bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stress-Permeability Characterization and Proposal of Creep Model for Pre-Salt Carbonates Under Lab-Scale Stepwise Hydrostatic Loading and Unloading
Authors: Garcia P. F. V. , Santos E. S. R. , Rossi D. F. , Ferreira F. H. , Borba A. M. 
Published: August 2024

ABSTRACT:
In an attempt to expand the studies of rock creep deformation from the classic unidimensional creep theory, this study presents results obtained from geomechanical lab-scale tests of pre-salt carbonate cylindrical samples subjected to stepwise hydrostatic loading and unloading ramps, from 30 to 80 MPa and back, followed by short-term 2.5-hour periods of stress hold. All samples were simultaneously subjected to an axial flow of monophasic oil with upstream pressure measurements. By using Darcy's law, it was possible to obtain an estimate of absolute permeability variation as function of measured axial and radial deformation. It was possible to characterize a power fit nondimensional coefficient of the relation between permeability and porosity variations during loading conditions. Such coefficient, despite presenting higher values during stress hold steps (order 10 to 100) than during load ramps (order 0.01 to 0.1), its mean value was observed to be similar to the ones found in the literature (order 1). At unloading stage, most of the samples did not present permeability recovery, indicating a high level of plastic deformation. The authors also propose volumetric creep models for each sample by taking into account their porosity and their variation with each stress step that they were subjected to.

1. INTRODUCTION
It is known that reservoir rock permeability varies during the oil and gas exploitation process. This variation occurs due to increase/decrease of fluids pressure and/or rock stress state. In order to better emulate the variation of permeability in geomechanics and production simulators, lab-scale experiments can be performed on reservoir rock samples to obtain relations between permeability and stress states.
Petunin et al. (2011) proposed a power relation between the ratios of absolute permeability k and porosity φ to their respective reference state for sandstone, carbonate and fractured rock samples tested with hydrostatic compressions and simultaneous porosity and permeability measurements. Santos et al. (2014) successfully reproduced Petunin's k−φ relation on limestone and dolomite samples by testing them on robust compression test machine and indirectly measuring φ from volumetric deformation εv and estimating k from Darcy's law by imposing axial oil flow on the samples and measuring flow pressure.
Permeability Test on Opalinus Clay Shale with a Preexisting Discontinuity
Authors: Arzuaga-García I. M. , Einstein H. H. , Casagrande C. , Celleri H. M. , Sánchez M. 
Published: August 2024

ABSTRACT:
The interaction between Hydraulic Fractures (HF) and Preexisting Discontinuities (PD, like bedding planes and natural fractures, is affected by the coefficient of friction of the PD, the state of stress around the interacting fractures' tips, and the angle between the approaching HF and the PD. Recent formulations (Kresse et. al, 2013; Chuprakov and Prioul, 2016), also consider the effect of flow rate, fluid viscosity, and PD permeability in the crossing interaction. In this study, a series of permeability tests on cylindrical Opalinus Clayshale specimens were conducted in a triaxial pressure cell. The specimen of 1.5 in diameter and 3 in height includes a throughgoing longitudinal cut, representing the PD. Different confining pressure (CF) and flow rate (FR) conditions were tested for the same fluid (constant fluid viscosity) and temperature. The results obtained are comparable with other authors, with the Opalinus clayshale showing a higher fracture conductivity than Barnett shale (Zhang et al., 2013)), and Fayetteville shale (Jansen et al., 2015).

1. INTRODUCTION
Hydraulic permeability of rock discontinuities is widely investigated in geotechnical engineering and geomechanics. This is mainly due to the influence of mechanical discontinuities, such as fractures and faults, on the permeability of rock formations. Permeability is a critical parameter in the evaluation of numerous geotechnical and environmental aspects, including slope stability, underground fluid flow, and storage, exploitation of hydrocarbon resources, etc. Preexisting discontinuities (PD) act as preferential channels for flow, and the characterization of their permeability is vital to accurately model flow. Furthermore, in the context of geological storage and carbon sequestration, the permeability of discontinuities is essential to evaluate the long-term integrity of the host formations. Many authors have studied the effect of permeability of discontinuities. For instance: Carlsson and Olsson (1993) analyzed the increase in conductivity in fractures due to shear displacement. Makurat (1996) showed that the permeability of natural fractures is affected, among other factors, by tortuosity, roughness, and wall strength.
Update on Rock-Type Specific Hoek-Brown Constant “s”
Authors: Khamitova A. , Suorineni F. T. , Madenova Y. 
Published: August 2024

ABSTRACT:
Martin (1993) established the m-zero failure criterion following extensive field and laboratory testing at the Atomic Energy of Canada Limited Underground Research laboratory. The m-zero criterion is widely used for assessing excavations in rockmasses with a Geological Strength Index ≥75. Based on the m-zero criterion stopes in massive sulfides in underground nickel mines that were expected to fail did not fail. This observation prompted further studies on the m-zero criterion at the Geomechanics Research Centre. According to the m-zero failure criterion, damage in massive rockmasses is caused by destruction of the Hoek-Brown failure criterion constant "s" with the frictional constant "m" playing no role. The value of the constant "s" to initiate damage was established as 0.11. However, this value was based on studies on the La du Bonnet granite. Suorineni and Kaiser (2002) argued that the "s" value of 0.11 should vary depending on the rock type, and hence the need for rock type-specific "s" values. Suorineni et al. (2009) presented a procedure for the determination of rock type specific "s" values. This paper presents "s" values for different rock types from Kazakhstan in a continuing effort to provide users of the criterion with a database of rock type-specific "s" values.

1. INTRODUCTION
There are various failure criteria that exist in rock engineering for the evaluation of the performance of underground excavations in rock. Two frequently used failure criteria are the Mohr-Coulomb (Mohr, 1900; Coulomb) and Hoek-Brown (1980) failure criteria. This paper focuses on the latter, given its history. Given the long history of the Mohr-Coulomb failure criterion which dates to the 1700s, one would ask why there was the need for another failure criterion in the 1980s? The Mohr-Coulomb failure criterion has its foundation in soil mechanics. Hoek and Brown (1980) provide the key reasons why the Hoek-Brown failure criterion was necessary for rocks. These authors noted that to utilize the knowledge of stresses induced around underground excavations it was necessary to have available a criterion or a set of rules which will predict the response of a rockmass to a given set of induced stresses. The search for such a criterion for rockmasses had been challenging because of the complexity of the rockmass compared to a soil in that the behaviour of the rockmass transitions from an intact rock to a heavily jointed rockmass as shown in Fig. 1. All the rockmass components in Fig.1 are of concern to the underground excavation designer or rock engineer. The stability of the entire system of underground openings which make up a mine or any underground excavations network depends upon the behaviour of the entire rock mass surrounding these openings, including all the various components of the rockmass in Fig. 1. This observation implies that a failure criterion developed for soils is unlikely to be applicable to a rockmass, and hence the need for a more suitable failure criterion for rockmasses.
Multi-Interbedded Continental Shale Reservoir Evaluation and Fracturing Practice
Authors: Xiaobing Bian , Yuan Gao , Shuangming Li , Bo Xiao , Shikun Zhang , Xing Liu , Luo Zuo , Jiawei Kao 
Published: August 2024

ABSTRACT:
Continental shale oil resources are abundant in Sichuan Basin in China, according to multiple limestone interbeds and variable longitudinal stress characteristic, continental shale reservoir characteristic evaluation method including radar map, geological sweetness and fracability index, were established considering multi-thin interlayer, horizontal stress difference, etc. The continental shale in area A demonstrates the characteristics of high clay mineral content with strong plasticity and serious heterogeneous. The fracture geometry inverse analysis is established based on the results of microseismic monitoring and numerical simulation, the continental shale has simple fracture geometry and lower fracture length propagation rate. Further reducing cluster spacing and increasing fluid intensity are the technological directions to improve the SRV of fractured wells in area A. The study could provide guidance for the shale evaluation and fracturing program design of continental shale oil wells.

1. GEOLOGICAL CHARACTERISTICS OF CONTINENTAL SHALE
There are abundant shale oil and gas resources in the Sichuan Basin in China. At present, the marine shale gas have developed commercially especially in Wufeng & Longmaxi formation, and the continental shale oil resources are important strategic replacement resources (Wei et al, 2022; Shu et al, 2023; Guo et al, 2023; Jin et al, 2023; Zhao et al, 2023; Yu et al, 2023; Wang et al, 2023). Compared with the marine shale oil and gas reservoirs, continental shale in area A is of strong heterogeneity and low oil & gas abundance, the formation is strong plastic with clay mineral content more than 50%, and multiple limestone interbeds exist resulted in variable longitudinal stress, the higher shale thermal evolution leads to complex fluid properties and aggravates the difficulty of multiphase flow (Jiang et al., 2023; Shu et al, 2023; Sun et al, 2023; Wang et al, 2023). Because the huge geological charactristic between marine shale and continental shale, bottleneck problems such as fracture height and fracture complexity limit emerge in conventional hydraulic fracturing technology, which greatly restricts the effective exploration and economic development of continental shale oil & gas (Jiang et al, 2023). Thus, the reservoir characteristic and fracturing effect evaluation method should be developed according to the field cases.

2. COMPREHENSIVE EVALUATION OF RESERVOIR PARAMETERS

2.1. Radar map of key geological parameters
Key geological parameters such as clay minerals, interlayer thickness, natural fracture, etc., and rock mechanics parameters such as horizontal stress difference and Poisson's ratio, etc., were selected as evaluation data set to draw a non-dimensional rose map of the above 9 parameters to qualitatively show the differences in geological parameters among wells.
Axial Stiffness Evolution of Rock Observed During Uniaxial and Triaxial Compression Strength Tests
Authors: Gaines S. , Diederichs M. S. 
Published: August 2024

ABSTRACT:
Elastic properties, including Young's modulus and Poisson's ratio, are commonly reported parameters estimated from standard compression strength tests of intact rock core. Although it is recognized that axial stiffness is not constant during loading, Young's modulus is often estimated at a pre-defined portion of the stress-strain curve, typically at approximately 40-50% of the peak strength. Poisson's ratio, which is an indication of the axial to lateral strain response, is also highly non-linear and varies throughout the loading cycle as damage is initiated and accumulates in the rock specimen. While this method of interpreting elastic properties is sufficient for some rock materials under specific test conditions, plotting the instantaneous Young's modulus, or tangent modulus, as a function of axial stress reveals that the maximum stiffness and/or most linear region of elastic response does not necessarily fall within the typically applied fixed range of the stress-strain curves often used for interpretation. A series of uniaxial and triaxial compression tests were completed on Westerly granite, Stanstead granite and Indiana limestone to investigate the relationship between axial stiffness and stress during loading. It was found that while the maximum tangent modulus (i.e. maximum stiffness) for both the Westerly and Stanstead granites is reached between 45-55% of the peak axial strength during UCS tests, as confinement is applied the range decreases to approximately 20-25% and 30-40% of peak axial strength under 30 MPa confinement, respectively. Therefore, applying a standardized fixed range as a percentage of peak stress for calculating elastic properties under various confinement levels can be problematic. An improved strategy is to determine the maximum tangent modulus and select a range of stress or percentage around the stiffness inflection point to estimate Young's modulus.

1. INTRODUCTION
An understanding of the physical and mechanical properties of rock material is critical to safely designing structures involving earth materials. This includes surface or near-surface geo-engineering projects such as open pit mines or foundations, and deeper underground projects such as tunnels, mines, or waste repositories. Furthermore, knowledge of material properties is important to effectively design borehole drilling programs and model subsurface behavior for large scale subsurface storage operations/projects.
Correlations Between Microscale Dimensions and Elastic Anisotropy in Shale
Authors: Zhu Junfeng , Zhang Guangqing , Zhang Min , Xu Chuangchao , Chen Houze 
Published: August 2024

ABSTRACT:
Shale exhibits significant anisotropy on both macroscopic and microscopic scales, which can influence the efficacy of the fracturing process. Existing research lacks investigations on the laws governing the variation of mechanical anisotropy at the microscopic scale relative to size This study focus on the variation of mechanical anisotropy in shale within the size range of 50-2000 nm. Through nano-indentation experiments conducted on shale samples aligned parallel and perpendicular to the bedding planes under varied loading conditions, we have discerned that the micro-elastic mechanical properties of shale exhibit distinct variations across different sizes. Our findings are as follows: (1) The anisotropy ratio (bed-parallel to the bed-perpendicular) of the Young's modulus in shale is substantial, with minimal fluctuation across sizes, decreasing from 1.61 to 1.50 as the indentation radius increases from 1.1μm to 3.5μm; The anisotropy ratio of the hardness is lower and demonstrates significant variation with size, decreasing from 1.46 to 1.18; (2) The variation in micromechanical properties of shale with respect to indentation depth requires a holistic analysis that incorporates mineral distribution and the indentation process; (3) The microscopic orientational arrangement of clay minerals plays a pivotal role in the emergence of anisotropic characteristics and their variation with size.

1. INTRODUCTION
Shale oil and gas represent a crucial component of the anticipated growth in the production of hydrocarbon resources. These resources are found within shale formations rich in organic material, typically characterized by their low permeability and narrow hydrocarbon-bearing layers (Li et al., 2022; Zhijun et al., 2021). The exploitation of such formations necessitates the application of hydraulic fracturing technologies to enhance extraction outcomes (King, 2012). Shale, a sedimentary rock, emerges from the consolidation of clay minerals, carbonates, quartz, and other minerals, showcasing prominent bedding features. The interlayer bonding is notably weak, and its compressibility is significant, leading to pronounced anisotropy in its mechanical properties, such as elastic modulus and compressive strength. This anisotropy influences the magnitude of in-situ stresses, potentially triggering uncontrollable fractures during hydraulic fracturing processes, thereby compromising reservoir stimulation efficiency (King, 2012).
Seismic Monitoring Systems in Mines, where are we Today?
Authors: Meyer S. 
Published: August 2024

ABSTRACT:
Seismic monitoring systems have long been identified as a key tool for engineers to observe, quantify, and manage the seismic rockmass response to mining. The design of the seismic system, in terms of sensor layout, spacing, and type, is an important first step and is dependent on the specific objectives of seismic monitoring at the mine in question. Once installed and operational, the systems expand and evolve to better meet the requirements of the mine. This paper provides an overview of modern microseismic monitoring systems in mines. We examine trends in the configuration and performance of seismic systems over the years and how advances in technology, processing methods, and computational power have lead to larger and richer datasets than ever before. Differences in geological setting and mining method may inform the monitoring approach and are discussed. The results from this review provide engineers with a way to compare their system configuration and sensitivity to other mines, or for new mines to make an initial estimate of their seismic system monitoring requirements.

1 INTRODUCTION
Microseismic monitoring in mines has become ubiquitous in deep, hard rock mines, being one of the fundamental tools used by engineers to identify, quantify, and manage ground control hazards. The earliest examples of seismic monitoring in mines can be traced back to South Africa, Canada, and Australia, going back many decades to the 1970s and 1980s.
Over the recent decades, there have been monumental changes in seismic monitoring in mines. These changes are driven by multiple factors. Some of the earliest and potentially most significant improvements were due to technological advances in data transfer speeds. Around the early 2000s, seismic stations started becoming compatible with ethernet, a significant upgrade from serial ports. This provided a massive boost in data transfer speeds, from a maximum of 115 kb/s over serial ports to 100 Mb/s with ethernet. Upgrading existing in-mine infrastructure to the newest technology can be a difficult and time-consuming process, and newer and smaller mines were often the first to benefit from such new technologies. This meant that while new technologies were available, there was often some delay before the benefits could be realized.
Study on Stress Sensitivity Damage Evaluation in Tight Low-Permeability Gas Reservoirs
Authors: Zhai Hengli , Yu Xing , Zhu Qingjiangpeng , Liang Tongyao , Huang Qirui , Wang Haizhu , Wang Bin , Stanchits Sergey , Cheremisin Alexey 
Published: August 2024

ABSTRACT:
Current stress sensitivity evaluation experiments lack accuracy due to the absence of considering the dynamic impact of the slip effect. This paper uses a correction method for Klinkenberg permeability that accounts for the dynamic variation of the slip effect. Gas measurement evaluations are conducted using varying confining and pore pressure methods under in situ reservoir conditions, fitting permeability and effective stress, and establishing a stress-sensitive gas well productivity equation that considers eliminating the slip effect. The results indicate that as effective stress increases, the gas slip effect intensifies. The average damage rate of corrected permeability increases by 0.9% and 12.09% in the two methods, with the pore pressure variation method being closer to field conditions. The greater the stress sensitivity, the faster the decline in gas well productivity, and both excessively high or low bottom hole flowing pressure are detrimental to gas well production. By calculating data from a gas well in Linxing, the reasonable range of bottom hole flowing pressure is determined to be 13.07 MPa to 13.99 MPa, while the reasonable production pressure difference range is 1.29 MPa to 2.21 MPa. This provides effective guidance for the development of low permeability reservoirs and reservoir protection.

1. INTRODUCTION
With the sustained and stable development of Chinese petroleum industry, the development focus has gradually shifted towards low-permeability oil and gas reservoirs as middle to high permeability reservoirs are gradually being developed and the proportion of low-permeability oil and gas reserves continues to increase. Currently, low-permeability oil and gas reservoirs account for a relatively high proportion of petroleum reserves in China and are the main source of petroleum and natural gas production at this stage. During the production of tight low-permeability gas reservoirs, the pore pressure in the reservoir decreases, causing deformation of the reservoir rock and compression of the internal flow channels within the rock, resulting in damage to reservoir permeability, which is one of the reasons for the decrease in production well capacity. The tight sandstone gas reservoirs in Linxing area are highly heterogeneous, with low porosity and permeability, and their high clay content makes them vulnerable to permeability damage caused by stress changes. Therefore, understanding the stress sensitivity of low-permeability reservoirs is of great significance for formulating reservoir protection measures and guiding the efficient development of oil and gas reservoirs.