Brittle Shale Research Articles

Sealing of oil-gas reservoir caprock: Destruction of shale caprock by micro-fractures

The sealing ability of caprock is affected by many factors, such as cap thickness, displacement pressure, fracture development, and lithology of caprock. Shale is one of the ideal materials for oil and gas sealing cap formation due to its low porosity and permeability. Microfractures can destroy the sealing property of shale caprock. When buried deep enough, shale will change from toughness to brittleness. In general, the greater the brittleness of shale, the more developed the fractures will be. In areas with high tectonic stress, such as the anticline axis, syncline axis and stratum dip end, the strata stress is high and concentrated, and it is easier to generate fractures. When the stress state of the caprock changes, new micro-cracks are formed or previously closed cracks are re-opened, reducing the displacement pressure of the caprock. These micro-fractures are interconnected to form microleakage spaces, which reduces the sealing capacity of the caprock.

Quantitative Evaluation of Shale Brittleness Based on Brittle-Sensitive Index and Energy Evolution-Based Fuzzy Analytic Hierarchy Process

Quantitative Evaluation of Shale Brittleness Based on Brittle-Sensitive Index and Energy Evolution-Based Fuzzy Analytic Hierarchy Process

Experimental Study on the Adaptability of Plugging Drilling Fluids to Wellbore Stability in Hard Brittle Shale Formations.

The problem of wellbore stability in hard brittle shale formations is an important research topic in the exploration and development of shale gas. To solve this problem, the adaptability of the plugging drilling fluid to wellbore stability in the hard brittle shale of the tertiary Dongying formation in Bohai Bay Basin, China, was investigated. The results show that the clay content of the hard brittle shale in the study block is as high as 39.2% on average, with great possibility for hydration. The pore structure in the shale is dominated by micron-scale fractures and pores. A dense structure was formed on the surface of the shale after being immersed in plugging drilling fluid, and the matrix permeability of the shale was reduced by 91.1% and the fracture permeability by 98.7%. The water content increment of the shale after immersion was merely 0.75%, which reduced the probability of hydration greatly. Compared with the field-inhibitive drilling fluid, the plugging drilling fluid improved the uniaxial compressive strength of shale by 28%, which is more conducive to maintaining the wellbore stability. The seepage stress aggravates the risk of wellbore instability, while the hydration stress does not, but both increase the risk of rock instability at positions away from the well wall. The plugging drilling fluid affects the seepage stress and hydration stress by reducing the shale permeability and water content. With the decrease of permeability and water content, the potential instability zone of a wellbore becomes smaller.

Predicting shale mineralogical brittleness index from seismic and elastic property logs using interpretable deep learning

The mineralogical brittleness index (MBI) of organic-rich shale formations is one of the key parameters to identify the optimal production well locations and optimize hydraulic fracturing. Since we as a community don't understand the exact physical relationship between the MBI and seismic properties from well logs, we have used traditional approaches like the log-based brittleness index (LBI) and the elastic brittleness index (EBI) to quantify the rock brittleness from seismic data and well logs. The LBI method is easy to use but is empirically derived from the porosity and sonic logs. On the other hand, the EBI method is dependent on the average values of Young's modulus and Poisson's ratio but is not physically meaningful in practice. Therefore, we develop a deep learning approach to obtain a more reliable MBI model from seismic properties and enhance the interpretability with Shapley values. First, we analyze the statistical relationship between the MBI and eight seismic properties from well logs and distinguish the influential input variables for the MBI prediction, such as bulk density, Young's modulus, and Poisson's ratio. Second, we find a multivariate linear regression (MLR) model with three input properties and quantify the relative statistical contribution of each input based on Shapley values. Third, we use a deep neural network technique to derive the nonlinear estimation model with a better fit to the MBI data than the traditional methods. We test and verify our approach on field log and core data from the Wolfcamp shales in the Permian Basin, Texas. In conclusion, this workflow can provide a more interpretable and accurate MBI estimation from seismic properties to enhance unconventional shale reservoir characterization.

Shale brittleness prediction using machine learning - A Middle East basin case study

Shale brittleness prediction using machine learning - A Middle East basin case study

Identifying Organic Matter (OM) Types and Characterizing OM Pores in the Wufeng-Longmaxi Shales.

Organic matter (OM) pores are considered to be an important pore type in the Ordovician Wufeng-Silurian Longmaxi Formation shales in the Sichuan Basin, China, because they have a high capacity to store natural gas. However, to the best of our knowledge, research on the characterization and quantitation of different OM pore characteristics is insufficient. In this study, detailed optical microscope and scanning electron microscope (SEM) observations and the pores/particles and cracks analysis system (PCAS) were applied to identify the OM pores and obtain quantitative information on pores such as pore size, surface porosity, form factor, and probability entropy. Moreover, CO2 and N2 adsorption experiments were performed to study the properties of pores for samples with different TOC and mineral compositions. The results show the following. (1) Pyrobitumen and kerogen can be distinguished under an optical microscope and SEM; the former can be further divided into pyrobitumen without a fixed shape and pyrobitumen with a certain shape, and the latter contains algal fragments, bacteria-like aggregates, graptolite, and micrinite. The overwhelming number of SEM-visible OM pores are mainly observed in pyrobitumen without a fixed shape, whereas pores in other OM types are complex. A PCAS analysis showed that meso-macropores are developed in pyrobitumen without a fixed shape, whereas pores in algal fragments and bacterial-like aggregates are mainly mesopores. (2) Quartz-rich brittle shale will provide more visible SEM pores compared to clay-rich ductile shale, and carbonates are unfavorable for pore development because they can block the pore as cements. Moreover, the rigid mineral framework, including that constructed by quartz recrystallization and pyrite cementation, and the pore-fluid pressure are favorable for the development of OM pores. (3) Adsorption experiments showed that pyrobitumen makes a great contribution to pore development, including micropores and meso-/macropores. Finally, we propose that the pore parameters (e.g., pore diameter, pore form factor, and deformation) of pyrobitumen without a fixed shape may characterize the enrichment condition of shale gas.

A new hybrid method based on sparrow search algorithm optimized extreme learning machine for brittleness evaluation

Shale brittleness is the key parameter to optimize reservoir fracturing modification and improve productivity. However, conventional methods based on rock mechanics and mineralogical parameters are limited by the lack of shear wave velocity and mineral composition data. Machine learning algorithms have been applied in the field of geophysical exploration, but the prediction accuracy of existing algorithms needs to be improved. In this study, a new hybrid model, an integration of the Sparrow Search Algorithm (SSA) and the Extreme Learning Machine (ELM), named SSA-ELM, is proposed for predicting the brittleness index. ELM is performed to create the original brittleness model, meanwhile, the SSA algorithm is utilized to automatically explore the hyperparameters of the model. Additionally, we also use 12 other favorite machine learning algorithms to validate the superiority of the proposed model combined with traditional logs and XRD-derived brittleness. 82 mineral brittleness databases from 5 exploration wells in the Songliao Basin, China were established. The simulation results of two Test wells indicate that the SSA-ELM model has the most accurate predictions and excellent generalization capability. The brittle profiles established based on the SSA-ELM model can effectively guide the fracturing exploration of shale oil reservoirs.

Hydraulic Fracture Vertical Propagation Mechanism in Interlayered Brittle Shale Formations: An Experimental Investigation

Hydraulic Fracture Vertical Propagation Mechanism in Interlayered Brittle Shale Formations: An Experimental Investigation

Quantitative evaluation and influencing factors analysis of the brittleness of deep shale reservoir based on multiply rock mechanics experiments

Due to a great increase in the plasticity of deep marine shale reservoirs in southern Sichuan under high-temperature and high-pressure conditions, the single brittleness evaluation method is difficult to effectively characterize its fracability, which significantly limits the selection of sweet spots and fracturing reconstruction in the area. In the case of the deep marine shale reservoir of the Wufeng-Longmaxi formations in the southern Sichuan Basin, through triaxial high-temperature and high-pressure experiments, fracture toughness and X-ray diffraction experiments, the mechanical properties and its influencing factors in the shale reservoir are studied, and the rock fracture morphology under various loading conditions is quantified. According to the morphological characteristics of shale, the analysis of influencing factors and comprehensive quantitative evaluation of the brittleness has been carried out. The deep marine shale resource in the southern Sichuan Basin is likely to be characterized by its high elastic modulus and low I fracture toughness. The mineral composition, temperature, pressure, and degree of bedding development are the primary factors for determining the brittleness; with high quartz mineral content (>50%), low confining pressure (<20 MPa), medium and low temperature (<60 °C) and high density of the shale bedding, the fractal dimension of the sample after the experiment is higher; whereas the geometry of cracks are mainly complex shear cracks, and brittleness is higher. The analytic hierarchy approach establishes a comprehensive evaluation index by analyzing the relationship between the normalized rock mechanical parameters, the stress–strain curve's brittleness index, and the fractal dimension. The brittleness of deep marine shale can be more accurately described by this evaluation index. The primary target layer for future shale gas exploitation, the 31 sublayer of the first member of the Longmaxi Formation, is shown to have a high brittleness index.

Factors Controlling Brittleness of the Wufeng–Longmaxi Shale in the Yangtze Platform, South China: Insights from Geochemistry and Shale Composition

Brittleness index is an important parameter used to select favorable fracturing intervals during shale gas exploitation. Mineral compositions exert a significant influence on rock brittleness, and various grain assemblages can be deposited under different paleo-environmental conditions. The Wufeng–Longmaxi marine shale is a hot spot of shale gas exploitation in China. However, for the Wufeng–Longmaxi shale, the relationship between sedimentary environments, grain assemblages, and shale brittleness are rarely discussed. To address these problems, a series of experiments including petrographic observations, mineral compositions, rock mechanics, and major (trace) element analyses were carried out on shale samples from the Wufeng–Longmaxi formations. The Wufeng–Longmaxi formations are divided into upper Longmaxi formation (ULMX), lower Longmaxi formation (LLMX), and Wufeng formation (WF). The results show that WF shale samples deposited under a sedimentary environment with low terrigenous detrital influx, suboxic depositional water, and high paleoproductivity are characterized by the highest energy-based BI, compared to ULMX and LLMX shale samples. Dolomite in the samples grew in situ during early diagenesis. Redox conditions, terrigenous detrital flux control authigenic carbonate contents, and the oxic depositional water of the ULMX formation restrain carbonate mineral formation. In contrast, the suboxic sedimentary environment of the LLMX and WF allowed the generation of carbonate minerals. Compared with the WF, the larger terrigenous detrital flux of LLMX formation do favor more authigenic carbonate formation. The paleoproductivity affects biogenic quartz generation, and abundant biogenic quartz, primarily occurring in the form of micron-size microcrystalline quartz in the shale matrix, and can connect the silt-size brittle minerals to form a mechanical framework, which makes a strong positive contribution to shale brittleness. Terrigenous detrital influx decreases brittleness because the weakening effect of terrigenous clay minerals on shale brittleness is greater than the strengthening effect of terrigenous brittle minerals on shale brittleness.

Shale brittleness within the Paleoproterozoic Isa Superbasin succession in the South Nicholson region, Northern Australia

The South Nicholson region, which includes the Paleoproterozoic Isa Superbasin, the Mesoproterozoic South Nicholson Group and overlying younger sediments, is sparsely explored and has recently come into increased focus as a result of the Australian Government’s Exploring for the Future program. Previous exploration has identified potential shale gas plays within the River and Lawn supersequences of the Isa Superbasin in northwest Queensland’s northern Lawn Hill Platform region. Understanding mineralogy is important for characterising shale reservoirs, as mechanical properties such as shale brittleness are influenced by mineral composition. Mineralogy can, therefore, be utilised as a proxy for mechanical properties that are crucial to minimising risks associated with exploring for and developing shale reservoirs. This study utilises three different methods for calculating brittleness: X-ray diffraction (XRD) mineralogy, X-ray fluorescence (XRF) major-element geochemistry and derived elastic properties. Results indicate highly variable mineralogy within the analysed samples, demonstrating heterogeneity in shale brittleness throughout the studied supersequences. Brittleness calculated from XRD analysis ranges from ductile to brittle, with zones of brittle shales present in all supersequences. Increasing quartz and decreasing clay content is the dominant control on shale brittleness in the studied samples. Correlation between XRF major-element geochemistry and XRD mineralogy is demonstrated to be moderate to poor, with brittleness derived from XRF major-element geochemistry observed to be significantly higher than brittleness derived from XRD mineralogy. Conversely, brittleness derived from derived elastic properties agrees closely with XRD mineralogy derived brittleness. As brittleness derived from XRF major-element geochemistry provides brittleness estimates that are excessively high and with minimal overlap with the other two brittleness datasets, the use of these data to calculate brittleness in the South Nicholson region is not recommended. Analysis of brittleness indices from this study, in combination with total organic carbon content drawn from regional geochemical analysis in the South Nicholson region, identifies potential shale gas target intervals in the River, Term and Lawn supersequences. Data presented on correlated well sections highlight intervals of exploration interest within these supersequences, being those depths where high-organic-content, brittle rocks are identified. The rocks that meet this criterion are primarily constrained to the already-known potential shale gas plays of the River and Lawn supersequences. Recent data from Geoscience Australia imply a significantly increased lateral extent of these potential shale gas plays, likely extending from the northern Lawn Hill Platform, underneath the South Nicholson Basin and into the Carrara Sub-basin. KEY POINTS This study utilises three different methods for calculating proxy values for shale brittleness: XRD mineralogy, XRF major-element geochemistry and derived elastic properties. Calculated brittleness indices should be considered for their utility as screening tools rather than as accurate representations of brittleness. Results indicate highly variable mineralogy within the analysed samples, demonstrating heterogeneity in shale brittleness throughout the studied supersequences. Analysis of brittleness indices from this study, in combination with total organic carbon content drawn from regional geochemical analysis in the South Nicholson region, identifies potential shale gas target intervals in the River, Term and Lawn supersequences.

Experimental Assessment of Fracture Initiation and Wettability in Low and High Brittle Shales by CO2 Foam Fracturing Fluids

Experimental Assessment of Fracture Initiation and Wettability in Low and High Brittle Shales by CO₂ Foam Fracturing Fluids

Factors Influencing the Pore Structure and Gas-Bearing Characteristics of Shales: Insights from the Longmaxi Formation, Southern Sichuan Basin and Northern Yunnan-Guizhou Depression, China

China hosts rich shale gas resources. The Longmaxi Formation (LF) in the Sichuan Basin is one of the important regions for shale gas exploration and extraction. Here, we investigate the pore structure and factors influencing the gas-bearing characteristics of the pores in the shale reservoirs in the LF. We employed scanning electron microscopy (SEM), X-ray diffraction analysis (XRD), gas content testing, gas saturation testing based on nuclear magnetic resonance (NMR), overburden porosity and permeability analysis, distribution of pore size, specific surface area (SSA) analysis, and geochemical analysis. Our results show that the organic matter of the shale in the LF in the study area is highly favorable to shale gas conditions; the brittleness of the regional shale generally increases with an increase in depth. The pores in the LF mainly include organic matter-hosted pores, intergranular pores, intragranular pores, and microfissures, with mesopores dominating. Meanwhile, the gas content also increases with an increase in depth. The pore structure in the study area is affected by organic matter content and mineral components, with the development of organic matter-hosted pores. The porosity and the SSA are positively correlated with the total organic carbon (TOC), whereas clay minerals have an adverse effect on the SSA of pores in the study area. Higher TOC and vitrinite reflectance (Ro) indicate higher gas content. It can be inferred that as the content of brittle minerals increases, particles break to form storage spaces as the depth increases, causing the gas content to increase. Higher SSA and total pore volume indicate higher volume of adsorbed gas. The bound water in rocks tends to reduce the content of desorbed gas. Our results suggest high potential for shale gas extraction in this region.

Creep Mechanical Properties and Constitutive Model of Hard Brittle Mud Shale

AbstractMud shale is characterized by low strength and strong swelling, with rheological effects and deformation caused by drilling fluid and formation water. Establishing a rheological model to characterize the deformation characteristics is key to solving the problem of wellbore stability. The influence of moisture content on rock strength and creep mechanical properties were studied by means of water absorption, uniaxial compression, and creep tests. The tests showed that with the increase in moisture content, the elastic modulus and strength of hard brittle mud shale decreased. Further, under the same load, the instantaneous strain increased with increasing moisture content. Meanwhile, under various loading stresses, rock creep exhibited non-linear characteristics, which can be divided into three different creep stages: attenuated creep, stable creep, and accelerated creep. Starting with a non-linear viscous dashpot, and then introducing aging degradation and water-bearing weakening effects, based on the water-bearing creep characteristics of hard brittle shale as well as the modeling ideas of the classic component combination model, a new improved creep model based on the Nishihara model was established to describe the characteristics of the accelerated creep stage of hard brittle mud shale with various moisture contents. Subsequently, the Levenberg–Marquardt non-linear, least-squares method was adopted to invert the creep parameters. The results showed that the simulated creep curves achieved by employing the new creep model were consistent with the experimental results, thereby confirming the ability of the new non-linear creep model to provide a theoretical reference for the study of wellbore stability of hard brittle mud shale.

Study on failure characteristics and in situ stress inversion of brittle shale under complex loading

Study on failure characteristics and in situ stress inversion of brittle shale under complex loading

The brittleness and ductility of shale from Setap shale, Miri, Sarawak

The brittleness and ductility of Setap Shale from Bekenu, Beluru and Long Lama area can be shown by analyzing the relationship between Poisson’s Ratio and Young’s Modulus. Both Young’s Modulus and Poisson’s Ratio can be calculated using P-wave and Swave value from ultrasonic velocity test. Ultrasonic velocity analysis on core samples from Bekenu, Beluru and Long Lama shows typical values of Poisson’s ratio and static Young’s Modulus of shale. The mineral composition of samples was analyzed using X-ray diffraction (XRD). Beluru 3 was described as marl samples shows significant number of quartz and dolomite which increase the density of the rock higher than Bekenu and Long Lama area. In the other hand, the Long Lama-5 sample shows high ductility compares to other location due to high clay constituents. High clay constituents can be defined by clay constituents greater than 40% composition. The shale with more than 40% are “true shale” where it may affect the conductivity of hydraulic fracturing phase due to high ductility. High ductile shale has the ability to re-seal the fracture due to high elastic material content. The brittleness of shale shows strong relationship between the mineralogical composition of the shale at different locality of Setap Shale and its elastic properties as different samples show different mineral composition.

Time-dependent borehole stability in hard-brittle shale

Rock damage appears in brittle shale even prior to peak stress (i.e., before failure) due to the occurrence of microcracks in these rocks. In this work, a coupled hydromechanical model was built by incorporating the mechanical and fluid seepage induced stresses around a wellbore during drilling. The borehole instability mechanism of hard-brittle shale was studied. The results show that even if a well is simply drilled into a hard-brittle shale formation, the formation around the borehole can be subjected to rock damage. The maximum failure ratio of the formation around the borehole increases with drilling time. A lower drilling fluid density corresponds to a faster increase in the failure ratio of the borehole with time and a shorter period of borehole collapse. When the initial drilling fluid density is too low, serious rock damage occurs in the formation around the borehole. Even though a high-density drilling fluid is used after drilling, long-term borehole stability is difficult to maintain. While drilling in hard-brittle shale, drilling fluid with a proper density should be used rather than increasing the density of the drilling fluid only after borehole collapse occurs, which is more favorable for maintaining long-term borehole stability.

An Environmentally Friendly Wbm System Can Prevent Hard Brittle Shale Instability

In the Weizhou Southwest oilfields, drilling delays and suspension of wells prior to reaching the targets due to wellbore instability had occurred frequently. The hard brittle shale played a problematic role. Conventional water-based drilling fluids didn’t conquer the problematic formation due to intrinsically performance deficiencies. While Oil based drilling fluids are routinely preferred in the more technically demanding applications, they are cause for increasing concern due to offshore environmental restrictions and expensive disposal costs. An environmentally acceptable water-based drilling fluid was developed to challenge the problematic formation based on the combination of methylglucoside-silicate concept. It stabilized the reactive shale by the same mechanism as did oil-based drilling fluid in preventing shale hydration, pore pressure increase and weakening of shale by effectively developing sufficient osmotic force to offset hydraulic and chemical forces acting to cause filtration flux into the hard brittle shale. A field trial was initiated on the CNOOC 931 platform in Weizhou oilfield. The data from the pilot well showed that the novel drilling fluid exhibited excellent inhibition and lubricity which approached or even exceeded oil-based fluids.

New insights into hydration-induced creep behavior of shale: A comparison study of brittle black shale and clayey oil shale at micro-scale

During hydraulic fracturing for shale gas development, water softening and creep deformation of shale rock are two common engineering problems that severely impair production performance. In order to understand the mineralogical and microstructural control on this mechanism from microscale, a brittle black shale from Lower Silurian Longmaxi Formation (named as LMX shale) and a clayey oil shale from Paleogene Youganwo Formation (YGW shale), which represent two members of shale family with different mineral constitutes and microstructures, were selected for hydration process under various durations (0.5 h–96 h) and temperatures (25 °C and 50 °C). The accompanied changes of microstructural and mechanical properties during hydration at microscale were investigated via nuclear magnetic resonance (NMR) and nanoindentation, respectively. Based on NMR T2 spectra, peak T2 time and water-infiltrated pore increment for both LMX and YGW shales rise sharply within the first 12 h, whereas remain invariable hereafter. And the values increase at higher temperature. For YGW shale, the maximum peak T2 time is lower but the incremental porosity is higher than LMX shale, respectively. Such difference indicates an occurrence of gradually enlarged and connected pores inside LMX shale after hydration, while a greater number of disconnected pores have been developed in YGW shale, comparatively. For both shales, great strength deterioration and creep enhancement are monitored within the first 12 h of hydration. The modulus reduction could be as high as 26.27% and 80.16% after 96 h soaking at 50 °C for LMX and YGW shales, respectively. Creep strain rate sensitivity increases from 0.026 to 0.234 for LMX shale, and 0.011 to 0.099 for YGW shale with intensified softening degree. The softening mechanism for LMX brittle shale is dominated by secondary pores and cavities generated as a result of dissolution of carbonate cementation and grain detachment after water infiltration, while microstructural integrity of YGW oil shale is degraded by clay swelling. Due to different mineral constitutes and microstructures, creep deformation for clayey YGW shale is mainly mediated by dislocation movement of fine clay grains, whereas diffusion creep plays the key role in coarse-grained LMX shale. This comparative study with two distinct shale samples provides the mineralogy- and microstructure-based framework for interpreting water softening process and creep mechanism of shale, which benefits hydraulic fracture design in different shale formations so as to enhance shale oil/gas production.

Mechanical properties of marine shale and its roof and floor considering reservoir preservation and stimulation

The mechanical differences between reservoir rock and its overlying (roof) and underlying (floor) rocks have significant influence on oil/gas preservation and hydraulic fracture propagation, which is still lack of adequate research in marine shale gas formation. In this work, homogeneous intact specimens of roof siltstone, reservoir shale and floor limestone were prepared from representative outcrops, and the corresponding siltstone-shale-limestone composite samples were also fabricated with strong/weak interface cementation properties. Mechanical parameters, fracture morphology, brittleness, and failure mechanism of marine shale and its roof and floor in tri-axial compressive state were comparatively investigated. Results show that reservoir shale had relatively low compressive strength, Young's modulus, internal frictional angle, and cohesive strength, making it more susceptible to rupture, compared with the roof and floor. The floor limestone had relatively high strength and low brittleness, which were beneficial for maintaining its integrity and the preservation of shale gas during tectonic movement. Considering the high brittleness of roof siltstone, more attention should be given to the integrity of the roof, where fractures induced by tectonic movement could provide as a pathway of gas escape. Interface cementation property played a key role in the fracture propagation behavior at lithologic boundaries. Interfaces with weak cementation tended to arrest extending fractures, which was advantageous to gas preservation or fracture height control in reservoir stimulation. Whereas fracture would probably cross over strong cementation interfaces, leading to the threat of oil/gas leakage or incontrollable hydraulic fracture propagation in vertical direction.