bluuebunny/crossref_metadata_2025_split huggingface dataset:
Managed Pressure Drilling Technique Commingled High Pore Pressure Section with Depleted Section, Eliminate Drilling Hazard and Pore Pressure Uncertainty Related High-Pressure High-Temperature in West Kuwait Jurassic Deep Wells
Authors: Mokaimi B. S. Al , Alsarhan M. , Mutairi A. Al , Al-Habib H. , Anton J. , Al-Khaldy M. , Selami B. , Benyounces H. , Alqabandi R. M. , Marin G. 
Published: November 2024

Abstract
The main goal was to successfully drill a re-entry well in the Rahiyah Field, West Kuwait, overcoming the challenge of commingle drilling from the Najmah to Middle Marrat formations characterized by High-pressure High-Temperature (HPHT) conditions and significant pressure uncertainty.
A high-level Managed Pressure Drilling (MPD) strategy was developed, involving the use of a 15.2 ppg mud weight with an Equivalent Circulating Density (ECD) of 16.9 ppg. The plan included performing Dynamic Pore Pressure Tests and MPD Build Up Pressure Tests at the bottom of the Dharuma Formation to accurately determine the pore pressure across transitional zones. Adjustments to mud weight and ECD were made based on real-time data, facilitating adaptation to varying well conditions.
The application of MPD techniques allowed for efficient and safe drilling through a highly uncertain pressure window, reducing the drilling time of commingled sections to 10 days, compared to over 30 days typically required for re-entry wells. The conventional approach would have necessitated a higher mud weight of 16.9 ppg, potentially causing a cycle of fluid losses and differential sticking. The oil-based mud (OBM) for the well’s final total depth (TD) was modified to a lighter density of 12.6 ppg with an ECD of 14.0 ppg, mitigating common issues in HPHT environments. This resulted in significant time savings and reduced non-productive time (NPT), demonstrating substantial improvements over traditional methods.
This case study demonstrates the effectiveness of combining MPD with real-time pressure assessments to manage significant pressure variations in deep well environments. The learnings from this pilot project are crucial for refining cost-effective field development strategies and could significantly influence well trajectory planning, completion designs, and recovery optimization in similarly challenging geological settings.
The Outstanding Geological and Stratigraphic Features Revealed by Abu Dhabi Mega Seismic
Authors: Elila A. , Al Hammadi M. , Xie A. , Al Hammami S. 
Published: November 2024

Abstract
The paper aims to showcase the significant role of mega seismic survey in identifying geological and stratigraphic features that were previously unclear in legacy seismic data, particularly in deeper sections. This has been achieved through the acquisition and processing of seismic data in such a way to produce a sharp image of the geology with minimal noise. The techniques employed include but not limited to broadband, high fold, long offset, full azimuth seismic data acquisition, up- down deconvolution, and FWI & RTM migration, which have resulted in detailed and well-imaged geological and stratigraphic features that would not have been discernible without the application of these advanced seismic data acquisition and processing techniques
Measuring Variations in Rock Mechanical Properties Due to CO2 Injection: Application of Nano-Indentation
Authors: Dontoh William Holdbrook , Mews Kim , Ghanbarian Behzad , Alhajeri Mubarak , Barati Reza 
Published: November 2024

Abstract
Injecting CO2 into geological formations has become an important process for carbon sequestration to reduce atmospheric CO2 levels and mitigate climate change. Therefore, understanding the impact of CO2 injection on rock mechanical properties is essential for assessing the integrity and safety of storage sites. This study employs nanoindentation to measure variations in rock mechanical properties caused by CO2 injection. Nanoindentation provides localized measurements of hardness and elastic modulus. Results indicate significant alterations of more than 95% reduction in Young's modulus of the carbonate rock samples post-CO2 injection, with implications for the long-term stability of sequestration sites. This research contributes to the development of more accurate models for predicting the mechanical performance of CO2-injected carbonate rocks, ultimately enhancing the safety and efficacy of carbon sequestration and enhanced oil recovery using CO2 efforts.
Case Study of the Pioneering Coring Preservation and Management of the First Underground Oil Storage in the Middle East Region
Authors: Osama Mohamed , Salem Gamal , Sumaida Ali Bin , Shamlan Abdulla Bin , Almazrouei Saeed , Al Marzooqi O. , Draz Alauddin Abou , Alajami Abdulaziz , AlSabi Haya , Siddiqui Faisal , Al Shehhi Mouza , El Yossef Bassem S. , Ahmed Mohamed , Abouseada Mahmoud 
Published: November 2024

Abstract
Underground Gas Storage (UGS) is considered a strategic method to balance the supply-demand chain of the energy required in a more economical and feasible way to save some of the storage challenges. The caverns were solution mined into subsurface salt domes, is the focus within the oil & gas industry over the past years. In the absence of caverns, in previous storage studies, oil was initially thought to be stored in porous sedimentary rock formations.
Oil stored underground in geological formations is commonly kept in salt caverns. Salt caverns are engineered from naturally occurring salt domes and due to the plastic nature of the salt, it makes it both efficient & beneficial for the storage of crude oil due to its healing nature of any fractures rapidly due to the pressure nature 2000-4000 feet underground that may occur within the salt. Wells provide the mechanism for the transport of fluids (oil and brine) into and out of the caverns. The wells are constructed in such a way as to provide critical isolation of cavern fluids from the surface environment and groundwater. Studies resulted in proven results for the Salt cavern storage to be a safe, reliable, sustainable, and cost-effective method for storing hydrocarbons, including crude oil, Strategic Petroleum Reserve (SPR) oil, and other refined products.
One of the first steps in this project, requires many sets of lithological data analysis and experimenting and that is the focus of this paper. Extensive core acquisition program was required from well's surface depth till TD, in order to have a full overview/analysis done on all sort of lithological changes across the well for better understanding in executing the salt caverns project. This paper focuses mainly on the coring program for handling core samples from the acquisition process till the preservation and handling phase. This also includes all application challenges from planning, execution to the lessons learned and results/conclusion along with the coring new record runs achieved for the first time setting new possibilities in performance and efficiency delivered with 100% recovery rates.
Fueling Sustainability: End-To-End Digital Oil Field Integrating Production Growth, GHG and Economic Management
Authors: AL Jadidi I. , AL-Saqri K. A. , Al Busaidi H. M. , Al-Mujaini A. S. , Al Ghafri R. S. , Alsharji H. , Al-Ghadani A. 
Published: November 2024

Abstract
The project objective was to build a customized field performance dashboard for enhanced opportunity management and visualization of prioritized surface and subsurface system optimizations. Moreover, it is part of global PDO vision towards digitalization. The project covers production, injection and facility systems using Integrated Production System Management, IPSM, tools which is connected to Digital Oil Field, DOF, Dashboard.
The Automation of Well Model Creation has significantly added value in reducing the total process time from days or weeks into minutes (The traditional average time per well model was around 4 hrs). this Portal has expedited the traditional labor-intensive process and leverage team productivity, while minimizing human-induced errors. The massive cycle time reduction unlocks the opportunity to keep the evergreen sustainable well model status and enables the team to spend more time in identifying the well optimization opportunities early in the game.
DOF as a tool was built to fuel the sustainability of the IPSM maintenance and value realization which is considered as one of the major challenges in any Well, Reservoir and Facility Management, WRFM, business. The above concept of End-to-end WRFM optimization is applicable to most of the water flooded Oil fields with ESP producers.
Significant Economic value has been realized from DOF through real time production and injection monitoring and optimization identification, well test validation and hidden deferment evaluation.
Taking a look to the global oil and gas industry perspectives; DOF adoption is a key lever for Cost competitiveness, Sustainable Production Growth and Gap-to-Potential optimization. An innovative practice to incorporate well operating economics and power consumption with global optimization to align with decarbonization targets. OPEX and Energy consumption analysis was an innovative addition to DOF to minimize GHG emissions and improve cost competitiveness.
Unlocking the Potential of a Giant Carbonate Reservoir: Optimizing Oil Recovery in Tight Zones Following a Long Period of Gas Injection Development
Authors: Abdelaty H. H. , Shbair A. , Alshehhi F. M. , Gutierrez R. R. , Almamari R. H. 
Published: November 2024

Abstract
Recurring evaluation of the selective completion and development strategy of individual reservoirs is crucial to ensure optimal performance. This paper presents a new approach for optimizing the injection scheme in highly communicated reservoirs. After a long period of gas injection in the subject reservoir, gas percolation to the overlying reservoir becomes critical. This paper aims to propose a plan that can enhance the recovery of the subject reservoir without compromising other reservoirs’ performance.
A full-field reservoir simulation model, in integration with surveillance data, including a tracer study were used to investigate various development scenarios, including additional wells, artificial lift need, voidage replacement ratio, balance between peripheral and pattern water injection, and the optimum target injection rates. After each scenario, it was observed that the predominant heterogeneities caused a large amount of oil to be left behind. Therefore, this paper also demonstrates a method for locating and quantifying the remaining oil and determining the best techniques for its recovery. The optimized scenario resulted in an extended plateau and an increased recovery.
The results demonstrated the benefits of switching from gas injection to water injection in the parts of the reservoir where water injection was feasible. The extreme north of the reservoir where water can’t be injected without fracturing, has insignificant remaining oil after long time of gas injection. The gas injectors in this part of the reservoir are sidetracked within the reservoir and switched to water injectors. These actions reduced the gas percolation to the upper reservoir, increased the ultimate recovery, and enhanced the economics significantly due to the lower operating cost. The new development plan of the subject reservoir showed the importance of thoroughly evaluating and integrating all the available data and connecting these data with the reservoir geology to better position the new wells. The updated development plan led to extension of the production plateau resulting in additional recovery and improved economics.
This paper highlights the importance of optimizing the injection scheme for the target and neighboring reservoirs. It highlights that relying solely on common development options does not recover the remaining oil effectively. To enhance recovery, the paper presents a method for quantifying and targeting the remaining oil to select the most suitable recovery technique.
Overcoming Challenges in Congested Environment to Successfully Drill CO2 Injection Project Which Holds Immense Value in Terms of Sustainability and Reducing CO2 Emissions in ADNOC Onshore.
Authors: Kodiah B. , Bethancourt R. , Al-Reaymi M. , Al-Jabery R. , Al-Wahedi K. , Nazarov T. , Khan F. 
Published: November 2024

Abstract
The SWAG (Simultaneous Water and Gas) injection project represents a significant milestone in enhancing oil recovery methods within the region. This project, the first of its kind in our area, faced numerous challenges, primarily concerning the selection of suitable drilling locations. The densities of managing both surface locations and subsurface targets added layers of complexity to usual drilling demanding operations.
The drilling targets were confined to a specific reservoir area, imposing precise adherence to location constraints. This limitation established a considerable challenge as we attempted to find a suitable surface location amid a congested field in a specific location surrounded by multiple facilities and roads. The congestion in the area not only complicated the logistical planning but also threatened to delay the project's timeline significantly.
Among the critical challenges were the difficulties in finding a surface location in a highly congested area, planning the well trajectory to ensure precise targeting of subsurface objectives, and mitigating collision risks with existing wells and the project wells. Additionally, the operation required drilling through multiple reservoirs, each characterized by significant pressure variations, which added to the complexity and risk of the drilling process.
Despite these barriers, Drilling, Asset development and Production teams collaborated closely to devise an innovative solution. By slightly shifting the proposed surface locations and repositioned to be in a straight line at a new PAD location in alignment with the subsurface targets, we were able to circumvent the congestion issues. This strategic adjustment not only facilitated smoother operations but also resulted in significant time and cost savings during the location preparation phase and during production facilities preparation prior drilling the wells.
This paper details the challenges encountered during the SWAG project's initial phase, the solutions implemented, and the lessons learned up to the current stage of the project. Our experience underscores the importance of flexibility and innovation in overcoming logistical barriers in complex drilling projects. Through these efforts, we aim to contribute valuable insights to the industry and pave the way for future projects in similarly constrained environments.
Experimental Investigation of Salinity and Pressure Impact on CO2 Solubility in Saline Aquifers
Authors: Elmasry Youssef , Enab Khaled , Addo-Mensah Alfred 
Published: November 2024

Abstract
Addressing global climate change necessitates innovative solutions for carbon capture and storage (CCS). With their vast capacities, saline aquifers emerge as promising repositories for CO2 sequestration. While solubility is the primary trapping mechanism for CO2 in saline aquifers, a significant knowledge gap exists regarding the role of salinity level and operation pressure on the CO2 solubility in saline. This study delves into the experimental investigation of CO2 solubility in different saline aquifers, focusing on phase behavior analysis through the use of a Pressure-Volume-Temperature (PVT) cell. The research aims to enhance our understanding of the fundamental interactions between CO2 and brine under reservoir conditions, critical for optimizing CCS strategies. Experiments were conducted to observe CO2 solubility in five different brines with different salinity levels at various pressures. The experiments were designed to measure the equilibrium phase behavior of the CO2-brine system, providing valuable data on CO2 dissolution rates and phase transitions under a range of pressure settings. The experimental data revealed that pressure and salinity significantly influence CO2 solubility in saline aquifers. Higher pressures were found to increase CO2 solubility, while the effect of salinity presented a more complex interaction; lower brine salinity showed higher storage and CO2 dissolution. These findings contribute to a deeper understanding of the thermodynamic principles governing CO2 sequestration in saline aquifers and highlight the importance of tailoring CCS operations to specific reservoir conditions.
sIn conclusion, the results of this experimental investigation illuminate the critical role of phase behavior analysis in understanding CO2 solubility in saline aquifers, marking a significant step forward in CCS technology. Integrating the presented empirical data with analytical modeling is the way to develop a new pathway for enhancing the efficiency and reliability of CO2 storage in saline formations. The results of this research efforts contribute to the broader effort of mitigating atmospheric CO2 levels and combating climate change. This model serves as a powerful tool for CCS project planning and optimization, enabling more accurate estimations of CO2 storage capacities in saline aquifers. The implications of this research extend beyond theoretical advancements, providing practical guidelines for the design and implementation of effective and safe CO2 sequestration projects.
Design and Installation of an On-Demand Activated Electronic Liner Shoe Mitigates Risk of Differential Sticking and Eliminates Intervention Cost
Authors: Beaman D. A. , Al Ali O. J. , Abdalla H. M. , Abdelghany M. M. , Young D. A. 
Published: November 2024

Abstract
This paper presents a case study of the first installation of an on-demand activated Remote Actuated Shoe (RAS) in offshore extended-reach wells. The Middle East operator faced challenges related to potential differential sticking while running lower completions in high overbalance conditions.
To mitigate this risk, the liners were equipped with isolation-valve Inflow Control Devices (IVICD) and a system at the toe of the liner to allow circulation from the shoe. However, conventional ball drop-activated shoe valves proved unreliable and time-consuming, often leading to expensive interventions to close the liner shoe. In collaboration with the operator, the original equipment manufacturer (OEM) designed a fit-for-purpose RAS tailored to offshore applications. The RAS was programmed to close after measuring 400 psi above hydrostatic pressure for 45 minutes, providing an on-demand solution for immediate closing of the liner shoe after reaching total depth (TD). A ported bullnose with choke functionality was also designed to create the pressure increase during circulation to signal the RAS to close once at depth.
Upon reaching TD with the lower completions, the wells were circulated for the prescribed 45 minutes before seeing the indication that the shoe had shut, and the completion was successfully set as per plans. The successful installation of the on-demand RAS resulted in significant cost savings, with $1 million saved in potential intervention costs and a reduction of 120 metric tonnes of CO2 emissions per well. Two offshore wells have been completed successfully so far using the on-demand RAS, leading to its adoption as the standard liner shoe for the operator's offshore extended-reach wells in these fields.
This case study demonstrates the effectiveness of the on-demand RAS in mitigating risks associated with high overbalance conditions, differential sticking, and operational challenges during the installation of lower completions in offshore extended-reach wells. The findings highlight the potential for significant cost savings and environmental benefits through the adoption of innovative intervention less technology in oil and gas operations.
Carbon Capture Options For Gas Processing Facilities
Authors: Kannan Srihari , Conradus Isabel 
Published: November 2024

Abstract
For operators of gas processing facilities seeking to decarbonise their operations through carbon capture, one significant challenge stands out: identifying the optimal point within the processing line-up for recovering a high-purity CO2 stream suitable for sequestration. By conducting a comprehensive techno-economic assessment of principal capture points within the gas processing line-up, this paper aims to provide valuable insights to address this specific challenge.
In this study, we will evaluate capturing CO2 (pre or post combustion) from various points within a standard natural gas treating line-up consisting of an acid gas removal unit (AGRU), acid gas enrichment unit (AGEU), sulphur recovery unit (SRU), tail gas treating unit (TGTU), and incinerator.
Real-world scenarios encountered by Shell Catalysts & Technologies’ customers inform our assessment, drawing upon simulations and designs developed by our team. For instance, recent projects like the one at Abu Dhabi National Oil Company, capturing CO2 post combustion from the TGTU, contribute valuable insights to our analysis.
The paper will conclude that the optimal location varies according to a wide range of factors, including the composition of the feed gas, particularly the levels of sulphur, and plant-specific requirements such as sulphur recovery efficiency and environmental regulations.
Crucially, we will also provide insights into the circumstances favouring each capture point. For example, the AGRU is advantaged for high-pressure CO2 capture, contingent upon very low sulphur content in the feed gas. However, there are circumstances in which the AGEU, with the right solvent, could be more effective, especially as it could achieve the twin purpose of preparing acid gas that is suitable for the SRU and generating a CO2 stream fit for sequestration. Such insights are crucial for operators seeking to implement an effective carbon capture project.
Carbon capture at gas processing facilities is relatively new, and uncertainty prevails in pinpointing the optimal location for CO2 capture. By tackling this challenge, this paper offers valuable, practical guidance for operators navigating the complexities of decarbonising gas processing facilities. It contributes to the evolving understanding of carbon capture technologies, facilitating more informed decision-making within the energy industry.