جستجوی مقالات مرتبط با کلیدواژه "تراوایی نسبی" در نشریات گروه "مهندسی شیمی، نفت و پلیمر"

Formation damage in the near-wellbore area has become one of the significant obstacles in the path of production from oil wells today. One neglected aspect of formation damage is the damage caused by the invasion of drilling fluid filtrates into the formation. Water-based drilling fluid, due to the presence of polymers and micrometer-sized compounds, causes changes in the electrostatic and flow properties of the rock surface upon invasion into the formation, resulting in various consequences such as reduced hydrocarbon fluid production, increased produced water cut, alteration in reservoir wettability, and changes in relative permeability of the reservoir rock. In this study, processed reservoir rock samples from southern Iran were obtained, and using real crude oil samples, reservoir environment and oil-rock contact were simulated in the laboratory environment using a core flooding apparatus. The drilling fluid sample, based on the commonly used formulation for oil and gas wells and approved by the Petroleum Industry Research Institute, was prepared and its filtrate was injected into the reservoir using a filter press device. The investigation conducted on clean core properties, core contaminated with crude oil, and core soaked with filtrate revealed that the commonly used drilling fluid filtrates cause alteration of the rock surface wettability from oil-wet to water-wet and significantly reduce the capillary force applied to hydrocarbon fluids and the relative permeability of the oil phase, leading to decreased oil production from reservoirs. However, a new formulation of drilling fluid replaced based on the presence of amine functional groups instead of hydroxyl groups showed improved wettability alteration upon filtrate injection into the reservoir. Additionally, the new drilling fluid sample will not negatively impact the hydrocarbon fluid flow within the pore and fracture networks, and the use of alternative materials will increase oil production from reservoirs.

Saturation/flow functions, i.e., water and oil relative permeability and capillary pressure are the most critical input parameters that play a key role in porous media simulation studies and forecasting the fluids recovery. Various methods including laboratory tests (steady or unsteady core flooding), and mathematical methods can be utilized to measure or estimate the flow function curves. In this research, history matching technique was performed using optimization genetic algorithms to adjust the parameters of the proposed model based on laboratory water flooding data (pressure drop and cumulative oil production) and the results of core flooding simulation. To do so, multi-objective genetic algorithms were employed to find optimum solutions for piecewise model and then the results are compared with several empirical models (e.g. Corey and Brooks-Corey models). History matching results showed that single objective optimization, i.e., considering cumulative oil production as an objective function provides a good fit for Corey’s model (R-squared= 99.56%) and single and multi-objective optimization lead to the best fits, respectively, with the accuracies of 99.57 and 99.16% for piecewise model during the imbibition process. Moreover, the drainage history matching results showed that the piecewise model exhibits the best performance employing the single objective and multi-objective optimization algorithms with the accuracies of 99.32 and 99.85%, respectively. Overall, the piecewise model can be utilized to address the history matching problem using multi-objective optimization and estimate the flow functions curves. Hence, it is proposed as an efficient method for estimating fluid relative permeability and capillary pressure functions based on experimental and simulation data.

In recent years, low salinity water-flooding has received much attention as one of the enhanced oil recovery methods because of its cheapness and low operating limitations. Tuning of injected water composition and concentration can induce a significant effect on the oil recovery during the spontaneous imbibition process and forced oil displacement in the fractured reservoirs. Numerous lab and field studies have been conducted to realize the mechanisms and factors affecting the low salinity and smart water injection. Despite these researches, some of the related mechanisms and determining factors in carbonate reservoirs, such as the initial water saturation and temperature, have not yet been fully understood. Therefore, extensive experiments are needed to optimize the conditions of injected water. In this study, the oil recovery of spontaneous imbibition by low salinity and smart water containing divalent ions has been investigated when the initial water saturations were in relatively small and high amounts in carbonate cores. Then, the coreflooding experiments were conducted with various temperatures, including equivalent and below the reservoir temperature. Based on relative permeability and capillary pressure measurements, the mechanism leading to higher oil recovery during smart water injection was also investigated. The results showed that the oil recovery was increased during spontaneous imbibition of low salinity and smart water under ambient conditions as the initial water saturation increased. It was also observed that elevating the temperature from 80 °C to 105 °C in secondary water injection could improve oil production significantly. The reduction of residual oil saturation in the relative permeability and capillary pressure diagrams due to the presence of sulfate and magnesium ions confirmed that the carbonate rock became more water-wet at the ambient temperature.

Nanomaterials are substances that, because of their size, can easily penetrate small pores and apply their impact. Nanofluids can allow appropriate wettability change in the reservoir rock, therefore, an accurate understanding of the behavioral mechanisms of these nanofluids is important in changing the wettability. This is because if there is no proper understanding of these mechanisms, they may exhibit the opposite behavior and cause damage to the reservoir. In previous research, CuO / TiO2 / PAM nanocomposite was synthesized and mechanistically introduced.

In this study, in continuation of the previous study, the behavioral and mechanism study has been investigated in a more accurate and documented manner, and spectral absorption tests, chemical flooding, and relative permeability diagrams confirm the effectiveness of enhanced oil recovery results of this nanocomposite. In carbonate rocks due to the positive surface charge of the rock and the negative charge of the nanocomposite, adsorption of nanomaterials in a double electrode layer state has been suggested as the dominant mechanism of wettability change. In sandstone rocks due to the charge coincidence of rock surface and nanomaterials which are both negative, the mechanism of disjoining pressure was the dominant mechanism of wettability change. To prove the abovementioned behaviors 200 ppm concentration of nanofluid was analyzed by spectroscopy method of adsorption analysis to validate the attraction forces of the nanocomposite with carbonate rocks and repulsion forces with sandstones.

Dynamic chemical flood tests were performed to confirm the effectiveness of this material in increasing oil production and showed 8.5% and 6.35% increase in oil production for carbonate and sandstone lithologies, respectively. Relative permeability diagrams showed an intersection point in the carbonate system with a 10% increase in water saturation and an intersection point in the sandstone system with a 12% increase in water saturation and the behavioral effect of the material at the studied concentrations.

In this study, the comprehensive review of empirical and analytical correlations, which are presented for estimation of the relative permeability of two-phase systems, is performed. 11 common and widely used correlations for modeling of two-phase flow of oil - water in porous media including the empirical correlations of Honarpour et al., Ibrahim & Koederitz and Al-Fattah and also those correlations which have adjustable parameters; such as, Corey generalized correlation, Brooks and Corey generalized correlation, Sigmund & McCaffery, Chierici, Van Genuchten-Maulem, LET, Ke and Li et al. were used. The accuracy of the above correlations was evaluated by using 644 experimental data points related to oil - water systems. Generalized Reduced Gradient nonlinear optimization method has been used locally and globally for determining the adjustable parameters of the parametric models. According to the performed adjustment and optimization, Sigmund & McCaffery and LET correlations showed the best agreement with experimental data of oil and water relative permeability, respectively. The decision tree for the best correlation to estimate the relative permeability in carbonate and sandstone rocks as well as for three states of wettability water-wet, intermediate-wet and oil-wet was presented. Also, due to the weakness of the correlations with adjustable parameters to be dependent on experimental relative permeability data in determining the values of their parameters, the best values of the parameters of these correlations were determined using global optimization on a wide range of experimental data. The results were reported for 4 correlations with the highest accuracy.

The low salinity water flooding caused an increased secondary and tertiary oil recovery in many laboratory and field tests. The extent of the reactions and interactions of this type of flooding led researchers to investigate and find the main mechanisms¡ governing this process. To describe the interactions¡ numerous mechanisms such as¡ fines migration¡ increase in pH¡ multiple ion exchange and electric double layer effect have been noted¡ but none of them¡ has not been accepted as a comprehensive mechanism due to the complexity of the crude-oil-brine-rock interactions. So far¡ most of what has been suggested in previous research was creating a favorable wettability state with dilute brine injection. In this laboratory experiments that take place on sandpacks¡ the effects of brine salinity¡ aging of oil in packs and the fines have been investigated on recovery of oil¡ end point water relative permeability in each salinity and wettability alteration. The obtained results from dilute brine injections show that without the presence of minerals and divalent ions and with NaCl brine¡ tertiary recovery was increased¡ and of course this increase was higher for the aged sample. Also¡ the wettability alteration towards more water wet has been probed by means of flooding data.

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.

Although there have been several models for predicting the asphaltene-induced permeability reduction, the present study investigates the hydrodynamic effects of asphaltene deposition in the porous media with a novel and partially analytical approach. In order to find the amount of permeability reduction, we have modeled the variations of hydraulic radius. The main idea for modeling the permeability reduction is the fact that by deposition of the particles, the available void space is reduced. Also, the drag force between the particles and the fluid reduces the flow potential. In this paper, using the size variation of the asphaltene particles during flocculation, with assuming that the size distribution is equal inside and outside the porous medium, permeability reduction is obtained and matches with the existing experimental results. Modeling is done using MATLAB and a code is written for calculating the permeability reduction due to formation damage. This model is partially analytical and do not use numerical estimations, thus it is flexible to be applied for other formation damage problems. In addition, this modeling can predict the deposition process if the changes of the particle size distribution is known as a function of time.

The determination of relative permeability model used in reservoir simulation software is the corner stone of reservoir studies. Nowadays, in order to estimate relative permeability, several models are presented, having their own features. Corey model is one of the most well-known models, because it has simple calculation. However, it behaves inappropriately in facing heterogenic carbonate rock. Also, insufficient studies on comparing different models on carbonate rock are undeniable. Therefore, the assessment of different models and determining the appropriate model to result in a better estimation in carbonate rock is the aim of this study. In this work, after conducting unsteady-state relative permeability experiment under reservoir conditions from three reservoirs, namely A, B, and C, the relative permeability was calculated by using JBN method. Then, all the models could be compared. According to the results, it can be concluded that the LET model in heterogenic carbonate rock (various rock type) leads to a better result compared with the other models and it causes a significant decrease in standard error value for the relative permeability of oil and water to 0.00488 and 0.00119. Furthermore, it is found that this model can predict the S-shape behavior of relative permeability, seeing in Iranian carbonate reservoirs, perfectly.

The productivity of condensate-gas reservoirs can be adversely affected by accumulation of condensate near the wellbore when the pressure decreases below the dew point. One of the proposed methods to prevent this condensate banking is altering rock wettability from liquid-wetting to gas-wetting by appropriate chemical treatment. We evaluated the performance of this treatment process for a real well by single well simulation study. The effect of relative permeability modification on the residual oil saturation in the region 1 around the well, total condensate production and total gas production were studied in our simulation work. The effect of chemical treatment up to different radial distances from the wellbore on total gas and condensate production were compared. The results showed short distance treatment around the well may be sufficient to prevent condensate accumulation near the wellbore. The economic analyses showed that the wettability alteration can increase gas production revenue. The results of the present work demonstrated that the chemical treatment can be economically applied in the field scales.

The gravitational drainage of oil in gas-invaded zone is identified as the major production mechanism in carbonate reservoirs. Oil is kept in a matrix block surrounded by gas and then subject to two distinct and opposing forces. Due to the difference between oil and gas densities, gravitational forces tend to expel oil through the lower part of the block, while oil-rock adhesive force acts to peneterate within the rock. Drainage arises when “gravitational” and “capillary” forces coincide. In this study, the mathematical modelling of gravitational drainage in naturally fractured reservoir is presented which involve capillary, gravitational, and infiltration processes. A simple approach was proposed to simulate gas-oil gravity drainage process in fractured porous media using an appropriate fracture capillary pressure. The permeability value is approximated by the location of fracture in the stack block. The capillary pressure in horizontal fracture is related to height of fracture in stack block to gas-oil interface. Numerical simulation results revealed good agreement with experimental data. This study revealed that capillary continuity and fracture transmissibility are the most important factors in oil recovery by gravitational drinage mechanism.