bluuebunny/crossref_metadata_2025_split huggingface dataset:
Maximizing CO2 Sequestration and Utilization Using Viscoelastic Surfactants Alternating Gas: Optimizing Efficiency and Environmental Impact
Authors: Elmuzafar Ahmed M 
Published: October 2024

Abstract
Greenhouse gases, particularly CO2, are driving significant environmental challenges, necessitating urgent measures to mitigate their impact. CO2 Enhanced Oil Recovery (EOR) presents a viable strategy for contributing to net-zero emissions by capturing and injecting CO2 underground to boost oil recovery, while promoting sustainable energy production. Despite its promise, the high mobility of CO2 poses risks such as viscous fingering, which limits recovery efficiency. Our study addresses this challenge by integrating viscoelastic surfactants (VES) into the CO2 injection process to maximize recovery and CO2 storage. The dual functionality of VES plays a critical role: CO2 reduces heavy oil viscosity, while VES increases the viscosity of the displacing phase and reduces interfacial tension (IFT), improving capillary action and enhancing both oil recovery and CO2 trapping.
A calibrated simulation model was employed, using data from a core flooding experiments conducted at 90°C and 1500 psi combined with micro-CT imaging, to optimize recovery and CO2 sequestration. The model was history-matched to experimental data to define the critical capillary number for desaturation and to refine the curvature of the relative permeability curves across various flooding schemes. Several scenarios were tested, examining the influence of injection rates, slug sizes, and the sequence of CO2 and VES injections. Results from these simulations confirmed the effectiveness of VES in controlling CO2 mobility. When VES is injected before CO2, it diverts gas flow into smaller pores, increasing capillary trapping and minimizing gas breakthrough. This leads to improved oil recovery and enhanced CO2 storage, with CO2 dissolution in brine and mineral trapping contributing to long-term sequestration.
The optimal injection sequence achieved a recovery factor of 59%, surpassing the recovery of other tested sequences. Additionally, the best-performing scenario resulted in a CO2 storage volume of 4,071 cc under standard conditions (SC). These findings demonstrate that incorporating VES into the CO2 EOR process significantly improves both recovery efficiency and CO2 trapping. By optimizing the injection sequence and ensuring that critical capillary numbers for desaturation are exceeded, this approach not only maximizes oil recovery but also provides a viable solution for large-scale CO2 storage in depleted reservoirs.
The application of VES combined with CO2 offers a promising pathway to more sustainable oil production while contributing to global carbon sequestration efforts. This method enables more efficient use of potential storage reservoirs, advancing efforts toward environmental sustainability and helping to mitigate the effects of greenhouse gas emissions.
Synergistic Effect of MgO Nanoparticles and SDS Surfactant on Interfacial Tension Reduction for Enhanced Oil Recovery
Authors: Kandiel Youssef E. , Metwalli Farouk I. , Khalaf Rafik E. , Attia Gamal M. , Mahmoud Omar 
Published: October 2024

Abstract
Innovative methods to enhance oil recovery efficiency remain a high priority in the energy sector. This study investigates the potential of magnesium oxide (MgO) nanoparticles, both alone and with sodium dodecyl sulfate (SDS) surfactant, to improve oil recovery by reducing the interfacial tension (IFT) between oil and water. The research focuses on the physicochemical properties of MgO nanoparticles and their efficacy in IFT reduction, critical for Enhanced Oil Recovery (EOR).
Preparation of MgO nanofluids was achieved using a Magnetic Stirrer and Sonics Vibracell VCX 750 Ultrasonic Homogenizer to ensure thorough mixing and dispersion. Characterization involved measuring density with Calibrated Density Bottles, dynamic and kinematic viscosity using a Falling Ball Viscometer, pH levels with an Electronic pH meter, and electric potential difference (mV). The Malvern Zetasizer Nano ZS assessed Zeta Potential (mV), Electric Conductivity (mS/cm), and Electrophoretic mobility (µmcm/Vs) for both the nanofluid and the surfactant-nanofluid systems.
Paraffin oil served as the oil phase, with nanoparticle (NP) concentrations tested at 0.01, 0.03, 0.05, 0.1, and 0.5 wt%. The SDS concentration remained constant at 0.5 wt% throughout the study. We employed Pendant Drop Interfacial Tension measurements to evaluate the oil-water, oil-nanofluid, and oil-nanofluid + surfactant systems.
Significant IFT reduction was observed—from 47.9 to 26.9 mN/m with a 0.1 wt% MgO nanofluid. Even a minimal concentration of 0.01 wt% MgO NP decreased notably from 47.9 to 41.8 mN/m. An IFT reduction of up to 70% was noted when MgO NPs were combined with SDS. This IFT reduction enhances oil mobility, suggesting the MgO-SDS system as an effective EOR technique. The study also recorded shifts in Zeta Potential from −2.54 to 3.45 mV and more alkaline pH levels from 8.4 to 10.8, indicating the nanofluid's altered surface charge and interaction dynamics. These physicochemical changes, aided by SDS, improved the dispersion and stability of MgO nanoparticles at the oil-water interface, thus boosting oil displacement efficiency.
These findings highlight the potential of the MgO-SDS system as a cleaner alternative to traditional EOR methods that use toxic chemicals, offering economic benefits from enhanced reservoir performance. However, practical challenges remain, including ensuring nanoparticle stability and compatibility under diverse reservoir conditions, managing surfactant adsorption, and scaling up to field-level operations. Future research must address these issues while maintaining interdisciplinary collaboration and rigorous field studies.
In conclusion, incorporating MgO nanoparticles and SDS surfactant presents a promising approach to improving oil recovery efficiency. Further investigation into its field application and economic feasibility is essential to gauge the potential of this technology in the energy industry.
Petrophysical Evaluation of Tight Gas Sand Using NMR and Conventional Logs
Authors: Hamada G. M. , Abushanab M. A. , Oraby M. 
Published: October 2024

Abstract
Petrophysical evaluation of heterogeneous gas sandstone reservoirs is one of the most difficult problems. These reservoirs usually produce from multiple layers with different permeability and complex formation, which is often enhanced by natural fracturing. Therefore, using new well logging techniques like NMR or a combination of NMR and conventional open hole logs, as well as developing new interpretation methodologies are essential for improved reservoir characterization. Nuclear magnetic resonance (NMR) logs differ from other conventional logs. Integration of NMR logs, other open hole logs and SCAL minimizes uncertainties in the determination of formation porosity, permeability and capillary pressure curve.
This paper concentrates on determination of three petrophysical parameters of heterogeneous gas sand reservoirs; 1) Determination of DMR porosity, ΦDMR, it is deduced from NMR porosity and density porosity, 2) NMR permeability, KBGMR, it is based on the dynamic concept of gas movement and bulk gas volume in the invaded zone and 3) Capillary pressure, it is derived from relaxation time T2 distribution.
35% Oil Increase for Gas Lift Platform Using Transient Modelling Approach
Authors: El-dessouky M. E. , El-Bohoty A. M. , Nasr A. A. , Abd-Ellatif M. S. , Mykaid O. A. , Ali A. M. 
Published: October 2024

Abstract
In the oil and gas industry, gas lift is a widely used artificial lift method to boost the oil wells production, particularly when the reservoir pressure is low enough to lift the fluid to the surface. Nevertheless, this application used to face several challenges which affected its processes and led to investing more costs to keep its operations running successfully. This paper summarizes a comprehensive study aimed at optimizing the gas lift operations for one of the crucial offshore oil platforms in the Gulf of Suez Petroleum Company (GUPCO) in Egypt, at minimal costs through the application of a holistic transient modeling approach.
While the steady state modeling approach is useful to many engineering processes in the O&G industry, it is not suitable for modeling the gas lift systems as it can experience many transient phenomenon such as transferring of the gas injection point to different levels across the well different operations, changing of the valves setting pressure to accommodate the variation in the temperature happened at the well's different production phases, pressure surging incidents that might occur due to the sudden closure of valves, and the presence of slug flow which can be attributed to improper gas lift design or due to the change of the formation fluid characteristics causing drastic changes in the production rates. Accordingly, a transient modeling approach had been applied to resolve all these gas lift dynamic issues. The findings provide valuable insights into the design, operation, and troubleshooting of the overall gas lift systems using multiple scenarios, including redesigning the valves operating pressures, adjusting the gas injection rates, recommending deeper points of injection, exchanging some types of the installed operating valves, advising a cleanup program for both the wellbores & the gas lift mandrels, and detecting the plugged valves that need to be exchanged in the next intervention plans.
The project resulted in increasing the net oil gain for the platform under study by 1500 BOPD (35% Gain) after applying some wellbores interventions as recommended by such a holistic modeling approach. The study also includes the cost measures of such services with a focus on finding the most cost-saving method, thus it helped GUPCO reach its production target with minimal efforts & costs.
This paper marks an exceptional solution for perfecting the gas lift applications in GUPCO by allowing the simulation of all the dynamic operations of the gas lift systems which helped in solving all the unstable production incidents & the unloading failures that cannot be captured using the customary steady state gas lift modeling approach, thus, it encouraged GUPCO to consider the gas lift transient modeling as a fundamental element in the optimization of all the future gas lift operations.
Downhole Wireline Tractor Glide in Horizontal Wells of UAE
Authors: Singh Chawla Tamanjot 
Published: October 2024

Abstract
Horizontal wells drilled in recent years in the UAE are becoming mature, yet wireline movement in such conditions is often restricted and hindered by high dogleg angles. The increased expense and risks at each stage—drilling, completion, and production—challenge the improvement of wireline interventions in horizontal wells. During workover intervention activities, deploying tractor tools has been crucial for the success of wireline operations in the UAE. This approach significantly diminishes client's rig time and well costs while critically limiting HSE risks associated with CTU conveyance. This paper presents utilization of tractors for wireline interventions in the challenging UAE field.
The tractor's gearbox is designed to convey a maximum torque of 1.2 ft-lb, enhancing the reliability of the tractor under high-temperature conditions over an extended period. The tractor is engineered to perform at a consistent full load output of 25,000 psi and 350°F. The wheel configuration has been optimized for traction and longevity, providing a more comprehensive approach to downhole conveyance.Torque is transmitted from the motor to the drive wheels through a series of gears built into the arms. The force magnitude is adjusted automatically in response to the applied load, maintaining traction throughout the horizontal range. The arm profile is designed to push well debris sideways, helping to avoid buildup ahead that could hinder progress along the well.
The success of logging and perforating with a tractor has proven its capacity to convey heavy gun strings and withstand the stress associated with the high shock created during perforation. Incorporating tractor technology for wireline intervention has demonstrated improved operational efficiency and significant cost savings.
The smaller footprint compared to CTU unit deployment for horizontal conveyance and the logging-from-anywhere capability of tractor deployment are particularly beneficial in offshore operations. The hazards inherent in overall intervention costs are minimized as a result. Creating sustainable solutions reduces the demand for CTU-conveyed wireline conveyance in horizontal wells.This paper highlights the innovative strategy of utilizing downhole tractors to support the long-term integrity of enhanced wireline interventions in an eco-friendly and cost-effective manner.
Successfully Engineered and Delivered a Highly Inhibitive Anti-Accretion Drilling Fluid System for Drilling Ancestral Nile Fill Well in the North Beni-Suef Area
Authors: Kamel Mohamed , Alsaeed Akram , Elsharkawy Mahmoud 
Published: October 2024

Abstract
Petrosilah, a joint venture between the Egyptian General Petroleum Corporation (EGPC) and IPR Lake Qarun Petroleum (IPR LQP)/Pharos Energy, holds a stake in the North Beni-Suef (NBS) exploration concession in Egypt's Western Desert. Drilling the Ancestral Nile Fill clastic deposits in offset wells west of the Nile has historically posed significant challenges due to borehole instability and highly reactive formations. These challenges have led to numerous drilling complications, including pack-off tendencies, tight holes, severe to complete losses, casing hang-ups, and mechanical sidetracks.
Traditional approaches to mitigate these issues have relied on expensive mud additives, heavy mud weights, varying casing depths, conditioning trips, and continuous reaming. Although the Drilling with Casing (DwC) system has been utilized, it has inherent limitations. To address these challenges, Petrosilah, in collaboration with Baroid Drilling Fluids, developed a novel approach to optimize a cost-effective drilling fluid formulation that enhances wellbore stability while reducing the overall cost impact observed in previous Beni-Suef offset wells.
The optimization process was divided into two key phases: planning and execution. The planning phase involved gathering and analyzing data, including sampling the Ancestral Nile Fill formation from offset wells at a sister company. These samples were assessed against various highly inhibitive fluids commonly used in the Egyptian Western Desert. Through rigorous laboratory analysis, particularly using linear swell meter results, a clear advantage emerged for a silicate-based fluid enriched with 3-5% v/v GEM GP, which was ultimately selected after evaluation against well objectives.
In the execution phase, the selected silicate-based fluid demonstrated remarkable efficiency during field application, delivering best-in-class performance in the first two exploration wells, NBS-SW-1X and NBS SW-5X.
This paper details the step-by-step process and methodologies employed in fluid selection, Ancestral Nile Fill formation analysis, and field observations, leading to the successful application of the silicate/GEM GP drilling fluid. This innovative approach effectively tackled previous drilling issues in the Beni-Suef wells’ intermediate sections, eliminating borehole instability and significantly reducing drilling costs. This work represents a substantial advancement in drilling practices for challenging environments.
Maximizing Mediterranean Gas Exploration Success Rate and Revolutionize Subsurface Imaging of The Reservoir Heterogeneity with Artificial Intelligence-Assisted Workflow
Authors: Hafez Ahmed 
Published: October 2024

Abstract
A successful gas exploration/appraisal drilling campaign of the Pliocene-aged complex deep-water incised canyon reservoir in the Mediterranean Basin is achieved with outstanding results through applying an innovative integrated workflow that firmly assisted with the artificial intelligence (AI) algorithms and technologies. The convolutional neural network (CNN) algorithm is the core building block of the workflow, which enabled us to recognize and delineate the internal depositional architectural elements of the incised canyon reservoir (i.e. 4th/5th order channels) directly from the 3D seismic data with high-level of accuracy. Six 4th/5th order channels have been successfully delineated within the deep-water incised canyon of interest. Three discrete depositional facies have been robustly distinguished for each 4th/5th order channel through implementing Kohonen self-organizing mapping (Kohonen SOM) algorithm. This enabled for confident high-resolution assessment of the reservoir facies and properties heterogeneities. A robust 3D reservoir model has been built utilizing the outcomes of the AI-assisted workflow, which then used to optimize the subsurface locations of the exploration and appraisal wells targeting the reservoir sweet spots. An appraisal well has been optimized and successfully drilled that encountered 102 m of net pay thickness. The long production test of the well has been shown 38 MMscf/d production rate, which is a very good commercial rate. The workflow is a major step in maximizing the exploration success rate of the Mediterranean Basins through accurate delineation of the deep-water turbidite reservoir heterogeneities and complexities, as well as in other basins where similar settings exist. By applying the workflow, the subsurface complexities were revealed with the artificial intelligence algorithms, uncertaintie s were captured, risks were reduced and project commercial value was uplifted.
A New Approach for Rock Strength Estimation Using Lab Test Measurements in the Southern Gulf of Suez
Authors: Abdelghany W. K. , Elkhawaga M. , Abdelhalim K. , Saad A. , Emara A. A. 
Published: October 2024

Abstract
Rock strength is an essential parameter for geomechanical modeling. Many correlations are normally used for rock strength modeling. These empirical relationships are developed for specific basins, rock types, and ages different from the studied basin. Therefore, UCS needs to be validated using quantitative data on core samples. This paper represents a new approach for UCS estimation using lab test measurements for the first time in the Gulf of Suez.
More than ninety core plug samples were used for the analysis, selected from twenty-seven wells distributed in ten different fields along the southern Gulf of Suez. The samples represent different facies, rock types, and rock strengths to help in monitoring the variation of the results based on each different parameter. A conventional uniaxial compressive strength test was proceeded in which confining pressure was zero. Well logs such as density and sonic logs used to build different relationships with the resulting UCS measurements.
Rock strengths are generally influenced by the physical and elastic properties of rocks. Different rock types have different log-strength relationships, based on their lithology, age, burial history, and consolidation state. Therefore, it is important to avoid applying a relationship calibrated for one rock type to another. Correlations using interpreted parameters such as clay content or total porosity using conventional regression analysis provided a better strength prediction model. In addition, Calibration was improved by using dynamic elastic moduli as they exploit two independent tool responses (sonic and bulk density) which are often more sensitive to strength variations than density or sonic alone and are not overly reliant on interpreted logs. An actual sand management study proceeded using the new empirical equation results to validate it showed good matching.
The results of the study represent a pioneering approach of using actual lab test measurements to calibrate the UCS values in the Gulf of Suez. The new data enhanced the geomechanical model results extremely, especially while proceeding sand management studies, which are sensitive to the UCS values.
Integrated Approach for 3D Complex Carbonate Reservoir Modelling: A Case Study of the Dahra Southeast Field, Sirte Basin
Authors: Elbashir M. B. , Saad N. , Benissa T. , Elakuri A. 
Published: October 2024

Abstract
The study's main objectives are to create a representative static model to be used for the Dahra Southeast field development plan. Moreover, understands the tectonic history and characterizes the fault system by evaluating and modeling the fault system within the field. A structural framework approach using volume-based modeling (VBM) was employed to address the complexity of fault modeling. This approach ensures that all 35 faults are accurately modeled without compromise, and resulted grid cells maintain orthogonality with minimal distortion. Subsequently, structured stair-stepped griding was constructed from the Petrel Structural framework model. To model the Facies and the rock types, trend maps based on thickness fraction were employed to guide the distribution of facies and rock types. Additionally, the porosity and permeability distributions were biased by the rock types. Furthermore, the Saturation Height Function was utilized to estimate water saturation distribution, the uncertainty analysis was conducted. The Dahra reservoir which is one of the Great Mabruk field reservoirs, situated within a shallow marine, rimmed carbonate platform, primarily consists of limestone with occasional dolomite streaks. Diagenetic processes significantly impact porosity and permeability, further complicating the distribution of facies and petrophysical properties. In the NW part of the field, reef-derived limestone overlies back-reef shoal deposits. Cores from central wells reveal proximal shallow-water carbonates, suggesting deposition in a shallow lagoon occasionally interrupted by sub-aerial exposure. These cores also exhibit dolomite streaks. The 3D-created model aligns with the depositional conceptual model and observed trends. Additionally, the successful distribution of petrophysical properties enables precise estimates of hydrocarbon volume, and an excellent history match is achieved. This study was a part of a full field development plan for Dahra Southeast Reservoir. The static model paved the way for strategic prediction scenarios aimed at enhancing oil production in the field.