• Energy Research
• 2021-2025close

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.

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 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.

Large volumes of heavy oil were distributed in the pre-Jurassic strata of Tainan sag, Turpan Hami Basin, China. The geochemical characteristics and origins of heavy oil are of great significance to future exploration in the region. This study classified crude oil using data on its physical properties, group composition, and biomarker compounds. Further, the distribution of different types of crude oil in lateral and vertical directions are clarified. Mechanism of densification of crude oil in the study area was aslo summarized. Results indicate that there are four categories of crude oil with different densities in the Tainan Sag, which are distributed across the areas of (from west to east) Tuyuke, Lukeqin, and Yingyeer: light oil (0.98 g/cm3). Notable differences were observed in the composition of these distinct crude oil types. As the densification degree of crude oil increases, the content of saturated hydrocarbon and aromatic hydrocarbon decreases gradually, and the content of asphaltene increases gradually. The light oil in the Tuyuke area of the Tainan Sag has undergone severe water washing and slight-to-moderate biodegradation. The extra-heavy oil in the Lukeqin area has undergone severe water washing but moderate-to-severe biodegradation. The ultra-heavy oil in the Yingyeer area has not undergone notable water washing but has been subjected to severe biodegradation. Biodegradation damages saturated hydrocarbons and aromatic hydrocarbons in crude oil to varying degrees, increasing the relative content of non-hydrocarbon constituents and asphaltenes and causing the oil to thicken gradually. This occurrence is highly common in areas of severe strata erosion. Water washing, usually occurring in the interlayers where oil and water are in contact with each other over a large area, causes densification of the oil by destroying the low-carbon aromatics in it. This study determined the geochemical characteristics, as well as the reservoir geology of crude oil under various causes of densification and, can serve as a scientific reference for research on the mechanisms of densification of crude oil in other locations.

The combustion of fossil fuels from the input of oil refineries, power plants, and the venting or flaring of produced gases in oil fields leads to greenhouse gas emissions. Economic usage of greenhouse and flue gases in conventional and unconventional reservoirs would not only enhance the oil and gas recovery but also offers CO2 sequestration. In this regard, the accurate estimation of the interfacial tension (IFT) between the injected gases and the crude oils is crucial for the successful execution of injection scenarios in enhanced oil recovery (EOR) operations. In this paper, the IFT between a CO2/N2 mixture and n-alkanes at different pressures and temperatures is investigated by utilizing machine learning (ML) methods. To this end, a data set containing 268 IFT data was gathered from the literature. Pressure, temperature, the carbon number of n-alkanes, and the mole fraction of N2 were selected as the input parameters. Then, six well-known ML methods (radial basis function (RBF), the adaptive neuro-fuzzy inference system (ANFIS), the least square support vector machine (LSSVM), random forest (RF), multilayer perceptron (MLP), and extremely randomized tree (extra-tree)) were used along with four optimization methods (colliding bodies optimization (CBO), particle swarm optimization (PSO), the Levenberg–Marquardt (LM) algorithm, and coupled simulated annealing (CSA)) to model the IFT of the CO2/N2 mixture and n-alkanes. The RBF model predicted all the IFT values with exceptional precision with an average absolute relative error of 0.77%, and also outperformed all other models in this paper and available in the literature. Furthermore, it was found that the pressure and the carbon number of n-alkanes would show the highest influence on the IFT of the CO2/N2 and n-alkanes, based on sensitivity analysis. Finally, the utilized IFT database and the area of the RBF model applicability were investigated via the leverage method.

The interaction between various components of shale and CO2 is interesting since it alters pore structures that are the governing factor in different projects. In this study, samples from the Upper...

Understanding the carbon dioxide (CO2) solubility in formation brines is of great importance to several industrial applications, including CO2 sequestration and some CO2 capture technologies, as well as CO2-based enhanced hydrocarbon recovery methods. Despite years of study, there are few literature data on CO2 solubility for the low salinity range. Thus, in this study, the solubility of CO2 in distilled water and aqueous ionic solutions of NaCl, MgCl2, CaCl2 and MgCl2 + CaCl2 were obtained in a low salinity range (0–15,000 ppm) at temperatures from 298–373 K and pressures up to 20 MPa using an accurate and unconventional method called potentiometric titration. An experimental data set of 553 data points was collected using this method. The results of the experiments demonstrate that increasing pressure increases the solubility of CO2 in various brines, whereas increasing temperature and salinity reduces the solubility. The role of different ions in changing the solubility is elaborated through a detailed discussion on the salting-out effect of different ionic solutions. To verify the experimental results of this research, the solubility points obtained by the potentiometric titration method were compared to some of the well-established experimental and analytical data from the literature and a very good agreement with those was obtained.