جستجوی مقالات مرتبط با کلیدواژه "سنگ کربناته" در نشریات گروه "مهندسی شیمی، نفت و پلیمر"

Accurately predicting subsurface flow properties holds immense significance across various domains, ranging from water resource management to the petroleum industry. In this study, recognizing the computational intensity and time constraints associated with digital rock analysis for petrophysical property calculations, we introduce a workflow that leverages deep learning to swiftly and precisely estimate these properties from micro-CT images, obviating the need for resource-intensive computational methods. Specifically, a Convolutional Neural Network (CNN) was employed to train and predict multiple physical properties of porous media using micro-CT scan images as input data. The micro-CT scan images, derived from a carbonate rock sample, were divided into 9,261 images, each with dimensions of 100x100x100, for network training. Key parameters such as porosity, throat size, pore size, connection number, and pore shape factor for each image were computed using network extraction algorithms. The designed network›s performance was evaluated, considering factors like the number of layers and learning rate. Subsequently, when tested on a separate dataset, the network exhibited impressive coefficients of determination for the mentioned parameters, namely 99% for porosity, 90.2% for Avg.throat size, 94.5% for Avg.pore size, 93.6% for Avg.connection number, and 75.3% for Avg.pore shape factor. Furthermore, the average relative error percentage for each property remained below 4%. These results signify a strong agreement between the predicted values and the actual properties, affirming the efficacy of this approach in swiftly and accurately estimating petrophysical properties from micro-CT images.

As oil fields approach to the end of the primary production phase, the new technologies should be employed to increase the recovery of hydrocarbons. In recent decades, nanofluid has been proposed as an efficient, and environmentally friendly approaches for EOR purpose. The target of this study is to investigate the effect of silica nanoparticle on the wettability alteration of the carbonate rock. In this study, four different concentrations of silica nanoparticle were used (0.01, 0.02, 0.05, and 0.1 wt.%) in low salinity seawater (1000 ppm of positive ions). The stability of nano particle in brine is one of the challenge while using for EOR. In this study the stability of nano fluid was achieved without using any surfactant. The Spontaneous imbibition experiments, and contact angle measurements were carried out at 75 °C to check the performance of nano fluids in wettability alteration of carbonate rock. The results showed that the silica nanoparticle has a significant effect on the oil recovery from carbonate rock. The diluted sea water (1000 ppm) without nano particle resulted to the oil recovery of 10.45% whereas nano fluid with concentration of  0.01, 0.02, and 0.05 wt.%  resulted to the oil recovery of 11.5%, 10.83%, and 22.16% , respectively. The contact angle results also confirmed that the silica nanoparticle has a positive effect on the wettability alteration of the carbonate rock surface toward water wetness. The permeability measurement after and before spontaneous imbibition tests showed that the pores were not blocked due to nano particle precipitation. The impact of initial water in the rock was investigated on the performance of wettability alteration while using nano fluid. The results depicted that the presence of initial water in the carbonate rock adversely affect the oil production.

Acid fracturing is one of the most widely used methods in the reservoir stimulation process for higher oil production. This method in carbonate reservoirs has a crucial role in enhanced oil recovery. Acid fracturing in fractured carbonate reservoirs changes fracture opening due to the reaction between the injected acid and minerals at the surface of fracture walls. In addition, fracture opening changes affect oil movement and the amount of oil production. In this type of reservoir, parameters such as reservoir temperature, acid injection flow rate, and injection acid type are parameters that directly affect the reaction rate between acid and carbonate rock. In this study, acetic acid was injected into two types of carbonate rock, and the effect of the rock type and acid injection rate on the final fracture opening was investigated. The results showed that dolomite rocks due to their specific nature of minerals in their structure had little reactivity with acid, thus fracture opening had lower value in comparison with the calcite rock sample. Finally, by decreasing the acid injection rate, the final fracture opening was increased after the acid injection because of more reaction between acid and fracture surfaces.

The enhancement of energy consumption and increasing demand for oil have led to using improve oil recovery methods. Chemical enhanced oil recovery methods are among the most widly used techniques. Generally, the effect of these methods has been less than the predicted amounts by the studies. One of the leading causes, could be due to the loss of chemicals by adsorption or precipitation of the surfactants on the rock surface. The mineralogy of the reservoir rocks is effective in determination of the interaction between the bulk of the fluid phase and rock surface. This effect will change in the surface charge of the adsorbent and wettability alteration of the rocks.

In this study, the adsorption of AOT surfactant on the surface of a hydrophilic adsorbent of carbonate reservoir was investigated. For this purpose, after the preparation of rock and fluid samples, the adsorption of surfactant was investigated in concentrations below and above the CMC.

Batch adsorption experiments were conducted to measure the amount of surfactant adsorption on the surface of carbonate rock. First different concenteration of AOT solutions and carbonate rock as adsorbent were combined. After 48h, the equilibrium concentrations were determined by using the calibration curve and. The amount of surfactant adsorption can be calculated by knowing the maqnitudes of equilibrium and initial concentration of the surfactant.

The results showed that by increasing the concentration of the surfactant in the liquid phase, the adsorption increased until it reaches a saturation point at the concentration of 1200 ppm. The results of the modeling showed that the Freundlich equilibrium isotherm with 1⁄n equals 0.8971 was the best fit for describing the prediction of AOT surfactant adsorption behaviour.

Using diverter agents in matrix acidizing is one of the common techniques in the heterogeneous reservoirs. These agents temporary block the high-permeability layer by increasing the viscosity and thus diverting the acid to the low-permeability layer. Here, a rheological model that was developed by previous researchers is used for in-situ gelled acids by considering the main parameters such as shear rate, pH, and temperature. Then, the rheological model is combined with the extended two-scale continuum model to describe the underlying reactive transport mechanisms. The results were compared with the Newtonian acid. Furthermore, the apparent viscosity of the in-situ gelled acid is estimated and updated at each time step of the modeling. In this study, the results of the linear and radial system were compared with each other. The results show that in the linear model, the growth and propagation of acid in high permeability region is stopped due to high viscosity. Therefore, acid starts diverting from high permeability zone to low permeability zone. However, several wormholes are formed in a radial model; moreover, the wormholes prevent diverting acid from high permeability region to low permeability region. In other words, the existing model could not respond to divert acid from high-perm region to low-perm region in the radial system.

Surfactant flooding is known as an essential and important method for enhancing oil recovery from carbonate reservoirs. High amount of Adsorption of some surfactants onto carbonated surfaces makes some difficulties in accurate prediction of oil recovery efficiency in this type of injection process. In this paper, the adsorption of nonionic surfactant Triton x-100 on the surface of the carbonate rock is experimented. The carbonate rock is crushed and contacted with surfactant solution, and the amount of the surfactant adsorption on the surface of the carbonate rock is measured after arriving the equilibrium condition. It is observed that the adsorption of the surfactant is saturated at about 500 ppm. Also, the adsorption results matched well with the Langmuir model. The amount of Langmuir constant is obtained 173.34 gr sol / gr surf and the maximum adsorption is obtained 19.23 mg surf /gr rock. Comparing the adsorption data shows that the amount of surfactant adsorption and its variations especially above the critical micelle concentration in carbonate rocks is greater than sandstones. So, it is more important to consider the surfactant adsorption and its waste during surfactant injection and its simulations in carbonate reservoirs.

One of the recently developed methods of enhanced oil recovery in carbonate reservoir is smart water flooding. Smart water can alter the wetting state of carbonate rocks from oil-wet to water-wet and increase oil production. In this study, we have investigated the effect of smart water composition on the carbonate rock wettability at different aging temperatures and pH’s through measuring the contact angle. The response surface methodology was utilized for the design of experiments. The results show that Mg+2, SO4-2, and K+ ions have important roles in wettability alteration due to interaction with carboxylic acids adsorbed on the rock surface. Not only Mg+2 and SO4-2 ions but also, inactive ions such as K+ influenced the wetting state of carbonate rock. Furthermore, an increase in temperature could cause more water wetting state and more activity of ions in solution. In addition, increasing pH could decrease the contact angle because of reduction in positive surface charge of carbonate rock surface. However, when pH was close to 8, the contact angle was raised probably due to the precipitation of Mg+2 ion.

The relation between compressional wave velocity and porosity depends on porosity, porosity type, mineralogy, saturation, and pressure in carbonate rock. Therefore, data points are scattered in a velocity-porosity cross plot. In this study, two methods of rock typing in carbonate rocks are analyzed to investigate the relation between compressional wave velocity and porosity. For this purpose, flow zone indicators and velocity deviation values are used. Flow zone indicators are determined from differences between sonic velocity and the velocity obtained from Wyllie time average equation using neutron porosity. The results show four hydraulic flow units with flow zone indicators from 2.23 to 19.95 and four rock types based on velocity deviation values from 139 to 1135 (m/s). Moreover, the results show that the rock typing based on velocity deviation values is more accurate than that obtained by flow zone indicators. The average value of correlation coefficient is 95% for grouping based on velocity deviation values, whereas this value is 67% for grouping based on flow zone indicators.