Oil source and hydrocarbon migration are critical in the study of hydrocarbon accumulation. Under the complicated conditions of hydrocarbon accumulation, traditional organic geochemistry has its limitation. Therefore, the purpose of this study is to try a new way to investigate hydrocarbon accumulation and migration. The occurrence of trace elements in crude oil and their activation and migration were studied. The fingerprint of trace elements was discussed. Our results indicate that rare earth elements and transition metals could be used for study of oil-source under the complicated conditions of hydrocarbon accumulation and migration. V/Ni ratio was a specific indicator in tracing hydrocarbon migration pathway. Tarim Basin, a typical complex superimposed basin in west China was studied. The result indicated that crude oil from the Ordovician in Tazhong (central Tarim) low uplift was characterized by mixed sources. The contributions of individual sources differed from formation to formation and from block to block. The distribution of underground fluid was significantly controlled by large-scale strike-slip faults. Our study result is consistent with the knowledge of field geologists. Application of trace elements as indicators is an effective method to study hydrocarbon accumulation and migration.

Tracing hydrocarbons migration pathway is of great significance in studying hydrocarbon accumulation process and predicting hydrocarbon bearing potential of exploration targets, but it is very difficult to trace the hydrocarbons migration pathway in ancient carbonate formations due to strong heterogeneity. In this paper, a combination of geological and geochemical methods is used to discuss the hydrocarbons migration pathway in Ordovician carbonate rock of the Lunnan-Tahe Oilfield in the Tarim Basin. Deep faults and karst unconformity constitute the hydrocarbons passage framework in this area. High angle fractures caused by tectonic stress, pores and cavities formed by karstification played an important role in the connectivity and continuity of this network system. Core observation and thin-section identification revealed that the karsted holes communicating with fractures in the geologic history were the effective pathway for hydrocarbons migration in carbonate formation. The marks of hydrocarbon migration were left in these kinds of fractures and cavities, which were the direct evidence of hydrocarbon migration. The regularities of geochemical parameters of crude oil and hydrocarbon inclusion could effectively indicate the direction of hydrocarbon migration. It could be seen from the section analysis results in this paper that the features of vertical migration in a single well are apparent due to fracture communication; while in the lateral direction, the network system in which fractures and cavities are interconnected constitutes the main lateral pathway for hydrocarbons migration. Analysis results of such wells as Lunnan 63, Jiefang 127, Lunnan 39 and Lunnan 44 indicate that hydrocarbons migration direction was from bottom to top in the vertical direction and from south to north and from east to west in the lateral direction.

Transitional upper carboniferous Shanxi Formation coal-bearing strata in Qinshui Basin have been proven to be a set of mixed unconventional gas-bearing reservoirs forming a multi-superimposed gas system that consists of multiple independent fluid pressure systems vertically through the strata. An experimental protocol was designed to compare the pore networks in high-rank coal, shale, and tight sandstone reservoirs from Shanxi Formation using quantitative and qualitative experimental methods, including high-pressure mercury injection porosimetry (MIP), low-pressure nitrogen gas adsorption (LN₂GA), and argon ion polishing–field emission scanning electron microscope (AIP-FESEM). The results show that genetic and structural differences in pore types, morphology, abundance, and proportion in coal, shale, and tight sandstone reservoirs are significant, reflecting strong heterogeneity characteristics. Pore networks determine the roles of different types of reservoirs in gas-bearing systems through differentiated pore structure, development degree, and spatial distribution. Due to the differences in nanopore development and connectivity, coal and tight sandstone reservoirs provide important reservoir spaces for adsorbed and free gas in the system. Thus, they become influential factors controlling the relationship between the gas-bearing subsystems with different fluid pressures. The lack of mesopores in shale and relatively weaker heterogeneity between layers lead to the phenomenon that continuously developed shales of a specific thickness are more likely to be the interlayers that divide the superimposed gas-bearing system. Systematic comparison of pore development characteristics will provide scientific support to further explain the formation mechanism of multi-superimposed gas systems in coal-bearing strata from the perspective of pore networks and provide guidance for the development of unconventional natural gas in coal-bearing strata.

Shale gas accumulates in reservoirs that have favorable characteristics and associated organic geochemistry. The Wufeng-Longmaxi formation of Well Yucan-6 in Southeast Chongqing, SW China was used as a representative example to analyze the organic geochemical and reservoir characteristics of various shale intervals. Total organic carbon (TOC), vitrinite reflectance (Ro), rock pyrolysis, scanning electron microscopy (SEM), and nitrogen adsorption analyses were conducted, and a vertical coupling variation law was established. Results showed the following: the Wufeng-Longmaxi formation shale contains kerogen types I and II₂; the average TOC value at the bottom of the formation is 3.04% (and the average value overall is 0.78%); the average Ro value is 1.94%; the organic matter is in a post mature thermal evolutionary stage; the shale minerals are mainly quartz and clay; and the pores are mainly intergranular, intragranular dissolved pores, organic matter pores and micro fractures. In addition, the average specific surface area (BET) of the shale is 5.171 m²/g; micropores account for 4.46% of the total volume; the specific surface area reaches 14.6%; and mesopores and macropores are the main pore spaces. There is a positive correlation between TOC and the quartz content of Wufeng-Longmaxi shale, and porosity is positively correlated with the clay mineral content. It is known that organic pores and the specific area develop more favorably when the clay mineral content is higher because the adsorption capacity is enhanced. In addition, as shale with a high clay mineral content and high TOC content promotes the formation of a large number of nanopores, it has a strong adsorption capacity. Therefore, the most favorable interval for shale gas exploration and development in this well is the shale that has a high TOC content, high clay mineral content, and a suitable quartz content. The findings of this study can help to better identify shale reservoirs and predict the sweet point in shale gas exploration and development.

Natural fractures in shale are important for the preservation and exploitation of shale gas. The classification of fracture types and characterization of system parameters would help to better evaluate reservoir properties. An evaluation of the relationship between natural fractures and hydraulic fractures may help to predict the effects of fracturing on reservoir properties and assist fracturing design. This study focuses on fractures in Lower Cambrian marine shale in southeast Chongqing, China. The fracture system is characterized in detail through observations and descriptions of several outcrops, cores, and thin sections. Hydraulic fracturing experiments were conducted using a large-size triaxial simulator, enabling us to discuss the effects of natural fractures on the creation of hydraulic fractures in a reservoir. The shale contains three primary fracture types: structural fractures, digenetic fractures, and abnormal pressure fractures. High-angle shear fractures (75°–90° from bedding) are the dominant type of seepage fractures observed in the study area. Three sets of tectonic fractures were formed during three tectonic movements. East–west fractures formed mainly in the Yanshanian. Hydraulic fracturing experiments indicated that the Lower Cambrian shale had a good level of reconstruction. The interference between natural fractures and hydraulic fractures has resulted in the segmentation. This study maybe have some reference for fracturing parameter design.