bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory Assessment of High-Power Ultrasonic Tools for Well Stimulation and Drilling Operations
Authors: Alfaraj Rima T. , AlTammar Murtadha J. , Mierez Jesus , Alruwaili Khalid M. , Oluyemi Gbenga , Liu Chao , Shaikh Aijaz A. , Alhamad Luai A. 
Published: January 2025

ABSTRACT:
This proof of concept study explores ultrasound technology applications in the oil and gas industry, focusing on its impact on permeability in core samples damaged by drilling fluids and its ability to break down drill cuttings. Laboratory experiments utilized a 20 kHz sonotrode to assess the effects of ultrasound power (500 and 1,000W) and exposure times (25 and 45 minutes) on tight sandstone cores. Initial permeability was measured before inducing drilling fluid damage, followed by ultrasound treatment. Post-treatment permeability results indicated significant permeability recovery of up to 40%, with enhancements exceeding initial rock permeability by up to 12%. Scanning electron microscopy (SEM) showed reduced deposits in pore throats, confirming treatment effectiveness. A notable shift in particle size distribution (PSD) of up to 14% was observed at 1,000W, indicating partial breakdown of drill cuttings, while no changes occurred at 500W. Computed tomography (CT) scans showed no induced micro-fractures. This study supports the potential use of ultrasound for stimulating low permeability reservoirs and improving hole cleaning during drilling operations.

1. INTRODUCTION
As the oil and gas industry moves towards more sustainable solutions in drilling operations and optimizing production of hydrocarbons, it still faces significant challenges when it comes to traditional techniques of chemical-based well stimulation methods that often come with substantial environmental impact and high operational cost. Drilling operations can cause formation damage due to infiltration of drilling fluids into formation rock, leading to overall lower permeability and well productivity (Mierez et al 2023).
Innovative and sustainable technologies are essential to overcome these challenges related to oil and gas production. One such emerging technology is ultrasound, which offers promising solutions for various oil and gas applications due to its ability to deliver energy effectively through media with less environmental impact. Significant advancements in ultrasound applications have demonstrated over 90% enhancement in oil recovery rates while simultaneously reducing viscosity by more than 80% (Mierez et al, 2024).
Lateral Variations in Geomechanical Properties of Mudstones: An Outcrop Analogues of Caprocks for Geological Carbon Storage
Authors: Iijima Yasutaka , Nifuku Ko , Watanuki Shunsuke , Kobayashi Yuki , Yamamoto Kazune , Suzuki Manabu , Sekine Kotaro , Ito Makoto 
Published: January 2025

ABSTRACT:
A better understanding of geomechanical properties of mudstone caprocks over a targeted storage area is crucial for effective geological carbon storage. However, it is difficult to evaluate lateral variations in geomechanical properties in detail because primary subsurface information obtained through appraisal wells is limited in most cases. Utilization of onshore outcrops as an analogue of subsurface geology enables us to overcome limitation of primary subsurface data. The present study investigated lateral variations in geomechanical properties of semiconsolidated mudstones collected from outcrops with precise lateral correlation. Triaxial compression tests of the mudstone samples revealed that both deformation and strength-related parameters do not show remarkable lateral variation in a spatial range in which pressure disturbance is induced by CO2 injection. It is also inferred from the present study that outcrop samples can be used to evaluate lateral variations in geomechanical properties with precise lateral correlation and the triaxial compression tests under the same confining pressure condition.

1. INTRODUCTION
For effective geological carbon storage (GCS), a better understanding of geomechanical properties of caprocks over a targeted storage area is crucial. Considering spatial range of pressure disturbance induced by CO2 injection, lateral variation of geomechanical properties in a few to tens of km need to be assessed in detail, whereas primary subsurface information obtained through appraisal wells is limited in most cases.
Variations in geomechanical properties, such as Young's modulus and Poisson's ratio, have been evaluated in some case studies for the characterization of shale gas reservoirs that targeted tight mudstones (e.g., Rickman et al., 2008). On the other hand, regarding GCS, a few case studies have only been conducted. Especially, it is pointed out that studies targeted the Neogene–Quaternary soft sedimentary rocks regarding GCS are very limited (Fujii et al., 2024), although GCS projects targeting these rocks are extensively planed in regions such as Southeast Asia and Japan.
Mineralogical Impact on CO2-Rock-Fluid Interactions in High-Temperature Carbonate Reservoir: Case Study from Offshore Malaysia
Authors: Kashim M. Z. , Md Shah S. S. , Tewari R. D. , Giwelli A. , Esteban L. , Clennell M. B. , Noble R. , Vialle S. 
Published: January 2025

ABSTRACT:
Understanding the evolution of rock porosity and permeability due to geochemical interaction is vital for assessing the impact on CO2 storage performance in identified geological formations. This study focused on the influence of rock mineralogy on CO2-rock-fluid interactions and their effects on rock porosity and permeability for S field, which is high temperature, high in-situ CO2 content (∼70%) offshore carbonate field located in Malaysian waters. Two representative core samples, one from gas interval and another from the aquifer interval, were selected from the S field for unsteady-state core-flooding experiments conducted at reservoir conditions (35 MPa/5076 psi and 150° C). Pre- and post-flooding core characterization was carried out using Nuclear Magnetic Resonance (NMR), X-Ray CT-imaging and porosity-permeability measurement to examine any petrophysical alteration resulting from the experiment. The results show that the gas interval sample exhibited a dissolution fingering pattern at the inlet face, induced by CO2 flooding, whereas the aquifer interval sample showed very limited changes. These observations were supported by increased gas porosity-permeability in the gas interval, as indicated by NMR porosity measurements and X-ray CT images showing fingering features, whereas no significant changes were detected in the aquifer interval sample.

1. INTRODUCTION
CO2-rock-fluid interaction could result in alterations of the petrophysical properties (Hao et al., 2013; Zekri et al., 2013; Garing et al., 2015; Khather et al., 2017; Khather et al., 2020) and the multiphase flow characteristics (El-Maghraby and Blunt, 2013; Bennion and Bachu, 2020; Seyyedi et al., 2020) of both rock formation and the subsurface system. The rates of surface reaction are very high in carbonate reservoirs, where calcite reaction rate is 1 × 10−5 mol/cm2/s and for dolomite is 1 × 10−7 mol/cm2/s, which usually lead to greatly uneven rock minerals dissolution (Wellman et al., 2003; Egermann et al., 2005). Even though the rock porosity and permeability are expected to increase due to the dissolution of rock minerals, the change in temperature/pressure conditions at downhole conditions could result in rock minerals precipitation, counteracting the dissolution mechanism. The net effect of this process will result in reduction of rock effective porosity and permeability (Oomole and Osoba, 1983; Izgec et al., 2005).
State of the Art Technology Development for Hydrocarbon and CCS Caprock In-Situ Stress Testing
Authors: Achourov V. , Bautmans P. , Reitan H. , Thompson N. 
Published: January 2025

ABSTRACT:
Until recently the measurement of reservoir caprock and shale in-situ stress has mainly been limited to extended leak off tests (XLOTs) performed during drilling operations at casing or liner shoes. Whilst the wireline formation tester tool has been used for in-situ stress data acquisition for many years, the technique's application has been restricted to particular environments constrained by the fracture initiation, propagation & closure capabilities of the tool. Although many hardware & operational practice improvements have enhanced the technique's success rate, these solutions have not always been successful in shallow and non-conventional formations such as the caprocks that are present in frontier exploration areas of the Norwegian Continental Shelf (NCS). Two flowback solutions were developed to improve the reliability of the wireline formation tester tool. These allow fluid to flow out of the fracture across a fixed choke or at a controlled rate and thereby provide suitable conditions for interpretable fracture closure processes. The technology permits repeated measurements due to its ability to conduct multiple flowback cycles with downhole fluid recycling. These two independent flowback techniques have been deployed in several exploration and development projects on the NCS over several recent years. These developments, together with other operational practice & hardware optimizations, have made it possible for the wireline formation tester to measure fracture closure in low and non-permeable open hole environments.

1. INTRODUCTION
Rock stress measurements in low permeable formations such as caprocks and shales provide critical input to hydrocarbon field developments as well as to carbon capture utilization and storage (CCUS) projects. The industry has traditionally acquired this data by performing (extended) leak-off tests (XLOTs) at casing shoes, which unfortunately aren't necessarily located there where the rock stress data is needed. Other stress testing methods, such as DFITs and minifrac tests, measure rock stress at the depth of interest by perforating a cemented casing, but these often require a tailored well design with associated time and cost implications.
Field-Based Mud Design Optimisation for Mitigating Time-Dependent Wellbore Instability in a Shale Formation in Gulf Region
Authors: Tan C. P. , Zainudin W. N. S. W. M. , Idris I. H. , Razak M. S. A. , Devadass L. , Ariffin M. S. M. 
Published: January 2025

ABSTRACT:
It is estimated that time-dependent shale instability accounts for up to 20% of the wellbore instability problems in Field X, Gulf region which are related, at least in part, to incorrect mud salinity and mud type. While drilling the Shale X formation, severe time-dependent instability problems due to shale sloughing have led to invisible lost time associated with hard back-reaming and stuck pipe. However, conventional method of handling time-dependent shale instability in using offset well drilling experience and practice in the field has not been robust and effective in mitigating the problems. Hence, a study was conducted to deploy the field-based Optimal Mud Salinity Design Tool to eliminate time-dependent wellbore instability problems related to improper mud salinity design in the field. Petrophysical and chemical properties of the shale formation were characterised on sizeable cuttings. End of Well reports of the offset wells were reviewed, and numerous time-dependent wellbore instability-related drilling events in the shale formation were identified. The integrated back-analysis of the identified instability events showed the instability was attributed to insufficient salinity in the drilling fluid which resulted in pore pressure increase due to the mud pressure penetration mechanism not being counteracted by the chemical potential mechanism. The output from the back-analysis were subsequently used to develop two optimal mud design criteria for the shale formation based on breakout mud weight and mud weight used. The tolerable upper limit hole enlargement and lower limit chloride concentration required for optimal mud salinity design were determined based on the invisible lost time for offset wells together with chloride concentration used and associated hole enlargements. Following that, the optimal mud design criteria were used with input from mechanical wellbore stability analysis to develop optimal mud salinity design for drilling the shale formation with water-based mud in two planned wells. As the required mud activity is approximately 0.85 and as excessive high KCl concentration could be detrimental to some shales with generation of microfractures, combined KCl and NaCl salinities with KCl limited to 5% are recommended as optimal mud design for the two wells.
Transforming Subsurface Insights: A Rock Physics Atlas for Enhanced Seismic and Geomechanical Analysis
Authors: Ambati Lokesh , Tiwari Upendra , Bt Abdullah Irmawaty , Rajput Sanjeev 
Published: January 2025

ABSTRACT:
Wireline log data is essential for subsurface characterization, but incomplete data, such as missing shear sonic logs, can limit our understanding of rock properties. In this study, we developed a rock physics model to predict shear sonic logs in wells with missing data. The predicted logs were then used to estimate geomechanical properties, which showed excellent agreement with measured values. To further explore the implications of our results, we conducted fluid and lithology substitution modeling using the predicted elastic logs. This allowed us to investigate how different fluid types and saturations affect seismic responses. Additionally, we constructed a rock physics template to integrate all relevant information for subsurface analysis, making it accessible to geologists, geophysicists, and geomechanical engineers. The predicted elastic logs can be applied to various subsurface characterization studies, including seismic reservoir characterization, 4D analysis, stress estimation, and wellbore stability assessment. Our research demonstrates the value of rock physics modeling in addressing data gaps and providing valuable insights into subsurface properties.

1. INTRODUCTION
Rock physics has historically been crucial in linking geological characteristics with elastic and seismic parameters, enabling the precise interpretation of well logs and seismic data. This pilot study in the Sarawak Basin, Malaysia, advances the field by integrating rock physics with geomechanical principles. By developing and applying rock physics techniques, we significantly enhance subsurface modelling and prediction. We created a pilot rock physics atlas over the study area, incorporating geological, geophysical, well log, and reservoir engineering data. This atlas offers geoscientists detailed, accessible analyses, dramatically improving exploration and production efforts.
One of the most discussing challenges in geophysics is tracking the most accurate relationship between elastic properties and pore structure of porous rocks. It is important to find the relations between fluids, pore space and rock, and how they modify the rock properties. The elastic bounds give the narrows of such a system without considering the interconnectivity details, pore shape, and size. Several analytical methods have been suggested to describe the dry rock/porous saturated elastic bounds. These methods depend on stress-strain investigation or are accurately based on the microstructural information. Recently, several elastic bounds such as Voigt-Reuss Bounds, Voigt-Reuss-Hill (VRH) approximation, and Hashin-Shtrikman (HS) Bounds etc.
Field Cases for Back-Analysis of Maximum Horizontal Stress of Oil Fields from Breakout Formations
Authors: Al Sabri M. , Al Ajmi A. , Al-Hadrami H. , Al Aamri M. 
Published: January 2025

ABSTRACT:
Efficient in-situ stress prediction in oil fields is a vital step in wellbore stability and drilling optimization. In many cases, the lack of accurate prediction of in-situ stresses is the key issue in borehole instability problems; consequently, drilling issues with high severity often occur, leading to non-productive time periods and significant increases in drilling costs. Three-dimensional geomechanical models have improved the prediction of the maximum horizontal stress of the fields from the formed breakouts. This 3D model is based on poroelastic constitutive law in conjunction with Mogi-Coulomb shear failure criterion. However, the classic Mohr-Coulomb failure criterion has been also used to verify the effect of the intermediate principal stress on the back analysis of the maximum horizontal stress. In all the field cases, the Mogi-Coulomb failure criterion was able to accurately predict the maximum horizontal stress that was well compatible with the actual field.

1. INTRODUCTION
When a well is drilled, the removal of rock mass will result in a redistribution of stress around the wellbore. The redistribution of stresses near the wellbore may lead to shear or tensile failure at the borehole wall, resulting in wellbore instability. These changes in stress distribution are functions of the magnitude of the far-field in-situ stresses, their orientation relative to the wellbore, rock properties, formation fluid pore pressure, and the annular mud pressure inside the wellbore. Far-field stresses are natural earth stresses prior to drilling, away from the wellbore, and are not affected by the borehole. In contrast, wellbore stresses are near-wellbore stresses and are affected and controlled by far-field stresses, mud density, and the corresponding equivalent circulating density (ECD). Far-field stresses are normally described in cartesian coordinates, with one vertical stress σV and two horizontal stresses orthogonal to each other. They are known as minimum horizontal stress σh and maximum horizontal stress σH. The wellbore stresses are described in cylindrical coordinates, with one radial stress σr and two orthogonal stresses, which are the axial stress σz and the tangential or hoop stress σθ, as illustrated in Figure 1.
Transfer Learning: A Key Approach to Fault Prediction and Extraction in Deep Learning
Authors: Khan Muhammad , Bery Andy Anderson , Ali Syed Sadaqat , Aldossary Saleh 
Published: January 2025

ABSTRACT:
Faults are key subsurface features that significantly influence geomechanics, affecting stress fields and playing a crucial role in hydrocarbon exploration, production, and CO2 storage. The redistribution of stress around faults depends on factors like fault size, orientation, and the mechanical properties of surrounding rocks. Seismic data is commonly used to interpret faults, but the process can be labor-intensive and subjective. Structural attributes such as variance, curvature, fault likelihood, and ant-tracking have improved fault detection, but still require substantial manual editing to create a comprehensive fault framework. To overcome these challenges, we propose a novel approach using 3D deep convolutional neural networks (DCNN) with transfer learning from six dip lines to incorporate local structural knowledge. This method generates fault probability volumes with high training and validation accuracies (0.98 and 0.965). Ant-tracking is used as a post-processing step to enhance fault discontinuities both vertically and horizontally, allowing for the automatic extraction of fault planes ranging from 58 km to 1.25 km in length with minimal manual intervention. We successfully applied this approach to the Poseidon 3D dataset, detecting major and minor discontinuities, demonstrating its robustness and effectiveness in complex fault systems.

1. INTRODUCTION
The interpretation of faults has traditionally represented a fundamental aspect of subsurface characterization within the fields of geomechanics, hydrocarbon exploration, geothermal and assessments of CO2 storage and sequestration. Initially, the identification of faults was accomplished through manual interpretation techniques, wherein skilled geoscientists visually analyzed seismic sections for structural discontinuities. This process required the identification of abrupt changes in reflector continuity, displacements within stratigraphic layers, or other geophysical indicators that implied fault activity. However, manual interpretation is inherently laborious and subjective, leading to variability in results that depend on the interpreter's proficiency and understanding of the geological framework. Despite these limitations, manual interpretation laid the groundwork for the advancement of more refined fault detection techniques by establishing criteria for fault recognition in complex structural settings.
Comprehensive Post-Fracturing Analysis of a Typical Deep Shale Gas Reservoir Pad
Authors: Zeng Bo , Huang Haoyong , Xu Ersi , Feng Jiangrong , Guo Lingkong , Yu Wei , Liu Chuxi 
Published: January 2025

ABSTRACT:
This study presents an integrated approach combining hydraulic fracture simulation, production history matching, and Estimated Ultimate Recovery (EUR) prediction to optimize well performance in a deep shale gas pad located in the Sichuan Basin, China. The boundary element method was employed to simulate fracture propagation, incorporating key reservoir properties such as in-situ stress variations, natural fracture networks, and rock brittleness. The model's accuracy was validated by comparing the simulated hydraulic fracture geometry with microseismic data and pumping pressure curves, revealing a strong correlation and confirming the model's reliability. Following the fracture simulation, production history matching was conducted, using gas flow rate constraints to match bottom hole pressure data, successfully capturing reservoir heterogeneity with an average porosity of 4.2%. EUR predictions demonstrated variability across the four wells, with Well-1, Well-2, Well-3, and Well-4 showing EUR values of 1.24×108 m3, 1.08×108 m3, 1.86×108 m3, and 1.50×108 m3, respectively. The results highlighted the impact of reservoir heterogeneity on production potential and provided critical insights for optimizing future well planning and stimulation strategies.

1. INTRODUCTION
The development of shale gas reservoirs has emerged as a critical component in the global energy mix, particularly in regions with vast unconventional resources such as the Sichuan Basin in China. Shale gas extraction requires complex hydraulic fracturing techniques to unlock the potential of tight, low-permeability formations. This process involves creating fractures in the reservoir rock to enhance gas flow, but the heterogeneity of the rock properties, natural fracture networks, and in-situ stress variations can significantly impact fracture propagation and overall well productivity. Recent advancements in hydraulic fracturing technologies, combined with sophisticated simulation models, have provided deeper insights into fracture behavior and enabled better optimization of fracture designs for improved production outcomes (Liu et al., 2024; Pearson et al., 2024). However, the challenges posed by reservoir complexity continue to demand advanced modeling techniques and field data integration to ensure the economic viability of shale gas operations.