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The Chang 9 oil layer deposits within Ansai District, Ordos Basin, yield considerable reserves of crude oil, yet their source remains ambiguous. This research endeavor was designed to characterize the Chang 9 crude oil and the Chang 7 and Chang 9 source rocks (SRs) of the Yan‐Chang Formation via organic geochemical analysis. The results indicate that the Chang 9 crude oil exhibits a Pr/Ph ratio of 0.84–2.29 and Ga/C30H less than 0.1, implying formed in a weak reduction to weak oxidation freshwater environment. The regular sterane C27‐C28‐C29 configuration assumes an inversed "L" type, reflecting mixed sources and dominant terrestrial plant input. Ratios such as C2920S/(20S + 20R) (0.54–0.6) and C29ββ/(ββ + αα) (0.44–0.58) indicate a mature oil stage. The depositional environment of the C7 and C9 SRs is similar, with weak oxidation to reduction conditions, and consists mainly of Type I and II organics, with a relatively higher maturity of the C9 SRs. A difference in C19/C23TT and C30D/C30H was found between the C7 and C9 SRs. The results show that the C9 crude oils have a similar C19/C23TT with the C9 SRs and similar diahopanes distribution with Class II SRs (C7 and part of the C9 SRs). Thus, the C9 crude oils most likely originate from the C9 SR mixed with the C7 SRs. [ABSTRACT FROM AUTHOR]

Diagenetic facies play a significant role in the evaluation and prediction of reservoirs as they comprehensively reflect the spatial distribution characteristics of deposition, diagenesis, and petrophysical properties. Based on the petrographic observation and considering pores, lithology, and diagenesis types, the diagenetic facies types were identified, and the pore evolution process and its influence on the quality of low permeability tight gas reservoirs were analyzed. The results show that six types of diagenetic facies were identified, including siliceous cementation intergranular pore facies (A), carbonate dissolution pore facies (B), matrix dissolution pore facies (C), clastic dissolution pore facies (D), matrix filling and strong compaction tight facies (E), and carbonate cementation and metasomatism tight facies (F). The evolution process of porosity shows that the restored original porosity is indicated to be between 34.2% and 36.0%. The average porosity loss caused by compaction was 17.1%, while the average porosity loss caused by cementation is 14.1%. The average porosity increased by 2.5% on diagenetic facies B, C, and D due to dissolution. Consequently, diagenetic facies A with weak compaction and diagenetic facies B, C, and D with strong dissolution are effective reservoirs with porosity greater than 6.6% and permeability greater than 0.25 − 0.6 × 10 − 3 μm2. The distribution areas of A, B, C, and D are favorable areas for tight gas exploration and are important indicators for the prediction of tight gas in the Upper Paleozoic Shanxi Formation in the eastern Ordos Basin. This study provides a new petrographic method for reservoir prediction and exploration of natural gas, which has practical value and economic significance. [ABSTRACT FROM AUTHOR]