Riyaz Kharrat
@put.ac.ir
Petroleum University of Technology
Scopus Publications
Scopus Publications
Reza Khoramian, Peyman Pourafshary, Saeed Golshokooh, and Riyaz Kharrat
Elsevier BV
Gerd Hublik, Riyaz Kharrat, Ali Mirzaalian Dastjerdi, and Holger Ott
MDPI AG
This study delves into the properties and behavior of xanthan TNCS-ST, a specialized variant designed for enhanced oil recovery (EOR) purposes. A notable aspect of this polymer is its transparency and capability to dissolve in high salt concentrations, notably up to 18% total dissolved solids. Various laboratory methods are employed to assess the polymer’s distinctive traits, including transparency, salt tolerance, and high pyruvylation. These methods encompass preparing xanthan solutions, conducting filtration tests, assessing energy consumption, and measuring rheological properties. The findings highlight the influence of salt concentration on xanthan’s filterability, indicating increased energy requirements for dissolution with higher salt and xanthan concentrations. Additionally, this study observes temperature-dependent viscosity behavior in different solutions and evaluates the shear stability of xanthan. A significant and novel characteristic of TNCS-ST is its high salt tolerance, enabling complete dissolution at elevated salt concentrations, thus facilitating the filterability of the xanthan solution with sufficient time and energy input. Core flooding experiments investigate fluid dynamics within porous rock formations, particularly sandstone and carbonate rocks, while varying salinity. The results underscore the substantial potential of the new xanthan polymer, demonstrating its ability to enhance oil recovery in sandstone and carbonate rock formations significantly. Remarkably, the study achieves a noteworthy 67% incremental recovery in carbonate rock under the high salinity level tested, suggesting promising prospects for advancing enhanced oil recovery applications.
Farshad Jafari, Mohammad Ali Karambeigi, Shahab Hejri, and Riyaz Kharrat
Elsevier BV
Ali Mirzaalian Dastjerdi, Riyaz Kharrat, Vahid Niasar, and Holger Ott
American Chemical Society (ACS)
The structural and dynamic properties of fluids under confinement in a porous medium differ from their bulk properties. This study delves into the surface structuring and hydrodynamic characteristics of oil/thin film carbonated brine two-phase within a calcite channel upon salinity variation. To this end, both equilibrium and non-equilibrium molecular dynamics simulations are utilized to unveil the effect of the carboxylic acid component (benzoic acid) in a simple model oil (decane) confined between two thin films of carbonated brine on the oil-brine-calcite characteristics. The salinity effect was scrutinized under four saline carbonated waters, deionized carbonated water (DCW), carbonated low-salinity brine (CLSB, 30,000 ppm), carbonated seawater (CSW, 60,000 ppm), and carbonated high-salinity brine (CHSB, 180,000 ppm). An electrical double layer (EDL) is observed at varying salinities, comprising a Stern-like positive layer (formed by Na+ ions) followed by a negative one (formed by Cl- ions primarily residing on top of the adsorbed sodium cations). By lowering the salinity, the Na+ ions cover the interface regions (brine-calcite and brine-oil), depleting within the brine bulk region. The lowest positive surface charge on the rock surface was found in salinity corresponding to seawater. Two distinct Na+ peaks at the oleic phase interface have been observed in the carbonated high-salinity brine system, enhancing the adsorption of polar molecules at the thin brine film interfaces. There is a pronounced EDL formation at the oleic phase interface in the case of CSW, resulting in a strong interface region containing ions and functional fractions. Likewise, the oil region confined by CSW exhibited the lowest apparent viscosity, attributed to the optimized salinity distribution and inclination of benzoic acid fractions uniformly at the brine-oil interface, acting as a slippery surface. Moreover, the results reveal that the presence of polar fractions could increase the oil phase's apparent viscosity, and introducing ions to this system reduces the polar molecules' destructive effect on the apparent viscosity of the oil region. Therefore, the fluidity of confined systems is modulated by both composition of the brine and oil phases.
Ali Mirzaalian Dastjerdi, Riyaz Kharrat, Vahid Niasar, and Holger Ott
Elsevier BV
Riyaz Kharrat, Nouri Alalim, and Holger Ott
MDPI AG
Numerous reservoirs that play a significant role in worldwide petroleum production and reserves contain fractures. Typically, the fractures must form a connected network for a reservoir to be classified as naturally fractured. Characterizing the reservoir with a focus on its fracture network is crucial for modeling and predicting production performance. To simplify the solution, dual-continuum modeling techniques are commonly employed. However, to use continuum-scale approaches, properties such as the average aperture, permeability, and matrix fracture interaction parameters must be assigned, making it necessary to improve the fracture depiction and modeling methods. This study investigated a fractured reservoir with a low matrix permeability and a well-connected fracture network. The focus was on the impact of the hierarchical fracture network on the production performance of gas-based enhanced oil recovery methods. The discrete fracture network (DFN) model was utilized to create comprehensive two-dimensional models for three processes: gas injection (GI), water alternating gas (WAG), and foam-assisted water alternating gas (FAWAG). Moreover, dimensionless numbers were employed to establish connections between properties across the entire fracture hierarchy, spanning from minor to major fractures and encompassing the fracture intensity. The results indicate that the FAWAG process was more sensitive to fracture types and networks than the WAG and GI processes. Hence, the sensitivity of the individual EOR method to the fracture network requires a respective depth of description of the fracture network. However, other factors, such as reservoir fluid properties and fracture properties, might influence the recovery when the minor fracture networks are excluded. This study determined that among the enhanced oil recovery (EOR) techniques examined, the significance of the hierarchical depth of fracture networks diminished as the ratio of major (primary fracture) aperture to the aperture of medium and minor fractures increased. Additionally, the impact of the assisted-gravity drainage method was greater with increased reservoir height; however, as the intensity ratio increased, the relative importance of the medium and minor fracture networks decreased.
Armin Abbaspour, Arezou Jafari, Delaram Sadat Tarahomi, Seyyed Mohammad Mousavi, and Riyaz Kharrat
Elsevier BV
Riyaz Kharrat and Holger Ott
MDPI AG
Naturally fractured reservoirs are indescribable systems to characterize and difficult to produce and forecast. For the development of such reservoirs, the role of naturally forming fractures in the different development stages needs to be recognized, especially for the pressure maintenance and enhanced oil recovery stages. Recent development in the field of naturally carbonate fractured aimed at fracture characterization, fracture modeling, and fracture network impact of fracture networks on oil recovery were reviewed. Consequently, fracture identification and characterization played pivotal roles in understanding production mechanisms by integrating multiple geosciences sources and reservoir engineering data. In addition, a realistic fracture modeling approach, such as a hybrid, can provide a more accurate representation of the behavior of the fracture and, hence, a more realistic reservoir model for reservoir production and management. In this respect, the influence of different fracture types present in the reservoir, such as major, medium, minor, and hairline fractures networks, and their orientations were found to have different rules and impacts on oil production in the primary, secondary, and EOR stages. In addition, any simplification or homogenization of the fracture types might end in over or underestimating the oil recovery. Improved fracture network modeling requires numerous considerations, such as data collection, facture characterization, reservoir simulation, model calibration, and model updating based on newly acquired field data are essential for improved fracture network description. Hence, integrating multiple techniques and data sources is recommended for obtaining a reliable reservoir model for optimizing the primary and enhanced oil recovery methods.
Milos Pejic, Riyaz Kharrat, Ali Kadkhodaie, Siroos Azizmohammadi, and Holger Ott
MDPI AG
Since more than half of the crude oil is deposited in naturally fractured reservoirs, more research has been focused on characterizing and understanding the fracture impact on their production performance. Naturally open fractures are interpreted from Fullbore Formation Micro-Imaging (FMI) logs. According to the fracture aperture, they are classified as major, medium, minor and hairy fractures in decreasing order of their respective aperture size. Different fracture types were set up in this work as a Discrete Fracture Network (DFN) in synthetic models and a sector model from a highly naturally fractured carbonate reservoir. The field sector model includes four wells containing image logs from two wells and production data from two other wells. Numerous simulations were conducted to capture the contribution of fracture type on production performance. Primary recovery was used for synthetic and field sector models, while waterflooding and gas injection scenarios were considered just for the synthetic models. The results showed that the fracture type and its extent play an essential role in production for all studied models. The reservoir production capabilities might be underestimated by ignoring any fracture types present in the reservoir, especially the major ones. In the secondary recovery, fractures had different impacts. Better displacement and higher recovery were promoted for waterflooding, whereas faster breakthrough times were observed for the gas injection. The performance during gas injection was more dependent on fracture permeability changes than waterflooding. This study’s findings can help in better understanding the impact of the different types of fracture networks on oil recovery at the various production stages. Additionally, the history matching process can be improved by including all types of fractures in the dynamic model. Any simplification of the fracture types might end in overestimating or underestimating the oil recovery.
Reza Khoramian, Riyaz Kharrat, Peyman Pourafshary, Saeed Golshokooh, and Fatemeh Hashemi
MDPI AG
Organic surfactants have been utilized with different nanoparticles in enhanced oil recovery (EOR) operations due to the synergic mechanisms of nanofluid stabilization, wettability alteration, and oil-water interfacial tension reduction. However, investment and environmental issues are the main concerns to make the operation more practical. The present study introduces a natural and cost-effective surfactant named Azarboo for modifying the surface traits of silica nanoparticles for more efficient EOR. Surface-modified nanoparticles were synthesized by conjugating negatively charged Azarboo surfactant on positively charged amino-treated silica nanoparticles. The effect of the hybrid application of the natural surfactant and amine-modified silica nanoparticles was investigated by analysis of wettability alteration. Amine-surfactant-functionalized silica nanoparticles were found to be more effective than typical nanoparticles. Amott cell experiments showed maximum imbibition oil recovery after nine days of treatment with amine-surfactant-modified nanoparticles and fifteen days of treatment with amine-modified nanoparticles. This finding confirmed the superior potential of amine-surfactant-modified silica nanoparticles compared to amine-modified silica nanoparticles. Modeling showed that amine surfactant-treated SiO2 could change wettability from strongly oil-wet to almost strongly water-wet. In the case of amine-treated silica nanoparticles, a strongly water-wet condition was not achieved. Oil displacement experiments confirmed the better performance of amine-surfactant-treated SiO2 nanoparticles compared to amine-treated SiO2 by improving oil recovery by 15%. Overall, a synergistic effect between Azarboo surfactant and amine-modified silica nanoparticles led to wettability alteration and higher oil recovery.
Zeinab Taherian, AmirHossein Saeedi Dehaghani, Shahab Ayatollahi, and Riyaz Kharrat
Elsevier BV
Ronald Gugl, Riyaz Kharrat, Ali Shariat, and Holger Ott
MDPI AG
More than half of all recoverable oil reserves are found in carbonate rocks. Most of these fields are highly fractured and develop different zonations during primary and secondary recovery stages; therefore, they require a different developmental approach than conventional reservoirs. Experimental results for water-alternating gas injection [WAG] and foam-assisted water-alternating gas [FAWAG] injection under secondary and tertiary recovery conditions were used to investigate these enhanced oil recovery [EOR] methods in gas-invaded reservoirs. The relative permeability curves of the cores and the fitting foam parameters were derived from these experiments through history matching. These findings were then used in a quarter five-spot, cross-sectional, and a sector model of a carbonate reservoir where a double five-spot setup was implemented. The fracture and matrix properties’ impact on the recovery was illustrated through the cross-sectional model. The gas mobility reduction effect of the FAWAG was more noticeable than that of WAG. The apparent viscosity of the gas was increased due to the foam presence, which caused a diversion of the gas from the fractures into the matrix blocks. This greatly enhanced the sweep efficiency and led to higher oil recovery. The gas front was much sharper, and gravity overrides by the gas were much less of a concern. The properties of the fracture network also had a significant effect on the recovery. Oil recovery was found to be most sensitive to fracture permeability. At the same time, sweep efficiency increased substantially, improving the recovery rate in the early injection stages, and differed slightly at the ultimate recovery. However, a lower fracture permeability facilitated gas entry into the matrix blocks. The results of the reservoir sector model were similar to the core and pilot. However, the WAG injection recovered more of the uppermost layers, whereas significant portions of the lowest layer were not effectively recovered. In contrast, FAWAG was more effective in the lowest layer of the reservoir. The FAWAG was a beneficial aid in the recovery of gas-invaded fractured reservoirs, increasing the oil recovery factor with respect to WAG.
Reza Khoramian, Riyaz Kharrat, and Saeed Golshokooh
Elsevier BV
Zeinab Taherian, AmirHossein Saeedi Dehaghani, Shahab Ayatollahi, and Riyaz Kharrat
Elsevier BV
Riyaz Kharrat, Mehdi Zallaghi, and Holger Ott
MDPI AG
The enhanced oil recovery mechanisms in fractured reservoirs are complex and not fully understood. It is technically challenging to quantify the related driving forces and their interaction in the matrix and fractures medium. Gravity and capillary forces play a leading role in the recovery process of fractured reservoirs. This study aims to quantify the performance of EOR methods in fractured reservoirs using dimensionless numbers. A systematic approach consisting of the design of experiments, simulations, and proxy-based optimization was used in this work. The effect of driving forces on oil recovery for water injection and several EOR processes such as gas injection, foam injection, water-alternating gas (WAG) injection, and foam-assisted water-alternating gas (FAWAG) injection was analyzed using dimensionless numbers and a surface response model. The results show that equilibrium between gravitational and viscous forces in fracture and capillary and gravity forces in matrix blocks determines oil recovery performance during EOR in fractured reservoirs. When capillary forces are dominant in gas injection, fluid exchange between fracture and matrix is low; consequently, the oil recovery is low. In foam-assisted water-alternating gas injection, gravity and capillary forces are in equilibrium conditions as several mechanisms are involved. The capillary forces dominate the water cycle, while gravitational forces govern the gas cycle due to the foam enhancement properties, which results in the highest oil recovery factor. Based on the performed sensitivity analysis of matrix–fracture interaction on the performance of the EOR processes, the foam and FAWAG injection methods were found to be more sensitive to permeability contrast, density, and matrix block highs than WAG injection.
Loay Al Karfry, Riyaz Kharrat, and Holger Ott
Wiley
Payam Soleimani, Seyed Reza Shadizadeh, and Riyaz Kharrat
Elsevier BV
Abstract Different methods of enhanced oil recovery have been used to produce trapped oil. One of these methods is carbonated water injection in which CO2 contained water is injected in reservoirs in order to decrease free CO2 injection mobility, increase water viscosity and store/remove produced greenhouse CO2 gas safely. Another enhanced oil recovery method is smart water injection at which the ions in brine are modified in order to make controlled reactions with distributed ions on the surface of rock to cause more hydrocarbon recovery. Therefore, combination of these two methods may also have a great effect on enhancing oil recovery or may result in recovery factor less than each method used alone. In this paper hybrid smart carbonated water injection method is investigated to study its applicability in oil recovery using core flooding setup. The experimental core flooding setup was designed to perform different types of EOR methods for the sake of recovery comparison with the new hybrid method. The effect of both brine content and volume of CO2 is determining in hybrid EOR assessment. The main findings of this work show that the hybrid smart carbonated water results in the highest recovery factor in comparison to the most well-known EOR methods for carbonate cores.
Reza Elhaei, Riyaz Kharrat, and Mohammad Madani
Elsevier BV
Abstract In this study, the characterization and rheological behavior of silica suspensions in aqueous/polymeric media are investigated. The variation of silica nanoparticles size and concentration, polymer molecular weight and concentration, pH, valency, and concentration of electrolytes are considered for this purpose. The findings show that bridging flocculation of dispersed silica nanoparticle-augmented polymer solution increases with nanoparticle concentration, nanoparticle diameter, the charge of electrolyte, and electrolyte concentration. In contrast, it decreases with an increase in pH and polymer concentration. Also, the intrinsic shear viscosity of aqueous polymer solution increases with molecular weight, unlike the behavior of polymer solution in the presence of silica nanoparticles. The shear viscosity and the rate of bridging flocculation of the silica nanoparticle-augmented polymer solution primarily increase until it reaches a maximum and finally decreases with further increasing polymer molecular weight. In polymer high molecular weight and high concentration, the repulsion due to steric stabilization overcomes the interaction between two adsorbed polymer chains resulting in a stable form of suspension. By utilizing the proper conditions, core flooding experiments are designed and implemented to enhance the hydrolyzed polyacrylamide polymer flooding efficiency. Around 20–52% higher recovery was obtained for the silica nanoparticle-augmented polymer solutions with respect to the polymer flooding.
Payam Soleimani, Seyed Reza Shadizadeh, and Riyaz Kharrat
Inderscience Publishers
Muhammad Suleymani, Siavash Ashoori, Cyrus Ghotbi, Jamshid Moghadasi, and Riyaz Kharrat
Elsevier BV
Abstract Gas flooding is a practical secondary scenario for enhanced oil recovery. Channeling and fingering of the injected gas are the major problems facing this technique. These challenges can be mitigated by the injection of gas as foam. However, foam stability influences the overall efficiency of the process, which could be improved by nanoparticles (NPs). This work provides a theoretical and experimental analysis of the NPs wettability effects on foam behavior, in both static and dynamic states. The treated calcite (CaCO3) NPs along with a cationic surfactant (HTAB) were used for this purpose. By comparison of theoretical and experimental data, it was shown that the foam stability in the presence of NPs can be forecasted qualitatively using Reynold's formula and the extended Derjaguin–Landau–Verwey–Overbeek (xDLVO) theory. According to the theoretical results, the disjoining pressure decreases by increasing of NPs hydrophobicity, while the destructive effect of capillary pressure reduced. Based on the rheological measurements, the behavior of foam in the presence of NPs was less pseudo-plastic with the increasing of NPs hydrophobicity. For a fixed shear rate, the shear stress passed through a maximum by passing of the time, which could be justified by theoretical predictions. Finally, a series of flooding tests was carried out to evaluate the effect of NPs wettability on the Implicit Texture model parameters. It was concluded that while fmmob (foam mobility parameter) increased for more hydrophobic NPs, they suffered from large value of epdry (foam dry-out parameter), which indicated a sharp transition between high-quality and the low-quality regions.
Muhammad Suleymani, Cyrus Ghotbi, Siavash Ashoori, Jamshid Moghadasi, and Riyaz Kharrat
Elsevier BV
Abstract Foam flooding has been applied as a promising method in enhanced oil recovery to obviate the challenges of gas flooding such as fingering, channeling and overriding. However, long-term foam stability is crucial for mobility control. In this work, the effective mechanisms on foam stability in the presence of CaCO3 nanoparticles were assessed both theoretically and experimentally. The static and dynamic behaviors of cationic surfactant (HTAB) foam in the presence of CaCO3 nanoparticles with different hydrophobicity were evaluated. The CaCO3 nanoparticles were treated with a series of long-chain fatty acids to generate a range of wettability. Afterward, the underlying mechanisms were revealed by conducting the supplementary experiments, including measurements of effective diffusion coefficient (Deff), Henry's constant (KH), interfacial tension (IFT), and zeta potential of nanoparticles. Further, efforts were made to analyze the interfacial interactions using xDLVO theory. By increasing of nanoparticles hydrophobicity, the continuous reduction of effective diffusion coefficient, solubility, and IFT was observed, which means higher foam stability. However, the adsorption of modified nanoparticles on the air-solution interface could reduce the total disjoining pressure between two parallel plates, supported by xDLVO prediction. This phenomenon has an adverse effect on the thin film stability. Therefore, there would be an optimum extent of nanoparticles surface modification to obtain the most stable foam stability, which was in agreement with the both bulk and porous media observations. The optimum condition was shifted to the nanoparticles modified with the lower chain fatty acids by increasing the concentration of fatty acid solutions. In this case, the negative effect of reduced disjoining pressure was more pronounced.
Payam Soleimani, Seyed Reza Shadizadeh, and Riyaz Kharrat
Wiley
Enhanced oil recovery (EOR) has been noticed during recent years from reservoirs that are at the end of their life plateau or in which production has been declined. Two of these EOR methods are as follows: carbonated water and smart water injection. In carbonated water injection method, CO2‐contained water is injected in reservoirs in order to decrease free CO2 injection mobility, increase water viscosity, and store/remove produced greenhouse CO2 gas safely, and in smart water injection method, the ions in brine are modified in order to make controlled reactions with distributed ions on the surface of rock to cause more hydrocarbon recovery. In this paper, the combination of these two methods is investigated as hybrid smart carbonated water injection to find out the recovery factor change and effective mechanisms. Experimental core flooding setup is used for investigation of hybrid EOR injection applicability and mechanisms. Probable mechanisms are measured using different cores and five water samples are used for preparing carbonated water (at pressure of 2500 psi) including sea water (34 261 ppm), river water (1329 ppm), one of Iranian reservoir formation water (FW) (163 711 ppm), 10 times diluted FW (0.1 FW), and 100 times diluted FW (0.01 FW). The effect of both brine content and volume of CO2 is determined during hybrid EOR assessment. The main mechanisms activated including pH variation, oil swelling, oil viscosity reduction, ion concentration variation in brine and porous media, and wettability alteration have been investigated. Hybrid method resulted in highest recovery (70%) mainly due to ion exchange, wettability alteration, oil swelling, and permeability enhancement. In addition, type of salt concentration will affect recovery as 0.01 FW results in 8% and 16% additional oil recovery compared to sea and river waters, respectively. Coupling of CO2 and salts will increase recovery factor due to mechanisms activated by each of these factors as 0.01 FW results in 10% more oil recovery compared to FW. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.
Mohammad Ali Karambeigi, Narges Fallah, Manouchehr Nikazar, and Riyaz Kharrat
Informa UK Limited
Abstract Asphaltene deposition has a significant detrimental effect on oilfield production. The key to effective treatment of asphaltene deposition is recognition of the problem. Asphaltene and effective treatment can be identified and quantified using laboratory methods. The most commonly way to asphaltene precipitation reduction is applying an asphaltene inhibitor. Most researchers investigate the effect of asphaltene inhibitors on fluid and precipitation reduction in static tests. This study is a coherent approach to measure effect of asphaltene precipitation on reservoir permeability and survey effect of asphaltene inhibitors on damage permeability.
Mohammad Ali Karambeigi, Narges Fallah, Manouchehr Nikazar, and Riyaz Kharrat
Informa UK Limited
Abstract Asphaltene deposits can reduce the productivity of the reservoir as well as foul piping and surface equipment. Current chemical and mechanical methods for treating deposition are only partially effective partly because the deposition process is poorly understood. The most commonly way to asphaltene precipitation reduction is applying an asphaltene inhibitor. In order to investigate the extent of formation damage by asphaltenes in crude oil this work has used electro kinetic technique to study the adsorption of asphaltenes in rock pores. Most researchers investigate the kinetics of adsorption by monitoring changes in the concentration of asphaltene or polymer in a dispersion of adsorbent particles or capillaries. This study is a coherent approach to measure amount of asphaltene adsorption on rock surface and survey effect of asphaltene inhibitors on precipitation reduction in porous media.
Mehdi Madhi, Riyaz Kharrat, and Touba Hamoule
Elsevier BV
Abstract One of the most severe problems during production from heavy crude oil reservoirs is the formation of asphaltene precipitation and as a result deposition in the tubing, surface facilities and near wellbore region which causes oil production and permeability reduction in addition to rock wettability alteration in the reservoir. So one of the economical ways to prevent such incidents is using the chemicals which are called asphaltene inhibitor. In this study, the influence of three commercial inhibitors, namely; Cetyl Terimethyl Ammonium Bromide (CTAB), Sodium Dodecyl Sulfate (SDS), Triton X-100 and four non-commercial (Benzene, Benzoic Acid, Salicylic Acid, Naphthalene) inhibitors on two Iranian crude oils were investigated. This study extends previous works and contributes toward the better understanding of interactions between asphaltene and inhibitor. Effect of functional groups and structure of inhibitors on asphaltene precipitation were studied and it seems clear that the nature and polarity of asphaltene (structure and amount of impurities presented) has a significant impact on the selection of inhibitors. asphaltene dispersant tests and Core flood tests were designed for evaluation of inhibitors in static and dynamic conditions. The results revealed distinguished mechanisms for asphaltene solubilization/dispersion (such as hydrogen bonding, π–π interaction and acid-base interaction) and influence of additional side group (OH) on inhibition power of inhibitor. During the experiments, it was found that increasing inhibitor concentration may lead to the self-assembly of inhibitor and declining of asphaltene stabilization. So, finding optimum concentration of inhibitor with high efficiency and available at a reasonable price is very important. The results suggest that 600 ppm of CTAB and 300 ppm of SDS were approximately optimum concentrations for the studied crude oils. One of the most important findings that differ from previous studies is the revelation of the mechanism behind the SDS/asphaltene behavior in various concentrations of inhibitor. Effect of chosen inhibitors on asphaltene precipitation and consequently deposition in porous media was studied, and then experimental data were modeled for evaluation of permeability impairment mechanisms. Permeability revived after inhibitor squeezing and cake formation mechanism played an important role in permeability reduction before and after treatment in porous media. The findings can also be applied to prediction of future behavior of reservoirs in oil field scale and evaluation of formation damage in the different period of production if needed any treatment process.