فهرست مطالب ehsan kamari

One of the effective methods in the process of enhanced recovery of oil reservoirs is applying the nanotechnology to alter the wettability of the reservoir rock. In this study, the wettability alteration was investigated using synthetic graphene oxide-Hexamethyldisilazane (GO-HMDS). For this purpose, XRD and FTIR analyzes were used to identify the synthesized structure. In the present study, the effect of concentration (0.05, 0.1 and 0.2 wt% GO-HMDS) were investigated using the zeta potential analysis, Interfacial Tension (IFT), and contact angle. Subsequently, the concentration of 0.2% was determined as a powerful sample in altering the wettability of the reservoir rock through the zeta potential analysis. This sample was used for tests of contact angle and interfacial tension. In addition the zeta potential of the sample was measured by -36 mv. Moreover, the contact angle between the reservoir rock and the graphene oxide- (Hexamethyldisilazane) solution for 0.2 wt.% GO-HMDS solution decreased from 161 to 44 degrees. On the other hand, it is in agreement the results of the zeta potential and Interfacial Tension (IFT) examines. Therefore, the synthesized nanofluid reduces the and Interfacial Tension (IFT), contact angle, and wettability alteration toward the water-wet of the carbonate core.

Equilibrium ratios for the mixture of different components are very important for many engineering application processes. Different numerical methods were explored and applied to ensure efficient estimation of gas-liquid equilibrium ratio. In this paper, the Artificial Neural Network (ANN) approach along with data of experiments performed on 25 gas condensate reservoirs has been utilized to obtain a relationship of gas-liquid equilibrium ratios in gas condensate reservoirs. The relationship between the gas-liquid equilibrium ratio and parameters of components of a mixture (critical temperature, critical pressure, and acentric factor) has been derived. Finally, the results of ANN have been compared to the proposed correlations in the literature and results of the equation of state. This investigation demonstrated that the result of ANN is more precise than the equation of state and existing empirical correlations. Whereas comparison between experimental data of 3 gas condensate samples by ANN, EOS, and existing empirical correlation show that the average absolute error for ANN was between 7.82 to 13.74% and for others was between 29.99 to 94.99%.

In this article, strong correlations for the cementation factor and saturation exponent were discovered by genetic programming (GP) algorithm. The cementation factord GP-base model was trained by input variables such as porosity, permeability, and grain density derived from 175 routine core analysis (RCAL) samples of 21 carbonated oil fields. Also, porosity, permeability, and wettability index were considered as input variables of saturation exponent model. The proposed correlations using GP improved greatly the average absolute error for the Archie’s parameters. The root mean square error and correlation coefficient of validation data for the new cementation factor correlation were 0.062 and 0.91, and for saturation exponent model, they were 0.051 and 0.96 respectively. The importance of theses correlations is in their dependence on simple measurable parameters, and except wettability index all of the independent parameters are simple routine core analysis parameters which can be measured easily and at no considerable expense.

Formation of condensates around the wellbore in gas condensate reservoirs reduces the efficiency of well performance, and it can be intensified depending on the fluid type, reservoir and well properties. Adequate and appropriate information can be helpful for accurate modelling of gas condensate reservoirs. Disregarding the dependence of gas-oil relative permeability on capillary number and high the velocity flow (non-Darcy flow) may cause miscalculations and poor estimations in gas condensate reservoirs. In this paper, a sector model of South-Pars gas condensate field located in the Persian Gulf was simulated using ECLIPSE-300, and the effect of the capillary number and non-Darcy flow on cumulative condensate production and condensate formation near the wellbore and in the reservoir were investigated. Obtained results reveal that production increases as the bottom-hole pressure decreases and/or the production flow rate increases; however, more pressure drop and condensate blockage were occurred. Thus, bottom-hole pressure and the production flow rate should be optimized for efficient production. In addition, taking into account the effect of the capillary number on relative permeability decreases condensate formation near the wellbore and in the reservoir. Non-Darcy flow increases pressure drop, resulting in more condensate blockage near the wellbore. Ignoring the effect of the capillary number and non-Darcy flow in simulation process will strongly affect the accurate prediction of well performance in gas condensate reservoirs.

Here, a series of immiscible displacement processes have been performed on fractured porous medium developed on glass micro-models in order to investigate the role of fracture characteristics on oil displacement efficiency during immiscible displacement process. Oil recoveries were determined from image analysis of continuously recorded pictures during different flooding schemes. A clear bypassing of displacing fluid which results in premature breakthrough of injected fluid due to the fracture has been observed. Moreover, the results showed a decrease of oil recovery when fracture''s length increased. In contrast, an increase of fracture orientation from flow direction increased oil recovery. Results of this work may be useful for through understanding of immiscible displacement process as well optimal field development plans.

Iran''s proved natural gas reserves are the world''s second largest reserves. Mainly, because of different climate changes and different reservoirs characterizations, studying the behavior of producing outcome fluids and their transportation, is of major interest. One of the main problems occur in the gas reservoirs is related to the hydrate formation while producing from a well, either in production strings or lines (before and after choke). Effective parameters which lead to hydrate formations are: high pressure in strings, low wellhead temperature together with water presence; and hence, the high possibility of having this phenomenon in the reservoirs is quite obvious for the gas wells. Hydrate formation in production lines and facilities will also lead to different impediments such as: complete or partial closure in production lines and heat exchangers, erosion of the equipment, pressure reduction, and etc. In this research, the conditions of hydrate formation, using the experimental data from one the Iranian sour gas field that is helpful to determine the safe/unsafe zones by P-T curves, are thoroughly investigated. In addition, the results will be compared to the other presented correlations available in the literature.