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The Asmari Formation with Oligo-Miocene in age and a carbonate-siliciclastic lithology is considered as one of the main hydrocarbon reservoirs in the Zagros Basin of Iran. In this research, with the target of unraveling the reservoir heterogeneity, a comprehensive rock typing was performed using all available geological and petrophysical data. The procedure for reservoir rock typing was started with the identifying of sedimentary rock types derived from the description of cored intervals and the study of thin sections from 7 cored wells. These studies led to the identifying and classification of 12 sedimentary facies related to the inner, middle, and outer parts of a carbonate ramp platform. The statistical clustering algorithms were applied using Multi-Resolution Graph-based Clustering approach on well log data, resulting in the recognition of five electrofacies (EFs). Accordingly, five hydraulic flow units (HFUs), based on the flow zone indicator method were defined in the reservoir interval. A compatible relationship between EFs and HFUs demonstrates that changes in petrophysical attributes are mainly controlled by diagenetic features. By examining special core analysis data, appropriate capillary pressure curves were correlated with the identified reservoir rock types. The methodology used in this study shows the reservoir heterogeneity in addition to primary depositional texture is controlled by the effect of diagenetic processes such as compaction, cementation, dissolution, dolomitization, and fracturing. Dolomitization, dissolution, and fracturing are the main diagenetic processes, showing significant effect on increasing and improving the reservoir quality. According to the results, among different reservoir zones of the Asmari, zones 1, 2, 3, and 4 are considered as the most favorable zones from the reservoir quality and production point of view in the studied field.

The Fahliyan Formation, a significant carbonate reservoir in southwestern Iran encompassing the Izeh and Dezful Zones, underwent detailed petrographic investigations. These analyses revealed eight distinct microfacies associated with four different depositional settings within a homoclinal ramp model. From a diagenesis perspective, the formation has undergone various processes, including micritization, dissolution, compaction, cementation, dolomitization, stylolitization, and fracturing. These diagenetic features affected the Fahliyan Formation from early marine–meteoric to late burial diagenetic realms. Notably, dissolution developed as the most effective and widespread diagenetic feature, improving reservoir quality. Likewise, fracture and dolomitization positively impact reservoir quality, while compaction and cementation have destructive effects. Micritization and early isopachous calcite cement have a retentive role in reservoir characteristics. In addition, the Flow Zone Indicator (FZI) approach introduced three Hydraulic Flow Units (HFUs). The correlation between microfacies types and their petrophysical features indicates that the bioclastic peloid packstones and grainstones have better reservoir quality, which resulted from dissolution, and initial isopachous calcite cements. Also, Planktonic foraminifer’s bioclastic mud/ wackestone and Quartz-bearing mudstone, equivalent to HFU1, indicate lower reservoir quality due to the compaction (stylolitization) and cementation.

Tirgan formation of the Kopet-Dagh Basin (northeast Iran) represents one of the Urgonian carbonate platforms that were deposited during the Early Cretaceous time in the northern Alpine Tethys and deformed during the Alpine orogeny. In this study, six stratigraphic sections of the shallow-water platform sediments (Tirgan formation) were measured based on microfacies and fauna abundance. Detail study of petrography, fossil content, and sedimentary structures led to the identification of fifteen microfacies belonging to four facies belts including open marine, shoal, protected lagoon, and tidal flat. The sediments of the Tirgan formation exhibit calcareous green algae, abundant ooids, oysters, bryozoans, and crinoids in inner and middle platform ramp facies and planktonic bivalves and sponge spicules in outer-platform facies. Furthermore, the absence of basinal deposits and lack of evaporate evidence point to deposition under warm-temperate and humid climate conditions. Sequence stratigraphy analysis of Tirgan formation led to distinguish a single depositional sequence in all of the sections which are composed of transgressive and highstand systems tracts with sequence boundaries of type II (SB2). The lowermost lower Aptian Tirgan sequence in the study area relatively shows a similar trend in comparison with the global curve. This basin was deepened over time so that shaly and marly sediments of Sarcheshmeh formation were placed over Tirgan conformably and may suggest a drowning event that was likely related to unusual global warming. Last, this study contributes to the better understanding of the high distribution of facies assemblages in the Urgonian carbonate platforms.

Lower Cretaceous Shurijeh–Shatlyk Formations host some of the main reservoirs in the Kopeh Dagh-Amu Darya Basin. Exploration in this area so far has focused on the development of structural traps, but recognition of stratigraphic traps in this area is of increasing importance. Integration of 3D seismic data with borehole data from thirteen wells and five outcrop sections was used to identify potential reservoir intervals and survey the hydrocarbon trap types in the East Kopeh Dagh Foldbelt (NE Iran). Analyses of horizontal slices indicated that the lower Shurijeh was deposited in a braided fluvial system. Generally, three types of channel were identified in the lower Shurijeh Formation: type 1, which is low-sinuosity channels interpreted to be filled with non-reservoir fine-grained facies; type 2, which is a moderately sinuous sand-filled channel with good prospectively; and type 3, which is narrow, high sinuosity channel filled with fine-grained sediments. Results indicate that upper Shurijeh–Shatlyk Formations were deposited in fluvial to delta and shallow marine environments. The identified delta forms the second reservoir zone in the Khangiran Field. Study of the stratigraphic aspects of the Shurijeh succession indicates that both lower and upper Shurijeh reservoirs are stratigraphic reservoir traps that improved during folding.

To progress in the knowledge of Upper Triassic evolution of the central Tethys realm, an integrated approach which includes new sedimentological and sequence stratigraphy has described in central Iran. The Nayband Formation of Late Triassic age in central Iran is composed of various rocks of siliciclastic and mixed carbonate–siliciclastic deposits and represents an example of storm-dominated shelf deposition. Based on texture and sedimentary structures of the siliciclastic deposits, 11 lithofacies were identified and classified into three categories, i.e., conglomerate (Gms, Gcm), sandstone (Sp, Se, Sm, Sr, Hcs, Scs, Sh) and mud rock (Fm, F). These mainly consist of alternations of sandstone and shale, and constitute the lower and upper units of the studied section. The mixed carbonate–siliciclastic sediments crop out in the middle unit of the section. Based on field observations and petrographic studies, 12 microfacies were recognized which can be grouped into three depositional environments: shoreface (lower, upper), offshore-transition (proximal, distal) and offshore (upper, lower) on a storm-dominated shelf. Seven 3rd-order depositional sequences have been identified in this section based on field observations, facies analysis and sequence stratigraphy studies. The lower and upper boundaries of this succession are type 1 sequence boundaries (SB1); whereas, other boundaries are type 2 sequence boundaries (SB2). Depositional sequences are composed only of TST, MFS and HST, whereby the transgressive sequences (TST) mainly consist of deeper facies, and regressive sequences (HST) consist of shallower facies. Shelf transport was driven by the available accommodation space on the shelf and therefore was a function of eustatic sea-level fluctuations, but local tectonic activity has also controlled the thickness of the deposits.

Bangestan reservoir includes Sarvak and Ilam formations in the Mansouri oilfield consists mainly of carbonate rocks. In this research, we tried to overcome the problems in reservoir studies using well-logs data which are available in almost all wells in the oilfield. For this purpose, well-logs data from wells A and C were used as input data for the construction of electro-facies modeling. In the following, a model with 5 electro-facies was created and then this model was calibrated by microfacies in well A and core data such as porosity and permeability in the both wells in related to Sarvak Formation (wells A and C). The results of calibration reveal a good correlation between core data and electro-facies, so this model was propagated to un-cored wells in oilfield. The results of the study showed that reservoir quality from electro-facies 1 to 5 increases, respectively and pay zones of 2 in Ilam, 4 and 6 in Sarvak formations have the best reservoir quality. In order to future study, the velocity deviation log (VDL) that is mainly dependent on the type of dominant porosity in reservoir, was investigated to the specified electro-facies. Therefore, this log can be used as a tool for establishment of connection between porosity types and petrophysical data such as electro-facies.

The present study investigated the geochemical characteristics of Shemshak shales as a probable oil source rock in the Gushfil mine located in the Sanandaj-Sirjan Zone (SSZ), Iran. Trace elements such as nickel, vanadium, chrome, molybdenum, and cobalt are used as paleoenvironmental indicators. Moreover, the ratio of these elements shows that oxic to disoxic conditions prevailed during the sedimentation period. The interrelation of these elements indicates that the upper part of Shemshak Formation of the Jurassic age was deposited in a terrestrial to the marine-terrestrial influenced environment. The solid bitumen reflectance (BR) documents that the black shales presently are overmature. Conjugation of BR and the insolubility of organic matter in carbon disulfide illustrates the presence of pyrobitumen and its subgroup epi- to meso-impsonite, which is also characterized by the absence of any fluorescence under ultraviolet light. The ratio of light to heavy hydrocarbons proves that the type of solid bitumen before pyro-bituminization has been a primary-oil solid bitumen, which could migrate through fractures and coarse pores. The primary-oil solid bitumen might be derived from Kerogen types II and III as documented by fibrous plant fragments, translucent phytoclasts and pollens. Presently, due to intense degradation, kerogen type IV dominates. The modeling confirms that a thermal degradation had probably occurred after the deposition of Lower Cretaceous carbonates when the shales were able to produce bitumen. Ultimately, intense hydrothermal degradation led the solid bitumen to evolve into pyrobitumen and caused the shales to evolve into a dry gas window.

The purpose of this study is to use the geochemical analysis of recent sediments from the Rayen River (length of about 25 km), located in the Central Iranian zone and Urumieh-Dokhtar Magmatic Belt, to interpret their compositional maturity, chemical weathering, source rocks, and tectonic setting. Geochemical analysis (major and trace elements) of ten sediment samples suggests that mafic and intermediate igneous rocks are the sources of these sediments. Based on discriminant function, binary and ternary diagrams, it is concluded that the tectonic setting of the study area is similar to a continental island arc. The Chemical Index of Alteration (CIA) ranges between 50 and 57, suggesting low-to-moderate chemical weathering that reflects tectonic activity, erosion, and rapid deposition under arid climatic conditions, which gradually increased through time in the source areas. The ICV (Index of Compositional Variability) values show that these sediments have low compositional and mineralogical maturity. It is also shown that the bed load in the Rayen River has a mixed source from undifferentiated volcanic rocks. The data obtained from both petrography and geochemical analysis, which reflect the tectonic and climatic conditions in the study area, can be used as a guide for the interpretation of similar ancient sedimentary records.

Previous attempts to classify flow units in Iranian carbonate reservoirs, based on porosity and permeability, have faced challenges in correlating the rock's pore size distribution with the capillary pressure profile. The innovation of this study highlights the role of clustering techniques, such as Discrete Rock Type, Probability, Global Hydraulic Element, and Winland's Standard Chart in enhancing the reservoir's rock categorization. These techniques are integrated with established flow unit classification methods. They include Lucia, FZI, FZI*, Winland R35, and the improved stratigraphic modified Lorenz plot. The research accurately links diverse pore geometries to characteristic capillary pressure profiles, addressing heterogeneity in intricate reservoirs. The findings indicate that clustering methods can identify specific flow units, but do not significantly improve their classification. The effectiveness of these techniques varies depending on the flow unit classification method employed. For instance, probability-based methods yield surpassing results for low-porosity rocks when utilizing the FZI* approach. The discrete technique generates the highest number of flow unit classes but provides the worst result. Not all clustering techniques reveal discernible advantages when integrated with the FZI method. In the second part, the study creatively suggests that rock classification can be achieved by concurrently clustering irreducible water saturation (SWIR) and porosity in unsuccessful flow unit delineation cases. The SWIR log was estimated by establishing a smart correlation between porosity and SWIR in the pay zone, where water saturation and SWIR match. Then, the estimated saturation was dispersed throughout the reservoir. Subsequently, the neural network technique was employed to cluster and propagate the three finalized flow units. This methodology is an effective recommendation when conventional flow unit methods fail. The study also investigates influential factors causing the failure of flow unit classification methods, including pore geometry, oil wettability, and saturation in heterogeneous reservoirs.

Routine core analysis data (porosity and permeability)—used in various methods for hydraulic flow unit (HFU) determination of reservoir rocks—are unavailable in all drilled wells. On the other hand, raw petrophysical wireline logs—applied to determine reservoir electrofacies (EF)—are usually available in all wells. Since cores provide accurate data on reservoir characteristics, the lack of cores has always interested petroleum geologists and engineers. Therefore, introducing a new method to give almost accurate data about reservoir rocks in uncored wells has always interested petroleum geologists and engineers. As the type of input data that was used to determine HFUs and reservoir EFs are fundamentally different from each other, providing an approach that can create a better match between the results of these two rock typing methods is always one of significant interest for researchers. In this research, capillary pressure (Pc) test results are vital in obtaining reservoir EFs compatible with HFUs for the Oligo-Miocene Asmari Formation in Qale Nar Oilfield. So that only EFs that are compatible with Pc test results are approved. Flow zone indicator (FZI) method was applied to determine five HFU including A (Log FZI > − 0.05, average of core porosity and permeability are 5.8% and 0.37 mD) to E (Log FZI < − 0.65, average of core porosity and permeability are 0.07% and 0.03 mD). Furthermore, based on raw petrophysical wireline logs and MRGC algorithm in Geolog software, five electrofacies (EF) were indicated containing EF 1 (average of core porosity and permeability are 5.91% and 0.38 mD) to EF 5 (average of core porosity and permeability are 0.08% and 0.02 mD). The correlation between HFUs and EFs shows that HFU A to HFU E is compatible with EF 1 to EF 5. Also, examining the obtained electrofacies in the modified Lorenz plot indicates that EF 1 and 2 perfectly match intervals with a high fluid flow regime. By this method, it is possible to provide an almost accurate estimation of hydraulic flow unit distribution for wells and intervals without cores.