bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhancing LNG Production Efficiency by Mitigating Warm Ships Loading Challenges
Authors: Al Kalbani Mohammed 
Published: April 2024

Abstract
Oman Liquefied Natural Gas (OLNG) terminal faces persistent hurdles in maintaining high production rates during warm ship loading, a challenge magnified by the risk of over-pressurization in the fuel gas system. This scenario, occurring once a month on average, poses environmental threats due to potential unplanned flaring, hindering LNG throughput. Crucial to these operations are panel operators who strive to curtail flaring while sustaining production and environmental integrity.
This paper unveils a strategic framework addressing the multifaceted challenges encountered during warm ship accommodation. These initiatives not only boost operational and energy efficiency but also elevate operational excellence and asset performance within the LNG terminal.
One pivotal measure introduced additional activities in the Ship Activity Schedule, fostering collaborative efforts between Ship Officers, the Marine Department, and Operations Department. This collaboration streamlined risk management during Ship Tank Cool Down, offering better control over the fuel gas system and reducing flaring incidents, contributing significantly to operational excellence.
Another critical initiative mandated the presence of a Marine Pilot during Cool Down Operations, ensuring prompt interventions and minimizing over-pressurization risks while enhancing operational efficiency.
Technical guidelines underwent optimization, aligning with contemporary processes and technology, enhancing performance standards, asset efficiency, and operational excellence.
Internal tools, including the Fuel Gas Balance Dashboard, provide comprehensive visualizations of system performance, identifying optimization opportunities and enhancing energy efficiency, further amplifying operational excellence and asset performance.
A comprehensive Fuel Gas System Surveillance Tool enables in-depth performance analysis, driving continuous improvement and directly impacting asset efficiency.
The implementation of these strategic measures and tools at OLNG has effectively managed warm ship loading challenges, significantly reducing unplanned flaring, preserving the environment, and maintaining high production rates. This blueprint serves as a guiding reference for LNG terminals facing similar challenges, emphasizing the significance of proactive measures and collaboration in ensuring efficient operations, minimal environmental impact, and optimized energy utilization and asset performance.
Unveiling Success From Cyclic Steam Injections for Heavy Oil Recovery in India and the Orinoco Oil Belt
Authors: Rodríguez J. R. , Naranjo P. A. León , Molina J. W. , Molina J. D. , Molina F. , Matute A. K. 
Published: April 2024

Abstract
This study highlights the successful implementation of the cyclic steam injection process in a heavy oil field in India and in numerical reservoir simulation studies in the Orinoco Oil Belt. It focuses on optimizing key variables such as steam quality, reservoir energy transfer, well-productivity enhancement, and environmental impact. The methodology incorporates an innovative, comprehensive high-quality steam generation system, producing steam qualities ranging from 95% to 99%. In the Orinoco Oil Belt, the efficiency of injecting high-quality steam was evaluated within an extra-heavy oil formation situated at a depth of 3010 feet and under a pressure of 1100 psi. Numerical results from the Orinoco Oil Belt demonstrate a substantial impact of high-quality steam, achieving a 400% increase in oil extraction rates and an additional 28% increase in accumulated oil compared to conventional methods. This innovative system requires 8% less fuel for equivalent energy generation and leads to a 7.7% reduction in non-condensable gas production. These findings served as the foundation for designing a cyclic steam stimulation (CSS) pilot test in India. In preparation for the pilot test in India, a meticulously designed steam generation system with superheaters and cyclone separators was developed. This system demonstrates its capability by generating steam with qualities ranging from 95% to 99%, utilizing LPG as fuel. Facing challenges such as average reservoir depths of 3700 feet, low permeabilities (1000-2000 mD), oil viscosity of 20000 cP@140°F, and a pressure of 1650 psi, the execution of cyclic thermal stimulation involved 7 wells subjected to injection pressures between 1500 and 2100 psi, and temperatures of 300°C, maintaining steam flow rates from 3.0 to 4.0 tons per hour. Following thermal stimulation, oil production rates showed an overwhelmingly positive outcome with an average increase of 420%. The innovations and best practices presented in this study will facilitate the adoption of efficient thermal processes, ensuring a higher recovery factor, reduced water, and fuel consumption, and minimizing environmental impact. Operationally, non-productive periods were reduced to less than 2%, achieving steam generation with a quality exceeding 90%.
Rejuvenate The Production: A Success Story of Old Wells Revival Using Chemical Diversion
Authors: Raisi Omar Al , Kurniadi Stevanus Dwi , Mowad Benjamin , Lawati Yousuf , Hassan Karim , Salmi Fathiya , Hegazy Ahmed Elsayed 
Published: April 2024

Abstract
Operators are challenged to deliver gas in an ever-changing gas demand market. During periods of low commodity pricing, capitol spend on appraisal or new projects can be heavily reduced. To deliver in this type of environment, operators utilize cost-effective solutions using existing resources. One industry example is the revival of gas production by stimulating mature wells in the Saih Nihayda field in the Sultanate of Oman.
Gas wells in the Saih Nihayda field are typically completed with a combination of perforation in the sections with good rock quality and hydraulic fracturing in the tighter rock layers. As the field matures beyond its first decade, there remains a significant quantity of under stimulated wells in the field. Wells that currently produce below economic gas rates offer a substantial hydraulic fracturing opportunity. Candidate selection is key to unlocking these untapped reserves. Candidate criteria include reservoir properties, remaining gas in place, completion limitations, and well intervention requirements.
Depletion and lengthy perforation intervals present challenges in these wells. The ideal hydraulic fracturing technique would be able to effectively stimulate more than 100 m of clustered perforations and flow back almost immediately after fracturing operations. The fracture growth must be able to cover the entire perforation interval utilizing chemical diversion techniques and material. To validate the proppant placement distribution of the entire treatment, radioactive tracer is pumped and logged during and after pumping. In Saih Nihayda field, wells stimulated using these methods produced above expectations and met economic flow rates.
A fit-for-purpose workflow for candidate selection criteria and the process for stimulating sandstone gas wells in Middle East brownfields was developed. A unique diversion technique and strategies for long perforation intervals in depleted gas reservoirs is introduced, with results confirmed using surveillance techniques.
Using Downhole Electric Heaters to Complement or Replace Cyclic Steam Stimulation Operations
Authors: Cureton Ethan 
Published: April 2024

Abstract
The combination of downhole electric heaters with Cyclic Steam Stimulation (CSS) operations has been successfully piloted in a California heavy oil field. This paper focuses on a field case study of the installation of an electric heater in a horizontal CSS producer with the primary objective of extending the duration of the production phase of the well’s average steam cycle. History matched thermal reservoir simulations based on the results of this field trial predict that operating an electric heater in a comparable well from the beginning of its life could extend the duration of the average CSS cycle by at least 90% while maintaining equivalent cumulative oil production over a 5-year period. The history matched model was adapted for steam cycles of various durations ranging from 3 to 8 months, and the benefits of extending these cycles’ durations using the hybrid downhole heater application are analyzed.
Further modeling work determined that doubling the length of the productive interval of the field’s average horizontal CSS well while electrically heating could completely eliminate the need for steam injection and increase oil production on a per-well basis by more than 10%. Reductions in CO2 emissions through the elimination of steam are estimated to be greater than 80%, and reductions in water consumption can reach as high as 100%.
Whether electric heaters are used to complement CSS operations by extending steam cycle duration, or to replace CSS operations with longer horizontal wells, significant economic and environmental benefits can be realized by implementing the technology.
Laboratory Evaluation to Assess the Performance of a New Eco-Friendly Drilling Fluid Additive
Authors: Alsaba M. , Elgaddafi R. , Ismael A. , Marake T. , Hersi A. 
Published: April 2024

Abstract
Due to the strict environmental regulations particularly with chrome-based drilling fluid additives and due to the challenges faced when drilling HPHT wells in terms controlling the rheological properties and filtration characteristics of water-based drilling fluids, a lot of efforts have been put into the development of an efficient chrome-free based drilling fluid additives. Controlling the fluid loss and rheological properties under high temperature conditions can be very challenging due to the fact that a lot of polymers degrade at such conditions, which could result in poor fluid loss control as well as a dramatic increase or decrease in the rheological properties. This paper presents an extensive development and laboratory evaluation of a new chrome-free lignosulfonate with high thermal stability along with a comparison with some available commercial chrome-free products.
A water-based drilling fluid, which was contaminated with calcium sulfate to simulate the contamination occurring when drilling through thick anhydrite sections, was used as reference point to evaluate the performance of nine different Chrome-Free Lignosulfonate (CFLS) and the performance was compared with two commercially available CFLS. The performance of the new CFLS was evaluated under both low and high temperature. The rheological properties were assessed after aging the reference fluid samples for 24 hours under room temperature conditions and treating it with 8 lb/bbl CFLS. Then, the samples were aged for 16 hours under high temperature conditions (300o F) and both the rheological properties and filtration characteristics were measured. The performance of the CFLS was assessed in terms of the %thinning efficiency as well as the %reduction in fluid loss.
The results showed a significant reduction of 36% in terms of thinning efficiency and up to 42% in terms of fluid loss by the addition of 8 lb/bbls of the newly developed CFLS. On one hand, one of the evaluated commercial CFLS showed a 63% improvement in terms of thinning, however, the fluid loss increased by 33%. On the other hand, the other commercial CFLS resulted in adverse effect on the rheological properties, where the yield point was increased by almost 100% while the fluid loss was reduced by 48%. Based on the results, the newly developed CFLS product was able to maintain both good rheological properties and filtration characteristics under high temperature conditions. The newly developed CFLS outperformed the two commercially evaluated products under high temperature conditions, which shows the great potential of the new product in replacing the available products.
Navigating Sand Management Challenges in Mature Offshore Fields: A Deep Dive into Technologies, Strategies, and Best Practices in Offshore East Malaysia
Authors: Lin Catherine Tang Ye , Jeffry Suzanna Juyanty Bt M , Chandrakant Ashvin Avalani , Yusof Aqil M , Shyan Vincent Lim Ming , Lun Louis Chee Wuei 
Published: April 2024

Abstract
Sand production presents significant challenges in the management of mature offshore fields. Field A has faced persistent sand production issues since 2015, resulting in 16 incidents of loss of primary containment (LOPC) across surface valves and flowlines within a six-year period, leading to substantial production losses. The presence of sand has also caused significant locked-in potentials (LIP) in Field A, resulting from the choking or shut-in of wells due to the risk of sand production, and adversely impacted well performance even after remedial sand control measures were implemented. Consequently, considerable efforts were directed towards enhancing the effectiveness of sand management in Field A.
A comprehensive approach encompassing seven lenses of sand management was adopted, integrating subsurface and surface considerations. Digital technologies played a pivotal role in transitioning the team from reactive to proactive sand management practices. Continuous monitoring, improvisation, and enhancement of these seven lenses over the years have been instrumental in safeguarding production in Field A. Emphasis has been placed on the integration of these technologies through effective reservoir, well, and facilities management (RWFM) workflows, involving production engineers, operations engineers, and offshore crew members, thereby enabling holistic sand management.
As a result, significant production improvements were observed, and no LOPC events have occurred since 2020 at Field A. The applications of game-changing technologies such as erosion-resistant thru-tubing sand screens (ERTTSS), surface bulk desander systems, acoustic sand monitoring, ultrasonic flowline thickness sensors, and other initiatives also instilled higher confidence in managing sand production issues.
In conclusion, this paper offers a comprehensive summary of the key elements within the holistic sand management approach adopted in Field A. Overall, this paper highlights the operational philosophies underpinning real-time monitoring systems, predictive maintenance, and proactive intervention approaches implemented in Field A, that serves as a valuable resource for oil and gas operators seeking to optimize sand control practices and enhance overall production efficiency in mature oil and gas field.
Hybrid Virtual Flow and Pressure Metering Approach Integrating Physics and Machine Learning Models for Accurate and Efficient Rates and Bottom Hole Pressure Prediction
Authors: Abudeeb F. , Idris M. , Abdullah Z. 
Published: April 2024

Summary
Data collection is crucial in the Oil and Gas business. Reliable production and pressure measurements for oil and gas operations can be acquired from Multiphase Flow metering and bottom hole pressure metering. Accurate and continuous production and pressure measurements are crucial not only for field surveillance, but also for effective production optimization. Virtual Flow & Pressure Metering (VFPM) is an alternative to the conventional physical meters and can exist in two forms, physics-based VFPM and Machine learning-based VFPM. The physics-based VFPM relies on multiphase flow and pressure simulations including thermodynamics, fluid dynamics, fluid modeling, and optimization techniques. Machine learning VFPM however, uncovers the relationship between target variables and sensor data. Both methods have strengths but also have some limitations.
The proposed algorithm is the hybrid VFPM that merges both types, the physics-based VFPM and the Machine Learning VFPM. The approach first tests each VFPM method independently and checks for time consumed and accuracy. Then, it tests for the hybrid model option. In the hybrid model case, the framework starts with the basic well data going into the Physics-based Model to simulate the well behavior and create sensitivity analysis. The generated data is then fed to the Machine Learning model. The process then considers correlation between input features and removes highly correlated features. Data is split into train and test and then, the regression model is built using multiple model options to choose the most suitable model based on accuracy metrics and elapsed time. The best model is picked and the target variables are generated. The model here was decision tree-based Machine Learning Model as it represented the data best and needed few hyper-parameters to tune.
The effectiveness of the algorithm was tested and validated, achieving a high accuracy of 90% in predicting Multiphase Flow Rate and 98% accuracy in predicting bottomhole pressure, and a reduction of 45% in time consumed to generate the data.
The algorithm's prediction reduces the time needed to generate data using solely physics-based VFPM while increasing the accuracy of the solely Machine Learning-based VFPM. In addition, this approach can translate into a huge cost saving since it eliminates the need for a physical meter in each well.
Identification of Polymer Flooding Flow Channels and Characterization of Oil Recovery Factor Based On U-Net
Authors: Cao Jinxin , Li Yiqiang , Zhang Yaqian , Gao Wenbin , Zhang Yuling , Cai Yifei , Tang Xuechen , Li Qihang , Liu Zheyu 
Published: April 2024

Abstract
Image identification is a major means to achieve quantitative characterization of the microscopic oil displacement process. Traditional digital image processing techniques usually uses a series of pixel-based algorithms, which is difficult to achieve real-time processing of large-scale images. Deep learning methods have the characteristics of fast speed and high accuracy. This paper proposes a four-channel image segmentation method based on RGB color and rock particle mask. First, the micro model rock particle mask is divided together with the RGB component to form four-channel input data through image processing technology. Pixel-level training set labels are then created through traditional image processing techniques. Through the U-Net semantic segmentation network, the pixel-level oil and water identification and recovery factor calculation of the polymer microscopic oil displacement process were carried out. Combined with the pore distance transformation algorithm, the lower limit of pore utilization for different displacement media was clarified. The results show that U-Net can achieve accurate division of oil and water areas. Compared with conventional three-channel images, the improved four-channel image proposed in this paper has significantly improved the segmentation accuracy due to the addition of the constraints of the rock particle mask, and the global accuracy can be Up to 99%. Combining some post-processing methods, this paper found that polymer flooding increased the mobilization degree of small pores on the basis of water flooding and lowered the lower limit of pore mobilization from 25 μm to 16 μm. In microscopic experiments, the recovery factor was increased by 24.01%, finally achieving rapid and accurate quantitative characterization of the microscopic oil displacement process. The four-channel image method based on the U-Net semantic segmentation network and the improved rock particle mask proposed in this article has strong adaptability to the identification of flow channels in the microscopic oil displacement process. Quantitative characterization of the lower limit of pore movement and recovery degree during microscopic oil displacement provides a new method for microscopic image processing.
Techno-Economic Assessment of Integrated Crude Gasification and CO2-Plume Geothermal Systems: A Synergic Approach for Electricity Generation
Authors: Altowilib A. , Baaqel H. , Sarathy M. 
Published: April 2024

Abstract
Global hydrogen production contributes significantly to carbon dioxide emissions due to reliance on fossil fuels. This study aims to integrate and model various upstream and downstream processes to facilitate concurrent hydrogen production, underground storage, CO2 utilization, and electricity generation. The first part of this paper focuses on modeling gasification and CO2 capture processes, supplemented by an economic analysis to estimate critical capital and operating costs for design, scale-up, and integration considerations. The second part of this work shows how CO2-plume geothermal systems and power generation plants can complement gasification and CO2 capture processes to create a sustainable energy system. Key findings reveal a H2/VR ratio is 0.24 % wt/wt with a CO2 intensity is 3 % wt/wt. The CO-2 capture process achieves a capture rate of 97%, with an initial CO2 flow rate of 582.0 kg/s and a captured CO2 flow rate of 565.8 kg/s. Additionally, the levelized costs of H2, with and without carbon capture, are determined as 1.795 $/kg and 1.684 $/kg, respectively. The CO2-plume geothermal model demonstrates varied outcomes, with the 1000 md scenario exhibiting the lowest CO2 sequestration due to its high average CO2 flow rate, while the 25 md scenario produces the most water owing to low permeability values. Notably, the 250 md and 1000 md scenarios achieve the highest and second-highest average power output, attributed to high CO2 flow rate, low water cut, and prolonged maintenance of CO2 in a supercritical state. This research provides valuable economic and technical insights that support the transition towards a low-carbon hydrogen future. The findings pave the way for more sustainable and efficient energy solutions.
Evaluation of the Effectiveness of the Acid Treatment of Low-Permeability Carbonate Reservoirs Using a Developed Foam-Acid Composition Through Physical Modeling and 3D and 4D Tomography on Core Models
Authors: Malakhov A. O. , Leukhina M. A. , Valisheva D. I. , Zharkov D. A. , Badretdinov E. N. , Kadyrov R. I. , Saifullin E. R. , Bykov A. A. , Nazarychev S. A. , Abdelrehim A. , Varfolomeev M. A. , Abusalimov E. M. , Lutfullin A. A. 
Published: April 2024

Currently, fields with carbonate reservoirs are the main objects of geological exploration, providing the bulk of the increase in oil and gas reserves. Carbonate deposits are highly productive and provide about 60% of global oil production [1]. More than 200 fields with carbonate reservoirs are exploited in Russia. In recent years, low-permeability rocks have become increasingly promising as productive reservoirs. This paper examines the deposits of the Republic of Tatarstan. This fields are characterized by an average reservoir temperature of 23-25 °C, reservoir pressures of 50-60 bar and high salinity of water in the near well-bore area. The oil in the fields is highly bituminous, and the mineralization of water is more than 20 g/L. Currently, carbonate deposits are being actively developed in this area. Contamination or clogging of the bottomhole zone of production wells is one of the main problems that complicates oil production from carbonate reservoirs [2]. In the process of field development, the effectiveness of geological and technical actions to bottomhole treatment of wells decreases due to changes in the structure of reserves, well stock, deterioration of reservoir properties of the near well-bore area, increase in water cut, changes in the component and salt composition of the produced fluid.
The most common method of cleaning the near well-bore area for carbonate reservoirs is the use of various types of hydrochloric treatment. The experience of using hydrochloric treatment technology in the fields of Tatarstan [3–6] has shown that this technology in its traditional design has less efficiency every year. The high rate of reaction with the rock does not allow the acid to penetrate deep into the formation, the low viscosity of the agent leads to the formation of large channels in highly permeable zones. As a result, low efficiency of repeated treatments is observed due to the expansion of existing channels and less radial distance from hole axis.