• Energy Research

The Yinggehai Basin is an important Cenozoic gas bearing basin in the South China Sea. With the gradual improvement of gas exploration and over-development in shallow layers, deep overpressured layers have become the main target for natural gas exploration. There are no large-scale faults in the strata above the Meishan Formation in the central depression, and hydraulic fracturing caused by overpressure in mudstone cap rocks is the key factor for the vertical differential distribution of gas. In this paper, based on the leak-off data, pore fluid pressure, and rock mechanics parameters, the Fault Analysis Seal Technology (FAST) method is used to analyze the hydraulic fracture risk of the main mudstones in the central depression. The results show that the blocks in the diapir zone have been subjected to hydraulic fracturing in the Huangliu cap rocks during the whole geological history, and the blocks in the slope zone which is a little distant from the diapirs has a lower overall risk of hydraulic fracture than the diapir zone. In geological history, the cap rocks in slope zone remained closed for a longer time than in diapir zone and being characterized by the hydraulic fracture risk decreases with the distance from the diapirs. These evaluation results are consistent with enrichment of natural gas, which accumulated in both the Yinggehai Formation and Huangliu Formation of the diapir zone, but it only accumulated in the the Huangliu Formations of the slope zone. The most reasonable explanation for the difference of the gas reservoir distribution is that the diapirs promote the development of hydraulic fractures: (1) diapirism transfers deep overpressure to shallow layers; (2) the small fault and fractures induced by diapir activities weakened the cap rock and reduced the critical condition for the natural hydraulic fractures. These effects make the diapir zone more prone to hydraulic fracturing, which are the fundamental reasons for the difference in gas enrichment between the diapir zone and the slope zone.

Understanding geomechanical properties of rocks at multiple scales is critical and relevant in various disciplines including civil, mining, petroleum and geological engineering. Several upscaling frameworks were proposed to model elastic properties of common rock types from micro to macroscale, considering the heterogeneity and anisotropy in the samples. However, direct comparison of the results from different upscaling methods remains limited, which can question their accuracy in laboratory experiments. Extreme heterogeneity of natural rocks that arises from various existing components in them adds complexity to verifying the accuracy of these upscaling methods. Therefore, experimental validation of various upscaling methods is performed by creating simple component materials, which is, in this study, examining the predicted macroscale geomechanical properties of 3D printed rocks. Nanoindentation data were first captured from 3D printed gypsum powder and binder rock fragments followed by, triaxial compression tests on similar cylindrical core plugs to acquire modulus values in micro and macroscale respectively. Mori-Tanaka (MT) scheme, Self-Consistent Scheme (SCS) method and Differential Effective Medium (DEM) theory were used to estimate Young’s modulus in macroscale based on the results of nanoindentation experiments. The comparison demonstrated that M-T and SCS methods would provide us with more comparable results than DEM method. In addition, the potential applications of 3D printed rocks were also discussed regarding rock physics and the geomechanics area in petroleum engineering and geosciences.

An accurate evaluation of the shale oil mobility is crucial to its cost-effective exploitation. This study presents a method to assess shale oil mobility by integrating the pore structure and oil states distributions. First, a set of three discrete organic extracts (EOM-A, B and C) were obtained by sequential extraction. The relationships among the EOMs and the oil states were inferred from the group compositions and fluorescence properties of the produced shale oil (free state). The results showed that EOMs A and B represent free oil in the open and closed pores, respectively, while the EOM-C represents adsorbed oil. Then, NMR T1-T2 map is used to determine the T2-cutoff values that indicate the pore size ranges of different oil states. Free oil resides mainly in larger pore space (T2 > 0.5 ms), while the adsorbed oil in smaller pore space (0.2 ms  0.5 and T2-cutoff > 1.0 ms suggest that the free oil in connected pores has the highest mobility. This work can provide a reference for evaluating the shale oil potential and prospectivity in other regions.

Abstract Various compositional, depositional and maturity related influencing factors affect the complex pore structure of coal. To study the pore structural evolution at nanoscale, a well characterized sample set of vitrinite-rich Carboniferous coals from the Ukrainian Donets Basin, covering a maturity interval from 0.69 to 1.47%Rr, was selected. Conventional bright field transmission electron microscopy (BF TEM) and high-resolution TEM (HRTEM) imaging was used to directly determine pore size distributions, pore morphology, geometry factors and other structural features, while gas invasion techniques such as low-pressure gas adsorption (CO2 and N2) were used for the investigation of micro- and mesopore structural parameters. High-pressure CH4 sorption experiments revealed changes in the methane storage capacity within the investigated maturity range, while associated structural changes of vitrinite were monitored by Raman spectroscopy. The results indicate pore occlusion in vitrinite mainly at peak oil window maturity, the sensibility of micro- and mesopore structure to thermal maturity and the importance of organic sulphur as a catalyst for kinetics of structural modification. Observed structural changes at 1.10%Rr were related to the onset of wet-gas generation. A structural control on micromechanical properties of vitrinite is indicated by the correlation between reduced elastic moduli from a previous study and average nanopore diameters obtained by HRTEM. The applied comprehensive approach improved the understanding of depositional and maturity-related processes that may affect pore evolution and resulting gas storage capacity of coals.

Abstract Breakthrough pressure is a key parameter of the caprock sealing ability for gas reservoirs. It has also become an important parameter for gas production from tight reservoirs, such as shale gas reservoirs, as water in these tight formations may require gas to overcome the breakthrough pressure before being produced. Laboratory measurement is essential to obtain the breakthrough pressure because no field methods can accurately estimate it. In this review article, the definition, the experimental methods, and experimental data for breakthrough pressure on tight rocks are reviewed. The advantages and issues of each experimental method are discussed. Furthermore, the relationships between breakthrough pressure and rock properties, especially its permeability, are investigated. It is found that breakthrough pressure has a close relationship with pore structure and most of the experimental data show that it has a power law relationship with absolute permeability. Moreover, water saturation, gas type, and effective stress are all found to have an impact on the breakthrough pressure. Finally, future research topics are proposed, including investigating sample length on breakthrough pressure measurement and developing more theoretically based models for breakthrough pressure with regards to absolute permeability or other measurable rock properties.

Abstract CO2 foam fracturing fluid has the advantages of water saving and environmental protection, which has been widely used in unconventional oil and gas reservoir. However, there are still many technical difficulties in fracture propagation model and numerical calculation method of CO2 foam fracturing. In this paper, a CO2 foam fracturing fracture propagation model with temperature-pressure-phase coupling is established. Physical parameters of CO2 are calculated by Span-Wagner method, and the finite difference and displacement discontinuity methods are used to solve the model. Moreover, we compare the results of this model with the field measured data, KGD model and EFRAC-3D model to verify the model. The computation results show that in the process of fracturing, improving the CO2 foam quality can significantly enhance the fracturing effect. When the quality increased from 0.5 to 0.8, the fracture width raised by more than 2 times. In addition, the fracture propagation is significantly affected by injection temperature. With the increase of injection temperature, fracture width decreases continuously, and if the CO2 foam is supercritical phase state, it is not conducive to increase the fracture width.

Abstract Scanning electron microscopy (SEM) is one of the most prevalent methods used to image and quantify the pore size distribution of shale rock, critical in understanding unconventional petroleum systems and production. Generally, digital greyscale SEM images of shale are currently processed for pore quantification either by a manual drawing method, manual threshold method, automatic threshold method, edge detection or watershed methods, all of which have some limitations that impact the quality of pore extraction results. A new, Edge-Threshold Automatic Processing (ETAP) method is reported here to enable robust extraction and quantification of pore data in shale images. Image pre-treatment makes the greyscale of regions brighter than that of kerogen set to the peak value of kerogen greyscale. The pore image is subsequently obtained using an edge detection method. A discriminant function has been designed to determine the best threshold of the greyscale image to obtain the pore image. Finally, combination of both processed pore images gives the final pore image. Our new method overcomes the impact of kerogen, mineral, roughness and artificial debris caused by pre-treatment of samples, which potentially introduce errors using alternative methods. We compare our new method to a systematic manual drawing method. The processing results through ETAP provide reliable results, and gets the highest value of 0.7466 using a discriminant function Qt, compared with the automatic threshold methods, the edge detection method and watershed method. The application of the ETAP method on shale samples of the Longmaxi Formation and Qiongzhusi Formatiosn in Sichuan basin shows that samples from the Longmaxi Formation have more organic pores than that of the Qiongzhusi Formation, however a larger size of inorganic pores develop in the Qiongzhusi shale. This indicates that shale of the Longmaxi Formation has better reservoir properties and reliable preservation conditions.

3D printing technology offers an innovative approach to manufacture rock samples with controlled properties. However, in this process, pore structure is one of the major concerns when printing similar specimens to natural rocks. The purpose of this study was to lay out an optimal post-processing of 3D-printed samples that can facilitate replicating natural rocks with similar microstructure characteristics. In this study, four cylindrical rocks were manufactured without designed porosity by 3D printing using gypsum powder as the main component. Various types of infiltrants (Colorbond® and Surehold®) and coating conditions (SmoothOn® and WBAE®) were used after completing the printing process of binder jetting. Mercury injection porosimetry was then used to investigate their petrophysical properties including porosity and pore throat size distribution. Multifractal theory was applied to understand the heterogeneity of pore throat distribution within the 3D-printed samples on different pore size intervals. The results showed that 3D-printed rocks have a clustered and negative skewness of pore throat size distributions. The majority of pore sizes are micropores, while a small portion can be categorized under nanopore size category. Multifractal analysis results found a homogeneous distribution of micropores but a heterogeneous distribution of nanopores. Comparing four different samples, it was found that infiltrants could mainly affect the heterogeneous distribution of nanopores more than the micropores, whereas coating does not impact pore structure significantly. In comparison with pore multifractal characteristics of common types of natural rocks, 3D-printed rocks exhibited a higher heterogeneity of pore size distribution.