bluuebunny/crossref_metadata_2025_split huggingface dataset:
Research on Productivity Recovery Mechanism of Fractured Parent Well of Interwell Stereodimensional Infill Well in Fuling Shale Gas Reservoir, Sichuan Basin
Authors: He Yongsheng , Tang Xuanhe , Zhu Haiyan , Li Kuidong , Liu Wei , Zheng Feng , Xiao Jialin , You Yuan 
Published: September 2023

ABSTRACT
During the fracturing process of infill wells in the Fuling shale gas reservoir, it was found through real-time monitoring of fracturing that the monitored pressure of the parent well increased to different degrees when each fractured stage of the adjacent infill wells was fractured, and a significant increase in production following the re-opening of the well. To study the production and pressure recovery mechanisms of parent well associated with the infill well fracturing, a coupled flow and geomechanics model was established based on the comprehensive work flow of four-dimensional in-situ stress during the devolopement of multi-layer three-dimensional infill horizontal well in shale gas reservoir.
In the integrated modeling, a natural fractures network was embedded in the geological model firstly. Second, a fracturing model is developed to simulate hydraulic fracture propagation of parent wells. Thirdly, a coupling flow and geomechanics model was established to simulate the spatiotemporal stress evolution in a multilayer shale gas reservoir with complex fracture geometry. Finally, the complex hydraulic fractures propagation of the infill well was stimulated. It can be concluded from the simulation results that: (1) Reservoir stress changes are influenced by fracture modification, but the range of stress evolution is greater than the range of fracture modification; (2) The natural fracture zone connects the fractured wells to the producing wells, and the fluid can be run long distances through the natural fracture zone to the fracture modification edge of the old wells to achieve the fracturing of more wells and to increase the production of the old wells (3) The fractures(tennsile fractures, shear fractures) communicating between the fractured edges of the tightened wells and the old wells are able to transfer fracturing fluids and add production to the old wells.
This discovery is beneficial to the production of fractured encrypted wells and the continued high production of old wells.
Prediction of Diverting Performance of VES Acid Based on SVM and Coupled Rheology-Reaction Model
Authors: Wang Yunjin , Zhou Fujian , Zhang Ying , Zhang Guchang , Wang Qing , Shi Guanghao , Jiang Tingxue , Dong Rencheng 
Published: September 2023

ABSTRACT
Viscoelastic-surfactant (VES) acid is widely used in heterogeneous carbonate reservoir as an important acid system for uniform acidizing. Temperature is a significant parameter that affects the rheological properties and reaction rate of VES acid. However, existing rheological models of VES acids do not consider the effect of temperature, and the diverting performance of VES acid at different reservoir conditions and injection technology is still unclear. Here, the relationship between the rheology of spent VES acid and temperature was studied, and the rheological model of VES acid was optimized. A coupled model of temperature field and two-scale continuum acidizing model was established. Based on this model, the effects of temperature, injection velocity and permeability contrast on the diverting performance were investigated. In addition, a support vector machine (SVM) model was introduced to train and predict the diverting results. The results showed that the viscosity of spent VES acid increased and then decreased with the increase of temperature. With the temperature increasing to 313 K, the viscosity of spent acid reached the maximum of 453.1 mPa·s. The higher the temperature, the worse the diverting performance of VES acid. When the temperature was higher than 343 K, the distance of wormhole propagation was significantly reduced. When the temperature is high, the diverting performance of VES acid can be improved by appropriately increasing the injection velocity. However, when the injection velocity is higher than 0.005 m/s, the uniform dissolution due to the excessive injection velocity will reduce the acidizing efficiency. The higher the permeability contrast, the worse the diverting performance. The maximum diverting permeability contrast of VES is not a constant. The maximum diverting permeability contrast of VES acid at a temperature of 323 K and 343 K is about 10 and 8, respectively. The SVM model has high accuracy for diverting performance prediction of diverting acid, with an overall average correct prediction rate of 87.5% for 200 repetitions of training and prediction. This work quantifies the effects of temperature, injection velocity, and permeability contrast on diverting performance, and proposes a diverting performance prediction model for diverting acid system.
Modeling and Analysis of Micro Proppant Transport and Deposition in Rough Fracture Networks
Authors: Zhou Qianqian , Wang Haizhu , Wang Bin , Zheng Yong , Stanchits Sergei , Cheremisin Alexey 
Published: September 2023

ABSTRACT
Micro-proppants are instrumental in maintaining secondary fractures, which evolve around primary propped fractures in unconventional formations. Given their minute size, micro-proppants can infiltrate induced fractures, thereby augmenting production through the fracture network. Yet, the mechanisms through which micro-proppants bolster the conductivity of secondary fractures remain incompletely elucidated. To bridge this knowledge gap, we have conducted a simulation study that models the transport and sedimentation of micro-proppants in rough fractures. We utilized a coupled computational fluid dynamics and discrete element method (CFD-DEM) for this purpose. Our research also considers key determinants such as particle properties, fracture morphology, and injection parameters to assess their impact on the flow field and micro-proppant distribution. Preliminary findings indicate that, unlike larger proppants, micro-proppants are not impeded by rough and tortuous fracture surfaces, enabling a more uniform proppant distribution due to their smaller particle size. These insights deepen our comprehension of particle settling behavior in rough rock fractures and underscore the benefits of using micro-proppants. They will also assist in the design of more effective fracture enhancement projects.

INTRODUCTION
Hydraulic fracturing serves as a pivotal method for enhancing oil and gas recovery from wells. This is accomplished by the high-pressure injection of a mixture comprising water, sand, and chemicals into rock formations. This process induces fractures in the rock, thereby releasing entrapped hydrocarbons. Despite its experimental beginnings in 1947 in the Hugoton gas field of Grant County, Kansas, in the United States, the first successful commercial application was not realized until 1950. Numerous oil and gas fields would be economically nonviable without the implementation of hydraulic fracturing. Proppants, solid particles instrumental in maintaining the created fracture pathways and preventing fracture closure post-fluid injection, are an integral part of the fracturing process. The placement and properties of the proppant bed within the stimulated fracture network are crucial determinants of the efficacy of the fracture network and the eventual productivity of the well (Kong et al., 2015; Montgomery et al., 2010). Recent decades have witnessed improved understanding of proppant transport mechanisms in hydraulic fracturing, thanks to numerical simulation. This has led to the optimization of proppant types, fracturing fluid compositions, and injection strategies.
The Effect of SCCO2 Treatments on the Petrophysical Properties of Continental Shale with Different Mineral Compositions
Authors: Sun Lianhe , Wang Haizhu , Wang Bin , Dang Kaiyan , Shi Mingliang , Zhang Yunpeng , Liu Mingsheng , Wu Yuqian 
Published: September 2023

ABSTRACT
CO2 Pre-pad Energized Fracturing has been widely used in China in recent years to effectively develop shale oil. The petrophysical properties of continental shale vary with different sedimentary conditions. However, it is unknown how CO2 pre-injection affects these properties for different continental shale reservoirs. In this study, three sets of continental shale from the Qikou Sag, Jiyang Depression, and Yanchang Formation were selected for the experiment. The effects of SCCO2 on the petrophysical properties of different samples were analyzed by N2GA, XRD, and uniaxial compression tests. According to the results, the SCCO2-water-shale interaction induced the dissolution and precipitation of shale minerals during the immersion test. In addition, the average pore size of QK samples increased due to the dissolution of minerals, while the strong swelling effect and mineral precipitation reduced the average pore size of JY and YC samples. After interacting with SCCO2, the pore structure complexity of the QK and JY samples decreased slightly. Furthermore, the changes in mineral matrix and pore structure led to significant deterioration of the mechanical properties of the three shale groups, especially for the JY sample. These findings provide an experimental basis for applying CO2 Pre-pad Energized Fracturing technology to different continental shale reservoirs.

INTRODUCTION
In recent years, with the advancement of oil and gas exploration and development technology, China has made major breakthroughs in unconventional oil and gas development, and the proven reserves of unconventional oil and gas account for 41% of the country's oil and gas resources (Yang et al., 2015). As an important unconventional oil and gas resource, shale oil is mainly divided into two types: continental and marine. Continental shale is the main shale oil reservoir in China, and its development and utilization are different from those of marine shale oil in North America in terms of geological environment and development methods (Wenzhi et al., 2020). At present, shale oil enrichment layers have been discovered in numerous basins in China, such as the Junggar Basin, the Ordos Basin, and the Bohai Bay Basin (Feng et al., 2020; Ju et al., 2020). In 2022, Wu Xiaozhi (Xiaozhi et al., 2022) predicted that the national shale oil geological resources would reach 335.3 × 108 t. Therefore, realizing the efficient and economical development of continental shale oil is of great significance for ensuring China's energy security.
Prediction of Fault Damage Zones Using Artificial Neural Networks
Authors: Santos L. F. , Quevedo R. , Carvalho B. R. B. M. , Roehl D. M. 
Published: September 2023

ABSTRACT
Fault damage zones can affect the flow pattern in reservoirs owing to the presence of geological structures such as fractures and deformation bands. Therefore, preliminar and fast characterization of damage zones is vital for developing exploration and production strategies. This study proposes a methodology for assessing the damage zones widths using artificial neural networks (ANNs). The database used to train the ANNs was built considering several numerical models which adopt geomechanical parameters, fault length, and maximum displacements as input variables to determine the damage zone along a single fault. Such numerical models are based on elastoplastic constitutive relationships and the finite element method (FEM). The best set of hyperparameters for the neural network model is defined through a Bayesian optimization strategy, which found a simple neural network with one hidden layer, 76 neurons, and a learning rate of 0.024. The rectified linear unit (ReLU) and the adaptative stochastic gradient descent method (ADAM) are adopted as activation function and optimizer algorithm, respectively. The damage zone width along the fault was predicted and compared with the expected responses of the numerical FEM models, reaching a coefficient of correlation of R2 = 0.989, a mean absolute error equal to 2,428 meters, and a mean absolute percentual error of 4,2%.

INTRODUCTION
The study of geological faults present in reservoirs is essential in the petroleum engineering and geology field. In general, these faults can directly affect the exploration and production of oil and gas reservoirs, acting as pathways for fluid migration or barriers (Holder, 1993; Davies & Swarbrick, 1997).
Faults can promote zones of high permeability due to fractures allowing preferential flow paths in some regions of the reservoir. On the other hand, faults can also act as barriers owing to decreases in porosity and permeability provoked by crushing and compaction of the host rock (Caine et al., 1996; Paul et al., 2007; Hennings et al., 2012; Zhao & Zhang, 2020; Qiao et al., 2019; Hu et al., 2019; Meng et al., 2019; Sun & Wu, 2019).
Heavyweight Magnetite as a Novel Weighting Material for Cementing HPHT Formations
Authors: Alvayed Dandi , Mahmoud Ahmed Abdulhamid , Elkatatny Salaheldin , Alafnan Saad 
Published: September 2023

ABSTRACT
The development of cement slurry with specified qualities, such as high density, is necessary to overbalance the high-pressure formations while cementing deep and ultra-deep oil wells. Hematite is now primarily utilized as a weighing material in oil fields, although its use raises several operational and environmental issues. The creation of a non-elastic cement matrix and cement segregation are the two most frequent problems associated with using hematite as a weighing ingredient. This study examined the effectiveness of using magnetite as a weighing component when cementing a deep production casing at a depth of 15,000 feet. The magnetite used in this study has a particle size of 18.84 μm and is composed of more than 99% iron. In-depth laboratory research was done on the performance of 18.0 ppg hematite- and magnetite-weighted cement slurry. In this work, the qualities of cement segregation, compressive and tensile strength, porosity and permeability, and elastic properties were investigated. This study demonstrated that using magnetite instead of hematite as a cement-weighting material might be successful. The density of the created magnetite-based cement system varies very slightly along the depth of the well, with only a 7.3% difference between the top and bottom of the cement. Both the casing and the drilled formations may be supported by the magnetite-based cement's high compressive and tensile strengths of 65.1 and 8.1 MPa, respectively. Additionally, impenetrable, the cement system created with magnetite has a permeability of only 0.003 mD. The capacity of the Magnetite-based system to lower the Poisson's ratio and boost cement elasticity, which is highly essential, especially for very deep wells, was confirmed when Poisson's ratio for the system created in this work was compared with that of hematite-based.

INTRODUCTION
Weighting materials are used to increase the drilling fluid's density to successfully balance the higher pressures in deep wells (Caenn et al., 2011; Hossain & Al-Majed, 2015; Stroud BK, 1922, 1926). When dealing with unbalanced wellbores, deformable/plastic formations, and high pore pressures, high mud weight above 18 ppg can be utilized, and cement samples of equivalent weight should be used (Magarini et al., 1999). The well may never produce its most total capacity without effectively isolating problematic zones (Nelson, 1990). Primary oil-well cementing procedures are carried out to meet various goals, including inhibiting fluid communication and flow between drilled formations and the wellbore, shielding the casing from acidic liquid attack, and supporting the casing (Mitchell & Miska, 2011).
On the Path to Least Principal Stress Prediction: Quantifying the Impact of Borehole Logs on the Prediction Model
Authors: Dvory N. Z. , Smith P. J. , McCormack K. L. , Esser R. , McPherson B. J. 
Published: September 2023

ABSTRACT
Knowledge of the minimum horizontal principal stress (Shmin) is essential for geo-energy utilization. Shmin direct measurements are costly, involve high-risk operations, and provide only discrete values of the required quantity. Other methods were developed to interpret a continuous stress sequence from sonic logs. These methods usually require some ‘horizontal tectonic stress’ correction for calibration and rarely match sections characterized by stress profiling due to viscoelastic stress relaxation. Recently, several studies have tried to predict the stress profile by an empirical correlation corresponding to an average strain rate through geologic time or by using machine learning technologies. Here, we used the Bayesian Physics-Based Machine Learning framework to identify the relationships among the viscoelastic parameter distributions and to quantify statistical uncertainty. More specifically, we used well logs data and ISIP measurements to quantify the uncertainty of the viscoelastic-dependent stress profile model. Our results show that the linear regression approach suffers from higher uncertainty, and the Gaussian process regression Shmin prediction shows a relatively smaller uncertainty distribution. Extracting the lithology logs from the prediction model improves each method's uncertainty distribution. We show that the density and the porosity logs have a superior correlation to the viscoplastic stress relaxation behavior.

INTRODUCTION
Comprehensive recognition of the least principal stress is essential for economic multistage hydraulic fracturing stimulation design. It is well established that hydraulic fractures propagate perpendicular to the least principal stress and that the stress profile prominent the hydraulic fractures generation in both the lateral and horizontal direction (Fisher et al., 2012; Hubbert and Willis, 1957; Kohli et al., 2022; Valkó and Economides, 1995; Zoback et al., 2022)c. In other words, the stress layering could act as a ‘frac barrier’ that limits fracture development in discrete directions and promotes progress in different directions (Singh et al., 2019). Detailed knowledge of the least principal stress profile is significant for hydraulic fracture growth assessment, proppants technology optimization, and efficient landing zone detection (Pudugramam et al., 2022). Traditionally, these considerations were aligned with the oil and gas industry. Still, today, they have substantial implications for enhanced geothermal system development, carbon storage integrity, and in a broader sense, a safe path for a carbon neutrality economy.
3D Hydraulic Fracture Propagation in a Heterogeneous Rock Formation Using a Mesh Transition Technique
Authors: Rueda C. J. , Mejía C. , Paullo L. F. , Roehl D. , Rossi D. , Henriques F. 
Published: September 2023

ABSTRACT
Hydraulic fracturing is a stimulation technique widely used in oil and gas production. Forecasting the induced fracture geometry can improve the efficiency of the stimulation process. Traditional numerical models consider fracture propagation in homogeneous formations. However, in carbonate reservoirs, the high variation of the rock formation properties due to anisotropy and heterogeneity can affect hydraulic fracture propagation. This work presents a numerical methodology to simulate 3D fluid-driven fracture propagation in a carbonate reservoir. The heterogeneity is introduced as a multi-layered formation. The model incorporates fractures using interface elements with the pore-cohesive zone model (PCZM). A mesh transition technique is adopted using the tie constraint technique to reduce the computational cost and maintain the solution's accuracy. The model is verified against analytical solutions. Moreover, the work investigates the influence of the mesh transition on the numerical results and the computing time. The numerical results show that many slave elements per master element can reduce the accuracy and computational efficiency. Finally, we study the main parameters that affect fracture propagation in a large-scale heterogeneous formation.

INTRODUCTION
Hydraulic fracturing is one of the most commonly used stimulation techniques to enhance reservoir permeability in oil and gas production. The correct prediction of the hydraulic fracture geometry results in the stimulation process's efficiency (Barbier, 2002; O’Sullivan et al., 2001). Several approaches have been developed to model the hydraulic fracturing process, such as analytical solutions (Adachi & Detournay, 2002, 2008; Bunger et al., 2005; Detournay, 2016; Dontsov, 2016, 2017; Garagash et al., 2011; Savitski & Detournay, 2002), pseudo-3D models (Nasirisavadkouhi, 2015), and numerical solutions. The analytical solutions assume a linear elastic behavior for the rock formation and disregard the energy dissipation or plastic deformation at the fracture tip. Numerical solutions are more suitable for modeling hydraulic fracturing, especially considering nonlinear material effects, rock formation heterogeneity, complex boundary conditions, and hydromechanical coupling terms. In the last decades, several numerical formulations have developed to simulate hydraulic fracturing: finite elements (Rueda Cordero et al., 2019), displacement discontinuity method (J. Xie et al., 2018; L. Xie et al., 2016), discrete element method (Fatahi et al., 2017; Zhou et al., 2017), and mesh-free discretization (Keshavarzi & Jahanbakhshi, 2013; Khoei et al., 2016; Taleghani, 2010; Wang et al., 2018).
Ground Support Asset Management
Authors: Wellman E. C. , Akbulut N. A. , Kemeny J. 
Published: September 2023

ABSTRACT
Geotechnical Asset Management is an approach that has been adopted by civil infrastructure and state highway departments to assess the "value" of rock slopes and develop a tool to assess the cost-effectiveness and importance of prioritizing slope and ground improvement projects to enhance transportation corridor reliability. The Ground Support Asset Management program aims to adopt an asset management framework for the underground construction and mining sectors.
The University of Arizona operates the San Xavier Mining Laboratory south of Tucson, Arizona. The mine has adits and openings over three levels, including shaft access. The S.X. underground mine will be the launch site and be used as a testbed for trialing the Ground Support Asset Management program. Key aspects that degrade the useful life of elements are corrosion and deformation due to excessive convergence yielding ground in weak rock, deep, and high-stress environments. The primary focus will be on utilizing systems that collect high-resolution point clouds and spectral data to assess deformation and corrosion based on the point cloud data. A secondary project aim is to assess the rock mass and ground conditions for rock reinforcement and ground support design.
The research project aims to develop a framework to assess the remaining useful life of ground support and rock reinforcement elements. Then, using the tools and logic developed in this project, the U.A. San Xavier mine and other mining companies can make informed decisions on when to rehabilitate access drifts and critical openings based on proper safety and economic basis.

INTRODUCTION
Fall of Ground (FOG) events still occur in underground mines – even in areas of supported ground. These events are typically the result of unsupported or inadequately supported ground. Like slope failures, FOG occurs with precursory deformation that can be confirmed with monitoring. Convergence is currently measured in underground mines using tape extensometers, multipoint borehole extensometers, or fixed-station lidar systems. These are now commonly used in underground mines in high occupancy and high-traffic areas. Lidar scanners are commonly used for mine surveys; however, repeated scans are not usually undertaken to measure convergence and geomechanical monitoring. This is due to the time it takes to conduct a scan and the additional processing time to calculate deformation or convergence from successive scans.