The 8# coal seam in the Benxi Formation of the southeastern margin of the Ordos Basin is a deep coal seam with abundant coalbed methane resources. Calcite veins are commonly developed within the 8# coal seam, and their formation processes and mechanisms have significant implications for the enrichment of deep coalbed methane. Genesis of the calcite veins was analyzed to reveal the impact of the calcite veins formation on coalbed methane accumulation, with an integrated application of petrographic study by thin section, cathodoluminescence analysis, carbon-oxygen isotope analysis, and homogeneous temperature measurements of fluid inclusions. The research findings indicate that the calcite veins in the 8# coal seam can be classified into three stages: C1, C2, and C3. The diagenetic fluids of C1 primarily originated from contemporaneous seawater. The fluids responsible for the formation of C2 primarily consist of organic fluids enriched in biogenic gas, whereas the fluids contributing to the formation of C3 are primarily associated with liquid hydrocarbons originated form decarboxylation of organic matter. Furthermore, the development of both C2 and C3 is influenced by deep hydrothermal fluids resulting from tectonic heating events during the Early Cretaceous. By combining analysis of the hydrocarbon accumulation history and burial history in the study area, it has been established that C2 formation occurred during the Late Triassic to Early Jurassic, while C3 formation took place during the Late Jurassic to Early Cretaceous. The exploration and production practices in the study area have firmly established the crucial significance of the formation and evolution of calcite veins within the 8# coal seam for the migration and accumulation of coalbed methane. The research outcomes provide valuable insights for the exploration of deep coalbed methane enrichment areas.

As the hydrocarbon vertical migration pathway, fault and its relationship with reservoir extremely affect the distribution and accumulation of oil and gas in the non-hydrocarbon generating layers. On both sides of the fault, there are frequently various sand bodies with different oil and gas enrichment. However, previous researches on this differential charging are mostly based on empirical formulas or physical simulation experiments instead of fluid seepage mechanism. This paper proposed a quantitative evaluation method on the basis of Darcy's law to analyze the difference in hydrocarbon lateral diversion capacity through the oil-source fault. It can be seen that in the process of hydrocarbon migrate along the oil-source fault, hydrocarbons could divert laterally into sand bodies through the fault when there is a downward pressure gradient. Conversely, hydrocarbons can only migrate upward along the fault. Furthermore, among the four normal fault-sand body configuration types, the opposite fastigium type is most favorable for hydrocarbons laterally charging whereas the fastigium type is the least beneficial. The ratio of resistance in the sand body to in the fault was proposed as the evaluation index ( F_s) to quantitatively evaluate the hydrocarbon lateral diversion migration capacity, on the assumption that hydrocarbons in different sand bodies are sourced from the same source rocks. The index ( F_s) is directly proportional to the lateral diversion capacity of hydrocarbon, and is complex controlled by many geological factors including the reservoir permeability, fault-sand body contact length and dip angles of sand body and fault. And the higher the value of Fs, the stronger the hydrocarbons laterally divert ability of the sand body. In addition, the calculation result of well GG16102 in the Beidagang buried hill coincide well with the oil and gas interpretation result indicating that the method is practical to quantitatively evaluate the laterally diverting hydrocarbons of sand bodies under the condition of fault-sandstone configuration.