bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation of the Failure Mechanisms for Inducing Rock Slope Hazard in New Jersey, United States
Authors: Oppong F. , Khadka P. , Kolawole O. 
Published: August 2024

ABSTRACT:
Rock slope stability analysis is of great interest to researchers and engineers due to its potential geo-hazards. This is primarily governed by the shear strength and the acting shear stress which is often expressed in terms of Factor of Safety (FoS) over a potential slip surface. This study investigated the susceptibility of road-cut slopes to rockfall hazard and its associated risks in Northeastern New Jersey, United States, as well as predicted the failure transition to rapid sliding. Four (4) vulnerable rock slopes were identified and demarcated for detailed slope stability analysis. The field data were subjected to three kinematic analyses (planar, toppling, and wedge analyses) using the Dips program in Rocscience software which showed a high potential for both planar and toppling failure and a low potential for wedge failure. The highest risk of failure will be due to toppling failure, with a 26% likelihood of critical failure, which exceeds the acceptable threshold. This indicates that the rock-cut slopes are in unstable conditions and need to be reinforced in the identified locations. It is further recommended that coupled expansive grouted anchor bolts and steel-mesh reinforcement support mechanisms be implemented to strengthen the stability of the cut slopes to prevent rockfalls. This study provides valuable insights for mitigating potential geohazard and the findings here are relevant to other locations across the world..

1. INTRODUCTION
Rockfalls are a major concern in mountainous areas as they can impact both the evolution of steep rocky landscapes and pose significant hazards (Stock and Uhrhammer, 2010; Barlow et al., 2012; Matasci et al., 2017). However, rockfall hazard is not limited to mountainous areas alone. Urban areas are also susceptible to rockfall hazards, particularly where excavations can destabilize slopes and create risks for people and infrastructure (Hungr et al., 2014; Corominas et al., 2017; Gili et al., 2022). Therefore, accurately predicting the areas where rockfalls are likely to occur is crucial for reliable hazard assessment. This requires an understanding of which areas are most likely to be affected by rockfall events (Guzzetti et al., 2003; Corominas et al., 2017; Gili et al., 2022).
Study on RF Heating Mode of Heavy Oil Reservoir Rocks Based on Two Antenna Elements Distributed Along the Horizontal Well
Authors: Wang Zhengxu , Guo Qingfeng , Cai Xiao , Zhang Jingtian , Zhao Qing , Li Bo , Chen Xuefeng , Gao Haiyang 
Published: August 2024

ABSTRACT:
To achieve precise heating of reservoir layers with varying thicknesses using the RF (radio frequency) heating method while minimizing thermal energy loss, a novel solution is proposed leveraging a multi-antenna configuration. In this configuration, consisting of two antenna elements, the application of equal and distinct voltages to the antenna elements is categorized based on the diverse characteristics of the reservoir. Additionally, the impact of inter-antenna element distances on temperature profiles was thoroughly examined within these configurations. Research results indicate that these configurations can effectively address varying heat requirements of the reservoir, whether necessitating more, less, or no additional heat, through the adjustment of both distance and voltage. This comprehensive approach offers a viable solution to enhancing the efficiency of heavy oil reservoir heating processes during RF heating in horizontal wells at the operational level.

1. INTRODUCTION
As one of non-conventional hydrocarbon resources, heavy oil reservoirs are widely distributed in the world. Nevertheless, high viscosity prevents the rich resources from being large-scale exploited (Hassanzadeh and Harding, 2016). Besides, with the situation of sustained low oil prices, traditional thermal recovery projects have been terminated because of high production costs and low recovery efficiency (Hasanvand and Golparvar, 2014; Wise and Patterson, 2016). To solve the above problems, oil companies are exploring other alternative heating processes, one of the most promising being radio frequency (RF) heating technology. It is effective in deep, shallow, thin and thick reservoirs, besides the extra energy loss in the pipeline, wellbore and overburden can be avoided (Chhetri and Islam, 2008; Wang et al., 2018).
In recent years, many scholars have investigated the feasibility of RF heating. Ramcharan et al., 2016 explored the viability of using RF heating to extract heavy oil by applying COMSOL Multiphysics and CMG software. Their research results indicated that when an operating frequency of 10 MHz and a current of 50 Amperes were applied, the oil recovery rate was in the range 30-60%. Saeedfar et al., 2016 developed a synthetic homogenous reservoir model to conduct the simulation of RF heating method, and the results revealed that the method had the ability of highly efficient heating of oil sand reservoir.
Fluid Flow in a Fracture Network Under Changing Stresses: A Laboratory Study
Authors: Mei Z. , Li W. , Jin W. , Neupane G. , Atkinson T. 
Published: August 2024

ABSTRACT:
Fluid flow in fractured rocks is ubiquitous in natural and human-induced subsurface processes. Subsurface technologies, such as in-situ mining, CO2 storage and geothermal exploitations, require large contact areas between the flowing fluid and the rock to facilitate efficient heat and mass transport and, therefore, ensure the effectiveness of these technologies. Much of the experimental research on fluid flow in fractures has focused on a single fractures in a rock specimen, which leaves the fluid flow in fracture networks under changing stresses largely unexplored. Here, we study fluid flow in a fracture network under changing stresses using a triaxial system. We create the fracture network composed of five orthogonal fractures in rock specimens by assembling six saw-cut rock parts. We measure the overall permeability of the fracture networks under changing vertical and horizontal stresses. We find that the fracture network permeability decreases when the vertical and horizontal stresses both increase. A greater reduction of permeability is observed with increasing horizontal stress than that with increasing vertical stress. We show that this phenomenon results from the larger total area of the vertical fractures than that of the horizontal fractures, making the fracture network more sensitive to horizontal stress changes. Our study shows the importance of the relative orientations between the fractures and the stresses in determining the permeability of the fracture network. This insight can be incorporated to improve the discrete and continuum modeling of fracture networks.

1 INTRODUCTION
Fracture networks are the "highways" for the fluid flow in subsurface rock-fluid systems. They provide a fast path for contaminant transport in fractured aquifers (Tsang and Tsang, 1987; Grisak and Pickens, 1980; Grisak et al., 1980). They could increase the permeability of a geothermal reservoir and, at the same time, reduce the heat extraction efficiency by inducing short-circuiting (Gee et al., 2021). They can also localize the dissolution of porous rocks to the fracture along and induce larger cavities earlier (Li et al., 2021). The overall permeability of a fracture network is affected by the fracture orientation, stress conditions, and fluid pressure. Understanding and predicting the the fracture network permeability as the stresses and pore pressure changes are important for many engineering applications in the subsurface rock-fluid systems.
Equivalent Circulating Density Calculation After Gas Kick Considering Temperature and Pressure
Authors: Jiang Zhenxin , Tao Zhenyu , Wang Zheng , Zhang Wenbo , Liu Yuhan , Liu Jitong , Fu Jing , Fan Honghai , Sun Lewang 
Published: August 2024

ABSTRACT:
Deep water is rich in oil and gas resources, which is of great significance to world energy. However, its reservoir geological conditions are complex, the drilling safety density window is narrow, the wellbore pressure is difficult to control, overflow, kick and other accidents are prone to occur, and there are high temperature and high pressure phenomena. In order to deal with a gas kick through managed pressure drilling in time after the gas kick, it is necessary to comprehensively consider the effects of temperature and pressure on the density and rheology of drilling fluid, and accurately calculate the bottom hole ECD after gas kick. Based on the wellbore multiphase flow model and considering the influence of temperature and pressure on the density and rheology of drilling fluid, combined with the special process flow of deep water managed pressure drilling, a more accurate ECD calculation method for deep water managed pressure drilling after gas kick is established in this paper. Verified by the data of well M in a sea area of China, the error of this method is 2% with high accuracy, which provides the basis for field managed pressure drilling.

1. INTRODUCTION
With the development of oil and gas exploration and development technology in the world, the future exploration and development will gradually turn to deep unconventional oil and gas resources. Among them, the reserves of deep water oil and gas resources are rich, which may exceed 70 billion tons. Deepwater oil and gas resources are of great significance to world energy. However, its reservoir geological conditions are complex, the drilling safety density window is narrow, the wellbore pressure is difficult to control, overflow, kick and other accidents are prone to occur, and there are high temperature and high pressure phenomena. (Li, 2021; Li, et al, 2021; Yang, et al, 2023). Managed pressure drilling technology can accurately control the bottom hole pressure and quickly balance the bottom hole pressure difference, which is an important means to solve the drilling problem. (Yin, et al., 2020). ECD, the equivalent circulating density of drilling fluid, is a critical engineering parameter in the process of managed pressure drilling. If managed pressure is inaccurate, overflow and leakage will occur. Providing accurate ECD is the key to the successful implementation of managed pressure drilling. (Liu, et al, 2020; Fan, 2014).
New Understanding of Matrix-Fracture Dual Media Reservoir Damage Based on Pressure-Controlled Fracturing
Authors: Zhang Yang , Qiao Yan , Zhang Shiling , Wu Hongjun , Bai Jie , Guo Xudong , Li Senmu 
Published: August 2024

ABSTRACT:
The Tarim Oilfield Krasu tectonic zone is deeply burial, high temperature, low porosity and permeability, and constitutes the complex matrix-fracture dual media seepage channels. Reservoir damage evaluation for such reservoirs is important for subsequent development. In this study, we firstly processed the fracture network in the reservoir core by controlled-pressure fracturing to improve the fracture tortuosity, and verified the reasonableness of this method by CT scanning and shape factor calculation. Then, based on the dual-media condition, we establish the water/oil-lock damage evaluation method, the stress-sensitive evaluation method, the fluid-sensitive evaluation method, and the in-well fluid damage evaluation method. Based on the above methods, the sensitivity of matrix-fracture dual-media reservoirs is moderately strong for water-oil locking, stress, and fluid salinity, moderately weak for liquid alkalinity, weakest for liquid flow rate. In-well fluid damage replacement experiments show that reservoir damage caused by first contact is the most important factor of reservoir damage during the whole process of drilling-completion-reconstruction. For deep tight reservoirs, fracturing fluid is easy to cause serious reservoir damage, and it is necessary to pay attention to reservoir protection during fracturing in low-yield blocks.

1. INTRODUCTION
Reservoir damage is defined as any process that causes a reduction in the natural inherent productivity of gas or oil producing reservoir, or a reduction in the injectivity of a water or gas injection well (Ahmed E. 2021). Reservoir damage is a generic term. It relates to the permeability reduction of a reservoir due to a series of adverse processes (Lucas G. 2012). In the process of oil and gas development, the oil and gas transportation channels are blocked by fluids, stresses and other factors, and the permeability of the reservoir rock decreases (Civan, F., 2000; Radwan, A.E.2019a; Radwan, A.E.2019b). Fomlation damage from drilling and completion fluids can have substantial impact on the productivity of a well (L. Bailey, 1998). During hydraulic fracturing, a large amount of fracturing fluid is retained in the fractures and cannot be discharged, blocking the pores and fractures and reducing the gas relative permeability of the reservoir (Chen et al., 2021; O'Malley et al., 2016; Zhang et al., 2019; King et al., 2012). The main types of fluid damage to reservoirs includes water sensitivity damage, acid sensitivity damage, alkali sensitivity damage and velocity sensitivity damage (Zhou, 2022). Stress sensitivity damage means that after the microfracture closes under the effective stress action, the reservoir filtration capability decreases greatly. And the closed fracture is difficult to open after the effective stress release (Hana, 2022).
De-Risking Stress Testing Operations and Maximizing Injection Longevity
Authors: Karpfinger F. , Donald A. , Gisolf A. , Schlicht P. , Diaz Granados I. , Velez E. 
Published: August 2024

ABSTRACT:
A calibrated geomechanical model is one of the key inputs that defines the longevity of carbon capture and sequestration (CCS) projects, ensuring cap rock integrity and maximum reservoir injectivity. The characterization of horizontal stress magnitude is pivotal for model accuracy. Stress testing is the only direct measure of stress magnitudes to calibrate the geomechanical model. The success of stress testing depends on a good understanding of the geomechanical environment and the appropriate choice of equipment. In this paper, we introduce a planning workflow that de-risks the stress testing operations and enables real-time updates of the stress profile. At the end of the stress testing program, the calibrated mechanical earth model (MEM) is then ready to be used as input for defining the injection plan.

1 INTRODUCTION
In the early stage of carbon capture and sequestration (CCS) site characterization, three pillars define if a project has a chance to succeed:
• Capacity–How much CO2 can be stored?
• Injectivity–How fast can CO2 be injected?
• Containment–What is the risk of leakage?
Measuring the minimum horizontal stress magnitude in the caprock and the zone of injection will help to address injectivity and containment. With stricter government regulations for CCS projects, the measurement of the minimum stress becomes increasingly critical. This is also the case for oil & gas field development to enhance hydrocarbon recovery.
The first step in a wireline formation tester stress testing workflow is to determine the feasibility of achieving formation breakdown in a target well for a defined set of downhole equipment. The chance of success (CoS) for formation breakdown along the entire interval will be computed. CoS is defined as the probability of breakdown for a given formation tester and packer specifications at the maximum differential pressure permissible for this equipment. At this stage, accurate model inputs are often not available, and parameter ranges over the full wellbore section can be used as inputs. Parameter uncertainty over the wellbore section is addressed using a probability density function (PDF). Based on the computed CoS for various packer configurations, the hardware will be selected.
CFD Simulation to Study the Grouting Behavior in Rough-Walled Fractures
Authors: Miyoshi T. , Yasuhara H. , Kishida K. 
Published: August 2024

ABSTRACT:
In rock engineering projects such as dam and tunnel, rock grouting is performed to increase strength and reduce leakage of the rock mass. In rock grouting, grout materials, typically cement slurry, is injected in rock mass. For jointed rock mass, the cement slurry is considered to flow through the rock fractures as fractures are significantly more permeable than the rock matrix. Although several numerical and experimental works have been conducted to understand the filling and penetration behavior of grouting into rock fractures, the fracture is oftentimes assumed to be a parallel slit, while the aperture of actual fracture is not constant, and exhibits roughness. In this paper, the influences of fracture roughness on the penetration and filling behavior of the cement slurry are investigated through numerical simulation. This is achieved by simulating the grout flow in an idealized sinusoidal fracture with computational fluid dynamics approach. The combined effect of pressure, water-cement ratio, and roughness of the fracture are examined through parametric studies. Based on the simulation results, the insights regarding the penetration behavior and filling behavior of the cement slurry in rough-walled fractures are obtained.

1. INTRODUCTION
In rock engineering projects such as dam and tunnel construction, grouting is performed to increase strength and reduce permeability of the rock mass (Utuski et al. 2013). In grouting, grout materials, typically cement slurry, is injected in rock mass. For jointed rock mass, the cement slurry is considered to flow through the rock fractures as fractures are significantly more permeable than the rock matrix. The measure of the effectiveness of grouting is typically expressed by the penetration length of cement slurry. Therefore, understanding the penetration behavior of the cement slurry is crucial for the grouting design. Gustafson and Stille (1996) estimated the stop distance of cement slurry by solving a force balance equation assuming the cement slurry to be Bingham fluid that is characterized by the shear strength and viscosity. This theory was further developed as a criterion that is applicable in the practical application of grouting design. Although the criterion has been applied extensively in practice, this theory is based on the simplified assumptions that the fracture is a parallel slit, while the aperture of actual fracture is not constant, and exhibits roughness. In terms of the effect of fracture roughness on the fluid flow, previous research has shown that the roughness of fractures has significant effects on the flow behavior of water. However, the influence of roughness on the flow behavior of cement slurry has not been examined in detail.
Failure Mechanism Analysis of CO2 Flooding Wellbore Tubing
Authors: Li Hui , Li Jun , Shan Liping , Lian Wei , Liu Jinlu 
Published: August 2024

ABSTRACT:
Carbon dioxide flooding enhanced oil recovery technology has been tested in many major oil fields in the world. It can not only improve oil recovery but also realize long-term geological storage of some carbon dioxide. In the process of low temperature carbon dioxide injection, heat is exchanged with the wellbore assembly, and the ice volume of water in the oil casing annulus expands, resulting in frost heaving force which damages the tubing casing and shorens the life of the wellbore. Based on the theory of fluid-solid heat transfer and phase transformation, a tubing-casing - cement ring - formation assembly model is established in this paper. The damage mechanism of frost heaving force on tubing is studied, and the changes of tubing force and wellbore temperature field under the action of frost heaving force are analyzed. The analysis results show that the frost heave force caused by the freezing of water in the annulus is the main cause of the tubing damage during the low temperature carbon dioxide injection.

1. INTRODUCTION
CO2 flooding enhanced oil recovery technology has been widely tested in major oil fields in the world, and the oil displacement efficiency has been significantly improved, and part of the carbon dioxide geological storage can be realized in the process of oil displacement, which is of great significance to restrain the greenhouse effect. It is also an important part of CCUS. In the process of carbon dioxide flooding, the temperature of liquid carbon dioxide injected at the wellhead is generally 223.15K to 253.15K, and the daily injection volume is 20-40 tons. In the process of low temperature carbon dioxide injection, heat is exchanged with the wellbore assembly. The water in the annulus of tubing and casing will freeze and expand, resulting in frost heave force, which significantly increases the risk of tubing damage increases significantly well integrity being compromised and shortens the life of wellbore. Among them, Sheng li Oilfield in Taizhou, China carried out low-temperature CO2 injection operation for more than two months, and its injection temperature was 253.15K. Practical engineering problems of tubing damage occurred in some test Wells (Fig. 1). According to the field situation, the actual situation of tubing damage in the process of low temperature CO2 injection is known, and the wellbore integrity failure is caused by pipe string damage, and the life of the wellbore is greatly shortened. Therefore, it is of great practical significance to study the failure mechanism of low temperature CO2 injection tubing.