حسین رحیم پور بناب

The Oligocene-Miocene dolomitized Asmari Formation has expanded all over the Arabian plate with numerous supergiant and giant hydrocarbons in SW Iran, Iraq, Saudi Arabia, and the United Arab Emirates. Concertedly, the Asmari Formation and age-equivalents in adjacent areas of Middle East include more than 90% of recoverable oil reservoirs (Ghazban, 2007). The best reservoir units of this succession occurs within dolomitic parts exhibiting better reservoir quality than do the intercalated limestones and silisiclastics. Dolomite sequences play an important role in the production of oil and gas in the world's major hydrocarbon basins (Fallah-Bagtash et al, 2020; Noorian et al, 2020; Omidpour et al, 2021; 2022; Fallah-Bagtash et al, 2022). Similarly, in the Asmari reservoir with poor primary reservoir properties, fracturing and dolomitization enhanced porosity and permeability and thus hydrocarbon production (Aqrawi et al, 2006). Shadegan Oil Field is one of the important oilfields of Iran, due to its carbonate- siliciclastic nature, different parts of this formation have been exposed to the process of dolomitization. This has led to the development of porosity and permeability in its different parts. Therefore, in this research, using various data such as detailed petrographic studies along with geochemical studies of dolomites, the dolomites types of the Asmari Formation in the Shadegan Oil Field, dolomitization models, diagenetic history, diagenetic alteration and evolution of dolomitized fluids have been discussed. The results of this study can finally be used to evaluate the effect of dolomitization on the reservoir potential of Asmari Formation in this field.

The present study is based on a petrographic analysis of 1123 thin sections from cores of five wells drilled in the Asmari Formation. All thin sections were stained with potassium ferricyanide and Alizarin Red-S to distinguish carbonate minerals (Dickson, 1965). Dolomites are classified based on dolomite-rock texture classification presented by Sibley and Gregg (1987), Mazzullo (1992) and Chen et al. (2004). Facies analysis and interpretation of the depositional environment was performed using by Burchette and Wright (1992) and Flügel (2010) schemes. Ten uncovered thin sections were also analyzed by cathodoluminescence microscopy. These analyses took place at the Central Laboratories of Ferdowsi University of Mashhad, Iran. Ten gold-coated samples were analyzed with backscattered electron imaging using a Scanning Electron Microscope (SEM) in order to evaluate dolomite types, crystal sizes, micro-textures and pore spaces. Finally, thirty-two dolomitic samples were analyzed for their trace and major element contents using atomic absorption spectrophotometry (AAS) at the Ferdowsi University of Mashhad, Iran. 

The Asmari Formation, in Shadegan Oil Field, with Oligocene-Miocene age, consists of carbonate unit and siliciclastic intervals, which is mainly composed of medium to thick layered limestone and dolomite with interlayers of shale and sandstone. Detailed description of the core samples along with petrographic studies of the Asmari succession led to the identification of 26 carbonate-evaporite microfacies. In general, mineralogical, geochemical, and especially the interaction of facies with the distribution of dolomite indicates dolomitization by five different mechanisms/models in the carbonate platform of the Asmari Formation. These models include: Sabkha model, Seepage-reflux model, Meteoric-mixing zone model, Burial model and Bacterial mediation model. Dolomitization, as the most important diagenetic process in the depositional sequence of the Asmari Formation, has formed in several diagenetic environments, including syndepositional diagenetic realm (near surface), shallow burial, and intermediate to deep burial.

Four texturally and geochemically different types of dolomite include D1 (<10 μm, fabric-retentive), D2 (16-62 μm, fabric-retentive), D3 (62-250 μm, fabric destructive), and D4 (150-250 μm, fabric destructive). The lateral and vertical heterogeneity in dolomite percent indicates that the Asmari reservoir was subject to the multiple dolomitizations that could be categorized by five models in the near-surface to deep burial environments. Thin-layered sabkha dolomites (D1) are formed at or just below the sediment-water interface in mud-supported facies soon after deposition or during shallow burial. The matrix dolomites (D2 and D3) are the most abundant type of dolomites with the most contribution to reservoir porosity. They were formed during intermediate burial stages of the Asmari succession, indicated by their close association with the formation of an early generation of stylolites and fairly high iron concentration. These dolomites formed from warmer and more saline basinal fluids and/or from the dissolution of high-magnesium calcite or earlier dolomites, or recrystallization of D1. The D4 and other dolomites associated with the shaley facies, formed in a deeper burial setting by hydrothermal processes, utilizing hot and slightly-saline fluids that were affected by brine enrichment.

The high heterogeneity in carbonate rocks makes it impossible to relate reservoir and production parameters to the rock properties and generalize it to the reservoir. Hence, in order to reduce diversity, different rock types have been created based on various factors such as lithological parameters, porosity, and petrophysical properties. Fluid flow parameters are not adequately addressed in these classifications, and some of these rock classifications are overly complex, rendering them challenging to utilize. Considering the features of fluid flow in classification, utilizing minimal data input can have a major impact on carbonate rock studies. In this study, the focus of investigation is on analyzing the reservoir quality of Winland throat radius rock typing, while also exploring fluid flow parameters as production and dynamic parameters. In this regard, using the petrophysical data of 779 carbonate rock samples from the Ilam, Sarvak and Fahliyan formations, the Winland rock typing was determined, and then the appropriateness of the rock typing was investigated using lithological, petrophysical, pore and dynamic parameters. Investigations showed that by correcting the boundaries of the Winland rock typing, regular connections are established with the mentioned parameters. The results showed that although the reservoir properties show improvement with the increase in the group number, the dynamic properties do not follow this trend. Overall, the middle groups are the most desirable part of the rock typing in terms of reservoir quality and production parameters. The shift of static rock typing towards dynamic rock typing and also the use of the ratio of recovery factor to irreducible water saturation are as a key parameters to check production quality which are recommended.

The Fahliyan Formation, located in the Abadan Plain, is one of the most significant productive units in the Zagros Basin. Its Mesopotamian Basin equivalent, the Yamama Formation, also contains large quantities of hydrocarbons. Due to the geochemical similarities of these two reservoirs, investigating trapped oils and correlations can yield significant results. However, there have been limited studies describing the relationship and oil-oil correlation between the Fahliyan and Yamama oil samples. In this study, geochemical analyses such as GC, GC/MS, and stable carbon isotope were used to analyze the Fahliyan oil samples. Furthermore, Yamama data were taken from previously released studies in the Mesopotamian Basin. The results showed that both Yamama and Fahliyan oils were non-biodegraded and mostly paraffinic and light, indicating peak mature or late mature levels. The indices also suggested that the oils had a marine carbonate source with type II kerogen, which was deposited under anoxic and low salinity conditions of the deposition environment. The Jurassic source rock of these reservoirs was confirmed by the geological age biomarkers. Following this and previous research, it was concluded that the Sargelu and Garau (Sulaiy) formations are the most likely source rocks. Investigations of the oil biomarkers and the results of other studies in these areas deduced that the Fahliyan and Yamama oils in study areas are classified in the same genetic family. These results will affect the field development plan.

This study integrates the results of petrographic studies of core samples and thin sections with petrophysical data for the evaluation of heterogeneities in the distribution of reservoir properties in the Upper Dalan and Kangan formations. Reservoir rock types, hydraulic flow units, and reservoir zonation of these formations are determined in a sequence stratigraphic framework. Accordingly, 7 rock types and 8 hydraulic flow units are defined using the petrographic evidence and flow zone indicator values, respectively. Based on the Lorenz approach, 15 reservoir, barrier, and baffle zones have been differentiated. Among the defined rock types, PRT1 (compacted anhydrite) has lowest reservoir quality, and PRT7 (dolomitized packstone and grainstone) has highest reservoir quality. A combination of depositional facies characteristics and diagenetic alterations controlled the reservoir properties in these formations. There are one reservoir and one baffle zone in K1 unit, two reservoir zones and one speed zone in K2, one reservoir, baffle, barrier, and speed zone in K3, and three reservoirs, two baffle, and one barrier zone in K4 unit. All macroscopic and microscopic heterogeneities are determined in sequence stratigraphic framework. Results showed that non-reservoir units of Permian–Triassic formations are concentrated within the RSTs (regressive systems tracts) of UDS3 and KS1 sequences. On the other hand, reservoir zones correspond to KS2 and UDS4 sequences.

Kangan Formation with Triassic age, it has the largest gas reserves in the Middle East and the world. This formation is in Salman field (Including 187 meters of thickness in the 2SK-1 well and 189 meters of thickness in the 2SKD-1 well) And in Lavan field (including 186 meters of thickness in LN-3 well), and with the sequence of carbonate, limestone, Dolomite limestone, Dolomite with anhydrite Layer, Marl and shale (on the Kangan Formation). According to microscopic studies in the mentioned wells, 15 faces were identified which belong to four facies belts: Sabkha, Tidal flat, Lagoon and Shoal. Based on the identified microfacies, a homoclinal carbonate ramp can be introduced. The known diagenesis processes in the Kangan Formation, which are effective on the reservoir quality are: mechanical and chemical compaction, anhydrite and calcite cement as a reservoir quality reducer and dissolution, dolomitization and fracturing can be mentioned as increasing reservoir quality. The types of porosity observed are: Intragranular porosity, Moldic, Fenestral, vuggy, Intraparticle, and fracture. The vertical changes of the facies indicate three third-order depositional sequences and five fourth-order depositional sequences in Salman and Lavan fields. Each sequence consists of two system tracts, TST (including intertidal, lagoon, back shoal) and HST (including intertidal and shoal) in reservoir units K1 and K2. Reservoir quality study also according to distribution and separation of samples of Grain supported and Mud supported facies, sedimentary environment and the size of dolomite crystals, compared to the available porosities and permeability, indicates class 1 and 2 of Lucia.

South Pars gas field is one of the fields in southwestern Iran in the Zagros sedimentary basin and includes two reservoirs, Kangan and Dalan. Kangan and Dalan formations that belong to Dahram group and are considered as the most important gas reservoirs in the Persian Gulf region. The use of well drilling logs in uncored wells to identify rock-related features has always been discussed by geologists.  In this study, based on wavelet analysis of gamma-neutron and sonic logs, stratal surfaces including sequence boundary and maximum flooding surface were identified.  In this study, using wavelet analysis of well log data such as GR, NPHI, RHOB, DT and also combining them with Cyclolog data, a suitable and low error method for automatic determination of these boundaries was presented. Also in this study, sequence stratigraphy was investigated by INPEFA method of Cyclolog software to determine sequence boundaries (SB) and maximum flooding surface (MFS) with positive inflection points and negative inflection points of available INPEFA log curves , respectively. In addition, the highstand system tract (HST) was identified by the negative trend of the INPEFA curve and the transgressive system tract (TST) was determined by the positive trend of this curve. Accordingly, sequence stratigraphy study of Dalan and Kangan formations was performed by INPEFA method in 4 wells of South Pars gas field.  Finally, the agreement between the automatic sequence boundaries obtained from the wavelet transform method and INPEFA and its comparison with the core information in four wells from the study field, shows satisfactory results.

Shurijeh Formation (Neocomian - Barremian) is the main hydrocarbon reservoir in north east Iran. Most gas reservoir production place in zones B and D of this formation. In this study, comprehensive petrographic and petrophysical studies were performed to understand the factors controlling the reservoir quality of this formation. With respect to the petrographic studies, well log data, evidence achieved from the core and drill cuttings, five primary facies (petrofacies), including microconglomerate, sandstone, claystone/shale, sandy dolomudstone, and dolomitic- sandy dolomitic ooid grainstone / hybrid, were identified in the deposits of Shurijeh Formation. Sedimentary facies of the Early Cretaceous reservoir in the studied wells belong to the upper part of the supratidal zone, intertidal zone, lagoon, braided river (longitudinal bars) and meandering river (flood plain and oxbow lake). In this study, based on porosity and permeability data, 4 units of Hydraulic flow units (HFUs) were identified using flow zone indicator (FZI) method. The results of this study showed that the diagenetic processes like dissolution, dolomitization and chemical compaction (stylolites and dissolved vein) are related to the grain supported facies including micro-conglomerate, sandstone and dolomitic- sandy dolomitic ooid grainstone / hybrid and hydraulic flow units (HFU4) and hydraulic flow unit (HFU3) that have the best reservoir quality are connected. The results of this study showed that the diagenetic processes like dissolution, dolomitization and pressure dissolution (stylolites and dissolved vein) are related to the grain supported facies including micro-conglomerate, sandstone and dolomitic- sandy dolomitic ooid grainstone / hybrid and hydraulic flow units 4 and 3 that have the best reservoir quality are connected. Diagenetic processes of cementation (Silica, carbonate and anhydrite) and alteration of feldspars are associated with the dominant mud facies including claystone/shale, sandy dolomudstone of hydraulic flow units 2 and 1 which have the lowest reservoir quality.

The aim of this study is geochemical evaluation of the Fahlian, Gadvan, and Surmeh formations as possible source rocks in Gachsaran oil field using Rock-Eval Pyrolysis manner. All of the studied samples possess migration index amounts lower than 1.5 showing indigenous nature of their hydrocarbons. TOC versus S2 and TOC against S1+S2 diagrams suggest fair hydrocarbon generation potential for the Fahlian and Surmeh formations and fair to good potential for the Gadvan formation. for the Fahlian and Surmeh formations type III kerogen and for the Gadvan formation mixed type II and II-III kerogens were identified. So, the Fahlian and Surmeh formations contain organic matter with terrigenous source (gas prone) and the Gadvan Formation possess both of marine and terrigenous organic matter (oil and gas prone). According to the cross plot of Tmax versus Hydrogen index (HI), the Gurpi formation is capable of mixed gas and oil, and gas generation and the Fahlian and Surmeh formations considered only gas prone formations. In terms of organic facies type, the surmeh, Fahlian, and Gurpi formations located in CD, C and CD, and BC and C zones of jones diagram, respectively. So, the Gadvan formation in compare to the Fahlian formation and the Fahlian formation in compare to the Surmeh formation, deposited under more anoxic conditions. In terms of thermal maturity, All of the Fahlian, Gadvan, and Surmeh formations located in oil window zone, but the Surmeh formation possess higher maturity than the Fahlian formation and the Fahlian formation have highr maturity in compare to the Gadvan formation.

Paleohighs play an important role in increasing the quality and sedimentological characteristics of the reservoirs. The Upper Dalan Formation with Late Permian age in the center of the Persian Gulf Basin is known as a giant gas reservoir. In this paper, 60 meters of the Upper Dalan Formation have been studied in two fields in the center of the Persian Gulf Basin. Petrographic studies of the two fields led to the identification of seven microfacies in field A and six microfacies in field B in the form of four facies belts in the carbonated ramp environment. In order to evaluate the heterogeneity of the reservoir, the determination of rock types was performed by using four standard methods. Examination of the average porosity and permeability shows that the dissolution in field B is more severe than in field A. Study of diagenetic processes, the type of dolomites formed and the average porosity and permeability in the samples of the two fields indicate that the location of field B on the Qatar arc leads to the formation of dolomicrites, increased dissolution and finally higher reservoir quality in microfacies groups in this field in comparison with field A.

Jahrom and Asmari Formations in two wells from Nargesi field in the southern part of Dezful Embayment were studied to interpret the sedimentation and diagenesis history of Paleocene-Miocene successions. A total of 14 different microfacies were identified based on the study of 270 m drilling core and 495 microscopic thin sections,which are located in four sets of open marine, shoal, lagoons and tidal flats. The microfacies of the Asmari Formation are include tidal and lagoon sets. The microfacies of the Jahrom Formation are include middle ramp and the open marine, and energetic facies of the shoal sets have been observed in abundance in this formation, and to a lesser extent has lagoon facies. According to the characteristics of the above microsfacies, it is suggested that a shallow carbonate ramp with a gentle slope be used as a sedimentation environment for these Formations in Nargesi field. Asmari Formation is deposited in the shallower parts of this ramp. The paragenetic succession of Jahrom and Asmari Formations has been interpreted based on petrographic evidence in four marine, meteoric, burial and uplifting environments, and have affected sediments, during the three stages of eogenesis, mesogenesis and telogenesis. Dolomitization, cementation, anhydritization, micriticization, neomorphism, compaction, dissolution and fracture are the predominant diagenetic processes in these Formations. Dolomitization and anhydritization processes have been observed throughout the Asmari Formation, but are less intense in the Jahrom Formation. Asmari Formation cements are mostly dolomitic and anhydrite, but Jahrom Formation cements are mostly calcite.

Shurijeh Formation with Early Cretaceous (Neocumin-Barmin) age is one of the most important clastic reservoir rocks in northeastern Iran. By combining core information, petrographic study and application of petrophysical logs and data obtained from core analysis (porosity and permeability) of hydraulic flow unit and Electrofacies in the sedimentary sequence of Shurijeh Formation in five wells field were identified. The purpose of this study is to survey relationship between hydraulic flow unit and Electrofacies with the position of sequences (sequences and system tracts) and zonation of sedimentary sequences of Shurijeh Formation in the study reservoir. Based on the porosity and permeability data obtained from the core analysis, four hydraulic flow units were determined using the Flow zone indicator method. The fourth Electrofacies was determined based on gamma, neutron, density, sound and effective porosity logs obtained from possible evaluations using MRGC clustering method. Afterwards, the Hydraulic flow units and Electrofacies determined in the framework of sedimentary sequences were used and their distribution in the reservoir and field was determined to provide a clear match between the reservoir zones and the sequence stratigraphic framework. Finally, petrophysics (micro conglomerates, sandstones, and Sandy Dolomitic Ooid Grainstone / Hybrid) are associated with high-energy braided river environments and the high-energy section of the lagoon to Barrier Tidal or shoal, the best reservoir units are in the sedimentary sequence of zone D, B and the middle part of zone C (C2). On the other hand, petrophysics (Claystone/shale, dolomadstone sandy) related to low-energy environments of Braided river (floodplain), meandering river and superatidal stream (above tidal), the Poorest reservoir unit of these sequences in zone A, E sediment sequence and alternately formed in zones C and D.

The Sarvak Formation was deposited on shallow-marine carbonate platforms under the controls of tectonic and eustatic changes during the Upper Cretaceous in the Zagros area. It forms on of the most important reservoir intervals in SW Iran. Complex depositional setting and diagenesis history have resulted in a heterogeneous carbonate reservoir. This study, integrates the results of petrographic (facies and diagenesis) studies with petrophysical and reservoir data (core porosity-permeability and wireline logs) to evaluate the controls of depositional and diagenetic processes on the distribution of reservoir quality in the Sarvak Formation. Ten hydraulic flow units are determined using the FZI concept. Twelve reservoir and non-reservoir (baffle and barrier) units are identified using the Lorenz approach. Finally, dominant depositional facies and diagenetic alterations are evaluated in each HFU and reservoir zone. Results of this study showed that meteorically-dissolved rudist-dominated facies and high-energy facies of shoal complexes formed the best reservoir units in the Sarvak Formation. In sequence stratigraphic point of view, these zones are located in the RSTs of third-order sequences, beneath the disconformity (paleoexposure) surfaces. In contrast, the compacted and cemented mud-dominated facies concentrated in the TSTs and around the maximum flooding surfaces (MFS) formed the non-reservoir units of the Sarvak Formation.

The Ilam Formation is one of the important reservoir units in the Zagros area. Integrated sedimentological and petrophysical studies have been used to evaluate its depositional and diagenetic history, sequence stratigraphy and, finally, reservoir quality in an oilfield in the Lurestan area. Facies analysis has resulted in the recognition of 4 microfacies including pelagic mudstone/marl, planktonic foraminifera mudstone/wackestone, microbioclast wackestone to packstone, and oligosteginids planktonic foraminifera wackestone/packstone. Petrophysical logs of two wells A and B (Neutron, Sonic, Gamma-ray, and Resistivity( are used to define lithology, porosity and water saturation in the Ilam Fm. Clean to argillaceous limestone was the main lithology of the Ilam Fm. in studied wells. The formation has microscopic pores (up to 15%) as dominant pore types. Based on the MRGC method, 5 electrofacies have been defined and correlated with core-based microfacies. Finally, six integrated reservoir zones have been differentiated and correlated in a sequence stratigraphic framework.

Cenomanian –Turonian carbonate sequences of the upper Sarvak Formation are among the most important hydrocarbon reservoirs of the Zagros area in SW Iran. Depositional and diagenesis histories were investigated using the petrographic studies of core samples and thin sections of this formation in 6 wells from 5 oilfields located in central and southern parts of the Dezful Embayment. Facies analysis has resulted in the recognition of 14 microfacies that are grouped into six facies associations (basin, outer ramp, middle ramp, open marine lagoon, shoal, and restricted lagoon), according to their facies characteristics and comparison to the standard microfacies models. A homoclinal ramp model was proposed as depositional setting of the Sarvak Formation. Important diagenetic alterations of this formation include dissolution, cementation, dolomitization, de-dolomitization, silicification, neomorphism, compaction, and fracturing. They represent a paragenetic sequence of marine, meteoric (eogenetic and telognetic), and shallow- to deep burial realms. Sequence stratigraphic interpretations resulted in the differentiation of two (third-order?) depositional sequences in the upper Sarvak Formation (mid Cenomanian – early Turonian). Finally, facies characteristics and diagenetic alterations are interpreted in a sequence stratigraphic framework.

In this work, we determine the factors affecting soil erosion and its effect on dust formation around the Mineral Salts Company in Mighan playa of Arak. Seventy samples are randomly sampled from a depth of 10 cm above the ground around Mighan playa. Some factors involved (e.g. sample aggregation, lime, organic matter, pH, Na, K, Ca, and electrical conductivity) are determined and compared with the statistical parameters such as the correlation matrix and cluster analysis in order to determine the erosion rate in each sample based on the soil properties. The results obtained show that soil salinity, as a major factor in erosion, causes soil depletion and degradation in the area. Also a high amount of sand in the environment causes the soil texture instability. The factors such as the amount of gravel, organic matter, and K are the main erosion inhibiting factors, which have little effect on the majority of the samples. The organic matter content in most samples is less than 4%, and does not have much effect on erosion. The amount of clay in the samples is less than 10%, and has no effect on the adhesion of soil texture. The main factor affecting the erosion rate is EC and Na in the soil. The inhibitors such as gravel, organic matter, K, and clay amount in the samples can be considered as a protective or reducing factor in erosioning. Rising in the mentioned factors in the soil causes a lack of density and instability in the soil, and increases the rate of soil erosion. The results of this work show that addition of soil erosion increases the amount of fine-grained soil, and dust is a result of increased production. Also the presence of mineral salt in the area increases the production rate of dense soil, and as a result, rises the amount of dust produced in the area. Therefore, we need to stabilize mining soil, and prevent dust generation around the Mineral Salts Company.

Upper Dalan and Kangan carbonate formations with Late Permian–Early Triassic ages are considered the main gas reservoir rocks in some Persian Gulf fields. In this study, to investigate the factors affecting the distribution of reservoir rock types, microfacies and diagenetic processes in the upper part of Dalan and Kangan formations in one of the Persian Gulf fields have been investigated. A total of 1110 thin sections and 840 porosity and permeability data (RCAL data) were used. In the petrographic studies, 15 microfacies were classified into four facies belts of the tidal zone, lagoon, shoal, and open marine in an epeiric carbonate platform environment. Studies showed that diagenetic imprints such as calcite cementation, dolomitization, anhydrite nodule formation, dissolution, and compaction had been occurred in three marine, meteoric, and burial diagenetic environments. To investigate and group the reservoir rock types on the Lucia petrophysical diagram, the porosity and permeability data were plotted on this diagram. Depending on the type of microfacies and diagenetic processes, porosity and permeability data are included in all parts of the diagram. This study shows that the reservoir rock of the studied field is very heterogeneous in terms of reservoir properties and is affected by sedimentary and diagenetic processes. Accordingly, grain supported samples have been moved from classes one and two to the lower parts of the diagram, in the non-reservoir section, due to calcite and anhydrite cement. In contrast, in some cases, dissolution and dolomitization in mud-supported microfacies led to data placement from class three of Lucia to classes one and two. Dissolution and dolomitization in grain-supported microfacies have resulted in the placement of these samples in the upper parts of classes one and two.

Fluid permeability is one of the most important parameters in reservoir characterization. In this study, permeability calculated from different models and compared with the laboratory measured permeability in a hydrocarbon field in the central part of the Persian Gulf. The permeability models used in this study include Winland, Swanson, Pittman, and Dastidar. In this analysis, 50 mercury injection experiments from Dalan and Kangan formations were used. Conclusions indicate that Swanson and Winland permeability models are the best reservoir permeability prediction models for the Kangan and Dalan carbonate formations, respectively. Swanson’s model unlike other models considers the effects of pore throats in mercury injection curve as the main factor, which it has a key role in permeability prediction. In carbonate environments, there is not specific relation between porosity and permeability. Therefore, models that considered porosity as a factor for permeability prediction show less accuracy. The reservoir’s lithology (carbonate or clastic), because of the different facies and lithology, have various petrophysical features. In this manner, the models that have been calibrated based on carbonates lead to a better prediction in the carbonates in comparison with models which calibrated based on clastic or both.

The Dariyan formation (Shuaiba equivalent) with aptian-albian in age is one of significant reservoirs in the Zagros and the Persian Gulf. This formation in the study field (western Persian Gulf) include sequence of 185 orbitolinaid shallow and deep carbonate facies. The Dariyan formation in this area is divisible into four zones: Lower Dariyan with gray Limestone and dissolution cavities, Kazhdumi Toungue with dark gray Marl and without structure, Upper Dariyan dark to light clean Limestone and Upper clastics with Sandy Siltstone and Shale. Microfacies study of the Dariyan led to recognition of 8 microfacies and 3 petrofacies in 5 facies belt inclusive Delta, Inner ramp, Mid-ramp, Outer ramp and Basin. Microfacies interpretation which is done based on the fauna mainly indicates shallow marine environment. Also uniform variation of microfacies and absence of rim and buildup faunas, and replacement of corals and rudists by the Lithocodium-Bacinella is coeval with the Oceanic Anoxic Event 1a, that Lithocodium-Bacinella had fewer abilities to build huge reefs so this depositional environment predicted as carbonate ramp with patch reefs and mounds. The three sequences were recognized in the study field. These sequences belong to Early, Middle and Late Aptian, respectively. In the first and third sequences, the sequence boundaries were identified by the unconformities and their related features, while in the second sequence, the retrogradation and alteration of the intrashelf basin facies (Kazhdumi) to shallower fscies were recognized. The maximum flooding surface was also identified by the maximum transgrassion and deep outer ramp and basin facies in addition to rather increase in oxygen and carbon isotope values. Finally, a siliciclastic sequence, due to the entrance of siliciclastic sediments to the basin, was recognized.

Geochemical investigation of Kazhdumi and Pabdeh formations suggest a shaly and carbonate lithology as well as a suboxic-anoxic marine depositional environment for both formations. On the other hand, the thermal maturity of the Kazhdumi Formation is equivalent to the mid of oil window while thermal maturity-related parameters show that the Pabdeh Formation has not entered the oil window. Biomarkers are indicative of derivation of the four oil samples from a carbonate-shaly or marly source rock. Also, thermal maturity-related biomarkers reflect a peak mature stage for all of the four samples. Different values of oleanane index in oil samples is implying a more significant role of the Pabdeh Formation in hydrocarbon embedded in 36, 56, 55 wells in compare to well number 22. In general, oil-source correlation introduces both Kazhdumi and Pabdeh formations as source rocks for the crude oils.

The Sarvak Formation deposited in the North to Northeastern margin of the Arabian Platform during the Mid-Cretaceous, and is extensively encountered in the Folded Zagros of southwestern Iran. It is the most important reservoir unit after the Asmari Formation in Iran. Petrographic analysis of the drilled wells of the Kupal oil field led to recognition of in studied wells led to determination of eight microfacies that deposited in 3 sub-environments; restricted lagoon, lagoon-open marine and shoal in an interior part of Continental carbonate ramp. Petrographic studies revealed that since deposition, the Sarvak Formation experienced several diagenetic realms including marine, meteoric, burial and telogenetic diagenetic environments. Location of the studied wells shows that the relative depth of the Sarvak Formation ramp increases from the east to the west. These diagenetic successions are mainly restricted to the upper and lower parts of the Cenomanian-Turonian disconformity. Meteoric water infiltration below this Cenomanian-Turonian disconfirm boundary and related Dissolution led to development of moldic and vuggy porosity And as a result, the reservoir potential has been increase. In this study Hydraulic flow units were identified firstly using flow zone indicators and secondly using a stratigraphic modified Lorenz plot. The flow units resulting from these two methods are compared, and their close correspondence within the sequence stratigraphic framework is discussed. Base on this results six hydraulic flow units are defined as flow units 1 and 2 of the best reservoir quality and the reservoir potential reduced to the flow unit 6.

Asmari Formation (Oligocene - Miocene) is the first fractured proliferous carbonate reservoir that ever known in the world and is the most important hydrocarbon reservoir in Iran. The large quantity of the produced oil in Dezful Embayment is from this formation. Thin section studies in this formation lead to identification of eight microfacies related to the homoclinal ramp with three subdivisions (inner ramp, middle ramp and outer ramp). Many diagenetic processes such as; micritization, neomorphism, bioturbation, dolomitization, dissolution, cementation, mechanical and chemical compaction, fracturing have affected the Asmari carbonates in studied oil field during eogenesis, mesogenesis and telogenesis processes. Three sequences (third order) have been identified based on sequence stratigraphy studies. Based on all results from this study it could be pointed out that; dolomitization, dissolution and cementation are the most important factors that controlled the reservoir quality in this field. Cementation (calcite and anhydrite cements with different fabrics) reduced reservoir quality in different facies. Seemingly, fabric destructive dolomitization increased reservoir quality with creating intercrystaline porosity in mudstone facies and connecting isolated pores (via dissolution) in most of facies. Dissulotion has prime importance where occurred and increased reservoir quality. Contrasting to the other Asmari hydrocarbon fields in Zagros which fracturing is the most important factor in increasing reservoir quality, in Naft-Safid oil field, most of fractures have been filled by calcite cement. Thus, diagenetic imprints (such as dissolution and dolomitization) have more effects on increasing reservoir quality than fracturing.

Petrophysical rock type is a part of the reservoir that has the same properties such as geological and petrophysical characteristics. Therefore, the relationship between geological and petrophysical units can be useful for understanding the heterogeneity of the reservoir, especially in carbonates, which are highly variable from the pore type and pore throat size radius viewpoints due to the effect of diagenetic processes. The pore type and pore throat size radius as parameters which are relevant to the product of the geologic process (depositional and diagenesis) control the petrophysical properties of the reservoir. Accordingly, these two parameters are the best tools for communicating the geological and petrophysical characteristics of each petrophysical rock unit. In this paper, three methods including flow zone indicator, Winland R35, and discrete rock types (DRT) were used to determine the petrophysical rock type. The results show that the flow zone index outperforms the other methods, although the other two methods can have useful applications. To determine pore type and pore throat size radius in five flow units, which were identified by the flow zone indicator method, the velocity deviation log was used. Moreover, to determine the continuous distribution pore type the velocity deviation log was used. In addition, mercury injection data were employed to measure pore throat size radius. According to the results obtained from this study, the best flow units are in accordance with positive and zero velocity deviations, which have interconnected vuggy and intergranular which are the product of the dissolution (diagenesis) and depositional process. Finally, the results indicate that the reservoir quality of the Fahliyan Formation is affected by the two factors of diagenesis and sedimentation, but in general, diagenesis has the most contribution to determine the all reservoir quality of the formation.

Asmari Formation (Oligocene - Miocene) is the most famous carbonate reservoir that ever known in the world. It is the main hydrocarbon reservoir in Iran and also the major oil production in Dezful Embayment. In this study, in order to understand the reservoir quality controlling factors of this Formation, detailed petrography studies were carried out in Ghale Naar oil field. This formation in the Ghal’e Naar oil field is composed of grain-supported bioclastic-pelloidal (foraminiferal-algal) faciese and nine sedimentary facies have been identified based on eight hundred microscopic thin section studies from core and cutting samples in this oil field. These facies are related to the lagoon, shoal, nummulitic bank and open marine sub- environments of a homoclinal ramp carbonate system. The results of this study showed that the diagenetic processes like dissolution and dolomitization are related to the grain supported shoal microfacies and nummulitic shoal. Dissolution along with dolomitization are factors that increase reservoir quality and cementation and compaction are the most important factors in reducing the quality of reservoir in Asmari Formation.

Permo- Triassic subsurface section at Lavan 3 Well in Lavan Gas Field exhibits a 85 m-thick succession of limy dolostone and dolomitic limestone bearing anhydrite in the upper Dalan Formation, as well as a 154 m-thick succession of limy dolostone and dolostone with anhydrite intercalations in Kangan Formation. In the present study, 116 species belonging to 55 foraminifera genera were identified which were divided into two biozones, namely Charliella altineri- Paraglobivalvulina mira- Dagmarita chanackchiensis Assemblage zone (Dzhulfian in age) and Claraia aurita- Spirorbis phlyctaena Assemblage zone (Anisian in age). Nine primary microfacies were identified in the upper Dalan Formation, while, 13 microfacies were detected in Kangan Formation, together with different sub-environments (sabkha, tidal flat, lagoon, submarine ridge, and open marine) which were found to be deposited in a shallow marine carbonate platform in­ the form of a homoclinal ramp. Based on microfacies changes, aggradational, progradational and retrogradational stacking patterns of deposits and by conformation with the Gama-ray log, these strata could be divided into a couple of third-order sedimentary sequences for the upper Dalan Formation, as well as a couple of third-orders for the Kangan Formation, including two system tracts (TST and HST). On a global scale, the findings are comparable to the upper part of the Absaroka supersequence