MMSCFD) sweet gas used to be burnt and flared on site as a waste of energy causing more than 27,000 pounds per hour (lb/hr.) of CO2 emissions and wasting a power of 5.5 Mega Watt (MW), on the other hand site compressors and generators required a source of power, accordingly a new flared gas recovery skid with a capacity of 4 MMSCFD is installed on site for providing power to Compressors and Gas Generators, cutting the CO2 emissions, put an end to the bleeding running cost of flaring. Skid is designed to recover a flared sweet gas stream of approximately 73 % Molar fraction of Methane (C1) and 12 % Molar fraction of Ethane (C2), approximately 0.5 % of Pentane (C5) and 0.13 of Hexane plus (C6+). The maximum allowable acceptable water content for conditioned gas is 70 pound per Million Standard Cubic Feet Per Day (lb/MMSCFD). A maximum consumed power of 130 Kilo Watt (KW) as a total duty. The maximum allowable acceptable of CO2 downstream from the unit is 3.8 % Molar fraction. Gas Lower heating value should not be lower than 1,000 British Thermal Unit per Cubic Feet (BTU/FT3) The main process components of the skid are summarized as: gas filtration, gas metering (totalizer), gas heaters, gas reduction., outlet scrubbers, controlling and instrumentations and piping and accessories. Recovering a flared gas up to 4 MMSCFD, cutting total running cost of approximately 1.1 Million United States American Dollars (MMUSD)/year, saving the required power of approximately 10.6 MW for the site facilities and also reduce the environmental harm impacts of flared gas cutting the CO2 emissions of 27,141.34 lb/hr. As 60% of electric power is produced of natural gas, capturing flared gas could cover 5% of Egypt's energy needs and add 300 MMUSD to national economy the introduced solution of flared gas recovery skid is able to recover a flared gas up to 4 MMSCFD against an estimated cost of 1.1 MMUSD as a fixed cost and existing asset on site to put an end to the bleeding running cost of 1.1 MMUSD / year for power generation in addition to the cost of gas flaring. Moreover producing and saving total electrical power of approximately 10.6 MW for the existing sire facilities in addition to reduce the environmental harm impacts of flared gas through cutting the CO2 emissions of more than 27,000 lb/hr. matching with the Climate Change Conference that took place in Sharm El-Sheikh, Egypt (COP 27) and also Climate Change Conference (COP 28) that took place in United Arab Emirates.
Deploying Efficient and Lean Maintenance Model by Optimization and Standardization of Companywide Maintenance Job Plans and Resources Adopting a Centralized and Unified Approach
Authors: Rajpurohit Surendra S. , Adwan Mohamed Zaky , El Sayed Gamal Wael , Al Rashedi Mohamed Ali , Iyer Rajesh Sivaraman , Pramanik Mrinmoy Kumar , Al Mazrouei Khamis Humaid , Mohammed Abdalla Osama Omar , Ramachandran Ajay , Anilkumar Ravishankar , Al Zahmi Abdulazeiz Mohamed Rashed , Al Shehhi Talal Mohammed , Vadakkengara Abdul Gafoor , Patel Priteshkumar Amrutbhai , Ali Safdar , Beg Furqan Husain , Al Katheeri Mohamed Abdulla , Al Ali Ali Humaid 
Published: November 2024

Abstract
As part of our continuous efforts to foster uniformity, efficiency, compliance to best practices and standardization, a new systematic initiative was taken to standardize and optimize the maintenance job plans and resources (logistics and manpower) for three maintenance disciplines (Mechanical, Electrical & Instrument) across company sites to ensure optimal number of personnel required for a defined set of maintenance activities. We conducted an initial review and analysis of the maintenance plans across company sites and found discrepancies and different practices implemented. Potential opportunities were also identified which could be utilized to obtain lean and standardized maintenance programs across company sites. Thus, SMEs from different disciplines conducted deep dive reviews and brainstorming sessions to reach an optimal maintenance program that can be implemented without compromising HSE and asset integrity. It was also observed that there was no systematic and standardized practice being followed to quantify the required maintenance resources (manpower and logistics) and to validate the forecasted manpower for business plan. The outcome of maintenance job plan standardization exercise was later applied to validate the manpower requirement (existing as well as 5 / 10-Year business plan) and thus achieving significant optimization.
Evaluating and Enhancing Rig Controls Automation Through Digital Transformation Efforts
Authors: Auld S. , Wood A. , Whitlow Z. , Hopwood F. , Kern S. 
Published: November 2024

Abstract
Rig controls are essential for digital transformation, serving as an automation tool to execute complicated repetitive processes with precision and accuracy. Process execution and consistency are typically measured by time, while drilling processes use constant set points often incorporating system feedback. Evaluating the effectiveness of these processes, which depend on system feedback, goes beyond time metrics, and requires further digital transformation efforts for proper support and assessment of success.
Automation of rig controls has advanced to a point where an entire drilling stand can be drilled without driller intervention, utilizing predetermined system set points. The next stage of evolution involves optimizing these processes automatically and iteratively. To assess complex automated processes effectively, new digital tools are necessary to enhance scalability of the technology across a large fleet of rigs, enabling real-time interpretation of results. Consequently, a new digital system has been developed to better support rig control automation, enhancing scalability in the digital transformation process.
Drilling departments often focus on lagging indicators such as rate of penetration or well cycle times, overlooking critical leading indicators embedded within the design criteria for control performance. Rig control automations are designed with distinct objectives and performance criteria to measure and interpret.
For instance, an autodriller and stick-slip mitigation controller are typically associated with metrics such as rate of penetration (ROP) and potential bit damage during operations. To effectively assess autodriller performance, it is crucial to understand the system's priorities and analyze time data comparing control commands and responses. The stick-slip mitigation controller benefits from frequency domain data on torque disturbances at surface to properly evaluate performance.
Similarly, a process controller managing weight-on-bit requires time domain analysis similar to the autodriller, but these events are intermittent. This necessitates an event-based data model for mining performance data, including detailed substate analysis within each event. As automation evolves within digital transformation, sophisticated analysis tools are essential for evaluating performance of automated processes.
The drilling rig generates extensive data, much of which exceeds typical requirements for control analysis. However, due to the sheer volume, not all data can be transmitted back to a central data center. Therefore, the control design aims to provide the driller with as many indicators on location as feasible.
Delivering Record-Breaking Gross Footage with Single Slim Bottomhole Assembly
Authors: Fish R. , Saaidi A. A. , Greenwell N. , Kasimin A. , Muqarshi M. A. , Samir E. , Ali A. , Popov T. 
Published: November 2024

Abstract
A new field record for drilling the longest footage with a single bottomhole assembly (BHA) in a slim hole was recently achieved in the Safah field in northern Oman. A multidisciplinary team focused on digital advancements and process enhancements to improve the drilling efficiency and sustainability of the different aspects in the Safah development well construction process. The process considered the introduction of a remote operation structure comprised of directional drillers, geosteerers, and measurement engineers working together through an enhanced communication channel to improve and expedite decision making. Employing a remote operation model also helped to reduce the rigsite crew size, lower the HSE exposure in the rigsite, and enable faster deployment of new technologies. Lean geosteering processes were recommended to reduce off-bottom time and improve the penetration rate. Detailed shock and vibration analyses were conducted, exploring innovative designs and components for mitigation. An updated downhole software with a new downlink command was employed for the first time in the field, minimizing the number of downlinks and performing the downlinks on bottom for improved overall drilling efficiency and reduced the downhole vibration.
This case study highlights the technology innovation, engineering solutions, sustainable remote operation structure, and the valuable learnings that led to this record-breaking achievement.
The Smooth Transition: Cutting-Edge Drag Reduction for Decarbonization
Authors: Aslam Muhammad , Haider Farooq , Balooshi Eisa Al , Ketbi Abdulla Al , Alshehhi Khulood , Amir Muhammad Kashif , Ahmed S. , Ahmed MS. 
Published: November 2024

Abstract
Significant energy is consumed for the transportation and pumping of crude oil from processing facilities to terminals through long distance piping networks. This paper emphasizes on the technologies advancements and strategic initiative of drag reducing agents deployment at ADNOC Onshore asset that reduced the frictional losses of the network and thus saved more than 1.4 MM USD in terms of power tariff, enhanced facility availability and abatement of more than 16000 M ton CO2 / Year.
Major energy consumer in Oil and Gas facilities is export pumping system, where stabilized crude oil is pumped to shipping terminals. High energy consumption in the export pipeline system is caused by significant pressure losses due to turbulent flows caused by the trajectory and long length of network.
Suitable selection is very essential, to ensure the energy efficiency and compatibility of the chemical. Therefore, very stringent evaluation criteria DRAs adopted includes. Compatibility with the piping material to avoid any potential chemical reaction, thus integrity of network.Effectiveness in reducing the drag and improvement in pressure drop.Stability of the DRA under the extreme operating conditions.Operability concerns.Cost-effectiveness and rate of return.
Environmental and safety considerations, such as the toxicity and biodegradability of the DRA.
For the better understanding of drag reduction mechanism in crude oil pipelines and optimum dosage selection of chemical, various published literature and several technology providers were consulted. Based on the evaluation criteria, pilot was conceived at the major asset in Adnoc Onshore for one year. Pilot deployment of Drag reducing agent has shown significant energy saving. DRA dosage of 2 mg/L in the export crude oil network has reduced back pressure up to 5 bar from the network and thus enabled Asset to stop one export pump while maintaining the sustainable oil production rate. This strategic initiative for energy efficiency enhancement and decarbonization has resulted in OPEX reduction of more than 1.4 MM USD / year in terms of power tariff and GHG abatement of 16000 m Tons CO2 / Year, along with 30% enhancing the availability of facilities.
This paper presents the recent innovations of DRAs deployment for crude oil export system and also summaries the viability of chemicals utilization for friction reduction and provides stringent selection criteria that ensures optimum dosage to ensure net positive return on investment. This paper also sheds light on the operational constraints encountered during the deployment and design consideration during the design of new facilities.