<p>The Asmari reservoirs in Iran are renowned globally as classic fractured carbonate reservoirs. These reservoirs predominantly contain oil within Oligo-Miocene carbonate successions located in the giant anticlines of the southern central Zagros (Dezful Embayment) and their lithostratigraphic equivalents in Iraq, Syria, and the UAE. Although extensive fracturing significantly impacts production in these reservoirs, little attention has been paid to the rock matrix’s reservoir characteristics, as well as the microfacies and diagenetic influences on reservoir quality. The present study deals with the controlling role of depositional environment and diagenetic processes regarding the reservoir quality; this is done within sequence stratigraphic framework. The Asmari Formation was studied in two cored wells in the Pazanan oil Field. The formation in this field is highly fractured and exceptionally contains gas condensate. Petrographic studies indicate that this formation is dominated by foraminiferal and coralgal facies which have been significantly influenced by diagenetic processes such as dolomitization, cementation, compaction, and to a lesser degree dissolution. Eight sedimentary microfacies are distinguished in this formation, which are interpreted to have been deposited on a carbonate ramp containing coral patch reefs. Based on index fossils and strontium isotope dating (⁸⁷Sr/⁸⁶Sr ratios), this formation is dated as Chattian to Burdigalian (26.1 to 18.3 Ma). According to the deepening and shallowing trend in facies, facies stacking pattern, fossil assemblages, diagenetic modifications, five 3rd order depositional sequences have been identified. These sequences include two Oligocene sequences (early and late Chattian in age) whereas three Miocene depositional sequences are early Aquitanian, late Aquitanian and early Burdigalian in age. Porosity and permeability data from core samples show that the matrix porosity of the formation ranges from nil to approximately 30% with an average of 10%, while permeability varies from very low to about 100 md with an average of about 20 md. The better reservoir properties occur in coarse-grained, red-algae dominated, mid ramp facies with a progradational development. These facies with an average porosity exceeding 10% and an average permeability exceeding 20 md have a relatively better reservoir quality compared than the other facies. They were developed in the early Chattian and occur at the basal units of the formation in the area under study. Moreover, dolo-wackestone/mudstone with anhydrite nodule with an average porosity of 14% and an average permeability of 40 md constitute the most significant reservoir facies, highlighting the dolomitization effects on reservoir quality. The findings indicate that facies variations and diagenesis exert some control over the reservoir quality of the Asmari Formation and that the better-quality reservoir facies primarily extend within the Oligocene depositional sequences.</p>