bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

ABSTRACT:
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

ABSTRACT:
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

ABSTRACT:
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

ABSTRACT:
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

ABSTRACT:
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

ABSTRACT:
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

ABSTRACT:
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

ABSTRACT:
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).
IMPACT OF NUTRITION SYSTEM ON THE DURATION OF THEGROWING SEASON OF GARDEN PEAS IN THE WESTERN FORESTSTEPPE IN UKRAINE
Authors: Nebaba Kateryna 
Published: January 2025

Aim of the study. The purpose of the research is to identify the influence of mineral fertilizers and growth regulators on the duration of inter-phase periods and the growing season of garden pea varieties (Pisum sativum) for the period 2016-2018. Results. It was established that the duration of the growing season of the studied garden pea varieties was average and changed depending on the nutrition by different doses of mineralfertilizers and growth regulators. The fertilization up to 15 kg/ha d.r. in combination with different growth regulators on different garden pea varieties extended the growing season from 2 to 3 days on average. Additionally, there was a tendency to increase the growing season from 7 to 8 days compared to control in terms of nitrogen fertilization up to 30 kg/ha d.r. When nitrogen fertilizers were applied in dose up to 45 kg/ha d.r. the growing season of plants continued for another 2-3 days, depending on varietal signs of culture and processing technologies. Conclusions. The growth rate of a garden pea “Hotivskyi”, “Chekbek”, “Farhus” depended on temperature, humidity, the presence of nutrients and varietal features in the soil to a greater extend. It has been found that some plants grew quickly, accumulated enough nutrients, andmatured later than those species that grew slowly in the first phases of plant development. The growing season of garden pea “Chekbek” was the smallest compared to garden pea "Hotivskyi" and "Farhus". The longest growing season for all examined varieties of garden pea was observed when we applied N45Р30К45 in combination with plant growth regulators. On average, during three years, the growing season of garden pea “Hotivskyi” was 86 days, the growing season of garden pea “Chekbek” was 81 days and the growing season of garden pea “Farhus” was 92 days, which 72 ultimately led to a decrease in yield.