bluuebunny/crossref_metadata_2025 huggingface dataset:
Determining Hydraulic Fracturing Treatment Methods for Wells in Deep and Tight Carbonate Reservoirs
Authors: Xia K. , Wang W. , Rodoplu R. S. , Moreno Sierra F.
Published: January 2025

The development of deep and tight carbonate reservoirs is essential due to their widespread distribution and significant hydrocarbon accumulation. Acid fracturing is commonly employed to stimulate wells in these reservoirs, offering advantages such as ease of application and avoiding screen-out issue compared to proppant fracturing. However, acid fracturing may face challenges in maintaining effective fracture conductivity, particularly under high in-situ stress conditions typical of deep and tight reservoirs. Relying solely on acid fracturing can potentially lead to reduced oil and gas production. To address this challenge, we propose an integrated workflow for optimizing stimulation in deep and tight carbonate reservoirs. This workflow assists in selecting the appropriate fracturing method by incorporating several key components: carbonate rock typing, calculation of the breakdown pressure envelope and optimal perforation direction, estimation of acid fracture conductivity, identification of ideal perforation locations, and determination of fracturing methods (acid or proppant fracturing). To evaluate acid fracture conductivity and its potential decline, we introduce two new parameters: the acid fracture conductivity threshold (AFCT) and the fracture conductivity declining index (FCDI). These parameters, which can be derived from log data, 1D Mechanical Earth Model (MEM), and laboratory tests, help assess the performance of acid fracturing. The AFCT measures the effectiveness of acid fracturing, while the FCDI accounts for the impact of in-situ stress and rock compressive strength on fracture conductivity. The workflow recommends using acid fracturing when the AFCT is high and the FCDI is low, indicating favorable conditions for acid treatment. Conversely, it suggests proppant fracturing when the AFCT is low or the FCDI is high. An example study demonstrates the application of this workflow to select the appropriate fracturing method for wells in deep and tight carbonate reservoirs. By analyzing log data to identify optimal rock types and perforation locations, the workflow provides guidance on whether acid or proppant fracturing should be employed. Overall, proppant fracturing seems to be a better choice for deep and tight carbonate reservoirs compared to acid fracturing.
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

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

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

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

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

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

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

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

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

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).
Application of XGBoost on Fast Prediction of Hydraulic Fracture Propagation
Authors: Yang Lifeng , Liu Zhe , Liu Hao , Li Ning , Yu Wei , Wang Yu
Published: January 2025

This paper presents a fast fracture propagation prediction method using the XGBoost algorithm, designed to significantly reduce computation time while maintaining high accuracy. By utilizing key parameters such as geomechanical properties, fracturing operation data, and natural fracture distributions, the method efficiently predicts fracture geometry and properties. Latin Hypercube Sampling (LHS) is employed to generate training data, and the model is trained on numerical simulations. Testing on real field cases shows the method predicts fracture geometry with a relative error of 0.6% in length and 1.9% in height for simple fractures, and under 5% for more complex multi-fracture cases. The method's prediction time is proportional to the number of time steps and remains constant regardless of the complexity of the case, requiring only 13 seconds for simple fractures and 85 seconds for more complex ones, compared to traditional simulations that take several minutes or hours. This makes the method highly suitable for real-time hydraulic fracturing operations, providing accurate and timely predictions to support decision-making in complex geological environments.

1. INTRODUCTION

Hydraulic fracturing, commonly known as "fracking," is a critical technology for unlocking the vast potential of unconventional reservoirs, such as shale formations. Its importance stems from its ability to access and extract oil and natural gas resources that were previously unreachable. By injecting a high-pressure fluid mixture into rock formations, fractures are induced, creating pathways through which hydrocarbons can flow more easily toward the wellbore for extraction. The geometry of these fractures plays a key role in determining the efficiency of the fracturing operation and directly impacts the production performance of the reservoir (Li et al., 2019; Sun et al., 2021; Liu et al., 2023). Numerical simulations of hydraulic fracturing have become indispensable tools for predicting fracture geometry and understanding the mechanisms driving fracture propagation (Wu et al., 2015).

Despite the widespread use of hydraulic fracturing simulations, one of the primary challenges lies in their computational efficiency, particularly in reservoirs with complex geomechanical properties and dense natural fracture networks (Li et al., 2020). These simulations require detailed models of fluid-rock interactions, fracture growth, and stress distribution, and the computational burden grows significantly with increasing geological complexity (Wu et al., 2014). In reservoirs with heterogeneous rock properties or intricate natural fracture systems, traditional simulation methods often struggle to accurately capture fracture behavior. This results in extended simulation times, reduced predictive accuracy, and delayed decision-making during field operations.
Revisiting and Expanding the Application of Dc-Exponent Method: A Successful Fault Identification in a Sub-Thrust Exploration Well in Sanga Sanga Axis, Kutei Basin, Indonesia
Authors: Savitri Cindy Dhevayani , Manurung M. Syukur , Nursasono Danny , Said Dwi Kurniawan , Pasaribu Hendra Halomoan , Raharjo Budi , Berto Albertus Ditya , Melkybudiantoro Didi , Apranda Yoseph Robby , Putranto Asnanto Multa
Published: January 2025

The dc-exponent is a traditional method used for pore pressure analysis, known for providing latest depth assessments during drilling. It utilizes drilling parameters such as Rate of Penetration (ROP), Revolutions per Minute (RPM), and Weight on Bit (WOB). In this study, the dc-exponent demonstrated its effectiveness in detecting pore pressure, especially in wells with high subsurface uncertainty, and was also proven to be reliable for fault identification. Deviations from the normal compaction trend (NCT) indicated potential fault zones. In the exploration well P-1, located in the Sanga Sanga axis of the Kutei Basin, Indonesia, the dc-exponent was employed to detect faults in a sub-thrust geological setting. During drilling, negative deflections in the NCT were observed at the expected fault depth, suggesting a possible fault zone. This was later confirmed through wireline logging tools, which validated the fault zone depth identified by the dc-exponent. The method, aside from its primary use in pore pressure analysis, proved successful in fault detection during drilling operations. This method has been applied as a new guideline in some exploration and development wells in Sanga Sanga Axis. It is expected that dc-exponent could be reconsidered as a robust method for expanding its usage in the pore pressure, analysis and fault detection.

1. INTRODUCTION

The onshore of Sanga Sanga Axis, Kutei Basin, is located in Mahakam Delta, Eastern Kalimantan, Indonesia (Fig.1. and Fig.2.). The basin is the second largest hydrocarbon producers in Indonesia after Central Sumatera Basin and the largest gas producers (Ramdhan & Goulty, 2011). These fields are mature areas for hydrocarbon exploration and production, and has effectively produced oil and gas since 1976. The development area extends from the Samboja Field in the south to the Lempake Field in the north, and includes the Sanga Sanga and Semberah Fields, which mark the northern limit of the region's productive extension in the Kutei Basin.
Laboratory Workflow for Shale Drilling-Fluid Optimization and the Effects of Shale Preservation on Measurements—Widespread Applications in Major UAE Fields
Authors: Noufal Abdelwahab , Vantala Aurifullah , Haddad Mohamed , Shehab Abdulla M. , Aljaberi Hamad Abdulla , Molster Jon Bjorn , Muniz Eudes Siqueira , Subbiah Surej Kumar , Martin J. Wesley
Published: January 2025

Wellbore instability can cost millions of dollars lost due to stuck pipe and loss in hole and non-productive time. This known geomechanics phenomenon can be avoided using proper understanding of the rock mechanical behavior and optimized mud weight to keep the borehole stable. However, drilling through shale can be more complicated due to secondary mechanism of wellbore instability due to osmotic effect between mud system and shale formations. This type of instability normally worsens with time and known as time dependent wellbore instability (Subbiah et al., 2018). Therefore, selection of the drilling fluid to counter rock-fluid interaction together with optimum mud weight able to improve and minimize the wellbore instability risk. Inadequate mud weight and non-optimum drilling fluid chemical composition can lead to wellbore cavings and breakouts, which have been observed in the study area.

This scenario becomes more critical when the well inclination angle increases where plane of weakness failure can readily impact mud weight and composition selection. This paper highlights a new novel laboratory workflow for assessment of drilling fluid composition on shale reactivity. This allows optimal selection of drilling fluids to counter time-dependent shale reaction, a common problem encountered with Early Cretaceous Shale formation in the region. In addition, the importance of adequate shale preservation and the use of mineral oil to prevent property altering fluid loss is highlighted in this study.

1. INTRODUCTION

Drilling high-angle development wells in shale has been always a challenge due to nature of the anisotropy and lamination. This can worsen by time dependent on wellbore instability where the instabilities in the formations are largely attributed to the increase in pore pressure in the formations with time due to both mud-pressure penetration and chemical potential mechanism (Khan et al., 2016; Subbiah et al., 2018; Tan et al., 1996). Thus minimizing the drilling risk considering both mechanical and chemical aspect of shale is important for overall success for any drilling program. This can be achived by designing optimum safe and stable mud weight as well as optimum drilling fluid suited/or customized for specific shales.
Numerical – Geomechanical Investigation on the Relative Permeability Changes During CO2 Sequestration in Depleted Carbonate Gas Reservoir
Authors: Tewari Raj Deo , Pratama Edo , Yakup Muhammad Hamzi , Chidambaram Prasanna , Refani Mohammad Oggi , Eydinov Dmitry
Published: January 2025

In this paper, a fully coupled fluid flow and geomechanics simulation is performed to investigate the impacts of geomechanical parameters on relative permeability that may affect both fluid recovery and CO2 storage in the X field, a carbonate gas field located in the Central Luconia Basin, Sarawak. It is observed that by taking into account the effects of geomechanics into simulation model provides effects of deformation of porous media on multiphase systems. Fully coupled simulation geomechanical model indicates a systematic decrease in the gas relative permeability in response to pressure depletion during production. The history matched model is then designed for CO2 sequestration by injecting CO2 with group controls into the gas zone. During injection period, it is observed that there is an increase in gas relative permeability which provides more CO2 stored capacity. It shows that total CO2 stored when incorporating geomechanics effects on the simulation is higher than the model without incorporating geomechanics effects. These findings prove the crucial impact of effective stress-induced pore deformation on multiphase flow properties of rock, which are missing from the current characterizations of multiphase flow mechanisms in porous media, especially for CO2 sequestration.

1. INTRODUCTION

It is necessary to understand rock behavior during reservoir development and other technological operations in order to ensure rock stability or cause rockfall and manage these processes. Geomechanics is important in order to account for rock deformations due to pore pressure changes resulting from production and fluid injection (Gutierrez and Lewis, 1998). In this case, the problem of viscous compressible fluid flow in porous media should be coupled with the system of elasticity equations. The geomechanical model describes elastic rock stresses.

Relative permeability is one of the governing parameters that characterize multiphase fluid flow in porous media for oil and gas industrial applications including CO2 sequestration. Fluid production and injection in the subsurface formation will lead to pore deformation in response to the pore pressure/stress coupling effect. In this paper, a fully coupled fluid flow and geomechanics simulation is performed to investigate the impacts of geomechanical parameters on relative permeability that may affect both fluid recovery and CO2 storage in the X field, a carbonate gas field located in the Central Luconia Basin, Sarawak.
Study on the Rock Mechanical Properties of Deep Coal Under Different Confining Pressures
Authors: Shi Jiangang , Li Gensheng , Zeng Changhui , Yang Zhehua , Wei Qilong , Yin Pengbo , Mu Zongjie , Lai Peng , Wang Bo
Published: January 2025

Fracturing transformation of coalbed methane reservoirs is an important step for efficient production of coalbed methane, and the rock mechanical properties of coal have a significant impact on the formation of coal fractures. Taking deep coal seam cores from a parameter well in Xinjiang as an example, coal quality tests were conducted, and Brazilian splitting tests, uniaxial compression tests, and triaxial compression tests were carried out to analyze the tensile characteristics of coal with different bedding planes and mechanical properties under different confining pressures. The results show that the industrial components of coal are mainly volatile matter and fixed carbon, with low ash content. The microscopic components of coal are mainly vitrinite and inertinite, with an average vitrinite reflectance of 0.79%–0.81%, indicating medium- to low-rank coal. The average tensile strength of deep coal in the direction parallel to the bedding is 0.40 MPa, and in vertical bedding direction is 1.21 MPa. In the perpendicular bedding direction, the fractures formed after coal splitting are more complex, indicating that bedding direction has a significant impact on the tensile strength of coal; Under different confining pressures of 10 MPa, 20 MPa, and 30 MPa, the values of elastic modulus and Poisson's ratio of coal in the parallel bedding direction do not differ much, and the perpendicular bedding direction shows the same characteristics. However, under the same confining pressure, the values of elastic modulus and Poisson's ratio in the parallel bedding direction are greater than those in the perpendicular direction; Under confining pressure, these values are generally greater than those at 0 MPa, but the difference in Poisson's ratio is small, indicating that bedding direction has a more significant effect on the elastic modulus of deep coal. The loading curves of compression tests for deep coal show the same trend, but under confining pressure, coal samples do not have an obvious plastic stage before failure and fail rapidly after entering the plastic stage. During the failure stage, the stress curve drops sharply, exhibiting strong brittle failure characteristics. The greater the confining pressure, the higher the peak strength of the coal. The coal body structure of deep coal in this area is well preserved, with less influence from tectonic movements, belonging to primary structural coal, which is conducive to fracturing transformation of deep coal.
Alternative Geomechanics Analysis for Optimal Wellbore Stability in Sabah's Challenging Multi-Stack Reservoir Gas Fields
Authors: Hazlina H. , Mohd Shazwan S. , Nazrin R. , Kamaruddin S. , Shukri I. , Dzulfadly J.
Published: January 2025

This study presents geomechanical analyses for two gas projects off the coast of Sabah, offshore Malaysia: Field X and Field Y. Field X, a new development with high formation pressure, features a deep-water turbidite environment with varying stress regimes. Field Y, a brownfield with normal and HPHT regimes, has been producing for over ten years, with some reservoirs depleted by up to 6000 psi, resulting in a narrow drilling window. Conventional pore pressure prediction and wellbore stability analyses revealed narrow drilling windows in both fields, leading to high safety and cost concerns. To address these, an alternative study using Gassman fluid substitution on density and sonic logs, along with PVT data and 1D geomechanical models, was conducted. The models, validated through wellbore stability analysis and calibrated with core data, incorporated stress magnitudes, orientations, and rock properties. By applying fluid substitution, improvement on drilling windows were achieved, reducing the need for Managed Pressure Drilling (MPD) and significantly improve the project cost.

This case study demonstrates that fluid substitution enhances 1D geomechanics analysis and wellbore stability, improving drilling efficiency and reducing project expenses for gas fields.

1. INTRODUCTION

A new development campaign for Field X and an infill drilling program for Field Y with three wells has been planned for each field. Field Y has been in production for over a decade where significant reservoir depletion, with pressure drops of up to 6000 psi, has created challenging drilling conditions due to a narrow margin for drilling mud.

A 1D Geomechanical Earth Model (1D GEM) has been developed for both Field X and Field Y, representing the vertical variation of subsurface mechanical properties along the wellbore. The 1D GEM integrates all the data from well logs, well tests, core samples, and seismic surveys, focusing on critical geomechanical parameters such as rock mechanical properties, pore pressure, in-situ stresses, and elastic moduli.
Optimization and Transformation of Impeller Structure of Main Fan for Mines
Authors: Du H. L. , Gao X. Y. , Xu J. G. , Bai J. W.
Published: January 2025

Aiming at the problem of wheel hub cracking caused by the increase of exhaust resistance due to the exhaust air utilization device of Baijiaqu main ventilator, the optimization and transformation research was carried out. The main goal of the transformation is to improve the operating efficiency of the fan under the premise of ensuring low noise and structural safety of the fan. Mainly from the blade design, hub structure design and overall structural strength calculation and analysis. Firstly, in the aspect of blade design, the fifth generation bending-swept orthogonal three-dimensional design theory is used to optimize the blade shape, improve the efficiency of the fan and reduce the noise. Secondly, the structural stiffness design and structural natural frequency design control method are introduced into the hub structure design to ensure that the whole life of the fan is stable and trouble-free. Through the strength calculation and analysis of the hub structure using the finite element method, the rationality of the hub structure design is verified, and the strength conditions for safe and lasting operation are ensured. The operating efficiency of the main ventilator was increased from 28% to over 80% after the modification, and the overall energy consumption was reduced by 40%. It provides a theoretical and practical basis for the optimization and transformation of subsequent ventilators, and has guiding significance for improving efficiency and saving energy.

Introduction

1.1. Background

With the continuous growth of global energy demand and increasingly stringent environmental protection requirements, reducing the negative environmental impacts of coal mining has become a pressing issue. Thin methane in ventilation systems accounts for over half of methane emissions in the coal mining industry, while traditional ventilation systems often directly release methane-laden exhaust into the atmosphere, wasting valuable energy and contributing to environmental pollution(Kholod, 2020; Etiope, 2019; Nisbet, 2020; Newell, 2019). To effectively utilize this energy and mitigate pollution, the installation of exhaust gas recovery systems is essential.
Experimental Investigation of Shrinkage/Expansion of Oil-Well Cement
Authors: Lian Jihong , Feng Yingtao , Yang Zhi , Wang Youwei , Lu Xiangang , Zhang Hao , Xiao Wei , Xu Kaikai , Liu Wei
Published: January 2025

The expansion/shrinkage of oilwell cement is one of the key factors affecting cementing quality and the safe operation of oil and gas wells. Accurate measurement of cement expansion/shrinkage is crucial for ensuring cementing integrity. Existing devices can measure cement shrinkage accurately but fail to capture cement expansion. Therefore, this paper introduces a novel cement expansion/shrinkage evaluation apparatus, which converts cement expansion into radial stress, enabling effective measurement of cement expansion. Experimental studies on cement containing MgO expansion agents have validated the effectiveness of the device. The results indicate that the addition of MgO expansion agents effectively suppresses cement volume shrinkage, and the effectiveness of the MgO expansion agent is primarily influenced by temperature. The presence of overburden pressure inhibits axial cement expansion, explaining why existing devices are incapable of measuring expansion of cement. Furthermore, the water environment surrounding the cement significantly influences its expansion/shrinkage. When the cement is in conditions with excess water available, the cement with expansion agent exhibits a greater expansion magnitude.

1. INTRODUCTION

Cement volume shrinkage is a major cause of gas migration and poor cementing quality in oil and gas wells (Backe et al., 1998; Li et al., 2021; Prohaska et al., 1993; Reddy et al., 2007; Zhou and Wojtanowicz, 2000). Cement shrinkage compromises the bonding quality of the cement sheath, and severe shrinkage can create annular gaps, providing channels for oil, gas, and water flow, leading to interzonal migration (Bois et al., 2011). Cement shrinkage during and after setting significantly impacts cementing quality. To address shrinkage, expansion agents are added to cement formulations to mitigate shrinkage (Watters and Sabins, 1980), but due to the varying downhole conditions, cement with expansion agents cannot accommodate all complex scenarios. Hence, laboratory experiments on cement expansion/shrinkage are critical for controlling shrinkage behavior. Researchers began recognizing the importance of cement expansion/shrinkage for cementing quality in the late 20th century and initiated laboratory measurements (Chenevert and Shrestha, 1991). Currently, the primary methods for testing cement expansion/shrinkage include length measurement and volume measurement. Length measurement involves recording axial length changes in cement, including methods like the corrugated tube method (Jensen and Hansen, 2002) and the traditional ASTM expansion test (Fig. 1.), but these methods do not allow for high pressure and temperature conditions, making them unsuitable for oil well cement. Volume measurement, which reflects shrinkage/expansion by tracking cement volume changes, is commonly used for chemical shrinkage tests (Ghanem et al., 2024).