Iranian Oil Reservoir Research Articles

Screening of enhanced oil recovery techniques for Iranian oil reservoirs using TOPSIS algorithm

In recent decades, parallel to amazing advances in the development of data mining methods, screening, as the first step of any enhanced oil recovery (EOR) project, has become an interesting subject of data mining methods. Screening of EOR methods is a multi-criteria decision making process, and the Multi-Criteria Decision Making (MCDM) method as a systematic statistical method, can be applied in this regard. In this paper, the Technique for Order of Preference by Similarity to Ideal Solution (TOPSIS) as one of the methods under the MCDM category was used to screen 65 Iranian oil reservoirs. The screening method was employed for 10 different EOR techniques using a wide range of properties and conditions. The analysis used a database including more than 800 successful EOR projects across the world and for 9 ideal reservoir parameter values. The relative importance of the reservoir parameters was determined based on the Analytic Hierarchy Process (AHP) at nine importance levels. The findings showed that among the considered screening parameters, to determine the best EOR technique, lithology of the reservoir is the most influencing parameter. Additionally, almost 74% of the oil reservoirs under study, as a first priority, were eligible for CO2 injection, either miscible or immiscible. Thermal methods were in the second stage of ranking. The first and second candidate choice for onshore oil reservoirs was immiscible CO2 and hydrocarbon gas injection, respectively. For offshore reservoirs, CO2 injection and steam flooding were the best choices. Also, miscible N2 injection was the least important technique, due to the huge difference of considered reservoir pressure with minimum miscibility pressure (MMP) of N2 injection. The proposed technique is computationally fast and less expensive than field simulation studies for ranking EOR projects for any oil reservoir in the world.

Estimation of rock uniaxial compressive strength for an Iranian carbonate oil reservoir: Modeling vs. artificial neural network application

Estimation of rock mechanic parameters is an important issue in reservoir management. Uniaxial compressive strength (UCS) and elastic modulus are the most important factors in determining the rock mechanic parameters in petroleum engineering studies. Accessibility to the parameters in fields such as designing fracture, analyzing of wellbore stability and drilling programming are very useful. The most accurate method to assign the aforementioned parameters is measuring these parameters in a laboratory. Laboratory determination of these parameters is problematic work due to technology issues, lack of laboratory equipment and coring problems in oil and gas wells, so indirect estimation of these parameters is required. Using well log data is the cheapest and most available approach in order to indirectly estimate these parameters. In this investigation, different models including multiple linear regression (MLR) and artificial neural network (ANN) (i.e., multi linear perceptron (MLP) and radial basis function (RBF)) were utilized for prediction of UCS via the three parameters of porosity, density and water saturation. These data were obtained from analysis of sonic, neutron, gamma ray and electric logs. The best results were obtained from a 3-15-1 MLP network which included one hidden layer and 15 neurons from the hidden layer using the trial and error method, and a 3-17-1 RBF which included 17 hidden neurons and a spread ó of 1.6. The core data from one of the carbonate Iranian oil fields (Asmari reservoir) were utilized for training, validation and testing of the networks, and correlation coefficients of 0.68, 0.90 and 0.83 were obtained for MLR, MLP and RBF, respectively.

Coupled T-H-M processes’ effect on specific energy in continuous wave fiber laser rock perforation

Laser perforation of oil and gas wells is a new method for well completion as an alternative to blasting methods. Under real perforation in oil and gas wells, three main factors have influence on the laser perforation such as specific energy (i.e., energy required to remove the unit weight of rock). These three factors are temperature, the hydraulic pressure of fluid flow, and confining pressure. This paper investigates the role and significance of the coupled T-H-M (thermo-hydraulic-mechanical) processes on specific energy (SE) and rate of penetration (RoP). For physical modeling of T-H-M processes, a new cell and setup is designed and developed. In this setup, a circular part of the front side of the cylindrical sample is open in order to interact with the laser beam while the temperature, hydraulic pressure, and confining pressure are applied to the sample. The rock tested under four temperature steps from 25 to 120 °C (temperature range of major oil reservoir in fractured rocks), the hydraulic pressure was chosen in five steps from 0 to 35 MPa (fluid pressure range of more than 70% of Iranian oil reservoir rocks), and confining pressure was selected from 0 to 40 MPa (ranges of overburden pressures). Test results show rises in specific energy with incremental increases in rock temperature, hydraulic pressure, and confining pressure, while the rate of penetration decreases.Laser perforation of oil and gas wells is a new method for well completion as an alternative to blasting methods. Under real perforation in oil and gas wells, three main factors have influence on the laser perforation such as specific energy (i.e., energy required to remove the unit weight of rock). These three factors are temperature, the hydraulic pressure of fluid flow, and confining pressure. This paper investigates the role and significance of the coupled T-H-M (thermo-hydraulic-mechanical) processes on specific energy (SE) and rate of penetration (RoP). For physical modeling of T-H-M processes, a new cell and setup is designed and developed. In this setup, a circular part of the front side of the cylindrical sample is open in order to interact with the laser beam while the temperature, hydraulic pressure, and confining pressure are applied to the sample. The rock tested under four temperature steps from 25 to 120 °C (temperature range of major oil reservoir in fractured rocks), the hydraulic pressur...

Effect of CO2 and crude oil type on the dynamic interfacial tension of crude oil/carbonated water at different operational conditions

Concerns about climate change have persuaded the researchers to examine CO2 injection in the form of carbonated water (CW) into oil reservoir as a safe and effective CO2 storage and enhanced oil recovery process. Although interfacial tension (IFT) between crude oil and injected fluid has a vital role on the displacement of fluids in porous media, the effect of CO2 and crude oil type on the dynamic IFT of crude oil under different operational conditions is not well understood. Accordingly, this study was carried out to assess the effects of temperature, pressure, crude oil type and CO2 on the dynamic IFT of crude oil/CW. To achieve this goal, two types of crude oil were provided from southern Iranian oil reservoirs and dynamic IFTs with CW were measured in a wide range of temperatures and pressures (i.e. temperature range of 30–80 °C and pressure range of 500–4000 psi); the obtained results were compared with the system without CO2. In addition, the adsorption time of carbonated aqueous phase/crude oil, obtained based on the mono exponential decay model, was also compared with unadulterated water/crude oil system. The outcome of this study showed that crude oil type has the most significant effect on the IFT of crude oil/CW compared to pressure, temperature and CO2 content. In more details, the IFT of crude oil/CW can be affected by the amount and type of acidic/basic components in the crude oil as well as pH of the aqueous solution. Besides, the obtained results revealed that the effect of temperature was more considerable on the IFT of the heavy crude oil compared with the light crude oil in both studied aqueous solutions (i.e. unadulterated water and CW). Although the inversion phase temperature was obtained for unadulterated water/studied crude oils at all studied pressures, this phenomenon was not observed for crude oil/CW at elevated pressure, due to the high amount of CO2 at this condition.

Investigating the effects of rock and fluid properties in Iranian carbonate matrix acidizing during pre-flush stage

Acidizing of carbonate oil-wet rocks saturated with oil and saline formation water is subjected failure in some cases due to acid-induced damage such as sludge and emulsion formations. This condition may also lead to mineral precipitation, oil film barrier between acid and rock and diversion chemical malfunctions. Therefore, pre-flush process has been proposed as one of the most efficient stage for oil-wells matrix acidizing to reduce these challenges significantly. Besides, the pre-flush stage would result in more clean rock as the reservoir fluids are pushed back from the near wellbore regions, restoring rock wettability to more water wet state, preventing direct acid-oil contact and cooling rock surface to control acid-rock reaction at high temperature reservoir.This laboratory work is designed to study the effectiveness of three different pre-flush fluids and assess their ability in reducing interfacial tension (IFT) to displace original reservoir fluids around the wellbore as well as changing the rock wettability to increase rock dissolution rate. The results showed that a 0.5%wt of C16TAB aqueous solution (cationic surfactant additive) has passed successfully the pre-flush optimization criteria which can be utilized as pre-flush fluid of the carbonate oil-wet acidizing. It was shown that the wettability and IFT were changed quickly as it is requested for the pre-flush stage. The contact angle was decreased from 172° to 33° in two hours period and the IFT was reduced from 8.9 to 0.62 (dyne/cm) at reservoir condition (P = 4000 psia, T = 85 °C).In addition, the dissolution rate of dolomite rock from an Iranian oil reservoir at three different states of oil-wet, water-wet and pre-flush treated with 15% HCl was measured and compared. The measured dissolution rate of initially water-wet rock was measured to be 1 × 10−4 mol/cm2.s which is the same as the dissolution rate measured for C16TAB treated oil wet rock. This confirms the suitable wettability alteration through C16TAB pre-flush.

Investigating the effects of rock porosity and permeability on the performance of nitrogen injection into a southern Iranian oil reservoirs through neural network

In this work, a comprehensive model for Nitrogen injection into an oil reservoir (southern Iranian oil fields) was developed and used to investigate the effects of rock porosity and permeability on the oil production rate and the reservoir pressure decline. The model was simulated and developed by using ECLIPSE300 software, which involved two scenarios as porosity change and permeability changes in the horizontal direction. We found that the maximum pressure loss occurs at a porosity value of 0.07, which later on, goes to pressure buildup due to reservoir saturation with the gas. Also we found that minimum pressure loss is encountered at porosity 0.46. Increases in both pressure and permeability in the horizontal direction result in corresponding increase in the production rate, and the pressure drop speeds up at the beginning of production as it increases. However, afterwards, this pressure drop results in an increase in pressure because of reservoir saturation. Besides, we determined the regression values, R, for the correlation between pressure and total production, as well as for the correlation between permeability and the total production, using neural network discipline.

Feasibility study on application of the recent enhanced heavy oil recovery methods (VAPEX, SAGD, CAGD and THAI) in an Iranian heavy oil reservoir

ABSTRACTEnhanced oil recovery (EOR) methods assisted by gravity drainage mechanism and application of sophisticated horizontal wells bring new hope for heavy oil extraction. Variety of thermal and non-thermal EOR techniques inject an external source of energy and materials such as steam, solvent vapor, or gas through a horizontal well at the top of the reservoir to reduce in-situ heavy oil viscosity. So, the diluted oil becomes mobile and flows downwards by gravity drainage to a horizontal producer located at the bottom of the reservoir.In this paper, a sector model of an Iranian fractured carbonate heavy oil reservoir was provided to simulate and evaluate capability of some EOR techniques such as Vapor Extraction (VAPEX), Steam Assisted Gravity Drainage (SAGD), Combustion Assisted Gravity Drainage (CAGD), and Toe to Heel Air Injection (THAI) at its reservoir conditions and fluid properties. The simulation results demonstrated that wet CAGD in comparison with other nominated methods could improve heavy oil recovery factor to around 19% much more than each of SAGD, THAI, and VAPEX techniques. It could also reduce the total energy to produced oil ratio index up to 82% with respect to SAGD process in a year.Although lower oil recovery has been gained by VAPEX process, but using a proper vaporized solvent could produce a kind of de-asphalted and upgraded oil with increased API gravity up to 29°API with no considerable solvent loss.

A Proposed Systematic Approach for Experimental Asphaltene Investigation: An Oil-Reservoir Case Study

Summary Asphaltene precipitation and deposition are major flow-assurance issues that can reduce or completely stop the production of oil wells. To evaluate the severity of asphaltene problems in an oil reservoir, various laboratory tests should be planned. In this paper, a stepwise experimental approach is proposed to assess the asphaltene issue in oil reservoirs. Taking representative oil samples downhole is the first step to accurate experimental investigations. In case the sample does not represent the reservoir status correctly, all the laboratory data—even with accurate measurement—could be misleading. Then, reservoir-fluid characterization and saturate/aromatic/resin/asphaltene (SARA) analysis should be performed for primary evaluations and asphaltene-stability screening. Asphaltene-onset-pressure (AOP) measurement indicates the point at which asphaltene comes out of the solution. After that, assessment of asphaltene-precipitation potential depending on production scenarios (e.g., depletion or gas injection) at reservoir conditions should be performed. Finally, the effect of deposited asphaltene should be characterized in the presence of porous media in terms of deposition amount and its consequent permeability impairment. Eventually, this approach is used for an Iranian oil reservoir. This experimental approach, along with modeling and simulation of asphaltene precipitation and deposition, can be used as the best practice for assessing the asphaltene issue in oil reservoirs.

On the evaluation of Alkaline‐Surfactant‐Polymer flooding in a field scale: Screening, modelling, and optimization

AbstractChemical enhanced oil recovery methods, including alkaline surfactant polymer (ASP) flooding, have found special significance for oil reservoirs. ASP flooding provides different situations based on ratio of injection of three ASP components. This study identifies the behaviour of injection components and their interaction, investigating the synergy between them. To this end, an Iranian oil reservoir is studied. The factors influencing the injection process are identified and then a combination of these factors and the concentration of ASP components are modelled. All modelling results are fitted with R‐squared and adjusted R‐squared values above 0.96. Finally, the optimization is conducted to determine the best injection scenario. The most important aspect of this study is to investigate simultaneously the effect of different parameters of ASP in a real case. The screening results show that the effect of polymer on viscosity is the most influential factor in ASP flooding. The modelling results show that water cut in the case of simultaneous injection of three components is less than other cases of injection. This represents the synergy of components in the injection process during ASP flooding. The miscibility between water and polymer solution also leads to less produced water and more produced oil. In the final stage, the optimization results show that the optimal scenario is injection of surfactant and polymer with the greatest amount of miscibility between water and polymer solution. It can be concluded that with this approach, ASP injection can efficiently be analyzed and optimized from a technical point of view.

Statement of Removal

ABSTRACTAlthough nowadays finite difference simulators have many advantages for reservoir engineers to predict reservoirs in three dimensions, they have some disadvantages, such as spending much run time for complex fields with several thousand grids, which – by using streamline simulation – the run time was decreased considerably. In this paper, first a brief summary of streamline simulation and its uniqueness applications were discussed and then an Iranian oil reservoir as a case study was simulated by using FrontSim streamline simulator. Then, besides testing the results of Sayyafzadeh et al. (2010) to find the location of infill wells, the most suitable locations for infill drilling were selected. After that, vertical and horizontal infill wells were investigated and overall 34 scenarios were tested by using the streamline simulation method and FrontSim software. Finally the results of simulation and testing infill drilling scenario show significant increase in field oil production and field oil recovery factor, approximately 13%, and also a reduction in field water cut. In addition, distinguishing fractures or faults, well’s drainage area, and understanding how much injectors affect the field oil production are some of the other benefits of the streamline simulation method. The novelty of this paper was to study the effects of horizontal infill wells and to compare the results between horizontal and vertical infill drilling using streamline simulation.

Investigation of the minimum miscibility pressure for injection of two different gases into two Iranian oil reservoirs: Experimental and theory

AbstractThe results of the minimum miscibility pressure (MMP) determination for miscible injection of two gases (CO2 and an associated gas of one of Iranian gas reservoirs) into two different oil samples from two Iranian oil reservoirs using a slim tube apparatus are presented in this work. For efficient determination of MMP, prior to slim tube experimentation, cell‐to‐cell simulation of the slim tube experiment was performed using a tuned Peng Robinson equation of state as a pre‐experiment and the results were used as initial estimates of MMP to select the pressure steps for the slim tube experiment. Finally, a comparison between the measured MMP values obtained by the slim tube experiments and those calculated by cell‐to‐cell simulation was made. It was shown that the cell‐to‐cell slim tube simulation predicts the results of slim tube experiments with a relative error of less than 6 %. This low error value shows that cell‐to‐cell simulation can replace the slim tube test in the cases where time is a major concern. Moreover, since the slim tube is an expensive and time‐consuming experiment and selecting the pressures to run the test is very important, cell‐to‐cell simulation can help us select the pressures for performing a slim tube experiment.

A new approach for quality control of reservoir fluid composition data using live oil solubility parameter

Precise physical and chemical description of reservoir fluid is essential for accurate petroleum reservoir evaluation as well as for optimization of development plans of oil and gas fields. The uncertainties in the description of the reservoir oil composition data are the most serious issues for studying the thermodynamic phase behavior of the reservoir fluid. These data are widely used as the basis for calculation of reservoir fluid properties, and for simulation and modeling of underground oil reservoirs. Assumption of correct reservoir fluid (oil) composition is the basis of the most quality control methods presented in the literature, which are used for checking the accuracy of related experiments for thermodynamic phase behavior of reservoir oil (PVT experiments). This assumption may not be satisfied in most cases and affects seriously all related applications in chemical and petroleum engineering. Here, a new approach is introduced to resolve the uncertainties in reservoir fluid (oil) composition using solubility parameter concept of live oil. The solubility parameter of five live oil samples from different Iranian oil reservoirs was used for sensitivity analysis with respect to the molecular weight of the plus fraction to check the accuracy and consistency of the reservoir fluid composition data. Obtained results show that the solubility parameter of live oils at pressure and temperature conditions of oil reservoirs typically varies within a specified rang, which strongly depends on thermodynamic properties and composition of the oil sample as well as pressure and temperature range. The acceptable range of molecular weight of the plus fraction provides the best match for typical range of live oil solubility parameters. This approach provides a new insight into consistency and reliability of reservoir fluid composition data, which is highly beneficial and of special importance for optimization of different processes in both upstream and downstream oil industry.

Performance evaluation of optimized preformed particle gel (PPG) in porous media

Preformed particle gels (PPGs) are used as conformance control agents to improve oil production and control excess water production. This paper talks about optimized PPGs that are designed for high-temperature and high-salinity oil reservoirs and their synthesize process. The influence of cross linker concentration, size of dry PPGs, injection rate, temperature, permeability, and brine salinity on resistance factor (RF) and residual resistance factor (RRF) of PPG in porous media are investigated. The focus of study is to see how PPGs would perform in porous media by creating flow resistance to injected fluid, hence enhancing the sweep efficiency. A set of 51-cm slim tubes packed with carbonate cores from one of the Iranian oil reservoir is used to evaluate the performance of optimized PPG at wide range of different temperatures and permeabilities.PPG injection pressure increases with cross linker concentration, PPGs particle size, and brine concentration and injection flow rates but decreases with the increase of permeability and temperature during PPG injection. It was shown that increased injection rate does not increase PPG injection pressure to the same level and the reduction in water permeability caused by swollen PPG prepared in high salinity brine is higher than that prepared in low salinity brine. Synthesized PPGs can also change the permeability of different slim tubs to the same level. Resistance factor (RF) and residual resistance factor (RRF) increase with the increase in PPGs particle size, brine salinity and cross linker concentration. But, they decrease with the increase of temperature and the flow rate. Initially RRF increased gradually as the permeability of slim tubes decreased from 395 to 137Darcy but a sharp increase in RFF caused by swollen PPG in low permeability slim tube was observed.

Forecasting density, oil formation volume factor and bubble point pressure of crude oil systems based on nonlinear system identification approach

Accurate predictions of fluid properties, such as density, oil formation volume factor and bubble point pressure, are essentials for all reservoir engineering calculations. In this paper, an approach based on nonlinear system identification modeling; Nonlinear ARX (NARX) and Hammerstein-Wiener (HW) predictive model, is proposed for forecasting the pressure/volume/temperature (PVT) properties of crude oil systems. To this end, two datasets; one containing 168 PVT samples from different Iranian oil reservoirs and other a databank containing 755 data from various geographical locations, were employed to construct (i.e. train) and evaluate (i.e. test) the models. Simulation results demonstrate that the proposed NARX and HW models outperform previously employed methods including three types of artificial neural networks models (committee machine, multilayer perceptron and radial basis function), two types of ANFIS models (grid partition and fuzzy c-mean) and several empirical correlations with the smallest prediction error, and that they are reliable models for predicting the oil properties in reservoirs engineering among other soft computing approaches.

Sensitivity analysis on sampling from affected wells by gas coning

ABSTRACTOnly representative samples could represent original reservoir conditions and have prevented overdesigning surface facilities and have been requirements of reservoir management programs. Representative samples cannot be collected in unsteady state situations. In some cases, samples must be collected in this state, so non-representative samples are obtained. Gas coning is one of the parameters that makes unsteady state flows. There is no standard method to determine accurate original compositions from non-representative samples. In this article, an attempt is made to introduce an accurate method for obtaining original in situ compositions from gas coning wells. Four Iranian oil reservoir samples obtained from the pressure volume temperature laboratory are used for evaluating methods of obtaining original fluids in unsteady state situations for the first time. For this purpose a synthetic model is formed by compositional simulation, and fluid properties of each reservoir are imported to it. Separator sampling is performed in the model. Methods of synthesizing original compositions (recombination and equilibrium contact mixing) are modeled by detailed equation of state characterization in the new scheme. Then collected samples are imported to them. Comparisons are made on obtained results of recombination and equilibrium contact mixing methods to find the most accurate method. It is concluded that equilibrium contact mixing, which was uncertain for companies, is definitely the most accurate method. Also, the authors conclude that after more than 2 years production performing an equilibrium contact mixing method is impossible in volatile oil models with gas coning but recombination with low accuracy can be used; however, equilibrium contact mixing has no limitation in black oil systems with gas coning and has minimum errors.

Experimental investigation of effect of temperature and pressure on contact angle of four Iranian carbonate oil reservoirs

Abstract The knowledge of reservoir wettability is essential to understand the fluid displacement mechanisms, and to develop strategies for achieving higher recovery factors. Wettability is an important parameter which controls the remaining oil in place. It has a significant effect on multiphase rock fluid interactions. The objective of the present work is to investigate the influence of temperature and pressure on the wettability of four Iranian carbonate oil reservoirs. The contact angles were measured between live oil, synthetic formation water and slices of rock which were cut from different depths of reservoirs. The contact angles were measured by using captive drop system. The pendant drop method was used to measure the interfacial tension between live oil and synthetic formation water. In order to measure contact angle and interfacial tension, sixteen runs were undertaken for each of these four reservoirs at pressures 3000, 3500, 4000, and 4500 psi which all were above the bubble point pressure of these reservoirs and four temperatures which were the ambient temperature, reservoirs crest temperature, the temperature of water oil contact (WOC) and a temperature between the temperature of crest and WOC. Results demonstrated that pressure alone had little effect on the wettability of reservoir rock. Increase in temperature mostly changed the wettability of reservoir rock from water wet to intermediate wet system. The effect of temperature on each system differs from others and in some cases the contact angle decreased with increasing temperature but the general trend was increasing. The results of SARA-test showed that the ratio of resin to asphaltene in reservoir D was higher than reservoir A, hence it is expected that the contact angle of reservoir D to be lower than reservoir A which was shown in our results. In addition experimental data were analyzed by an equation of state model and it was observed that this model could predict the experimental contact angles with an acceptable accuracy.

Nonuniversality of the Archie exponent due to multifractality of resistivity well logs

AbstractArchie's law expresses a relation between the formation factor F of porous media and their porosity ϕ, , where m is the Archie or the cementation exponent. Despite widespread use of Archie's law, the value of m and whether it is universal and independent of the type of reservoir have remained controversial. We analyze various porosity and resistivity logs along 36 wells in six Iranian oil and gas reservoirs using wavelet transform coherence and multifractal detrended fluctuation analysis. m is estimated for two sets of data: one set contains the resistivity data that include those segments of the well that contain significant clay content and one without. The analysis indicates that the well logs are multifractal and that due to the multifractality the exponent m is nonuniversal. Thus, analysis of the resistivity of laboratory or outcrop samples that are not multifractal yields estimates of m that are not applicable to well logs in oil or gas reservoirs.

Investigation of oil recovery and CO2 storage during secondary and tertiary injection of carbonated water in an Iranian carbonate oil reservoir

Abstract Gas injection process for more oil recovery and in particular CO 2 injection is well-established method to increment oil recovery from underground oil reservoirs. CO 2 sequestration which takes place during this enhanced oil recovery (EOR) method has positive impact on reducing the greenhouse gas emission which causes global warming. Direct gas injection into depleted oil reservoirs, encounters several shortcomings such as low volumetric sweep efficiency, early breakthrough (BT) and high risk of gas leakage in naturally fractured carbonate oil reservoirs. Carbonated water injection (CWI) has been recently proposed as an alternative method to alleviate the problems associated with gas injection. In this paper, the results of extensive experimental tests of ultimate oil recovery efficiency as both secondary and tertiary CWI tests and their CO 2 storage capacity for an Iranian carbonate reservoir are presented. Besides, the CWI recovery efficiencies are compared with traditional water flooding (WF) test. The results showed that higher ultimate oil recovery is achieved when carbonated water is injected as secondary technique compared to tertiary process. The results showed 40.54% and 56.74% more oil recovery during tertiary carbonated water injection (TCWI) and secondary water injection (SCWI) compared to the corresponding water flooding, respectively. However, the CO 2 storage capacities for both TCWI and SCWI cases were almost the same, as it was measured to be more than half of the total delivered CO 2 .

Development of robust model to estimate gas–oil interfacial tension using least square support vector machine: Experimental and modeling study

The measuring of physical properties in laboratory is very important issue in petroleum industry. Secondary and tertiary oil recovery, gas condensate recovery, especially by gas injection, near-critical fluids recovery and wettability alteration surface tensions are very important to measure. One objective of this study is to perform a precise measuring procedure employing the pendant drop technique. Iranian oil reservoir samples as denser phase and its immiscible injecting gas are used at reservoir condition. While experimental measurements are often expensive and time-consuming, models are commonly used. Moreover, this study presents the potential of the least squares support vector machines (LSSVM) modeling approach to predict the gas–oil interfacial tension. To develop the model, a total of 75 data generated from our experiments covering a wide temperature range of 100 through 200F and a wide pressure range of 14.7 through 5000psi are used. Genetic algorithm (GA) as population based stochastic search algorithm was used to gain the optimal LSSVM models parameters respectively. The results revealed that the GA-LSSVM are capable of capturing the complicated nonlinear relationship between the input and output variables. For the purpose of predicting gas–oil interfacial tension, the GA-LSSVM models yielded the mean absolute error (MAE) and coefficient of determination (R2) values of 1.6028 and 0.9988, respectively for the whole data set.

Investigation of Inhibitors’ Performance on Different Asphaltenic Crude Oils

Asphaltene deposition is an ever-increasing problem at Iranian oil reservoirs and in many fields worldwide. Several procedures are used to remove or prevent asphaltene precipitation, but the uses of asphaltene inhibitors provide the most practical and economical solution for treatment of deposits. It is necessary to know the performance of an inhibitor before its application in the field. In this work performance of five inhibitors, namely, benzoic acid, nonylphenol, phenanthrene, phthalic acid, and salicylic acid on three types of Iranian oil with asphaltene content ranging from 0.321, 14.89, and 24.73% have been studied. The optimum concentration of each inhibitor was obtained. The results revealed that salicylic acid has the best efficiency on precipitation reduction for all cases of crudes.