Carbonate reservoirs are very complex and heterogeneous. Overcoming heterogeneity is important and necessary for accurate reservoir characterization. Dalan-Kangan formations, as the largest non-associated gas reservoir of the world, are heterogeneous and complex due to the influence of the sedimentary environment and diagenesis processes. Carbonate reservoirs are routinely studied using laboratory data. The use of well logging instead of using laboratory methods is very cost-effective in reducing time and cost. To overcome the heterogeneity by acoustic log, samples of Dalan-Kangan carbonate formations were prepared. A total of 87 limestone thin sections were evaluated by petrography, routine core analysis, and sonic velocity. Porosity, permeability, sedimentary textures, pore types, and diagenetic processes were determined precisely. From the studied well, well logging and acoustic logs were also available. After data quality control, the acoustic log was converted to velocity. Velocity-porosity model was constructed based on the differential effective medium (DEM) approach for different values of equivalent pore aspect ratio (EPAR). The results show that moldic, vuggy, interparticle, and microporosity pores have the largest aspect ratio, respectively. Due to their spherical shape and high aspect ratio at the given porosity, moldic and vuggy pores have higher velocity than flat and narrow pores. Through the geometrical shape and pore type and by using the acoustic log, the rock types were determined. These rock types clearly showed the porosity evolution, permeability changes and diagenetic processes that have been occurred in Dalan-Kangan reservoirs.

Determination of porosity, permeability, and pore volume compressibility of reservoir rocks and those variations with effective stress changes are of great interest in petroleum engineering. This paper has studied the influence of pore types of carbonate reservoir rocks on pore volume compressibility as well as Klinkenberg permeability and porosity at different stress values. In the current study pore volume compressibility tests have been done on 38 limestone and 8 dolomite samples. The experiments show the importance of rock type description of the reservoir rocks. Carbonate rocks with touching vug pores have different behavior from the other studied carbonates in this paper. This complex behavior is related to the role of connecting paths closure on the characteristics of hydraulic conductivity of the rock while there is no more changes in porosity or volume change. It means that the planar connecting paths have more effect on hydraulic conductivity of this rock type, while it has not more effect on porosity. Also, in all rock types excluding touching vuggy pores limestone, increasing the initial porosity leads to increase the permeability at the same effective stress value.

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.

Pore type distribution in reservoir rocks is the main factor controlling fluid flow in porous media. Therefore, determination of pore types in reservoir rocks leads to better prediction of the number of wells to be drilled in the field and to improved forecasts of recoverable hydrocarbon. Hydrocarbon reservoirs, especially carbonate rocks, have complex pore types and sizes. In this study, pore types of the Asmari formation are recognized with log data and are validated by core data. For determination of pore types from log data, a velocity deviation log method was used. Based on velocity deviation log and elastic properties, pore types were classified into three classes (positive, zero, and negative) and eight subclasses. They include intraparticle (intrafossil), moldic or vuggy, microporosity, interparticle, intercrystalline, intergranular, shale microporosity, and fracture porosities. In this field both carbonate and clastic intervals had high potential for production. To determine reservoir quality, hydraulic flow units along with their pore type’s spectrum were investigated. For this purpose, flow units were determined with the flow zone index method. Results of this study led to the determination of three flow units in the carbonate section, with two flow units in the clastic interval. Accordingly, pore type distribution was investigated in each individual flow unit. Finally, results of this study showed that the production in this field is controlled with four pore types that were recognized by the velocity deviation log along the well bore.

In hydrocarbon reservoirs (especially in carbonate rocks)، the variation of pore type and size is influenced by diagenesis effects. Hence pore type distribution and capillary pressure in the reservoir rock is the main factor controlling fluid flow in porous media. In other words، the determination of pore type/size and capillary pressure has an important role in understanding petrophysical features، optimizing the number of wells in the field، and forecasting the recoverable hydrocarbon. In this paper، pore types in the mixed carbonate-siliciclastic Asmari formation is divided by velocity deviation log into three classes (positive، zero، and negative deviation) and eight subclasses. Six subclasses are related to carbonate part (interaparticle or interafossil، moldic or vuggy، microporosity، interparticle، intercrystalline، and fracture) and two subclasses are related to clastic part (intergranular and shale microporosity). After identifying pore types، pore size and pseudo capillary pressure are continuously determined in each subclasses throughout the well bore by using NMR log. Pore size and pseudo capillary pressure are compared by mercury injection capillary pressure curves. The results of this study show that intergranular porosity is the main factor for production in calstic intervals; however، fracture، interparticle، and intercrystalline porosities play an important role in carbonate intervals. The distributions of each four pore types are continuously determined along the well bore.

The most prominent parameter of seismic studies is seismic wave velocity. This parameter is influenced by different factors such as rock properties (Compaction, age, Lithology, Porosity, Pore Shape and etc), fluid properties (Viscosity, Density, fluid type, Saturation) and environment (Stress history, Depositional environment, production history, temperature, pressure, etc). Therefore, by identification, study and investigation of the relationship between seismic velocity and these parameters, properties of rock, fluid and environment from seismic data can be inferred. The main factors affecting these parameters are the porosity and pore ambiences. Many studies have been conducted to obtain and understand these relations. Most of the theoretical equations haven’t considered changes in seismic properties from pores. Therefore, the seismic inversion, AVO and pore volume calculated based on these equations, include much uncertainties. One of the equations that consider several factors such as porosity, pore type, mineralogy and pore fluid is provided by Kuster and Toksoz. In this study, using this equation and inverse modeling technique, geometry and pore type and percentage of any type of pore shape in 3 wells penetrated one Irainain hydrocarbon reservoir were estimated. In this reservoir, Spherical and Disk shape have the highest percentage.

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.

Nano pore Mordenite membranes were prepared on the outer surface of ceramic tubular tubes via hydrothermal synthesis and evaluated for dehydration pervaporation of water unsymmetrical dimethyl hydrazine UDMH mixtures. Highly water-selective mordenite membranes were prepared and the optimum reaction condition was found to be 24 h crystallization time and 170 oC crystallization temperature. Effect of gel composition on separation factor and water flux of the water-UDMH mixtures was investigated. X-ray diffraction (XRD) patterns showed that mordenite is the only zeolite material which presents in the membrane. Morphology of the supports subjected to crystallization was characterized by Scanning electron microscopy (SEM). In PV of the water-UDMH mixtures, the membrane exhibits a hydrophilic behavior, with a high selectivity towards water and a good flux. The best membranes had a water flux of 2.67 kg/m2.h at 27 oC. The best PV selectivity was obtained to be 264.