سیدعلی معلمی

An accurate estimation of methane absolute adsorption in nanopores of shale gas is crucial for a good estimation of gas in place (GIP). However, experimental studies would only provide us with the excess adsorption isotherm directly. In this regard, knowing the adsorbed density is necessary to calculate the absolute adsorption. For this purpose, most researchers calculate the absolute adsorption isotherm via the Langmuir adsorption model with a constant value for the adsorbed density. In the present study, using hybrid grand canonical Monte Carlo/molecular dynamics simulations, we explained how to improve the calculation of the adsorbed density in calcite. For this purpose, methane inside calcite mineral with a pore size of 4 nm at temperatures of 30 and 90 °C and pressures up to 50 MPa is simulated, and the effects of temperature and pressure on the amount of adsorption and adsorbed density are investigated. This study showed that adsorbed density increases and decreases with increasing pressure and temperature, respectively. The results verify that the Langmuir adsorption model with constant adsorbed density will underestimate the absolute adsorption capacity, which is exacerbated with pressure. Finally, the adsorbed density obtained from molecular simulations to convert excess adsorption to absolute values can provide acceptable results that can be improved the GIP assessments.

Considering the importance of the Sarvak Formation and the significant role of rock typing in reservoir quality, the purpose of this paper is to determine rock types of the Sarvak Formation by using Hydraulic Flow Units (HFUs), Multi-Resolution Graph-based Clustering (MRGC), and Fuzzy C-mean clustering (FCM) methods inside petrophysical studies with multimin method in one oilfield of north Dezful Embayment. First, using the flow zone indicator (FZI) method, 4 rock types were obtained that accordingly reservoir quality of RT4 was very good and RT1 was weak. By using MRGC, 6 electrofacies (EF) were described that reservoir quality for EF6, EF5, and EF4 was good, and their presence in parts of the formation indicates a reservoir part in the Sarvak Formation. By using the FCM method, 7 RTs were determined that according to high porosity and permeability, the reservoir quality of RT7, RT6, and RT5 are very good. The correlation of obtained data finally led to the identification of 7 reservoir zones for the Sarvak Formation. Zones 3 and 7 have the best reservoir quality, mainly studied in the middle and lower part of the formation. The correlation of the obtained data with capillary pressure curves also correlates with the identified rock types and reservoir characteristics. This study shows the high efficiency of HFUs, MRGC, and FCM methods for determining rock types at intervals non-cored in the Sarvak Formation in the studied oilfield.

The Dariyan Formation with the Aptian age is the youngest reservoir formation of the Upper Khami group which is important in terms of hydrocarbon reservoir potential. This formation is 135 meters thick in the Kuh-e-Mish surface section and consists of thin, thick and massive limestone, marl and shale. Petrographic studies led to the identification of 13 microfacies. These have been deposited in four types of depositional environments, including inner ramp, mid ramp, outer ramp and basin, in a ramp type carbonate platform. Based on petrography, lateral and vertical facies changes, 3 third-order cycles distinguished. An integrated multidisciplinary approach including, petrography, surface gamma-ray spectrometry and trace element analysis have been used for recognition of original carbonate mineralogy and stratigraphic interpretations of this succession. Geochemistry of minor and major elements reveal original aragonitic mineralogy of the Dariyan Formation. Bivariate plot of Mn versus Sr/Ca values illustrated that the Aptian carbonates were affected by semi close diagenetic system with moderate water/rock interaction. Trace elements (Fe and Mn) contents are compared with distribution of sedimentary facies and depositional sequences to investigate and correlate stratigraphic boundaries, which are determined by sequence stratigraphy in shallow marine carbonate platform of the Dariyan Formation. The elemental peaks coinciding with the sequence boundaries and elemental peaks are correlated with maximum flooding surfaces.

In this study, the Asmari reservoir in 39 wells in one of the oil fields of southwestern Zagros, located in the Dezful region, was investigated using well log tomography of Gamma ray logs and core porosity data. For this purpose, two-dimensional and three-dimensional models of gamma and core porosity logs in 4 reservoir zones of Asmari Formation have been designed by Petrel software. Among the slice of Gama log and porosity data, 2 slice were selected from the upper and lower sections of the zones, and a total of 8 tomographic sections from 10 key wells were prepared and compared with each other. The results of gamma logs and porosity tomography models are very close and compatible with each other and show that there is an inverse relationship between gamma values and porosity in the slices made by Asmari Formation in the studied wells. Also, with increasing dolomitization in the zones, the petrophysical characteristics have changed and the amount of porosity has increased. Based on the well log tomography model of the studied oil field, it was found that zone 2 with the lowest gamma value and the highest dolomite value, has higher porosity than other zones and can be the main target of production wells in the field. Since drilling wells is expensive and time consuming, it is possible to achieve very close and accurate results of well drilling using well log tomography. Therefore, tomography studies can be very useful before increasing excavations in the area for general information.

The Asmari Formation is a thick carbonate-terrigenous succession in the Zagros Foreland Basin  deposited during the Oligocene–Early Miocene ages. The Stratigraphic forward modeling is n used in this study to determine the sediment supply, transportation parameters, and production rate of the Asmari Formation during precipitation in the Abadan Plain. The Dionisos Flow software is used for modeling studied depositional sequences. Argillaceous limestones, sandy dolostones, sandy limestones, sandy shales, limestones, sandstones, and shales are the main lithology of the Asmari Formation in studied wells. Also, the studied formation consists of four to five depositional sequences in the studied wells. The sedimentary environment of the Asmari Formation in the selected wells includes the inner to outer ramp (hemipelagic and pelagic deposits). The input parameters to the software for modeling include gamma log data, global sea-level curve, thickness and bathymetry maps, as well as sedimentary facies. Examination of the calculated data shows that the wave energy and water flow rate are effective factors in the sediment transportation and change in the sedimentation process of the region. The highest rate of carbonate production is estimated in the transgressive system tract of the second depositional sequence of studied wells in the inner ramp environment.

The Dezful Embayment is a depressed area within the Zagros Folded Belt. This embayment represents a foreland basin where subsidence at the foot of the uplifting mountain front fault has resulted in the deposition of thick post-Oligocene sediments. It has been one of the most productive areas where several potential source rock units with different geological ages were deposited in this tectonically developed depression making this area as the most prolific region in the Middle East. It is divided into northern and southern parts. The South Dezful Embayment at the foreland part of the Zagros Fold-Thrust Belt is a post-Oligocene subsiding basin. To the southeast, the South Dezful Embayment is bounded to the Kazerun Fault Zone and to the west, it bounded by the hendijan Fault zone, which is an N-S trending paleo-structure. Due to its vast oil resources, it has attracted the attention of researchers during time. The Dariyan Formation-Aptian age- is known as a carbonate reservoir in the Zagros Basin. It overlies the Gadvan Formation conformably and is overlain unconformably by Kazhdumi Formation. In the studied area, the Dariyan Formation has a thickness ranging from 195 to 45 m and can be divided into three members that are as follows: Lower Dariyan, Middle Dariyan, and Upper Dariyan. The Lower Dariyan consists of thick to medium-bedded limestone. The middle part of the Dariyan Formation is the so-called Kazhdumi Tongue. This part consists of thick black to greenish-grey shale and marl layers associated with a high abundance of planktonic foraminifers. In the East-West trend thickness of this part changes from 100 To 0 m where middle Dariyan and also Upper Dariyan change to Kazhdumi facies toward Kazhdumi intra-shelf basin in central part of Dezful embayment. The upper Dariyan Formation is composed of buff to grey medium, thick-bedded limestone. Many studies have been focused on Reservoir properties of Dariyan Carbonates in Zagros basin and Arabian plate but this is the first time that hydrocarbon source rock of the Middle part of Dariyan potential is going to be evaluated. The result may help to define new Petroleum systems that middle Dariyan will important role as a source rock for Upper Dariyan and above reservoirs.

This investigation is focused on the Khaneh-Zu Formation as a hydrocarbon reservoir as a point of view of microfacies, depositional environment, diagenetic processes and their effects on reservoir characterization. This study is based on the integration of lithostratigraphy, field study and petrography of this formation in 2 surfaces (Abghad and Khaneh-Zu) and 2 subsurface sections (Chahchaheh and Afshar wells) in the Kopet-Dagh basin. According to petrographic studies, 9 microfacies has been identified which were deposited in 3 facies belts including mid ramp, outer ramp and basin. The lack of calciturbidites and gradual change of microfacies to each other indicates the deposition in a carbonate hompclinal ramp. Diagenetic processes which have been affected on the studied interval are bioturbation, micritization, cementation (blocky and drusy), compaction, dolomitization, dissolution, pyritization and silicification. Vuggy, intercrystalline and fracture are different identified types of porosity. The porosity types are non-facies selective and formed as a result of diagenetic processes include dissolution, dolomitization and fracturing. Cementation and compaction have negative effects on reservoir characteristics. Based on low porosity percentage and low permeability, the studied sections dose not show high reservoir quality since most of the pores are filled with calcite cements. Dissolution, chemical compaction as stylolite and cementation are the most important diagenetic processes in this formation that result burial diagenesis. As a matter of fact porosities in Khaneh-Zu Formation are vuggy type, and they are not connected to each other to make permeability and a good reservoir. However, this report would be able to introduce more information about sedimentary environment and diagenetic processes controller for Khaneh-zu formation in Kopeth Dagh area.

The Asmari Formation (Oligocene – Miocene), as one of the most important oil reservoirs, consists of a thick sequence of carbonate – terrigenous rocks in southwestern Iran. In order to determine the structural geometry of this formation, the stratigraphic forward modelling method has been used in this study. So, 8 oilfields, including Yadanaran, Omid, Jufeyr, Sunsangerd, Khorramshahr, Mansuri, Dorquain and Azadegan have been selected in the Zagros sedimentary basin. Dionisos Flow Software has been used to determine the structural geometry of the sedimentary basin of the Asmari Formation in the studied fields. The studied wells in the oilfields are composed of three to five sedimentary sequences. Identifying each of the sequences that make up the wells per unit of time is the basis of the work. The results of sequence stratigraphic, gamma log and sedimentary environment data are the most important input parameters to the software for modelling. The present study shows that the geometric structure of the sedimentary basin of Asmari Formation in the studied fields has been controlled by parameters such as bathymetry, tectonic processes (rising and falling of the basin floor), global changes in sea level and accommodation space. The geometric structure of the sedimentary basin of Asmari Formation during the Oligocene – Miocene in the studied area was predicted as a progressive geometric structure with a gradual and cumulative nature towards the basin.

To the southwest of Iran there are large reservoirs of oil and gas including Jurassic and Cretaceous carbonates, with good source rocks in the succession of the Early Cretaceous and Jurassic. The purpose of this study was to investigate the production, migration and characterization of Pabdeh, Kazhdumi, Garru and Serglu source rocks in the study area. For this purpose, burial history and one-dimensional thermal modeling in four wells and two-dimensional modeling in one section for the study area were evaluated using Openuploo software to determine the maturity of layers and hydrocarbon outflow. Comparison of measured vitrinite temperature and reflectance values with model results was used for model calibration. The results of one-dimensional modelling of the burial and thermal history in this study show that the Sergloo, Grove and Kazhdumi formations have reached maturity and have had hydrocarbon outflow, but the Pabdeh Formation has not reached sufficient maturity for hydrocarbon maturation and production. The results of migration model in the studied section show that the two Early Cretaceous and Middle Cretaceous hydrocarbon systems were separated by Kazhdumi Formation and therefore hydrocarbon migration in deeper layers of Kazhdumi was mostly lateral to Abadan plain. The hydrocarbon produced from the Kazhdumi Formation, in addition to ornithologically rearing the upper layers, migrated to the Ilam and Sarvak layers due to the general slope of the layers laterally and toward the Abadan plain. In general, the process of maturation of source rocks decreased from east to west of the study area.

The first study on the Gachsaran Formation was first done by Pilgrim (1908), and others continued investigations from the 1920s (e.g., Richardson, 1924; Furon, 1941; Watson, 1960; James & Wynd, 1965; Setudehnia, 1972) Stratigraphic and sedimentologic studies of the Gachsaran Formation were carried out by Gill & Ala (1972), Kashfi (1980) and Motiei (1993). The studies were continued by Bahroudi & Koyi (2004), Moussavi Harami et al. (2010), Bahadori et al. (2011), Torabi et al. (2012), Gorjian et al. (2012), Aghdam et al. (2013) and Soleimani & Bahadori (2015). Most of these studies considered for geophysical properties, digenesis, and the geochemistry of deposits. There are a few biostratigraphic studies. Hence, the study of biostratigraphy and age determination of the Gachsaran Formation in this area improves understanding of this formation and provides useful and valuable information for exploration.The study area is located in the Zagros zone and the Coastal Fars as a sub-basin. Herein, we investigate the Gachsaran Formation for the identification of foraminiferal taxa, faunal assemblages, and biozones at a subsurface section in Bostaneh anticline located in the northwest of Bandar- e Lengeh.

In this research, 446 thin sections of well cutting were examined. Taxonomy of foraminifera was carried out in the micropaleontology laboratory of the Kharazmi University, using Loeblich and Tappan (1988), Henson (1950), Kennett & Sirinivasan (1983), Huang (1964), Adams & Bourgeois (1967), Papp & Schmid (1984), Bolli & Saunders (1985), Postuma (1971), Daneshian & Ramezani Dana (2007). Based on Gamma-ray logs and laboratory results, the lithostratigraphic boundaries were determined. The resulted biostratigraphy of foraminifers was followed and compared to those presented by Wynd (1965) and Adams & Bourgeois (1967).

The thickness of the Gachsaran Formation in Bostaneh anticline is 1288 m and consists of limestone, argillaceous limestone, anhydrite, salt deposits, marl, and thin layered shale. The studied sequence thickness is divided to Chehel, Champeh, and Mol members. In the investigated section, Gachsaran Formation underlies the Mishan Formation and overlies the Pabdeh Formation. Totally, 30 genera and 42 species of benthic foraminifera, and two genera and five species of planktic foraminifera were identified, from which the following zones have been identified.