A new method for identifying micro fractures and characterizing fractures of different scales

Oil and gas exploration professionals have begun to focus more on unconventional oil and gas reserves in recent years as a result of their increased efforts. Fractures have a significant impact on the permeability and connectivity of reservoirs as a crucial component of rock mechanics and hydraulics, which directly affects the production of oil and gas. The identification of fracture development zones or micro faults, as well as how to adequately define the fracturing model, have thus become crucial and pressing issues in the forecast of oil and gas reservoirs. In this study, we decompose the three-dimensional seismic data volume in a site in order to obtain the single frequency data volume that can be calculated using the ant tracking technique. We do this by taking advantage of the synchronous extrusion improvement of short time Fourier transform in time-frequency focusing. Coupled with the advanced DFN model, the extracted data are calibrated in various rock attributes to restore the morphology and characteristics of fractures. The findings demonstrate that this method is capable of providing not only a precise outline of micro fractures but also a reflection of the characteristics of fractures at various scales, including structure and associated properties. The precision and applicability of this method are confirmed in this paper, which is significant as a reference for the oil and gas exploration industry

The splicing of backscattered scanning electron microscopy method used on evaluation of microscopic pore characteristics in shale sample and compared with results from other methods

The splicing of backscattered scanning electron microscopy (SB-SEM) method was applied to evaluate the microscopic pore characteristics of the Lower Silurian Longmaxi Shale samples from Py1 well in Southeast Chongqing, China. The results from SB-SEM, including frequencies, volumes and specific surface areas of organic and inorganic pores with different sizes, were compared with those of low temperature nitrogen adsorption/desorption (LTNA) and mercury intrusion porosimetry (MIP). The results show that the changes in organic and inorganic surface porosity with increasing image area estimated from the SB-SEM method become almost stable when the SB-SEM image areas are larger than 0.4 mm, which indicates that the heterogeneities of organic and inorganic pore volumes in shale samples can be largely overcome. This method is suitable for evaluating the microscopic pore characteristics of shale samples. Although the SB-SEM underestimates the frequencies, volumes and specific surface areas of pores smaller than its resolution, it can obtain these characteristics of pores larger than 100 nm in width, which are not effectively evaluated by the LTNA method and are underestimated by the MIP method

Dynamic capillary pressure analysis of tight sandstone based on digital rock model

In recent studies, dynamic capillary pressure has shown significant impacts on the flow behaviors in porous media under transient flow condition. However, the effect of dynamic capillary pressure effect on tight sandstone is still not very clear. Since lattice Boltzmann method (LBM) is a very promising and widely used method in analyzing flow behaviors, therefore, a two-phase D3Q27 LBM model is adopted in this paper to simulate the flow behaviors and analyze the dynamic capillary pressure effect in tight sandstone. Moreover, a new pore segmentation method for tight sandstone base on U-net deep learning model is implemented in this study to improve the pore boundary qualities of pore space, which is crucial for two-phase LBM simulation of tight sandstone. A total of 3800 3D sub-volume data sets extracted from computed tomography data of 19 tight sandstone samples are selected as ground truth data to train the network and segment the pore space afterward. The simulation results based on the segmented digital rock model, show that nonwetting phase fluid prefer the path with lower dynamic capillary pressure in the seepage process before breaking through the porous model. Furthermore, the increase of injection rate causes the saturation changes more quickly, injection rate also shows apparent positive correlation relationship with capillary pressure, which implies that dynamic capillary pressure effect also exists in tight sandstone, and LBM based two-phase flow simulation could be used to quantitatively analyze such effect in tight sandstone.Cited as: Cao, Y., Tang, M., Zhang, Q., Tang, J., Lu, S. Dynamic capillary pressure analysis of tight sandstone based on digital rock model. Capillarity, 2020, 3(2): 28-35, doi: 10.46690/capi.2020.02.0

Palaeoenvironment and Its Control on the Formation of Miocene Marine Source Rocks in the Qiongdongnan Basin, Northern South China Sea

The main factors of the developmental environment of marine source rocks in continental margin basins have their specificality. This realization, in return, has led to the recognition that the developmental environment and pattern of marine source rocks, especially for the source rocks in continental margin basins, are still controversial or poorly understood. Through the analysis of the trace elements and maceral data, the developmental environment of Miocene marine source rocks in the Qiongdongnan Basin is reconstructed, and the developmental patterns of the Miocene marine source rocks are established. This paper attempts to reveal the hydrocarbon potential of the Miocene marine source rocks in different environment and speculate the quality of source rocks in bathyal region of the continental slope without exploratory well. Our results highlight the palaeoenvironment and its control on the formation of Miocene marine source rocks in the Qiongdongnan Basin of the northern South China Sea and speculate the hydrocarbon potential of the source rocks in the bathyal region. This study provides a window for better understanding the main factors influencing the marine source rocks in the continental margin basins, including productivity, preservation conditions, and the input of terrestrial organic matter

Revealing crucial effects of reservoir environment and hydrocarbon fractions on fluid behaviour in kaolinite pores

The adsorption interactions of hydrocarbons and clay surfaces are crucial to understanding fluid behaviour within shale reservoirs and to mediating organic pollutants in soils. These interactions are affected by the diversity of complex hydrocarbon components and the variations in environmental conditions. This study examines the interactions between kaolinite clay, featuring two distinct basal surfaces, and an array of hydrocarbons. We assess the impact of various molecular structures, functional groups, and environmental conditions (focusing on the reservoir temperature and pressure ranges) on the adsorption selectivity, surface packing, molecular alignment and orientation, and diffusion of hydrocarbons. Analyses of molecular interaction energies provide a quantitative elucidation of the adsorption mechanisms of hydrocarbons on the different kaolinite surfaces. Our findings suggest that molecular configuration, functional group properties, and spatial effects dictate the distribution patterns of hydrocarbons for the different kaolinite surfaces. The differences in the interaction energy between various hydrocarbons with kaolinite reveal the adsorption strength of different hydrocarbons in the order of asphaltenes > heteroatomic hydrocarbons > saturated hydrocarbons > aromatic hydrocarbons. Furthermore, we observe that the adsorptive characteristics of hydrocarbons on kaolinite are highly temperature-sensitive, with increased temperatures markedly reducing the adsorption amount. Beyond a certain threshold, the effect of pressure rise on the fluid behaviour of hydrocarbons is non-negligible and is related to molecular packing and reduced mobility. Simulation results based on actual geological characteristics demonstrate notable adsorption disparities among hydrocarbon components on different kaolinite surfaces, influenced by competitive adsorption and clay surface interactions. Polar surfaces are predominantly occupied by heteroatomic hydrocarbons, whereas on non-polar surfaces, asphaltenes and heavy saturated hydrocarbons develop multi-layer adsorption structures, with molecules aligned parallel to the surface

Association between Perivascular Spaces Burden and Future Stroke Risk in Ischemic Stroke and Transient Ischemic Attack: A Systematic Review and Meta-Analysis

Introduction: This meta-analysis aimed to explore the association of perivascular spaces (PVS) burden with the risks of future stroke events and mortality in patients with ischemic stroke and transient ischemic attack (TIA). Methods: We systematically searched PubMed, Embase, and Cochrane database from inception to December 31, 2023. We included eligible studies that reported adjusted estimated effects for future intracranial hemorrhage (ICH), ischemic stroke, and mortality with baseline PVS burden in patients with ischemic stroke and TIA. Data were pooled using an inverse-variance method for the fixed effects (FE) model and a restricted maximum likelihood method for the random effects (RE) model. Results: Thirteen observational studies (5 prospective, 8 retrospective) were included, comprising 20,256 patients. Compared to 0–10 PVS at basal ganglia (BG-PVS), a higher burden (>10) of BG-PVS was significantly associated with an increased risk of future ICH (adjusted hazards ratio [aHR] 2.79, 95% confidence interval [CI]: 1.16–6.73, RE model; aHR 2.14, 95% CI: 1.34–3.41, FE model; I2 = 64%, n = 17,084 from four studies) followed up for at least 1 year. There was no significant association between >10 BG-PVS and ICH within 7 days after reperfusion therapy (adjusted odds ratio [aOR] 1.69, 95% CI: 0.74–3.88, RE model; aOR 1.43, 95% CI: 0.89–2.88, FE model; I2 = 67%, n = 1,176 from four studies). We did not detect a significant association of recurrent ischemic stroke, mortality, or disability with BG-PVS burden. Neither >10 PVS at centrum semiovale (CSO-PVS) nor increasing CSO-PVS burden was significantly associated with the risk of future intracranial hemorrhage or ischemic stroke recurrence. Conclusions: Current evidence suggests that a higher BG-PVS burden may be associated with an increased risk of future ICH in patients with ischemic stroke and TIA

Controlling factors and physical property cutoffs of the tight reservoir in the Liuhe Basin

Tight gas sandstone reservoirs of the Lower Cretaceous Xiahuapidianzi Formation are the main exploration target in the Liuhe Basin in China. Petrology characteristics, reservoir space (pore space), controlling factors and physical property cutoffs of the tight sandstone reservoir in the Liuhe Basin were determined through the integrated analysis of several methods including: casting thin section, field emission scanning electron microscopy (FE-SEM), X-ray diffraction, mercury intrusion porosimetry, nuclear magnetic resonance and nitrogen gas adsorption. The sandstones dominated by lithic arkoses and feldspathic litharenites are characterized by low porosity, low permeability and strong microscopic heterogeneity. The porosity has a range between 0.48% and 4.80%, with an average of 2.26%. Intercrystalline pores, intergranular pores, dissolved pores and microfractures can be observed through the casting thin section and FE-SEM images. Compaction and carbonate cementation are the two primary mechanisms resulting in the low porosity of the Liuhe sandstones. Microfractures improve the permeability of the tight sandstones and provide pathways for fluid migration and the storage of hydrocarbon accumulations. Moreover, the theoretical cutoff of the porosity in the Xiahuapidianzi Formation tight sandstones is 3.3%.Cited as: Tan, Z., Wang, W., Li, W., et al. Controlling factors and physical property cutoffs of the tight reservoir in the Liuhe Basin. Advances in Geo-Energy Research, 2017, 1(3): 190-202, doi: 10.26804/ager.2017.03.0

Permeability evaluation on oil-window shale based on hydraulic flow unit: A new approach

Permeability is one of the most important petrophysical properties of shale reservoirs, controlling the fluid flow from the shale matrix to artificial fracture networks, the production and ultimate recovery of shale oil/gas. Various methods have been used to measure this parameter in shales, but no method effectively estimates the permeability of all well intervals due to the complex and heterogeneous pore throat structure of shale. A hydraulic flow unit (HFU) is a correlatable and mappable zone within a reservoir, which is used to subdivide a reservoir into distinct layers based on hydraulic flow properties. From these units, correlations between permeability and porosity can be established. In this study, HFUs were identified and combined with a back propagation neural network to predict the permeability of shale reservoirs in the Dongying Depression, Bohai Bay Basin, China. Well data from three locations were used and subdivided into modeling and validation datasets. The modeling dataset was applied to identify HFUs in the study reservoirs and to train the back propagation neural network models to predict values of porosity and flow zone indicator. Next, a permeability prediction method was established, and its generalization capability was evaluated using the validation dataset. The results identified five HFUs in the shale reservoirs within the Dongying Depression. The correlation between porosity and permeability in each HFU is generally greater than the correlation between the two same variables in the overall core data. The permeability estimation method established in this study effectively and accurately predicts the permeability of shale reservoirs in both cored and un-cored wells. Predicted permeability curves effectively reveal favorable shale oil/gas seepage layers and thus are useful for the exploration and the development of hydrocarbon resources in the Dongying Depression.Cited as: Zhang, P., Lu, S., Li, J., Zhang, J., Xue, H., Chen, C. Permeability evaluation on oil-window shale based on hydraulic flow unit: A new approach. Advances in Geo-Energy Research, 2018, 2(1): 1-13, doi: 10.26804/ager.2018.01.0

Evolution of Fractal Pore Structure in Sedimentary Rocks

Geological processes alter pore spaces over time, and their analysis can shed light on the dynamic fractal structure and fluid flow of rocks over time. This study presents experimental evidence to illustrate that the pore fractal structure evolves with sedimentation, carbonate cementation, clay growth, and dissolution. It examines, describes and characterizes a suite of core samples from the Gaotaizi oil layer of the second and third members of the Qingshankou Formation, Songliao Basin, China. The effects of mechanical compaction and other diagenesis effects on fractal pore structure on sedimentary rocks are discussed. A schematic diagram is proposed that describes the impacts of these diagenetic processes on fractal pore structure at the microscopic scale in sedimentary rocks. This work links the state of diagenetic alteration and fractal pore structure, which can guide practical applications such as predicting the permeability of sedimentary rocks. Key Points Evolution of fractal dimension with diagenesis was revealed Effects of diagenesis on fractal upper and lower limits were discussed Effect mechanism of fractal pore structure was revealed in sedimentary rocks Plain Language Summary Mechanical compaction or chemical alteration process will change the pore space of the rock, including pore size and grain-pore interface properties. We present the evidence that geological processes alter the “roughness” amplitude of grain-pore interface (fractal pore structure) in sedimentary rock, and discuss the evolutionary mechanism of the “roughness” amplitude of grain-pore interface. This work links the state of diagenetic alteration and fractal properties of rocks, which can guide practical applications such as predicting permeability of sedimentary rocks for any historical period

Total Cerebral Small Vessel Disease Score and Cerebral Bleeding Risk in Patients With Acute Stroke Treated With Intravenous Thrombolysis

OBJECTIVE: The aim of this study was to investigate the association of total cerebral small vessel disease (cSVD) score with the risk of intracerebral hemorrhage (ICH) in patients with acute ischemic stroke who received intravenous thrombolysis (IVT) using recombinant tissue-plasminogen activator (rt-PA). METHODS: We retrospectively reviewed clinical data from two stroke registries of patients with acute ischemic stroke treated with IVT. We assessed the baseline magnetic resonance (MR) visible cSVD markers and total cSVD score (ranging from 0 to 4) between patients with and without ICH after IVT. Logistic regression analysis was used to determine the association of total cSVD score with the risk of ICH after IVT, adjusted for cofounders selected by least absolute shrinkage and selection operator (LASSO). We additionally performed an E-value analysis to fully explain away a specific exposure-outcome association. Receiver operating characteristic (ROC) curve analysis was used to quantify the predictive potential of the total cSVD score for any ICH after IVT. RESULTS: Among 271 eligible patients, 55 (20.3%) patients experienced any ICH, 16 (5.9%) patients experienced a symptomatic ICH (sICH), and 5 (1.85%) patients had remote intracranial parenchymal hemorrhage (rPH). Logistic regression analysis showed that the risk of any ICH increased with increasing cSVD score [per unit increase, adjusted odds ratio (OR) 2.03, 95% CI 1.22–3.41, P = 0.007]. Sensitivity analyses using E-value revealed that it would need moderately robust unobserved confounding to render the exposure-outcome (cSVD-any ICH) association null. ROC analysis showed that compared with the National Institutes of Health Stroke Scale (NIHSS) score alone, a combination of cSVD and NIHSS score had a larger area under the curve for any ICH (0.811, 95% CI 0.756–0.866 vs. 0.784, 95% CI 0.723–0.846, P = 0.0004). CONCLUSION: The total cSVD score is associated with an increased risk of any ICH after IVT and improves prediction for any ICH compared with NIHSS alone