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

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

Organoporosity Evaluation of Shale: A Case Study of the Lower Silurian Longmaxi Shale in Southeast Chongqing, China

The organopores play an important role in determining total volume of hydrocarbons in shale gas reservoir. The Lower Silurian Longmaxi Shale in southeast Chongqing was selected as a case to confirm the contribution of organopores (microscale and nanoscale pores within organic matters in shale) formed by hydrocarbon generation to total volume of hydrocarbons in shale gas reservoir. Using the material balance principle combined with chemical kinetics methods, an evaluation model of organoporosity for shale gas reservoirs was established. The results indicate that there are four important model parameters to consider when evaluating organoporosity in shale: the original organic carbon (w(TOC0)), the original hydrogen index (IH0), the transformation ratio of generated hydrocarbon (F(Ro)), and the organopore correction coefficient (C). The organoporosity of the Lower Silurian Longmaxi Shale in the Py1 well is from 0.20 to 2.76%, and the average value is 1.25%. The organoporosity variation trends and the residual organic carbon of Longmaxi Shale are consistent in section. The residual organic carbon is indicative of the relative levels of organoporosity, while the samples are in the same shale reservoirs with similar buried depths

Facies and the Architecture of Estuarine Tidal Bar in the Lower Cretaceous Mcmurray Formation, Central Athabasca Oil Sands, Alberta, Canada

In this study, data obtained from the Lower Cretaceous McMurray Formation in the central Athabasca Oil Sands, northeastern Alberta, Canada, are examined and used to establish the architecture of stacked fluvial and estuarine tidal bar deposits. A total of 13 distinguishable facies (F1−F7, F8a−F8b, and F9−F13) corresponding to stacked fluvial and estuarine deposits are recognized. These facies are then reassembled into four facies associations: fluvial deposits, tidal flat, tidal bar complex, and tidal bar cap. Of these, the lower fluvial deposits show a highly eroded channel lag and tidal influences in the cross-stratified sand and wavy interbeds. The fluvial deposits pass upwards into upper tidal-dominated tidal flats and a massive homogeneous tidal sand bar complex. Very thick tidal-influenced facies (F8a−F8b, up to 22 m) caused by semi-diurnal and semi-lunar cycles are also observed in tidal flats. Based on studies of the facies and facies associations, a three-dimensional (3-D) architecture model is finally established and used to analyze the internal distribution of the stacked fluvial and estuarine deposits. This is the first time that a 3-D model of the paleo-estuary tidal bar has been constructed. The results of this study will assist future research analyzing the architecture of stacked fluvial and estuarine deposits

Combining nuclear magnetic resonance and rate-controlled porosimetry to probe the pore-throat structure of tight sandstones

Rate-controlled porosimetry (RCP), nuclear magnetic resonance (NMR) and micro CT tests were conducted on five tight sandstone samples, the results were compared to reveal the limitations of RCP in determining the pore size distribution (PSD) and pore to throat ratio (PTR), and then an effective method to test the pore-throat structure of tight sandstone by combining NMR and RCP was proposed. The quasi-PSD derived by RCP was bimodal, the left peak of which corresponding to throats was in good agreement with that of NMR, while the right peak corresponding to pore bodies had similar volume content and different distribution range with that of NMR. RCP reflected an equivalent spherical radius of pore body, and the calculation was significantly larger than the maximum inscribed radius (MIR) of the actual pore body with the same volume; whereas in NMR, the ratio of pore volume to surface area was used to estimate pore radius, and the pore radius calculated was close to MIR. The full-range pore body size distribution was determined by subtracting the RCP-derived throat size distribution from NMR-derived PSD, and then the pore throat connectivity was evaluated comprehensively. The mean value of PTR calculated by RCP was larger than 100.0 due to the differences in the calculation method between pore body size and throat size in RCP, while the mean value of PTR calculated by combining NMR and RCP ranged from 7.5 to 64.0. It is concluded that the combination of RCP and NMR experiment is an effective way to comprehensively reveal the size distribution of pore body and throat in tight sandstone. Key words: tight sandstone, pore throat structure, pore to throat ratio, pore size distribution, rate-controlled porosimetry, nuclear magnetic resonanc