bluuebunny/crossref_metadata_2025_split huggingface dataset:
1D and 3D Geomechanical Modeling of an Unconventional Shale Gas Formation for Well Placement Location and Completions Optimization
Authors: Musa I. H. , Tan C. P. , Leem J. 
Published: January 2025

ABSTRACT:
In unconventional shale gas formations, hydraulic fracturing is essential for production, making well placement and strategic planning crucial for maximising production output. PETRONAS employs machine learning (ML) techniques, particularly artificial neural network (ANN), to generate sweet spot maps located within Montney Shale Gas Formation in Canada for optimal well placement and field planning. Key inputs for the ML algorithm come from the 3D geomechanical model developed for Field A. This process begins with six (6) 1D geomechanical models, calibrated using pressure measurement data, rock mechanical properties, and drilling experience. These 1D models serve as inputs for the 3D geomechanical model, where the rock mechanical properties generated are propagated using co-kriging method. Rock strength properties for the 3D model are determined through specialised correlations developed for the field whilst 3D bulk density volume is used to calculate overburden stress, 3D compressional velocity volume is used for pore pressure prediction using Bower's method and finally, horizontal stress gradient method is applied for horizontal stresses determination. The 3D stresses are validated against the 1D geomechanical models for accuracy. The extracted 3D geomechanical data are then used in ANN algorithms to develop sweet spot maps, which guide well placement and field planning and maximizing production and economic viability

1. INTRODUCTION
Unconventional reservoirs, such as shale gas formations, present considerable production challenges due to their low-permeability source rocks that retain hydrocarbons in situ, rather than allowing migration to reservoir rocks. In contrast to conventional reservoirs, hydrocarbons in unconventional reservoirs require stimulation techniques, such as hydraulic fracturing, to enable extraction. Hydraulic fracturing, entails the injection of high-pressure fluids to create fractures in the reservoir rock, significantly enhancing permeability and facilitating the flow of hydrocarbons towards production wells which is a critical process for the economic recovery of shale gas (Aminzadeh, 2020 and Shi et al., 2022). The Montney Shale Gas Formation, located in British Columbia and Alberta, Canada, serves as a notable example of such an unconventional reservoir. This extensive formation is a major source of natural gas and natural gas liquids, playing a vital role in Canada's energy supply. Since 2013, PETRONAS Canada has been actively engaged in the North Montney Joint Venture (NMJV), focusing on the exploration and production of gas from this formation. The extraction strategy involves the drilling of horizontal wells, followed by hydraulic fracturing to stimulate gas production. The precise geosteering and placement of these horizontal wells are crucial for maximizing reservoir contact, optimizing recovery factors, and ensuring the economic feasibility of field development.
An Advanced 3D Geomechanical Forward Modelling Technique to Predict Sub-Seismic Fault Distribution in a Giant Oilfield, Offshore Abu Dhabi
Authors: Tsusaka K. , Montani H. , Goyara Y. G. I. , Mohamad-Hussein A. , Joonnekindt J. P. 
Published: January 2025

ABSTRACT:
Understanding the distribution of natural fractures is important for reservoir modelling to reproduce production history and for drilling operation to optimize well trajectory and required mud weight. The present study sought to model spatial distribution of sub-seismic faults developed by sedimentation, updoming and regional tectonic activities experienced in a giant oilfield, offshore Abu Dhabi. The study applied finite element analysis to reproduce the present-day geological structure in the field. Paleo-formation surfaces were created by using 3D structural restoration. A 3D geomechanical forward modelling simulated the evolution of geological structure from the time of deposition to the present day through sequential sedimentation process. The numerical simulation results appropriately reproduced the seismic structure from the viewpoint of geometry of dome structure and thickness of each formation. The distribution of rock strain by the simulation showed good agreement with the location of the seismic faults. The orientation of the fractures estimated in the simulation also showed good agreement with that of the fractures interpreted by borehole wall image log. The 3D geomechanical numerical simulation presented in this study significantly contributes on predicting the areas in which the fractures are likely to develop in response to the evolution of geological structure.

1. INTRODUCTION
In development of oil and gas reservoirs, understanding of the spatial distribution of natural fractures makes a significant contribution to reservoir modelling to reproduce hydrocarbon production history. Prediction of the fractured areas is also important to optimize well trajectory and required mud weight to avoid excessive mud loss or kick in drilling operation. Additionally, in carbon dioxide capture and storage (CCS) projects, the distribution of natural fracture network in the not only reservoir but also caprock is one of the key issues to prevent unexpected migration of CO2 injected and to ensure the containment. The extent and network pattern of faults in the subsurface is interpreted and mapped by 3D seismic reflection imagery. Although sub-seismic faults and fractures below the limit of seismic resolution are interpreted by borehole image log, it is not always straightforward to evaluate the spatial distribution between the boreholes.
Characterization of the Mechanisms of Debris Production to Minimize the Risk of Wellbore Instability in a Fractured Carbonate Reservoir
Authors: Fardin N. , Bym T. , Cottrell M. , Quinn S. , Orr R , Ghassan M. , Al Teneiji M. , Kessler J. , Rodriguez-Gonzalez J. G. , Jubb M. , Ginn C. 
Published: January 2025

ABSTRACT:
The joint venture between ADNOC Sour Gas and Occidental Petroleum Corp has been producing sour gas from a carbonate reservoir in the UAE. This naturally faulted and fractured Oolitic limestone reservoir has experienced wellbore instability after five years of production, with several wells producing debris. With new wells planned in the northern part of the field, a risk assessment of wellbore instability during drilling and production is essential. This study employs 3D stress characterization to identify mechanisms causing debris production and assess wellbore stability risks. The methodology includes data integration, discrete fracture network modeling, rock mass property characterization, and numerical 3D stress modeling. Results indicate that wellbore stability is influenced by horizontal stress variability and low-strength reservoir rock due to high porosity or natural fractures. Critical drawdown pressure (CDDP) reductions lead to instability and debris production. In the northern development area, lower porosity and higher rock strength reduce instability risks, though natural fractures remain a concern. Optimizing production rates at maximum allowable drawdown pressure can mitigate debris production, but as reservoir pressure drops, instability risks increase.

1. INTRODUCTION
Sour Gas has been producing from a carbonate reservoir in the UAE for a long time, but recently the producing wells encountered debris issues, prompting a 3D stress analysis and wellbore stability analysis for future developments to avoid similar problems. To better model the 3D stresses from 3D Discrete Fracture Network (DFN) model, predict locations that would be better/worse for these types of "debris failure" issues for both existing and future planned wells, whether the natural fractures do contribute to the debris production as well as wellbore stability of the planned wells in the field having potential highly depleted reservoir, the following tasks have been carried out:
• Data Review, QC, and Integration.
• 3D DFN Modelling.
• Improve Rock Mass Property Description.
• Develop Stress Model from 3D DFN Model.
• Debris Wellbore Stability Evaluation.
• Debris Production Prediction in the Planned Wells. The main purpose of this study was to better model the horizontal stresses, specially within the reservoir to investigate the main factors affecting debris production to prevent/minimise solid production from the planned wells to be drilled in the different part of the field.
Abstract-Experimental Study of Hydraulic Fracturing Fracture Propagation in Deep Shale in Southern Sichuan Basin, SW China
Authors: Bo Zeng , Junfeng Li , Liqing Chen , Qiyong Gou , Danlong Li , Haiyan Zhu , Xuanhe Tang 
Published: January 2025

ABSTRACT:
Due to the complex and strong heterogeneous geomechanics of deep shale gas reservoir in southern Sichuan basin, the hydraulic fracturing results present a significant difference among wells and sections. The uneven fracturing treatment results limits the efficient development of deep shale gas. To study the hydraulic fracture propagation characteristics under the complex geomechanics, true triaxial physical simulation tests were conducted on the 400×400×400mm artificial rock samples. The samples were made under different media characteristics based on the similarity criterion. The sensitivity analysis was carried out, including brittleness, natural fractures and in-situ stress condition. The results show that under the same stress condition, the brittle sample behaves a lower breakdown pressure and a faster propagation rate, while plastic sample generates an appear asymmetric fracture. Natural fracture in plastic sample more easily induced the hydraulic fracture than that in brittle one, the hydraulic fracture can be a bifurcation when it countering the natural fracture. Within the high stress difference, the difference between breakdown pressure and propagation pressure along the fracture direction is larger (about 10MPa), and the fracture initiation and propagation are faster.

1. INTRODUCTION
The Sichuan Basin is rich in shale gas resources and is the main position of shale gas development in China (Zou Caineng et al., 2021). At present, a number of shale gas production demonstration zones such as Fuling, Weiyuan and Changning - Shaotong have been built, which has achieved a major breakthrough in shale gas exploration and development (Wang Jian et al., 2023). However, the complex geological structures in Sichuan Basin, such as extensive development of natural fractures and significant differences in horizontal principal stresses, result in difficult fracturing reconstruction, high critical net pressure required for fracture opening, uneven hydraulic fracture propagation, and low complexity (Huang et al,2024; Zang et al.,2022) has become an important factor restricting the efficient development of shale gas in Sichuan Basin. At the same time, reservoir lithology difference, in-situ stress state and natural fracture development have great influence on the migration direction and fracture geometry characteristics in the process of hydraulic fracture propagation (Renshaw et al.,1995; Gao et al,2018; Tan et al.,2018), which directly affects the fracturing effect.
Recommendation of Specimen Geometry in Determining Point Load Strength Index for Anisotropic Rocks
Authors: Singh D. , Nilankar K. , Singh H. K. 
Published: January 2025

ABSTRACT:
The point load strength index (Is(50)) is the critical parameter in evaluating the mechanical response of rock. Due to its ease in specimen preparation, this index test becomes even more important for calculating the strength index of layered anisotropic rocks. However, an accurate estimation of Is(50) in anisotropic rocks remains a challenge due to the effect of weak planes. This challenge can be overcome by understanding the accurate specimen geometry (length/diameter "t/d" ratio). Therefore, in the present study, the axial point load test of foliated phyllite has been carried out on the specimens having t/d = 1 and 0.6 at various foliation angles (β) of 0°, 15°, 30°, 45°, 60°, 75°, and 90°. The results indicate a significant difference in the Is(50) value across the two specimen geometries. The trend of Is(50) value with β angle for t/d = 1 shows an increasing order up to β = 60° followed by a decrease at β = 75° and 90° with an R2 value of 0.76. Whereas the continuously increasing trend was observed for the t/d = 0.6 having an R2 value of 0.96. Specimens with a t/d = 0.6 exhibit less discrete data sets with valid failure modes, whereas those with a t/d = 1 display large discreteness in the data sets along with invalid failure modes at higher β angles.

1. INTRODUCTION
Major Engineering applications such as dams, tunnels, underground caverns, bridges, etc., are confined within hard and crystalline rocks and stretched within weak, soft, and anisotropic rocks (i.e., sedimentary and low-grade metamorphic rocks). Dissimilar distribution of stresses due to inherent anisotropy often leads to instability of foundations, yielding of rock masses, and excessive deformation, demanding a detailed investigation of the durability and deformability properties such as "strength" within such rock types.
Point Load Test (PLT) is the most practical and reliable index test that has acquired worldwide acceptance as a strength index in rock mechanics and rock engineering practices as per the International Society for Rock Mechanics and Rock Engineering (ISRM) and American Society for Testing Materials (ASTM) standard.
A Physics Informed Neural Network for Predicting Proppant Transport in Hydraulic Fracture
Authors: Ji Lu , Botao Lin , Siyuan Chen , Han Meng 
Published: January 2025

ABSTRACT:
The migration and displacement of proppant in fractures is the key to maintain fracture opening and enhance fracture conductivity. Numerous numerical simulations have been conducted to investigate the hydrodynamics of proppant transport. Since the numerical simulations are computationally expensive and time-consuming, machine learning methods were introduced for proppant transport modeling. However, current methods rely solely on data-driven models, demand large datasets for training, and often yield results that are inconsistent with physical laws. Thus, this study proposed a physics informed neural network (PINN) framework to predict the proppant transport. The PINN was trained on data generated from CFD simulations and used to predict hydrodynamic parameters of proppant, such as solid phase volume fraction and particle velocity. The results indicate that the PINN reduces computation time by 98% while maintaining prediction errors below 18%. Based on the dual constraints of data and physical laws, the PINN accurately describes the four stages of proppant transport and the distribution characteristics of hydrodynamic parameters. This framework offers novel pathways for rapid prediction of proppant transport in hydraulic fractures. Furthermore, this method can also serve as a surrogate model for other particle-fluid flows.

1. INTRODUCTION
Proppant distribution in hydraulic fractures is a key factor in the evaluation of the effectiveness of a hydraulic fracturing operation. Numerical simulation methods have been extensively applied in investigating proppant transport in hydraulic fractures. The Computational Fluid Dynamics (CFD) technique has been proven to be an efficient numerical method for proppant transport simulation (Zhang et al. 2022; Zhou et al. 2024). The prevailing mathematical models used for particle-fluid flow are Euler-Lagrange (E-L) model and Euler-Euler (E-E) model. The E-E model sets particles and the fluid as continuous media, and the flow field and the motion of the solid particles are described and solved by Euler's method (Hu et al. 2023). The spatial distribution of the different phases is described by the volume fraction.
Innovative Logging While Drilling Technologies: Enhancing Real-Time Wellbore Stability Monitoring
Authors: Hussein Mohamed , Fouda Mohamed , Taher Ahmed , Hamid Osman 
Published: January 2025

ABSTRACT:
Achieving wellbore stability is essential for safe and efficient drilling, logging, and completion operations. Pre-well geomechanics studies typically help determine the optimal mud weight for drilling; however, inherent uncertainties make real-time monitoring necessary. This study explores the integration of traditional and advanced logging-while-drilling (LWD) technologies to enhance real-time wellbore stability monitoring and improve the reliability of wellbore conditions.
LWD sensors, including density, neutron, resistivity, and ultrasonic tools, provide real-time data for analyzing wellbore deterioration during drilling operations. Shallow-reading sensors, which are more affected by wellbore instability, are compared with deeper-reading sensors to assess true formation responses. Azimuthal LWD data helps detect the direction of wellbore deterioration, while formation pressure testers allow for real-time mud weight adjustments. Recent LWD innovations, such as ultrasonic sensors, offer high-resolution imaging of near-wellbore deterioration, while ultra-deep resistivity sensors enable look-ahead applications, facilitating proactive decisions to avoid problematic formations.

1. INTRODUCTION
Logging While Drilling (LWD) technology has undergone significant advancements since its introduction to the oilfield industry, evolving into a critical tool for providing robust logging data and improving well placement. LWD tools are particularly advantageous in complex wells, where using traditional wireline logging methods would be either time-consuming or cost prohibitive. With the continuous advancements in LWD telemetry and tool design, new and customized solutions have been developed to address critical challenges in well construction.
A key advancement is the ability to utilize LWD data for real-time decision-making, specifically related to wellbore stability. This capability is especially important in mitigating risks associated with wellbore deterioration during drilling operations. For example, the development of azimuthal high-resolution ultrasonic sensors now allows for precise measurements of breakout width and the mapping of thin drilling-induced fractures. Additionally, real-time ultrasonic amplitude images provide critical insights into wellbore conditions, enabling the proactive monitoring of wellbore deterioration. This allows operators to make timely adjustments to drilling fluid density or modify drilling parameters, ensuring safer and more efficient drilling operations.
Green Hydrogen Storage in Depleted Gas Reservoirs
Authors: Konstantinou C. , Giakoumi M. , Papanastasiou P. 
Published: January 2025

ABSTRACT:
This study explores the potential of repurposing depleted natural gas reservoirs for green hydrogen storage, utilizing the material balance equation (MBE) framework. The presence of an aquifer, a common feature in many depleted reservoirs, is considered, and the Carter and Tracy aquifer model is applied alongside the Peng-Robinson equation of state for hydrogen. A case study is conducted using a reference reservoir geometry with varying hydraulic properties (porosity and permeability) and a range of natural gas production rates. Results indicate that natural gas production rate, formation permeability, and porosity are critical factors not only for gas extraction but also for determining the feasibility of hydrogen storage. The study finds that typical sandstone reservoirs are most suitable for hydrogen storage, while formations with very high or low permeability present challenges. The findings highlight that with appropriate reservoir management, depleted gas reservoirs could serve as an effective hydrogen storage solution, contributing to a more flexible and resilient energy system. Future research should focus on understanding biochemical reactions in these reservoirs when exposed to hydrogen, which remains a relatively unexplored area.

1. INTRODUCTION
The management of energy, a critical component in the transition from conventional energy resources to renewables, requires bridging the gap between demand and supply, often through the use of energy storage. One form of storage is hydrogen gas which is an energy carrier that can be used to store, transport, and deliver energy produced from other sources. In this energy transition, green hydrogen which is produced via electrolysis using renewable energy sources could play a vital role (Kourougianni et al., 2024).
Although the production of green hydrogen is largely secured from a technological standpoint, the limited storage capacity remains a significant barrier to further development. Current storage technologies can accommodate limited volumes. To store large quantities of hydrogen, subsurface formations like aquifers, caverns, and depleted oil and gas reservoirs are promising candidates. Depleted oil and gas reservoirs are porous media which host fluids within their pore network, which once accommodated hydrocarbons. Together with aquifers, they can store large volumes accommodating variations on a weekly basis with TWh in terms of energy storage capacity (Edlmann et al., 2021).
Key Factors Influencing Casing Deformation in Sichuan Basin Shale Gas Reservoirs
Authors: Wu Jianfa , Huang Haoyong , Li Junfeng , Chen Liqing , Xu Ersi , Yu Wei , Liu Chuxi 
Published: January 2025

ABSTRACT:
Casing deformation during hydraulic fracturing in shale gas reservoirs is a critical issue affecting wellbore integrity, operational efficiency, and production performance. This study investigates 18 shale gas wells in the Sichuan Basin, China, identifying 43 casing deformation points. Using geomechanical models, well logging data, and core analysis, the study examines the key mechanisms of deformation, including large dogleg severity, high incidence angles, and natural fractures. Three primary deformation types were identified: Type I due to large dogleg severity, Type II from high incidence angles, and Type III associated with natural fractures and fault slippage. These deformations commonly occur at geological interfaces, such as the Long1-1 and Long1-2 layers, where mechanical contrasts exacerbate stress concentrations. The distribution of observed cases includes 21 Type I, 20 Type II, and 14 Type III deformations. This research provides a comprehensive framework for understanding casing deformation mechanisms and offers practical recommendations for optimizing well designs, drilling strategies, and real-time monitoring to improve wellbore stability and reduce deformation risks in shale gas operations.

1. INTRODUCTION
Casing deformation during hydraulic fracturing in unconventional shale gas plays poses significant challenges to wellbore integrity, operational efficiency, and production performance. It not only compromises the mechanical stability of the wellbore but also affects the overall economics of shale gas operations by increasing repair costs and decreasing productivity. This issue is particularly prevalent in regions with complex geological settings, such as areas with high fault activity and dense natural fractures. Although casing deformation has been acknowledged as a critical concern, especially in regions like North America, research and published data remain limited (Uribe-Patino et al., 2024). In contrast, significant progress has been made in understanding casing deformation in other regions, such as the Sichuan Basin in China (Zeng et al., 2021; Liu et al., 2023; Han et al., 2023; Wu et al., 2023, 2024), highlighting the need for further research in other global shale gas plays, including North America and Argentina's Vaca Muerta shale (Filipich et al., 2024).