PETROLEUM RESEARCH
Year:2025 | Volume:34 | Issue:6|Papers Count:10

One of the significant challenges in enhanced oil recovery studies is to control and diverte the path of injected fluid towards target zones containing more remaining oil. One of the promising methods for fluid diversion is using foam to increase the performance of injected flow behavior. However, to achieve such a performance, it is necessary to investigate the foam flow behavior at the pore scale to elucidate the governing mechanisms involved in the diversion process. To this end, a porous medium pattern was designed, consisting of dual-layer with different permeabilities and cross flow between them. To conduct experiments, first the oil-saturated micro-model was flooded by brine to reach its residual oil saturation condition. Subsequently, foam performance was examined in the form of simultaneous gas and foaming agent injection. In this study, sodium dodecyl sulfate was used as the foaming agent at 35000 ppm of NaCl brine. Results showed that in gas injection, due to very high gas mobility and thus no enough pressure gradient for liquid diversion, oil recovery was only obtained from high permeability later with almost no contribution from low permeability layer. However, foaming the injected gas improved gas apparent viscosity and thus improving in the heterogeneous dual-layer system in a way that diversion of the injected fluid from the high permeability to low permeability layer occurred. Accordingly, fluid diversion by foam led to an increase in residual oil production from the low permeability layer, increasing the production efficiency from 9% to 85%. The effectiveness of foam injection in a heterogeneous, layered porous media and subsequently increasing residual oil production could be described in the light of viscous cross-flow, diverting the injected fluid from high to low permeability regions, and also enhancing the performance of gas displacement front. Results of this study indicate the promising potential of foam as a viable fluid diversion agent for controlling the mobility of injected fluid in a heterogeneous, layered system.

When the combination of salinity water, surfactants and Nanoparticles (NPs) are used simultaneously, the interfacial tension (IFT) could reach its lowest value and subsequently the oil recovery could be improved. In this paper, the method of modified metal oxide NPs with environmentally friendly surfactant dispersed in different base fluids was applied. Silica and gamma-alumina NPs and their hybrid nanofluids (HNFs) were used with mass ratios of 10:90, 30:70 and 50:50. Also, distilled water and various smart waters with salinities 4071, 8142, 20400 and 40710 (ppm) were considered as basic fluids. The presence of Ca2+ and Mg2+ ions in salinity water creates amphoteric properties in HNFs, which greatly causes the instability of nanomaterials in the vicinity of saline water. Therefore, in order to be more stable, gum arabic was used as a green surfactant.  After evaluating the duration of stability of HNFs, IFT was tested at temperatures 25 and 60 °C and viscosity at temperatures 25, 35, 45 and 55 °C. On the other hand, the results showed that an increase at temperature could lead to a decrease at IFT and viscosity for nanofluids. The lowest IFT at 60 °C was obtained for the HNFs with a mass ratio of gamma-alumina and silica of 50:50 dispersed in smart water with a salinity of 4071 ppm. The lowest viscosity at 55 °C was reported for HNFs with a mass ratio of 50:50 dispersed in distilled water. Minimizing the IFT and improving the rheological behavior of optimal nanofluids towards a strong water wet system could be considered as a promising solution in EOR applications.

Oil and gas production is usually associated with the production of water. As the life of the field increases, water production and related problems such as losing a large part of the hydrocarbon reserves, decrease in oil production, increase in production costs, formation damages, etc. also increase; So far, excessive water production has been considered as one of the main challenges of mature fields. In this research, in order to screen the appropriate technology for solving the excessive produced water problem in one of the southern Iranian oil fields, required technologies were identified and prioritized by employing the comprehensive approach. This approach was employed before conducting laboratory tests, simulation study, and pilot operations to save money and time. Therefore, before focusing on technical details, other contributing factors such as economy, environment, political/social aspects, market, technical capacities, and the effects of new technology entering the existing industrial ecosystem and finally the interaction of new technology with other industry components as a vital part in the technology development process were considered. Technology evaluation using the above-mentioned approach helps the organization’s technology strategy development process. In order to perform the methodology, sixteen technologies were identified in two categories of chemical and mechanical by reviewing scientific references and field preliminary data to reduce or eliminate excessive produced water. Fifteen attractiveness criteria along with six criteria for evaluating the company’s capability of using them were identified. These criteria were localized and weighted using the literature of technology management and experts’ opinions. Using the questionnaire, data related to each technology was collected from the perspective of each criterion. Therefore, the position of the technology in the attractiveness-capability matrix was determined; «Mechanical plugs (cement bridge, etc.)», «Short liner», «side track», «casing patch», «Straddle Packer», «Horizontal drilling» and «Polymer gel» were determined as the technology portfolio for the organization and proposed as candidates for future detailed studies.

One of the most crucial procedures for enhancing oil well extraction from those with little to no production is artificial gas lift. There is an optimum gas injection rate in gas production, and altering this rate will result in less oil being produced. During production, this optimal point changes, resulting in an ideal path. Additionally, the distribution of gas in a single time step lowers reservoir pressure and modifies the output of various wells. This problem may have an impact on the next time step›s ideal gas distribution. Numerous studies on the optimization of gas lift have been conducted in the past, but the majority of them did not make use of the effective tool in a dynamic model to identify a good optimal path. IPM software was utilized to simulate the field in this paper. Software from Pvtp, Mbal, Prosper, and Gap was used to model the fluid, reservoir, well, and surface equipment, in that order. Gap software was then used to integrate all the components into a single system to create a unified system. Lastly, the best gas rate path for the artificial gas lift wells was determined using gap optimization, which takes the dynamic model into account. The outcomes demonstrated that there is an optimal point at which higher production may be achieved when using integrated system optimization with less available gas limitation. This is because the integrated system optimizes the gas injection rate by taking into account the dynamic model and the impact of reservoir pressure.

During the lifetime of an oil well, the near wellbore areas are usually exposed to formation damage due to factors such as fines migration, clay swelling, etc., significantly reducing the oil well›s productivity and injectivity rates. One of the widely used well-stimulation methods to remove formation damage is acidizing in which the acid and chemicals (additives) are injected into the formation to increase the permeability of the formation by dissolving carbonate rocks. However, the lack of laboratory examination of the compatibility of injection fluids with formation fluids at the design stage results in induced damage such as acid emulsion in oil in formation. The conduction of laboratory tests in order to execute compatibility between fluids is time-consuming, expensive, and has issues related to safety. This research aims to predict the primary results of anti-emulsion tests using data-driven models in a short time. For this purpose, the most influential data on the results of these tests, including type and concentration of acid, and additives like anti-emulsion, anti-sludge, surface tension reducer, and iron ion reducer, as well as properties of 13 different types of oil from various reservoirs, such as viscosity, density, and ferric ion concentration, were collected and recorded as inputs to a data set. Then, some supervised classification models including random forest, support vector machine, multi-layer perceptron, and extreme gradient boosting algorithms have been implemented to predict the output of anti-emulsion tests. Additionally, the statistical technique SMOTE (Synthetic Minority Oversampling Technique) was employed to generate artificial data samples and enhance AI models’ performance. Ultimately, results indicate that the extreme gradient boosting with five estimators achieved the best performance with Cohen›s kappa values of 0.79 and 0.523 for training and testing datasets, respectively.

Evaluation of the mechanical properties of reservoir rocks is an essential criterion in determining suitable points for hydraulic fracturing operations. Meanwhile, Young›s modulus and Poisson›s ratio are two mechanical parameters controlling rock layers› brittleness. These two parameters can be calculated by performing tests on rock samples in different laboratory conditions (static method) or using sonic and density log data (dynamic method). The calculation of dynamic elastic moduli requires shear wave velocity data, which, despite its great importance, is only measured in a small number of wells in the field due to the limitation and high cost of measurement. In this study, due to the lack of shear wave velocity in the well in question, the bulk and shear moduli of the rock were estimated with the help of a carbonate rock physics model. Then, by calculating Poisson›s ratio and Young›s dynamic modulus and using the laboratory relationship to convert these moduli into the static state, the brittleness index was determined, and considering the effective reservoir parameters, the candidate layers for hydraulic fracturing operations were identified and prioritized.

This study investigates the performance of diacetylated sophorolipid acid biosurfactant in enhanced oil recovery (EOR) using oil displacement tests, surface and interfacial tension measurements, wettability alteration, and flooding in homogeneous and heterogeneous micromodels. The biosurfactant demonstrated significant potential, reducing the surface tension of pure water from 74 to 41.33 mN/m at 5000 ppm. In the presence of 80,000 ppm salinity, the interfacial tension decreased from 42.37 to 14.9 mN/m. Moreover, wettability alteration tests revealed that the biosurfactant changed carbonate rock wettability from oil-wet to water-wet, increasing the contact angle from 20.30° to 42.11°. Finally, micromodel flooding tests showed oil recovery rates of 78% and 71% in homogeneous and heterogeneous micromodels, respectively, under optimal conditions.

Due to the high toxicity of kerosene composition in humans and living organisms, in this project; the degradation of kerosene in water in the presence of nano zirconium oxide was investigated in different conditions. Moreover, the kerosene used in this research has aliphatic compounds whose number of carbons is between 6-22. Hydrocarbons in this sample were identified using the gas chromatography method and compared with ASTMD2163 test results. The degradation of kerosene in the presence of nano zirconium oxide was investigated using gas chromatography, a viscometer, a density meter, and a pH meter. In this project, data related to kinematic viscosity and dynamic viscosity were measured. The pH changes measured in the water show that the degradation of kerosene produces carbon dioxide gas because the pH is <7. Ultimately, in this study, the amount of changes in hydrocarbon fractions was investigated by gas chromatography method. Also, based on the obtained results, a mechanism for the degradation of kerosene, which can be carried out through the production of hydroxy radical, was reported.

Acidizing process increases the productivity of oil and gas wells, but its improper design can cause the formation of acid-induced sludge as a serious formation damage. There is a main question that is it possible to control the sludge through regulating operational parameters instead of using additives. In this research, the effect of main parameters such as crude oil-acid mixing speed (as a representative of acid injection rate), acid-crude oil mixture ratio (as a representative of acid injection volume), temperature, and crude oil specification (colloidal instability index and asphaltene content) were examined on sludge formation. Standard compatibility test RP-42 with some modification was utilized for this purpose. In addition, in order to study the effect of viscosity, some experiments were done using synthetic oil prepared by diluting the crude oil with toluene and heptane. Moreover, the results showed the noticeable effect of mixing speed, increasing it from 500 to 1500 rpm was led to increase the amount of sludge in three crude oil samples A, B and C by 2.1, 1.58 and 1.49 times, respectively. In addition, it can be attributed to create more interface area of acid and crude oil droplets for higher shears. Also, by changing the acid mixture ratio from 0.2 to 0.8 in crude oil samples A, B and C, caused to intense the sludge deposition by 1.27, 2.37 and 3 times, respectively. Furthermore, increasing the temperature from 30 to 85 °C produced similar behavior for sludge formation by increasing 2.7, 1.57 and 1.84 times, respectively. The crude oils have been shown different tendencies for sludge formation. The sample A has formed the sludge 6.1 and 37.7 times higher than B and C oils, respectively. Ultimately, the composition of sample A with higher colloidal instability index and asphaltene content leads to higher tendency for sludging. In addition, in order to investigate the effect of oil viscosity exclusively, the results of crude oil B and its synthetic oil showed the sludge reduction due to 1.68-fold decrease of viscosity in the prepared synthetic oil.

The presence of bubbles is evident in most two-phase gas-liquid flows. The measurement of void fraction in various industries, such as nuclear, chemical and petrochemical, provides valuable insight into the distribution of phases in a multiphase system. This understanding can lead to the improvements in the design, operation and maintenance of industrial processes in sectors like oil and gas, petrochemicals, chemical reactors, heat exchangers, and geothermal power plants. In many cases, bubbles are evenly distributed in the liquid, creating uncertainty in measurements. To address this issue, this research utilized a wide gamma beam in conjunction with a flat panel detector to minimize systematic errors caused by fluctuations in bubble placement along the path of the gamma ray passing through the flow tube. Next, in the Monte Carlo simulation environment, the numerical density of the bubble is calculated in a fixed volume. Using the calibration chart, the fraction of the bubble is determined in terms of the numerical density for various bubble radius values. Ultimately, after validating the code by comparing the results of the spectrum produced from the code with the spectrum of a reference sample from an X-ray tube, the graph displaying numerical density changes in terms of bubble fraction at different radii demonstrates the method’s ability to distinguish varying amounts of bubble fraction for different radii.