javad honarmand

The Fahliyan Formation (Early Cretaceous) is considered to be one of the major oil reservoirs in many fields of the Zagros sub-basins such as the Abadan Plain and the Persian Gulf. In order to investigate the diagenesis, geochemistry and reservoir quality of this carbonate succession in one of the fields located in the Abadan Plain, the results of geological-petrophysical studies including petrographic study of microscopic thin sections, conventional core analysis (porosity-permeability), XRD, petrophysical diagrams, carbon-oxygen isotope and elemental geochemical analysis are combined with SEM and CL microscopy. This formation has been affected by various diagenetic processes, including micritization, bioturbation, compaction, cementation, dissolution, dolomitization, and fracturing. Moreover, calcite cementation, compaction and extensive dolomitization are the main factors that have controlled the decrease of porosity and permeability, while dissolution (in the form of voids and molds) and fracturing have increased the reservoir quality of the studied succession. The core porosity and permeability data in the reservoir part of the Fahliyan Formation range from 0.01 to 27.5% and from less than 0.01 to more than 630 mD. These changes in porosity and permeability are strongly dependent on diagenetic processes that follow the pattern of facies changes. In addition, reservoir quality studies also show that diagenesis has had a major positive and negative impact on the Fahliyan Formation and has largely controlled the distribution of the pore system. Using elemental geochemistry and oxygen and carbon isotopic data, a surface corresponding to the maximum relative sea-level fall was identified. The porosity and permeability data associated with the facies of the lower (reservoir) part of the Fahliyan Formation were plotted on the Lucia diagram resulting in the separation of four different rock types, among which the floatstone/bondstone-greenstone has a higher reservoir quality. Moreover, two petrophysical methods were used to determine flow units, including flow zone index and porosity throat radius at 35% mercury saturation. Based on the FZI method, one non-reservoir unit and four reservoir flow units were identified, and based on the porosity throat radius method at 35% mercury saturation, four rock types and one non-reservoir rock type were identified according to the pore size.

The Oligo-Miocene Asmari Formation is one of the most important hydrocarbon reservoirs in the Zagros sedimentary basin, especially in the Dezful depression. The Formation in most of the oil fields of the Dezful depression consists of a mixed carbonate-siliciclastic sequence. In this study, the relationship between sedimentary sequences and diagenetic processes with reservoir zones is considered. For this purpose, sedimentological data and petrophysical logs of a key well were used. Based on microscopic studies on the core thin sections, four detrital petrofacies and eight carbonate microfacies were identified that were deposited in four facies belts, including open marine, shoal, lagoon, and tidal flat environments, related to a homoclinal ramp. In addition, six depositional sequences (third order) were identified by facies analysis and well logs. Reservoir properties have been increased by dissolution and dolomitization with pore space expansion, while being decreased by cementation and compaction. The Asmari Formation in the investigated well is subdivided into eight reservoir zones based on sedimentary characteristics and petrophysical properties. The coincidence of the facies boundaries with the reservoir zone boundaries in most cases shows that the changes in the reservoir properties are mainly related to the changes in the sea level. This is well-known in the lower zones

The Gorgan Plain is located in the north of Iran and has mud volcanoes and high-pressure zones. There is limited information on Miocene and older sediments in this area and the available data on the Pliocene and younger sediments do not provide a complete understanding of the geology of these areas. The absence of marker fossils in the sediments has led to ambiguities in age determination and study of layers expansion in the study area. The Cenozoic sediments of Gorgan Plain which include Paleocene-Miocene sediments and Cheleken (Lower Pliocene), Akchagyl (Upper Pliocene), Apsheron (Lower Pleistocene), Baku (Upper Pleistocene) and Neo-Caspian (Holocene) formations, are mainly composed of sandstone and mudstone. This study shows that the thick Pliocene-Present sediments of Gorgan Plain were deposited at high rates, which was simultaneous with the increase in orogenic activity in the region and the gradual separation of the South Caspian Basin from open waters and the change of the sedimentary environment from marine to fluvial-deltaic. Sedimentation rates of Cenozoic deposits increase towards the coastal parts of the Gorgan Plain. The lowest sedimentation rates are in the Paleocene-Eocene deposits, and the highest rates are in the Baku Formation. High sedimentation rate is one of the controlling factors in the formation of mud volcanos and high-pressure zones in the region, and these rates can have a significant impact on the processes and elements of the petroleum system.

The sandstones of Gadvan Formation (Barremian–Aptian) in the Abadan Plain show a wide range of porosity and permeability due to their complex diagenetic history. Therefore, their petrography was investigated by polarizing and scanning electron microscopy. The porosity-permeability was estimated by routine core analysis. Based on the results, Gadvan sandstones were divided into five diagenetic facies. Limitedvolume of chlorite has greatly reduced the effect of compaction by creating a coat on quartz grains and limiting the overgrowth of silica cement. Carbonate cements up to 9% of the total rock have improved the reservoir quality whereas mesogenetic carbonate cemented sandstones (25 and 32% cementation) have often acted as a barrier to the continued movement of hydrocarbons. After determining the porosity and permeability, in order to find the relationship between these two parameters with diagenetic facies, the flow units were determined by the flow zone indicator (FZI) method. It seems that HFU 1 and 2, which are equivalent to diagenetic facies 3 and 5, have the best reservoir quality in the studied wells.

The Ilam Formation (Coniacian? –Santonian), is among the most important oil reservoirs of the Abadan Plain, SW Iran. Despite its reservoir significance, there is no comprehensive knowledge about the geological characteristics and factors controlling reservoir quality. In this study, the Ilam Formation is investigated using detailed core description, thin section study, and conventional petrophysical well log data to explain facies characteristics, sedimentary environment, and presenting the sequence stratigraphic framework. Accordingly, a total of 280 m of cores in four key wells from three oil fields as well as 620 thin sections were described and studied. The results of facies analysis lead to the recognition of 12 microfacies grouped in four facies belts including lagoon, shoal, shallow and deep open marine and two siliciclastic petrofacies (shales) related to brackish water and shallow lagoonal environment, which deposited in a carbonate ramp. Frequency analyses of facies associations and petrophysical well log signature indicate that the sedimentary basin was deepening to the east. Based on the identified sequence boundaries and maximum flooding surfaces, one third-order sequence in the studied interval was recognized and correlated by using the petrophysical well log data in all studied wells. The maximum flooding surfaces are discriminated by the development of deep-marine facies and also high gamma-ray responses on the well logs.

The Fahliyan Formation (Early Cretaceous) forms one of the main oil reservoir rocks in many oilfields in the Zagros specifically in the Dezful Embayment and Abadan Plain. For investigation of facies characteristics, depositional environment, diagenetic overprints and reservoir quality of this formation in one of the wells of an oilfield located in Abadan Plain province, the results of geological and petrophysical data including petrographic studies of thin sections, conventional core analysis and well logs were integrated. Facies analysis resulted in recognition of nine microfacies in the carbonate and two petrofacies in the siliciclastic-carbonate parts in the studied well. In addition, the carbonate microfacies were deposited in lagoon and shoal sub-environments, whereas petrofacies related to the siliciclastics dominated part falls within tidal flat environment. Based on evidences obtained in this study and comparison with the results from previous studies, it can be suggested that the Fahliyan Formation was deposited on shallow parts of a homoclinal carbonate ramp. Moreover, petrographic analysis demonstrates that diagenetic features have considerable both negative and positive effects on the reservoir characteristics and mainly regulate pore system characteristics. To identify flow units, a petrophysical method including stratigraphic modified Lorenz plot (SMLP) was applied. The results indicate that this method successfully classified the studied reservoir into discrete flow units by considering the relationship between petrophysical properties and depositional and diagenetic features. Finally, Based on SMLP method, ten flow units including four reservoir units (two speed zone and two good to fair flow units), three baffle units, two barrier units and one baffle-fair flow unit were differentiated.

Providing information about the role of the major elements controlling the type of Pliocene deposits in the south eastern part of the Caspian Basin by assessing regional and global parameters is very important to demonstrate the relationship between the tectono-sedimentary evolution and facies distribution of the area, and thereby discover the fields with the best stratigraphic and structural traps potential. Also, there is an indispensable query: which factors had controlled the the Type of Pliocene Deposits in the Southeastern Caspian Basin, NE Iran? In the present research, the Cheleken and Akchagyl formations with the Pliocene age, as the most potent constituents of reservoir intervals in the Caspian Basin, were investigated by considering facies types and the factors that controlled their variations. This research was done based on field observations, microscopy studies, and 2D seismic interpretations. Interpretation of facies and correlation along three surface stratigraphic sections and eleven exploration wells clearly justify the role of tectono-sedimentary agents controlling the distribution of the Pliocene formations in the Gorgan and Gonbad plains. Furthermore, the thickness of the Cheleken Formation increases towards the South Caspian Basin (SCB), and lithologically, it is mainly composed of conglomerates and gravely sandstones at the marginal parts grading into the silty claystone to marl facies towards the SCB. In addition, deposition of the Cheleken was accompanied by sea-level falling, and rapid subsidence resulted from the uplift and subsequent erosion of the Alborz and Kopet Dagh moun tains. In contrast, the Akchagyl Formation represents a relatively uniform thickness, and lithologically, it is consists of high-energy carbonate facies in the northeastern Gonbad-e Kavous area changing into the claystone and siltstone facies towards eastern parts of the South Caspian Basin. Ultimately, according to this study, it is found out that Akch agyl Formation records a major regional transgression and reconnection of the study area to the global oceans, which was confirmed by the presence of marine biota and flat geometry pattern of the sedimentary basin.

Carbonate formations are typically heterogeneous and anisotropic; hence, dipole sonic logs have great efficiencies in evaluating their geomechanical and petrophysical parameters. In this study, the various uses of DSI logs and processing approaches of its modes are presented as a case study in one of the SW Iranian fields. For this purpose, data from three modes (i.e. 3, 4, and X-dipole) of DSI logs, conventional logs, image log and porosity-permeability core data have been used. Moreover, using the DSI log data, it has been found out that stress state in the studied well is strike slip-normal, and the pore pressure is close to the hydrostatic pressure. In addition, regarding to the wellbore breakouts, the maximum horizontal stress direction is to NE-SW. Moreover, the fast shear wave azimuth is often aligned with the maximum horizontal stress direction. Furthermore, using the DSI log data, energy, traveltime and Dt anisotropies were calculated. The Dt anisotropy increases in fracture and washout zones and traveltime anisotropy which is affected by washouts. In this study, the factors which affect the reflection of the Stoneley waves, and the chevron patterns creation, have been investigated. Also, the most important factor in this case is the wellbore washouts. Finally, it has been found out that the Stoneley permeability has a relatively good correlation with the core permeability.

Rock typing is known as the best way in heterogeneous reservoirs characterization. The rock typing methods confine to various aspects of the rocks such as multi-scale and multi-modal pore types and size, rock texture, diagenetic modifications and integration of static/dynamic data. Integration of static and dynamic behavior of rocks and their sedimentary features are practiced in this study. Porosity, permeability and pore size distributions are investigated as the static and capillary pressure, water saturation and irreducible water saturation as dynamic behavior of the rocks. Results from core data analysis in some intervals and continuously NMR data through the whole well are also involved. Initially, based on Flow Zone Index method, while considering geological attributes, 7 rock types are determined. The petrophysical properties of the rock types including Pc, SW and SWir are combined into the rock types. Afterward, pore types, facies characteristics, texture and diagenetic overprints are involved in the rock type’s classification to capture spatial trends and relationships. Eventually, the rock types are defined in the cored intervals by these parameters and predicted in non-cored intervals by NMR. The rock types are established to provide a clue on the high and low permeable zones and accurate reservoir zonation.

This study has been focused on the relationship between cementation and dissolution processes with depositional facies and unconformity surfaces of upper part of the Sarvak Formation (Cenomanian-Turonian and mid-Turonian unconformity surfaces), using core and thin section data from a key well. Based on petrographic studies, six facies related to lagoon, slope and open marine sub-environments were identified. The results of this study indicate that the dissolution and cementation processes have been occurred in several diagenetic stages. Dissolution of unstable skeletal grains under the effect of eogenetic diagenesis created extensive vuggy porosity. In addition, during the telogenetic diagenesis and in relation to unconformity surfaces, vuggy pore types within the grains and rock matrix have been developed. The distribution of calcite cement within the reservoir shows a close relationship with initial mineralogy of the skeletal grains, size of dissolution vugs as well as density and the width of the factures. Calcite cement occurs as drusy and blocky forms and with meteoric and burial source within the dissolution vugs and microfractues. Within the Turonian interval that has been situated below the mid-Turonian unconformity, due to the mud-dominated nature of lagoon and open marine facies, dissolution and cementation have insignificant distribution, and calcite cement is mostly observed in relation to fractures. In contrast, in the interval below the Cenomanian-Turonian boundary, these processes have more distribution due to the frequency of grain-dominated facies. The results of this study show that the nature of depositional facies has significant role on distribution of cementation and dissolution processes within the Sarvak Formation.

The Sarvak Formation with the late Albian-early Turonian age is the most prolific hydrocarbon reservoir of the Abadan Plain region. Permeability estimation in heterogeneous carbonate reservoirs; such as, the Sarvak Formation, due to the complexity of pore characteristics is challenging, and porosity-permeability relationship in these reservoirs is dependent on pore type, size and connectivity of pore systems. In this study, permeability estimation has been accomplished using the pore facies concept and empirical formula. Based on the core description, thin sections’ studies and SEM images, pore types were identified and described. Afterwards, with respect to the petrophysical nature of pore systems and their porosity-permeability relationships, four pore facies microporosity (PF-1), microporosity-vuggy (PF-2), vuggy (PF-3) and vuggy-interparticle (PF-4) were introduced. In each pore facies, an empirical formula for the permeability estimation based on porosity-permeability relationship were determined. Comparison the results with the permeability values estimated in previous studies demonstrates that the estimation of permeability on the basis of pore facies concept has higher concordant with depositional and diagenetic characteristics. Generally, the intervals with microporosity and separate vugs, due to the weak pore system connectivity, a lower value of permeability will be estimated. In contrast, the intervals with interconnected pore systems such as touching vugs and interparticle pore spaces show higher permeability in comparing with the other pore types with the same values of porosity. Regarding the importance of pore type and geometry on permeability distribution within the reservoir, permeability estimation in term of pore facies can be useful in investigating the reservoir properties of heterogeneous carbonate reservoirs.

The Oligo-miocene Asmari formation is one of the most important hydrocarbon reservoirs in the southwest of Iran. In order to evaluate reservoir quality and the factors controlling reservoir properties, detailed geological and petrophysical studies were carried out on 242 m of core samples from Asmari reservoir. This study is a part of a larger project that examines depositional history and reservoir properties of the Asmari formation in the Cheshmeh-Khush field. Macroscopic and microscopic studies resulted in the determination of 5 shallow marine carbonate facies (from proximal open marine to tidal setting) and also 5 silisiclastic lithofacies (including channel, barrier, tidal, and shoreface sandstones). Based on the integrated results from sedimentological and paleontological studies, Sr isotopes dating, gamma-ray logs, and seismic data analysis, 5 depositional sequences with constituent system tracts were distinguished.
In this research, the reservoir characterization of the Asmari reservoir were carried out through the integration of geological and petrophysical properties. In the first step, 21 hydraulic flow units (HFU or FU) were identified and then, to achieve better lateral correlation and modeling, HFU’s were merged to 17.
The results from this study showed different behaviors of the silisiclastic and carbonate facies next to the fluid flow. The findings of this study indicate that the lateral and vertical distribution of channel-filled sandstones (such as units 2 and 8) are strongly controlled by the geometry of depositional facies. Thus, the correlation and modeling of flow units, solely on the basis of lithology and thickness, and regardless of facies and its geometry, will cause different facies (such as coastal and channel-filled sandstones) with different geometry, and reservoir quality are placed incorrectly in a single flow unit.
In the carbonate parts of Asmari formation, the effect of diagenetic processes on reservoir quality is much higher than the facies. Hence, the LST limestones of unit 17, as a result of calcite cementation, were changed to a thick, distinct, correlatable, and barrier unit. On the other hand, dolomitic intervals that have not been affected by anhydrite cementation have formed porous and permeable carbonate reservoir units (such as units 18 and 21).

The Sarvak Formation is one of the most important carbonate reservoirs of Iran. This study presents an integrated geological and petrophysical reservoir characterization of the Sarvak Formation in a giant oil field in the Abadan Plain, SW Iran. On the basis of porosity-permeability data, core description and petrographic studies from two key wells, flow units were identified and interpreted. To identify flow units within the Upper Sarvak Formation, three different petrophysical methods including (1) Flow Zone Indicator (FZI), (2) Pore Throat Radius (R35) and (3) stratigraphic modified Lorenz plot (SMLP) were applied. The results indicate that the FZI and R35 methods cannot efficiently discriminate the different reservoir zones and flow units for this reservoir, because of the high changes in petrophysical properties have mainly inherited from the internal geological heterogeneity. In contrast, SMLP method successfully classifies the studied reservoir into discrete flow units by considering the relationship between petrophysical properties and depositional and diagenetic features. From depositional facies point of view, the best flow units are related to talus, shoal-biostrome and shallow open marine depositional facies, while lagoon and distal open marine commonly show low reservoir quality. In low reservoir quality units, calcite cementation and compaction are the dominant diagenetic processes, while dissolution is the main agent for enhancing of the reservoir quality in the reservoir units with high quality. The results indicate that the interpretation of flow units based on the depositional and diagenetic characteristics provides the crucial insight on distribution of reservoir zones within the heterogeneous carbonate reservoirs, such as, the Sarvak Formation.

During the precipitation of Sarvak formation imprints of climate, tectonic and sea level fluctuation lead to some of the most prolific reservoirs in Zagros and Persian Gulf basins. The reservoir quality of upper Sarvak formation in Abadan plain oil fields are highly influenced by various diagenetic process. Based on core studies, petrographic analysis, well logs and properm data from two key well in a giant field, diagenetic sequence is reconstructed and the main processes effecting the reservoir quality are discussed. Three main diagenetic environments including 1- marine diagenesis (Micritization, Bioturbation, marine cementation) 2- meteoric diagenesis (mineralogy stability, recrystallization, meteoric cementation, mixing zone dolomitization, Dedolomitization, fabric and none fabric selective dissolution) and finally 3- burial diagenesis (physical and chemical compaction, burial dolomitization, fracturing, burial cementation, Silicification and pyritization and some none fabric dissolution) have affected the upper Sarvak formation after deposition. Dissolution of matrix and grain, especially aragonite shells was a main porosity creating process, and took place primarily by meteoric diagenesis. Diagenetic studies indicate meteoric environment products highly modified reservoir quality. Calcite cementation and compaction are the chief factors controlling the reduction properm whilst dissolution and fracturing have enhanced reservoir quality of the studied interval. This study resulted that distribution and intensity of diagenetic process are dominantly controlled pore systems and reservoir quality.

The cretaceous (Albian) Burgan formation is one of the most important reservoirs in the hydrocarbon fields located in the Persian Gulf and Kuwait. In order to evaluate reservoir quality and the factors controlling reservoir properties, detailed geological (from lithological and sedimentological point of views) and reservoir studies (core analysis) have been carried out on 62.5 m of core samples from Burgan reservoir in the Foroozan field. This study shows that the Burgan formation, which mainly consists of very fine to medium-grained sandstone, claystone, carbonaceous shale, and some limited carbonate intervals, includes eight sedimentary facies deposited on a tide-dominated estuary system. These are: (1) cross-bedded channel sandstones, (2) mud flat/bay, (3) sand bar, (4) sand flat/mud flat alternation, (5) marine-influenced mud flat/shore face, (6) marine influenced sand flat/shore face, (7) restricted bay/marsh, and (8) oolitic shoal. Core porosity and permeability measurements of Burgan core plugs show that the porosity and permeability range from 3 to 36.3% and 0.6 to 13343 mD respectively. Core porosity and permeability values indicate that there is a good relationship between reservoir properties and depositional facies of the Burgan formation. Fine to medium-grained channel sandstones have the best reservoir quality, whereas shale and claystone samples belonging to mud flat to restricted bay/marsh settings have low porosity and permeability and considered as non-reservoir intervals. A comparison between core porosity/permeability values and grain size and textural parameters of the Burgan unconsolidated sands shows a good relationship between reservoir quality and grain size/sorting.

Asmari formation, assigned to Oligocene-Lower Miocene, forms the most important hydrocarbon reservoir in the south and southwest of Iran. In the studied field, Asmari formation constitutes a sequence of carbonate (common at upper part) and clastic (common at lower part) sediments. The carbonate section belonging to early Miocene and being commonly assigned to shallow marine, high energy barrier and lagoon is severely subjected to diagenetic processes. Macro-microscopic studies (core and thin section) along with geochemical and conventional core analysis showed that, in dolostone intervals, the development of intercrystalline pore spaces and the presence of primary interparticle pore spaces on the one hand and the performance of compaction and evaporite mineralization on the other hand caused considerable changes in reservoir quality. This study aimed to investigate the effect of evaporite (anhydrite and celestite) mineralization on the Asmari reservoir properties. This research showed that the quantity and distribution of evaporitic minerals, namely anhydrite and celestite, played a very significant role in controlling the reservoir quality of dolostone intervals. The most common and efficient forms of anhydrite and celestite distribution occur as pore space cement-filling, poikilotopic, replacement, and occasional fracture-filling. Evaporitic cement-filling that occupies about 40% of intergranular (in early burial) and intercrystalline pore spaces, noticed in some samples, have reduced the porosity and permeability of dolostone intervals to nearly zero value. Primary and secondary nodular forms having considerable extent in all facies have not decreased the reservoir quality of Asmari formation.