bluuebunny/crossref_metadata_2025 huggingface dataset:
Research on the Mechanism of Fracturing Fluid's Influence on Mechanical Properties of Sandstone
Authors: Liu Hanbin , Chen Houze , Wang Yajuan , Mou Chunguo , Zhao Qianyun , Ma Huan , Liu Qian
Published: September 2023

Fracturing fluid is the main cause of reservoir damage during hydraulic fracturing. Fracturing fluid will change the mechanical properties of reservoir rock, and the effect of proppant-propping hydraulic fractures will be affected. To study the changes and internal mechanism of sandstone mechanical properties after guar gum fracturing fluid damage, triaxial compression experiments, core flow experiments, scanning electron microscopy, and nuclear magnetic resonance tests were carried out on sandstone cores before and after damage. The results showed that: (1) The compressive strength and elastic modulus of sandstone decreased after guar gum fracturing fluid damage, which was caused by the increase of the average pore radius of the rock and the weakening of the interaction between particles. (2) The changes in sandstone microstructure after fracturing fluid damage are as follows: rock particle migration, fracturing fluid macromolecule residues, and the proportion of micro-pores decrease (11%). (3) Tight sandstone is more sensitive to guar gum fracturing fluid, and the lower the initial permeability of sandstone, the greater the decrease in compressive strength and elastic modulus after damage. (4) The change of rock mechanical properties is positively correlated with the range of permeability change. It is of great significance to consider mechanical properties as a factor in the study of fracturing fluid damage.

INTRODUCTION

Unconventional tight sandstone gas has become a natural replacement area for natural gas exploration and development. According to the fourth national oil and gas resource evaluation results, in the tight gas field, the currently proven recoverable reserves are 3.96×1012m3, accounting for 33% of the total proven resources and the remaining recoverable resources are 6.97×1012m3. From the distribution of remaining resources, the future tight gas exploration areas are still concentrated in the Ordos and Sichuan Basins (Zheng Min, 2019). The low-permeability tight gas reservoirs in the Ordos Basin have large reserves. However, they have poor physical properties, substantial heterogeneity, low reserves, and significant differences, and it is not easy to achieve long-term stable production and profitable development of gas reservoirs (Cheng Lihua, 2020).
The Role of Water in the Dynamic Mechanical Behaviors of a Granitic Rock
Authors: Yang H. , Cai G.-L. , Zhao Q.
Published: September 2023

Rock masses are frequently exposed to dynamic stress perturbations associated with natural events (e.g., earthquakes, landslides, and rock bursts) and engineering operations (e.g., blasting, explosion, and induced earthquakes). Understanding the dynamic mechanical characteristics of rock masses is essential to many geo-engineering applications such as underground excavation and hydrocarbon energy exploitation. Water is ubiquitous in the Earth's crust and plays a vital role in the dynamic mechanical behaviors of rock masses; hoever, the effects of water on the dynamic mechanical characteristics of rocks are still not fully understood. Therefore, it is necessary to carry out more dynamic tests to understand their mechanical responses to the presence of water. To this end, we conduct dynamic uniaxial compressive tests on dry and water-saturated granite rock samples via the split Hopkinson pressure bar (SHPB) technique. The test results demonstrate the strain rate dependence of dynamic mechanical properties of both dry and water-saturated granite rock specimens. The presence of water lowers the dynamic compressive strength and elastic modulus of granite rock specimens. The dynamic increase factor (DIF), characterizing the strain rate sensitivity of dynamic mechanical properties, for wet granite rock specimens is higher than that for dry ones over the tested strain rate range. These findings improve our understanding of the water effects on the dynamic mechanical behaviors of granite rocks.

INTRODUCTION

Dynamic loading is commonly encountered in natural activities, such as earthquakes and volcanic eruptions, and in engineering operations, such as rock blasting and hydraulic fracturing (Elsworth et al., 2016; Zhang & Zhao, 2014; Bažant & Caner, 2013). Such dynamic disturbance could strongly affect the mechanical behaviors of rock masses, causing the deterioration and damage of rock supports and structures. Understanding the dynamic mechanical behaviors of rocks is therefore essential for the design, construction, and maintenance of tunnels and caverns, defense and military infrastructures, mining facilities, etc. (Li et al., 2017; Qian & Lin, 2016; Zhao et al., 1999). Moreover, dynamic loading at high strain rates could be one of the origins of rock pulverization identified near the active faults, a marker of coseismic damage due to strong earthquakes (Aben et al., 2017; Doan & Gary, 2009). The knowledge concerning rock mechanical responses to dynamic loading could provide insights into rock pulverization, advancing the understanding of earthquake physics and seismic faults (Smith & Griffith, 2022; Griffith et al., 2018; Aben et al., 2016). In this context, more and more attention has been paid to the mechanical behaviors of rocks subjected to dynamic stresses.
Preliminary Study on a Strong Sand-Carrying and Low Damage Viscoelastic Slickwater Under a Wide Shear Range
Authors: Bai Hao , Zhou Fujian , Wu Junlin , Li Bojun , Wang Bin , Xu Hang , Wang Wenzhong , Lang Hao , Yao Erdong , Wang Jiachen
Published: September 2023

Slickwater or linear gel is often used for fracturing development in tight sandstone reservoirs. As it carries sand into the formation through the wellbore, its sand-carrying performance changes with the continuous change of liquid shear rates. In this paper, a new type of viscoelastic slickwater is proposed, which avoids the problems of low sand-carrying capacity of conventional slickwater and large damage of guar. Through theoretical calculation, taking the injection rate of 10 m3/min as an example, the maximum shear rate of fracturing fluid in wellbore and fracture is 884.82 s−1 and 8.33 s−1 respectively. Viscoelastic slickwater polymer is physically cross-linked and reversible associated to form a network structure. It has excellent shear resistance at different shear rates (0.01∼1000 s−1). The intersection point of viscoelastic modulus is lower than 0.021 Hz, and the viscoelastic performance is excellent. Under the low shear rates of fracture (0.01∼10 s−1), the performance of viscoelastic slickwater suspended sand is excellent, and the equilibrium height of sand bank is lower than 26.7% of fracture height. Under the high shear rates (10∼1000 s−1) in the wellbore, its viscosity is high, and the friction reduction rate can reach 81.59%. In addition, it breaks quickly, the amount of residue is low, and the conductivity can be retained by more than 90%. Under field application, the sand concentration of the system is as high as 300 kg/m3, and the production of vertical well after fracturing can reach 0.96 tons/day in more than one year. Viscoelastic slickwater can realize friction reduction and sand carrying at the same time, which has the value of popularization and application.

INTRODUCTION

The tight sandstone reservoir has features of tight lithology, low porosity, and low permeability, and others, mainly secondary porosity, and high feldspar and cuttings content. Due to low reservoir pressure coefficient, its natural productivity is low (Wang et al., 2022; Zhong et al., 2022). Compared with conventional reservoirs, tight sandstone reservoirs have staggered pore distribution and poor connectivity, high water saturation, strong stress sensitivity, and limited recovery by conventional oil displacement methods (Xie et al., 2022; Dong, et al.,2019). Therefore, new unconventional reservoir stimulation technologies and measures are urgently needed.
Numerical Study on Permeability Evolution of a Natural Fracture in Granite During Shearing
Authors: Li X. , Zhang F. , Du M. , Xiu N. , Weng D. , Cai B. , Fu H. , Huang L.
Published: September 2023

The permeability evolution of natural fractures during shearing is one of the critical issues in enhanced geothermal system (EGS). In this study, a series of numerical simulations of shear-flow tests under different normal stresses were carried out to investigate the permeability evolution and shear behavior of a natural fracture during shearing. All numerical simulations in this study were implemented based on a coupled hydro-mechanical pore network model (PNM) of fluid flow in discrete element method (DEM). Fluid grids in the simulations are continuously refreshed as the shear progresses. The results indicate that the fracture permeability positively correlates with the shear displacement when the normal stress is relatively large. The essence of permeability evolution is the variation of the local aperture distribution. Greater fracture roughness makes it easier to form high-permeability pathways. Besides, high normal stress amplifies the effect of fracture roughness on permeability evolution. These findings can contribute to a better understanding of the hydraulic-mechanical coupling effects in the fracture shearing process of EGS.

INTRODUCTION

Enhanced geothermal system (EGS), as a key technology for the extraction and utilization of geothermal energy from high-temperature rock masses in deep formations, has become a research and development hotspot in the field of earth energy and renewable energy (Huang et al., 2018). Many studies have shown that fluid injection in EGS may lead to induced seismicity (Hanano, 2004; Zang et al., 2014; Gaucher et al., 2015; Kim et al., 2018). EGS utilizes fluid to create a new fracture network in hot dry rock or to further expand the original natural fracture network, thereby creating a large number of fluid flow channels. This process involves a series of complex fluid-solid coupling effects and may cause shear slips of fractures or faults (Ishibashi et al., 2018). Fracture shear slip is often accompanied by the evolution of fracture permeability, and the evolution process of fracture permeability can reflect the frictional stability of fractures to a certain extent (Wu et al., 2017). It can be seen that the study of the permeability evolution process and its influence factors in the shearing process of natural fractures is of great significance for evaluating the safety and stability of EGS.
Development and Optimization of Epoxy-Resin Based Cement Reinforced with Low-Cost Fly Ash for High Durability Environmentally Friendly Cement
Authors: Fakher Sherif , Tamer Sara , Eltohamy Mohamed , Ali Mahmoud , Alsakkaf Aseel , Gehad Mennatallah , Haydar Raz , Mourad Karim
Published: September 2023

Cementing is an integral operation in any oil and gas well. Although conventional cement has been used for many years, it suffers from two significant problems. These include significant numbers of failures especially at extreme conditions, and environmental damage due to high emissions generated during cement production. This research overcomes these two problems by developing a novel environmentally friendly and high durability epoxy based cement reinforced with low cost fly ash. More than 100 different samples were prepared for the novel cement for evaluation. Different formulations were designed for testing by varying the fly ash concentration. The formulations had a fly ash concentration of 0, 10, and 30%. The samples were tested under temperatures of 25, 80, 120, and 160 °C, and hydrochloric acid (HCl) concentrations of 1, 10, and 20%. The samples were also tested for sedimentation, and density increase with the increase in fly ash concentration. Compared to the conventional class G cement, the developed cement showed higher acid and alkali resistance, higher thermal stability, and much higher overall compressive strength.

INTRODUCTION

After an oil well is drilled, metal piping called casing is placed in the hole to support the drilled hole from collapsing. In order to fix the casing to the hole wall, cement is used. The cement must have unique properties to avoid problems (Fakher, et al., 2020; 2021; 2022). These properties include high compressive and tensile strength, high bond strength with the casing and the formation, low porosity and permeability to avoid fluid migration through the cement, and high resistance to temperature, acidity, and alkalinity to avoid cement interaction with different underground fluids (Wagle, et al., 2021; Fakher, and Khlaifat, 2022). Although conventional cement has been used for many years in oil and gas wells, it suffers from two main drawbacks. Firstly, conventional cement relies on limestone as its raw material; this results in an ever-increasing cost of cement and the large volume of greenhouse gas emissions associated with the burning of the limestone to produce cement (Alanqari, et al., 2022; Lummer, et al., 2017; Fakher, 2020). Secondly, with the increase in technology, deeper wells are being drilled with more extreme conditions which results in cement failure. It is therefore necessary to produce enhancements to the cement in order to be able to withstand these severe conditions.
Pore Pressure Detection Method of Carbonate Formation Based on Multiple Logging Parameters
Authors: Lv Kunhong , Zhang Hui , Ouyang Yong , Lu Zongyu , Shi Jiangang
Published: September 2023

Prediction methods for the pore pressure of clastic rock formation are almost mature worldwide. However, due to the characteristics of carbonate rock formation, such as high matrix rigidity, pronounced heterogeneity, and the uncertain formation mechanism of abnormal pressure, the traditional prediction methods of formation pore pressure are difficult to apply in carbonate formation, which seriously threatens the drilling safety. Therefore, the method for calculating the pore pressure of carbonate formation was studied. Taking the carbonate formation of the Majiagou Group in the Mid-Eastern Ordos Basin as an example, this paper put forward a comprehensive interpretation of various logging parameters related to the formation mechanism of abnormal pressure. It established a pore pressure prediction model applicable to carbonate formation, which is not limited to the under-compaction theory using multiple nonlinear regression methods. The formation pore pressure detection method was applied to multiple wells in the Majiagou Group, Mid-Eastern Ordos Basin. The application results showed that the relative error of formation pore pressure between the model detection and measured values was less than 10%, which satisfy engineering requirements. It also provides a new approach to address the problem of pore pressure detection of carbonate formation.

INTRODUCTION

Abnormal high pressure has an important impact on the development of conventional and unconventional oil and gas reservoirs, which may cause many complex accidents, such as wellbore instability, drilling fluid leakage, and blowout. With the development of oil and gas reservoirs towards the complex formation, formation pore pressure prediction plays an increasingly important role in the future development of oil and gas reservoirs. Reasonable and accurate prediction of formation pore pressure is the basis for the rational design of drilling fluid density, wellbore structure design, and wellbore pressure maintenance. It also guarantees safe, effective, and rapid drilling. Formation pore pressure prediction includes forward-looking pre-drilling prediction, timely monitoring while drilling, and reference post-drilling detection. Among them, the accuracy of post-drilling detection is the highest. The logging data of adjacent and exploratory wells can provide theoretical support and reference for target wells’ formation pore pressure prediction.
Wellbore Stability of Mud-Shale in Ultra-Deep Carboniferous Formation: A Perspective from Mechanochemistry
Authors: Zhen Zhang , Jiaxin Li , Yong Sheng , Lin Chen , Zheng Fang , Yunhu Lu
Published: September 2023

The wellbore instability is a vital problem when drilling in the ultra-deep carboniferous shale formation in the southwest block of Tarim Oilfield. And, bits are frequently blocked and stuck. Unfortunately, the problems are hardly to be effectively solved by increasing the drilling fluid density. At present, the mechanism of wellbore collapse in the block is still unclear. In this way, it is unable to establish an effective prediction model for wellbore collapse. Therefore, this paper systematically analyses the formation mineral characteristics, physical and chemical properties and stress state in the block to clarify the reasons for wellbore instability of mud shale formation. Consequently, the wellbore stability model of mud shale is established considering the degree of formation collapse, drilling fluid density, activity and plugging. Then, through quantitative analysis and definition of the relationship between the wellbore collapse degree and the density and performance of drilling fluid, the technical countermeasures for wellbore stability are proposed. The analysis model proposed in this paper provides a new way for quantitative design of drilling fluid density and performance in ultra-deep carboniferous mud shale formations.

INTRODUCTION

Based on statistics, the confirmed recoverable reserves of deep oil and gas reach up to 7.29×1010 t oil equivalent, constituting 49.07% of the world's total recoverable reserves. As much as 70% of China's unconventional oil and gas resources are stored in deep formations, leading to a growing number of ultra-deep wells drilled(Chen et al., 2009; Y. Lu et al., 2011; Zhang et al., 2022). The Tarim Basin in China is a significant region for its vast oil and gas reserves. The Tangu Depression, particularly the Madong buried hill belt in the southwest block of the Tarim Basin, is recognised for its abundant oil and gas resources. However, the Madong structural belt underwent multiple tectonic movements, resulting in extremely complex structural conditions in the basin. The reservoirs in this area are buried deep, reaching depths of more than 6000m on average and are subjected to high temperatures and ultra-high pressure. As a result, this area faces complex wellbore stability issues during exploration and development. In the initial stages of development, due to an unclear understanding of the lithological characteristics and structural stress in the area, complex problems such as well wall collapse, drag, and pipe sticking were common during the drilling process(Zhang & Chen, 2022).
Numerical Analysis of Dynamic Instability of Juncture in Multilateral Drilling Based on Chemo-Mechanical Coupling
Authors: Xie Renjun , Yang Qiqi , Chen Xuyue , Yin Zhiming , Zhang Tianwei , Wang Gan , Liu Nanxiang
Published: September 2023

During the drilling of multilateral wells in oil and gas fields, the juncture in multilateral drilling is a high risk area for collapse. Studying the factors affecting the stability of the multilateral well juncture is helpful to improve the success rate of sidetracking in branch wells. In this paper, based on the experiment, the variation law of shale rock mechanical parameters before and after drilling fluid immersion is obtained. The three-dimensional model of the juncture of multilateral drilling considering the decrease of rock strength under the action of hydration is established. The angle of the main branch well and the borehole azimuth angle of the main branch well on the stability of the multilateral well juncture is analyzed. The three-dimensional Coulomb failure criterion is introduced to characterize the dynamic failure of the rock, and the failure range and failure length of the multilateral well juncture under different conditions are obtained. The results show that the smaller the angle, the more obvious the stress concentration and the longer the failure length; the smaller the azimuth, the more stable the multilateral well juncture; with the increase of drilling time, the failure range of the multilateral well juncture is gradually expanding, and after 2d, the hydration effect gradually slows down. The model can simulate the influence of different conditions on the failure range and failure length of sidetrack multilateral well juncture, and has certain guiding significance for improving the success rate of sidetrack drilling and increasing production efficiency.

INTRODUCTION

After continuous production in oil and gas fields, production well output decreases and some production wells may even break down leading to scrapping or shutdown, and these conditions are a common problem in the middle and late stages of oil and gas field development. If new wells- are deployed, a significant increase in economic investment is required. However, if these low-producing wells, faulty wells, and shut-in wells are transformed into an optimized new well that can be reused in the original well network, the drilling cost will be greatly reduced and old wells will be revived, dead wells will be revived, and oil fields will gain increased production (Zhu et al, 2011). Lateral drilling branch well technology is to make full use of the old well network and the re-usable well section in the upper part of the old well to drill a new borehole that can reach the target layer and be used again. Lateral drilling branch wells are widely utilized because they have the characteristics of less time, low cost, increased oil absorption area and higher recovery rate (Sun et al, 2018 and Chen et al,2022). It provides economic development and relieves energy tension.
Neural Networks Modeling of Shear Wave Velocity for Tight Gas Sandstone Formation
Authors: Yang Fan , Li Yesong , Yang Qi , Zhou Libo , Wu Jian , Mei Wenbo , Pu Shengxian , Feng Chun , Li Hui , Li Ben
Published: September 2023

Shear wave velocity (Vs) is a key parameter in the calculation of rock elastic properties, such as Young's modulus, Poisson's ratio, shear modulus. However, due to technical and economic limitations, Vs is not always available (especially for older Wells). It is very important to predict Vs effectively and accurately. The characteristics of shear wave velocity prediction methods in different ultra-deep sandstone formations are compared, and an optimized neural network model is proposed. Training data is derived from real logging and logging interpretation results. The input parameters were determined according to the rock physical model, and the structure of the neural network (the number of hidden layers and the number of hidden neurons in each hidden layer), transfer function, training function and learning function are optimized according to the accuracy and training time. In order to solve the limitations of a single evaluation index on the evaluation of machine learning, a new evaluation index M4 of neural network was proposed in this paper. The accuracy of model predictions and sensitivity to outliers can be adequately evaluated. In addition, the interpretability analysis of the training model is carried out, and the results presented can be used to (1) estimate the S-wave velocity according to the above variables, and (2) evaluate the influence of each variable on the S-wave velocity.

INTRODUCTION

The unconventional resources from an ultradeep tight gas reservoir have received significant attention in recent decades (Li et al., 2021). Therefore, it is of great significance to conduct deep and ultra-deep gas resource exploration and development for expanding reserves, stabilizing production, and seeking new areas for exploration in old oil and gas fields (Li et al., 2019). In oil and gas field development engineering, parameters such as Young's modulus, Poisson's ratio, bulk modulus, and shear modulus are important elastic parameters that characterize rock properties and fluid information (Zhang et al., 2019). The cross-wave velocity in logging data is an important parameter for calculating and predicting reservoir rock physical parameters, reservoir identification, and pre-stack inversion.
Development of a Wellbore Stability Prediction Model Using Multiple Regression with Missing Core Samples: A Case Study of the Shunbei Oil and Gas Field
Authors: Chang Qifan , Fu Yun , Zhou Yitian , Zheng Lihui , Li Jie , Jin Yi
Published: September 2023

The Shunbei oil and gas field, characterized by its intricate deep fault-karst reservoirs and fractured carbonate lithology, presents formidable challenges to wellbore stability during drilling and completion phases, precipitating adverse events such as wellbore collapse and fluid loss. This study embarks on addressing the paucity of data integral for effective wellbore stability prediction in this region, employing a tripartite methodological approach: identification of pertinent data and influential factors, enhancement of multiple regression accuracy, and selection of controlling factors. The study revealed that the multiple linear regression model delivered the most precise predictions for both the leakage rate and well diameter expansion rate. Crucial factors such as geodetic coordinates, drilling pressure, and azimuth were identified as exerting substantial influence on wellbore stability. By scrutinizing primary controlling factors and underscoring the crucial role of drilling pressure and displacement in averting collapse and leakage, this study provides invaluable insights applicable to actual production settings. This study, while enhancing understanding of wellbore stability through analyzing key factors, does not delve into quantitative control strategies. Nevertheless, it provides a practical framework for better management of wellbore collapse and leakage in Shunbei oil and gas field.

INTRODUCTION

Meeting the global energy demands requires exploration and development of oil and gas fields (Cui et al., 2023). However, drilling and completion of deep fault-karst reservoirs such as the Shunbei field (Baozeng et al., 2020) present significant challenges due to wellbore instability issues. These issues include wellbore collapse, fluid loss, and other prevailing problems (Lixin, 2020), which can lead to extensive equipment damage, increased drilling and operational costs, and endanger the safety of personnel.

The wellbore instability issues faced in the Shunbei field are primarily due to the fractured carbonate lithology, which exhibits fragility and poor mechanical properties (Yingtao et al., 2019). Precise prediction of wellbore instability and fluid loss in such formations is essential for efficient field development. The field of rock mechanics and wellbore stability has a long history, dating back to the early 20th century, when the first recorded studies focused on the stability of oil and gas wells (Cheatham, 1984).
Temperature Effects on Core Mechanics Testing – An Eagle Ford Case Study
Authors: Roberts Jon , Chapman Philip , Arrington Sean
Published: September 2023

It has long been recognized that an important step in acquiring mechanical properties from core is to take the measurements at reservoir conditions. However, the actual test often only replicates the effective downhole stresses, while ignoring the elevated temperature downhole. To quantify the effects of temperature in the Eagle Ford Formation, a core testing program was designed to take advantage of having a large volume of similar rock provided by the HFTS 1 phase III horizontal core. This program involved 46 samples taken from ∼2.4 m of horizontal core. This ∼2.4 m of horizontal core represents ∼0.3 m of vertical section inside the Lower Eagle Ford Member. Multiple tests were performed on the core including anisotropy parameters, static and dynamic triaxial testing, pore volume compressibility and tensile strength. Some of the notable results include that the majority of samples showed an increase in tensile strength with temperature, a decrease in shear velocity at temperature, and an increase in Biot coefficient with temperature.

PROJECT INTRODUCTION

The Zgabay A 14H is the monitoring well associated with the HFTS 1 Phase III refracturing study in the Eagle Ford trend. As part of this study, a horizontal core was taken with the primary objective of understanding hydraulic fracture intensity and behavior in the far field. Geomechanical core testing was one component of the core analysis program designed to help understand and model hydraulic fracture growth.

Recent studies by industry and internal testing have shown there is a change in mechanical properties with temperature (Mitra, 2022) However, we had not investigated the effect of temperature on the Eagle Ford Formation. Therefore, with the relatively large volume of rock available in a similar facies provided when taking a horizontal core, we decided to use this unique opportunity to test the effect of temperature, in situ vs. ambient, on core testing results.
Pouring and Calibration of Hydrate-Bearing Sediment Substitutes
Authors: Hui Chengyu , Zhang Yiqun , An Youkeren , Wu Xiaoya , Huang Haochen , Li Gensheng
Published: September 2023

As a potential pollution-free energy with wide distribution and huge reserves, the effective development and utilization of natural gas hydrate is of great significance to alleviate the shortage of resources and realize sustainable development. Improving the mining efficiency is the critical issue to realize the commercial exploitation of hydrates. Although hydraulic fracturing is one of potential stimulation methods, the occurrence environment of hydrate is not conducive to implement indoor experimental research and testing. Through physical properties determination and calibration, a pouring method of gas hydrate bearing sediment substitute has been optimized. We used the cured samples to prepare 25 * 50 mm standard cylinders and carried out triaxial shear test and porosity & permeability test. The physical properties test results show that the substitute corresponds well with the hydrate bearing sediments in the Shenhu area of the South China Sea. The stress-strain curve consists of three main phases, with strain softening occurring after initial plastic deformation. The cohesive force and internal friction angle correspond well to the actual hydrate bearing sediments by means of plotting Mohr circles. The substitute sample prepared by this pouring method can be used to carry out indoor fracturing experiment research, which is expected to promote the research progress of hydraulic fracturing of natural gas hydrate.

INTRODUCTION

Natural gas hydrate (NGH) is a clean energy source with high energy density composed of methane gas molecules and water molecules(Sloan, 2003). NGH resources are abundant and mainly distributed in terrestrial permafrost regions and shallow areas of the deep-sea continental shelf(Cai et al., 2020). Researches show that the global hydrate resources account for almost 1/2 of all energy resources in carbon reserves, and their effective exploitation is of great significance to alleviate the shortage of resources and realize sustainable development (Cui et al., 2019; Li et al., 2016).
Coupled THM Modeling of a Heated Borehole Test in Rock Salt
Authors: Tounsi H. , Rutqvist J. , Hu M.
Published: September 2023

The very low permeability of intact salt rocks makes them promising media for the geologic disposal of nuclear waste. However, permeating flow can occur through fractures in rock salt. These fractures can be induced by excavation operations that create a localized damage rock zone where brine could migrate towards the excavation, or by strong temperature changes, around a high-heat emitting nuclear waste package, causing compressive (during heating) or tensile (during cooling) thermal stresses that could cause rock salt damage and a potential brine migration towards the heat source. Coupled thermo-hydro-mechanical simulations were performed to predict quantitatively the brine flow into a borehole excavated in rock salt as a result of excavation, heating/cooling and damage. The rate of water release was shown to rise with any change in temperature, with the greatest increase occurring during the cooling phase. Heating-induced compressive thermal stresses and creep caused the initial mechanical damage of rock salt, leading to the creation of higher-permeability zones (e.g., fractures) for pore water flow. The subsequent cooling led to an enhancement of these zones and the formation of additional ones as a result of tensile rock failure.

INTRODUCTION

Rock salt has been identified as a suitable medium for nuclear waste disposal due to its low permeability, high thermal conductivity, and self-sealing capacity (Sweet and McCreight, 1983; Cosenza et al., 1999; Winterle et al., 2012). However, micro-fractures in the salt host rock can compromise the hydraulic integrity of the disposal facility by providing pathways for brine migration (Hansen and Leigh, 2011). Micro-fracturing is often initiated by two phenomena: shear-induced dilatancy (Stormont, 1997) and tensile stresses exceeding the tensile strength of salt which is around 1 MPa (Hoffman and Ehgartner, 1998).

Several laboratory and in situ tests have been conducted in the 1990s or earlier to characterize the movement of brine in rock salt under isothermal and heated conditions (Hohlfelder and Hadley, 1979; Hohlfelder, 1980; Ewing, 1981; Krause, 1983; McTigue and Nowak, 1987; Finley et al., 1992). In the absence of heating, the brine inflow response varies from one experiment to another, mainly due to the heterogeneity of the tested rock salt formation that the excavation intersects (Finley et al., 1992). In the presence of a heating phase, the experiments show that brine inflow rates increase with an increasing borehole temperature (Hohlfelder and Hadley, 1979; Hohlfelder, 1980; Ewing, 1981; McTigue and Nowak, 1987). Additionally, some of these tests have shown that a considerable amount of brine was released during the heater shut-down (Hohlfelder and Hadley, 1979; Ewing, 1981).
Boundary Condition Effect on 3-Point Bending Test via FDEM
Authors: Huang Y. , Lei Z. , Rougier E. , Euser B. J. , Padilla A. M. , Knight E.
Published: September 2023

Three-point bending test is a widely used laboratory test for the estimation of the flexural force-displacement response of the material. It is well known that the results of the three-point bending test are sensitive to the specimen and the loading. In this work, the impact of the boundary effects on a single notch three-point bending test is studied using LANL's combined finite-discrete element method (FDEM) based code, the Hybrid Optimization Software Suite (HOSS). To this goal, a series of virtual experiments with different specimens and boundary conditions are conducted. The influence of the notch location, and fixture shape are studied. Results clearly show that these boundary conditions greatly influence on the fracture initiation and propagation behaviors as well as the flexural force-displacement response.

INTRODUCTION

Three-point bending test is a long-used technique applied mainly in the oil and gas industry to estimate the fracture toughness of rocks in the laboratory. In this test, the vertical tension is applied to the convex side of a sheet or plate specimen placed on two supporting fixtures with a set distance apart.

A variety of numerical approached have been proposed to analyze the crack initiation and growth behavior of three-point bending test in the past several decades (Fakhimi, 2005; Kokot, G., Binkowski, 2011; Ramos, 2015; Klasztorny, 2018: Sauvage, 2020). However, the effect of boundary conditions is still lacking consideration in the previous studies.

Motivated by the prior works and the knowledge gaps remaining in effect of boundary conditions, a finite-discrete element method (FDEM) model is applied here to interpret three-point bending experiment results in order to characterize dependence of rock fracture behavior on boundary conditions and notch location. The present study therefore aims to capture the crack initiation and propagation behavior for laboratory experiments using material properties and traction-separation law that has been calibrated by comparing the simulation results with lab experiments provided by Jiang et al. (2021) and Jiang et al. (2022), regardless of notch location.

This study aims to revisit the effect of boundary conditions on crack initiation and growth behavior under three-point bending test. For this purpose, a 2D plane-strain model is developed using HOSS, a combined finite-discrete element method (FDEM) based code. Different boundary conditions and notch locations are considered for lab-scale simulations. Indeed, simulation results indicated that the crack initiation location and crack growth behavior can vary with different boundary conditions and notch locations, which can challenge the general belief that the crack initiation and propagation behavior should not be affected by the boundary conditions greatly.
Novel Approach for Elastic Anisotropy Assessment in Organic-Rich Shales: A Case Study from Early-Mature Region of the Bakken Formation
Authors: Malki Mohamed Lamine , Rasouli Vamegh , Latrach Abdeldjalil , Mellal Ilyas , Sennaoui Billel , Chellal Hichem A. K. , Larbi Anis
Published: September 2023

The middle Bakken (MB) is a major unconventional oil producing formation in the U.S. with an enormous contribution of upper (UB) and lower (LB) Bakken members, source rocks. The three Bakken members form a crucial petroleum system in the Williston, where UB and LB, the target of this study, have similar lithologies, composed of siliceous, pyritic black shale, and middle Bakken (MB) which is a calcareous siltstone and fine-grained sandstone. Shales are characterized by their anisotropic nature due to layering. Therefore, isotropic modeling can lead to errors in stiffness estimations.

The main objective of this study was to develop anisotropic rock physics modeling of the Bakken formation to assess the elastic behavior and determine the key parameters controlling the velocity dispersion with respect to layering. Maturity effect was also investigated by including kerogen content into the system via solid substitution modeling. Laboratory data was scattered against the lab-scale rock physics templates to capture the dominant pores morphology with respect to beddings in the Bakken shale. Furthermore, this study captured the implications of different pore structures on controlling the degree of anisotropy in the medium. The results showed that UB and LB shales exhibit large anisotropy due to high presence of clay minerals, and fractures.

INTRODUCTION

The Bakken formation is a major oil producer in the U.S. The members constituting the Bakken formation are upper (UB), middle (MB), and lower (LB) Bakken members. Both UB and LB units, which are the subject of this study, are source rocks with similar lithologies, composed of siliceous, pyritic black shale (Laalam et al., 2022a; Malki et al., 2022a; Sennaoui et al., 2022a; Sennaoui et al., 2022c). Total organic carbon (TOC) in the Bakken shales may reach 40 wt.%, with potential oil in place in a range of 10-500 billion barrels (Aoun et al., 2023a; Ozotta, et al., 2022a; Sennaoui et al., 2023a; Sorensen et al., 2010), but ultra-low porosity and permeability characteristics (Afari et al., 2022; Laalam et al., 2022b; Ozotta et al., 2021c; Sennaoui et al., 2023b).
A Novel Rock Drillability Characterization and Prediction Method Based on Drilling Big Data and Unsupervised Clustering Algorithm
Authors: Lu Zongyu , Jiang Zhenxin , Wu Zhe , Song Xianzhi , Ye Shanlin , Liu Zihao
Published: September 2023

Rock drillability measures the ability of rock to resist damage by the drill bit. Accurate evaluation of rock drillability is crucial for understanding formation properties and selecting appropriate drill bits and drilling parameters. However, many existing intelligent evaluation methods for rock drillability mainly rely on supervised learning algorithms, which require a large number of rock core samples for drillability analysis data as labels. Core acquisition is difficult and expensive. To address this issue, this study proposes a method for continuous formation drillability evaluation using logging big data and unsupervised clustering algorithms. Firstly, self-organizing mapping (SOM) neural network is used to cluster logging data. The formation is then divided into six drillability grades by analyzing the rate of penetration (ROP) distribution of each type of logging data. We used this method to grade the drillability of the test well formation. The results show that the ROP of the formation decreases gradually with the increase of drillability grade, which verproves the effectiveness of our method.

INTRODUCTION

Rock drillability is a crucial factor that determines drilling efficiency, reflecting how easily the rock breaks during drilling operations. Accurate evaluation of rock drillability can help drilling engineers select drilling tools and parameters to improve drilling efficiency (Kong, et al. 2022). The microdrill bit experimental method is a classic approach for evaluating drillability. It involves recording the time it takes for a miniature gear or PDC bit to drill 2.4mm under a specific drilling pressure and rotation speed condition, and calculating the formation drillability based on standard formulas and recorded time. (Zhang & Xue, 2019; Chen, et al. 2010). In the experimental method, the test rock core samples are not in the real underground environment, and the accuracy of the results is difficult to guarantee. Statistical analysis is another method for evaluating rock drillability, which predicts the drillability of rock by establishing a mathematical model that incorporates logging data, drilling parameters, and other factors that influence drillability (Andrews, et al.; Tang, et al.). However, a significant amount of rock core data is required to support the model and ensure accurate predictions.
Impact of Pore Structure on Stress-Dependent Behavior of Permeability for Fluid Flow Through Porous Medium
Authors: Wang Xiaohan , Peng Yan , Lyu Peihong
Published: September 2023

Stress-dependent behavior of permeability is an important characteristic of fluid flow through porous medium. It is widely accepted that the stress-dependent permeability behavior relates to pore volume change, but ignore the real stress distribution around pores. In this study, the coupled flow-geomechanics numerical simulation is conducted to simulate the real process of fluid flow through a real pore structure. The fluid flow inside pores is described by the laminar flow, and calculate the pore volume change by elasticity theory. Permeability is calculated by Darcy's law. The affections of pore structure on stress-dependent permeability behavior are studied and then main factors affecting this behavior are discussed. The main results show: (1) There is a dominant cross-section in the whole pore controlling the stress-dependent behavior of permeability. This dominant cross-section may be the cross-section where the flow velocity is highest along the pore. (2) The three stress components have different impacts on permeability stress-dependent behavior. The major stress component can be determined through the deformation of dominant cross-section which is the dominant one for permeability. (3) The pore geometry shape also affects stress-dependent permeability. (4) The pore's orientation also affects stress-dependent permeability behavior.

INTRODUCTION

Rock is a typical porous medium consisting of pores and a solid skeleton. Rock permeability is one of the most important fluid transport properties. Stress-dependent behavior of permeability significantly affects fluid flow behavior of in areas of underground storage, petroleum engineering and mining engineering. The rock permeability is determined by the connected pores and their distribution in the rock. Based on the rock mechanics theory, pore shape can cause stress concentration affecting pore deformation (Peng et al., 2021). The stress-dependent behavior of permeability results from pore deformation (Peng et al., 2022). In addition, the stress-dependent behavior of permeability is also affected by the stress variation. The in-situ stress of unconventional reservoirs varies significantly after many treatments, such as hydraulic fracturing and water flooding (Pan et al., 2012; He et al., 2020; He et al.,2020). Therefore, the stress-dependent behavior of permeability affects production behaviors of unconventional reservoirs.
Numerical Simulation Study on Fracture Propagation Induced Flooding in Tight Reservoirs
Authors: Peng Yan , Lv Peihong , Wei Shengjie
Published: September 2023

Tight reservoirs are important resources all over the world, but its recovery rate is low. The common enhanced recovery technique is water flooding. If the fracture propagation is induced during water flooding, the recovery rate of tight reservoirs will increase. However, the quick fracture propagation can connect injection wells and production wells, and then induce the sudden water influx, therefore, the injection pressure should be carefully controlled. In this study, we established numerical simulation model that considered the impacts of two-phase fluid flow through tight reservoirs, rock deformation, water-rock interactions and fracture propagation. Using this model, the propagation mechanism of fracture induced by water flooding was discovered and then factors controlling fracture propagation were discussed. The main conclusions are (1) the heterogeneity magnitudes of rock properties, such as Young's modulus, are decreased by water flooding. The rock property is changed by the long term of water-rock interactions and its magnitude depends on water amount. This heterogeneity of rock property further causes the stress redistribution and stress decrease around fracture tip. The decrease magnitude of stress can be up to 26.5%. (2) The impact of water-rock interaction on mechanical rock properties affected the propagation magnitude of WIF. The maximum magnitude of WIF propagation length can reach 25.7% of initial WIF length. (3) To avoid WIF propagates rapidly, the injection pressure needs to be controlled carefully. It is because that water-rock interaction makes critical injection pressure decreases, maximum decrease magnitude of critical injection pressure can reach 26.5% of the minimum horizontal stress.

INTRODUCTION

Tight reservoirs are widely distributed in China, such as Permian in Junggar Basin, Triassic in Ordos Basin, and Jurassic in Sichuan Basin (Zhu et al., 2019. Wang et al., 2007. Gao, 2009.), with abundant reserves and great oil production potential. At present, the most effective oil recovery technology is the water flooding. During the Oil production period, if fracture propagation occurred, it may promote the recovery of tight reservoirs. However, if the fracture propagates too fast, it is very likely to cause the water-induced fracture (WIF) to connect with the production fracture to form a flood channel, thereby reducing the development efficiency of tight reservoirs. Therefore, exploring the propagation mechanism and influencing factors of WIFs to improve the recovery rate of tight reservoirs is of great significance.