Search

To address marketing challenges in the agricultural sector, provide financial support for small-scale farmers over marketing seasons, manage price risks of agricultural products, and enhance the functioning of agricultural mercantile exchanges, it is attainable to implement an efficient and compliant warehouse receipt system (WRS) that aligns with the legal, institutional, social, and economic-financial conditions of a country. The aim of this study is to design, simulate, and assess the feasibility of an innovative WRS in the agricultural sector. To achieve this, a WRS was designed and evaluated for maize crop in Iran. The research methodology of this study is divided into three main parts: design, simulation, and feasibility assessment of the WRS. The design process incorporated the FAO-provided (2009) warehouse receipt system development, considering the experiences of various countries and the institutional and financial regulations specific to Iran. Additionally, a dynamic programming model was used to simulate the system, and an agent-based model was utilized for system feasibility assessment. The study results demonstrated that it is possible to design an innovative and efficient WRS by involving five key actors, including farmers, buyers (maize traders), banks, mercantile exchange market, and the warehouse (governmental institution), and establishing clear communications among them. Based on simulation results using dynamic programming model, it was evident that four parameters, namely the annualized loan interest rate, the valuation coefficient for loan collateral, price volatility of the product over the marketing season, and the warehouse cost-to-product value ratio, significantly impact the adoption of the WRS by farmers. In conclusion, the findings from the agent-based model revealed that setting the annualized loan interest rate at 8%, a collateral valuation coefficient of 85%, price fluctuations over the non-harvest time at 60%, and a warehouse cost-to-product value ratio of 2% can result in the participation of nearly 100% of farmers in the proposed WRS., (© 2024. The Author(s).)

The drainage and imbibition processes are critical mechanisms in petroleum engineering. These processes in a porous medium are controlled by surface forces and pressure gradients. The study of these processes in the pore scale by common simulators always has limitations in multiphase flow modeling. Also, obtaining relative permeability curves through laboratory analysis requires expensive equipment. Additionally, these laboratory experiments are quite expensive and may introduce significant uncertainties. For this purpose, this study investigated the creation of relative permeability curves and their effect on oil production. Initially, single-phase fluid and two-phase droplet flow within a fracture with both soft and rough surfaces were utilized to validate the formulation of the Smoothed Particle Hydrodynamics (SPH) method. Then, by using three randomly constructed porous medium models, the imbibition and drainage processes have been studied. Finally, sensitivity study has been carried out on critical parameters related to fluid flow dynamics in the porous environment, including pressure changes, wettability, and heterogeneity in drainage and imbibition processes. The simulation results were consistent with current theories; therefore, it is reasonable to consider SPH to characterize the fluid flow dynamic during the drainage and imbibition processes. According to sensitivity studies, pressure gradient (residual saturation of displaced fluid is about 5.65% and 8.44%) and heterogeneity (the residual saturation of the displaced fluid was 4.04% and 2.98%) have the largest impact on flow modeling in both drainage and imbibition processes and wettability (the residual saturation became 36.62% and 5.12%) has significant effect on the drainage process through porous medium. In general, fluid flow dynamic studies can be performed using the SPH method to model fluid flow in simple and complex porous medium under various flow conditions. The SPH method can also be used as an applicable tool to investigate the hydrocarbon fluids flow within larger geometries in the future., (© 2024. The Author(s).)

Miscible gas injection in tight/shale oil reservoirs presents a complex problem due to various factors, including the presence of a large number of nanopores in the rock structure and asphaltene and heavy components in crude oil. This method performs best when the gas injection pressure exceeds the minimum miscibility pressure (MMP). Accordingly, accurate calculation of the MMP is of special importance. A critical issue that needs to be considered is that the phase behavior of the fluid in confined nanopores is substantially different from that of conventional reservoirs. The confinement effect may significantly affect fluid properties, flow, and transport phenomena characteristics in pore space, e.g., considerably changing the critical properties and enhancing fluid adsorption on the pore wall. In this study, we have investigated the MMP between an asphaltenic crude oil and enriched natural gas using Peng-Robinson (PR) and cubic-plus-association (CPA) equations of state (EoSs) by considering the effect of confinement, adsorption, the shift of critical properties, and the presence of asphaltene. According to the best of our knowledge, this is the first time a model has been developed considering all these factors for use in porous media. We used the vanishing interfacial tension (VIT) method and slim tube test data to calculate the MMP and examined the effects of pore radius, type/composition of injected gas, and asphaltene type on the computed MMP. The results showed that the MMP increased with an increasing radius of up to 100 nm and then remained almost constant. This is while the gas enrichment reduced the MMP. Asphaltene presence changed the trend of IFT reduction and delayed the miscibility achievement so that it was about 61% different from the model without the asphaltene precipitation effect. However, the type of asphaltene had little impact on the MMP, and the controlling factor was the amount of asphaltene in the oil. Moreover, although cubic EoSs are particularly popular for their simplicity and accuracy in predicting the behavior of hydrocarbon fluids, the CPA EoS is more accurate for asphaltenic oils, especially when the operating pressure is within the asphaltene precipitation range., (© 2024. The Author(s).)

In the enhanced oil recovery (EOR) process, interfacial tension (IFT) has become a crucial factor because of its impact on the recovery of residual oil. The use of surfactants and biosurfactants can reduce IFT and enhance oil recovery by decreasing it. Asphaltene in crude oil has the structural ability to act as a surface-active material. In microbial-enhanced oil recovery (MEOR), biosurfactant production, even in small amounts, is a significant mechanism that reduces IFT. This study aimed to investigate fluid/fluid interaction by combining low biosurfactant values and low-salinity water using NaCl, MgCl 2 , and CaCl 2 salts at concentrations of 0, 1000, and 5000 ppm, along with Geobacillus stearothermophilus. By evaluating the IFT, this study investigated different percentages of 0, 1, and 5 wt.% of varying asphaltene with aqueous bulk containing low-salinity water and its combination with bacteria. The results indicated G. Stearothermophilus led to the formation of biosurfactants, resulting in a reduction in IFT for both acidic and basic asphaltene. Moreover, the interaction between asphaltene and G. Stearothermophilus with higher asphaltene percentages showed a decrease in IFT under both acidic and basic conditions. Additionally, the study found that the interaction between acidic asphaltene and G. stearothermophilus, in the presence of CaCl 2 , NaCl, and MgCl 2 salts, resulted in a higher formation of biosurfactants and intrinsic surfactants at the interface of the two phases, in contrast to the interaction involving basic asphaltene. These findings emphasize the dependence of the interactions between asphaltene and G. Stearothermophilus, salt, and bacteria on the specific type and concentration of asphaltene., (© 2024. The Author(s).)

Among the Enhanced Oil Recovery (EOR) methods, gas-based EOR methods are very popular all over the world. The gas injection has a high ability to increase microscopic sweep efficiency and can increase production efficiency well. However, it should be noted that in addition to all the advantages of these methods, they have disadvantages such as damage due to asphaltene deposition, unfavorable mobility ratio, and reduced efficiency of macroscopic displacement. In this paper, the gas injection process and its challenges were investigated. Then the overcoming methods of these challenges were investigated. To inhibit asphaltene deposition during gas injection, the use of nanoparticles was proposed, which were examined in two categories: liquid-soluble and gas-soluble, and the limitations of each were examined. Various methods were used to overcome the problem of unfavorable mobility ratio and their advantages and disadvantages were discussed. Gas-phase modification has the potential to reduce the challenges and limitations of direct gas injection and significantly increase recovery efficiency. In the first part, the introduction of gas injection and the enhanced oil recovery mechanisms during gas injection were mentioned. In the next part, the challenges of gas injection, which included unfavorable mobility ratio and asphaltene deposition, were investigated. In the third step, gas-phase mobility control methods investigate, emphasizing thickeners, thickening mechanisms, and field applications of mobility control methods. In the last part, to investigate the effect of nanoparticles on asphaltene deposition and reducing the minimum miscible pressure in two main subsets: 1- use of nanoparticles indirectly to prevent asphaltene deposition and reduce surface tension and 2- use of nanoparticles as a direct asphaltene inhibitor and Reduce MMP of the gas phase in crude oil was investigated., (© 2024. The Author(s).)

The purpose of this work was to study the ability of nineteen food-grade microorganisms as Pickering emulsion (PE) stabilizers. Medium-chain triacylglycerol (MCT) oil-in-water (50:50) PEs were fabricated by 10 wt% or 15 wt% of thermally-inactivated yeast, cocci, Bacillus spp. and lactobacilli cells. The characteristics of microorganisms related to "Pickering stabilization" including morphology, surface charge, interfacial tension, and "contact angle" were firstly studied. After that, the cells-stabilized PEs were characterized from both kinetic and thermodynamic viewpoints, microstructure and rheological properties. The interfacial tension and "contact angle" values of various microorganisms ranged from 16.33 to 38.31 mN/m, and from 15° to 106°, respectively. The mean droplet size of PEs ranged from 11.51 to 57.69 µm. Generally, the physical stability of cell-stabilized PEs followed this order: lactobacilli > Bacillus spp. > cocci > yeast. These variations were attributed to the morphology and cell wall composition. Increasing the microorganism concentration significantly increased the physical stability of PEs from a maximum of 12 days at 10 wt% to 35 days at 15 wt% as a result of better interface coverage. Shear-thinning and dominant elastic behaviors were observed in PEs. Physical stability was affected by the free energy of detachment. Therefore, food-grade microorganisms are suggested for stabilizing PEs., (© 2023. Springer Nature Limited.)

Asphaltene instability in oil causes severe problems such as deposition and more stable emulsions. Formation and stability of W/O emulsions based on location in which they are formed can either be helpful or detrimental for enhanced oil recovery. Changes in oil composition (saturate, aromatic, resin, and asphaltene) can also render the stability of asphaltene. In this study, the formation and staility of emulsions are investigated using changes in the colloidal instability index (CII) at ambient and reservoir conditions. Experiments were conducted for crude oil samples from various reservoirs which showed that when CII is greater than 1.059, due to the excessive instability of asphaltene and its movement toward the water-oil interface, the formed emulsion would be more stable. When CII was below 1.059 though, the asphaltene became stable hence did not tend to be placed at the water-oil interface, thus less stable emulsion was expected. Higher pressures led to an increase in the stability of the emulsion. These changes in the process of emulsion stability are related to two mechanisms of asphaltene absorption and greater shear stresses., (© 2023. Springer Nature Limited.)

Smart water injection is one of the engineering techniques to enhance oil recovery (EOR) from carbonate and sandstone reservoirs that have been widely used in recent decades. Wettability alteration and IFT are among the essential and influential mechanisms that can be mentioned to achieve EOR. One of the critical issues in the field of EOR is the effect of reservoir ions on the formation and stability of the emulsion. Investigating the role and performance of these ions during EOR processes is of significant importance. These processes are based on smart water injection and natural production. In this research, stability was investigated and formed during the injection of different concentrations of anionic and cationic surfactants, respectively alpha olefin sulfonate (AOS) and cetrimonium bromide (CTAB), into a water-oil emulsion with a volume ratio of 30-70. Considering the droplet diameter distribution and the flow speed of separation by centrifugation, the optimal concentration level has been investigated in both surfactants. Based on the results, the highest stability and emulsion formation occurred in the presence of AOS surfactant. Then different concentrations of CaCl 2 , MgCl 2 , and NaCl salts were added in optimal concentrations of both surfactants. The formation and stability of the emulsion was checked by examining the distribution of the droplet diameter and the separation flow rate. AOS anionic surfactant had the most stability in the presence of MgCl 2 salt, and better performance in stability of the emulsion was obtained. The maximum number of droplet diameters in the optimal concentration for AOS and CTAB surfactant systems is 1010 and 880, respectively, and for binary systems of AOS surfactant and MgCl 2 , CaCl 2 and NaCl salts, it is 2200, 1120 and 1110, respectively. Furthermore, for the CTAB binary system in the presence of MgCl 2 , CaCl 2 , and NaCl salts, it is 1200, 1110, and 1100, respectively. The stability of the emulsion of salts in the presence of both AOS and CTAB surfactants was MgCl2 > CaCl 2  > NaCl., (© 2023. The Author(s).)

Gas injection is one of the most common enhanced oil recovery techniques in oil reservoirs. In this regard, pure gas, such as carbon dioxide (CO 2 ), nitrogen (N 2 ), and methane (CH 4 ) was employed in EOR process. The performance of pure gases in EOR have been investigated numerically, but till now, numerical simulation of injection of rich gases has been scared. As rich gases are more economical and can result in acceptable oil recovery, numerical study of the performance of rich gases in EOR can be an interesting subject. Accordingly, in the present work the performance of rich gases in the gas injection process was investigated. Methane has been riched in liquefied petroleum gas (LPG), natural gas liquid (NGL), and Naphtha. Afterwards, the process of gas injection was simulated and the effect of injection fluids on the relative permeability, saturation profile of gas, and fractional flow of gas was studied. Our results showed that as naphtha is a heavier gas than the two other ones, IFT of oil-rich gas with naphtha is lower than other two systems. Based our results, gas oil ratio (GOR) and injection pressure did not affect the final performance of injection gas that has been riched in NGL and LPG. However, when GOR was 1.25 MSCF/STB, rich gas with naphtha moved with a higher speed in the domain and the relative permeability of each fluid and fractional flow of gas were affected. The same result was achieved at higher injection pressure. When injection pressure was 2000 psi, movement of gas with higher speed in the domain, alteration of relative permeability and changes in the fractional flow of gas were obvious. Therefore, based on our result, injection of naphtha with low pressure and high GOR was suggested for considered oil., (© 2023. The Author(s).)

Due to population growth, the need for energy, especially fossil fuels, is increased every year. Since the costs of exploring new reservoirs and drilling new wells are very high, most reservoirs have passed their first and second periods of life, and it is necessary to use EOR methods. Water-based enhanced oil recovery (EOR) methods are one of the popular methods in this field. In this method, due to the possibility of emulsion formation is high, and by creating a stable emulsion, viscosity and mobility improved. In this study, the parameters affecting the stability and viscosity of the emulsion have been investigated step by step. In the first step, 50% (v/v) of water has been selected as the best water cut. The type of salt and its best concentration was evaluated in the second step by measuring the average droplets size. The third step investigated the effect of SiO 2 nanoparticles and surfactant (span80) on emulsion stability and viscosity. According to the results, the best amount of water cut was 50% due to the maximum viscosity. In salts the yield was as follows: MgCl 2  > CaCl 2  > MgSO 4  > Na 2 SO 4  > NaCl. The best yield was related to MgCl 2 at a concentration of 10,000 ppm. Finally, it was shown that the synergy of nanoparticles and surfactants resulted in higher stability and viscosity than in the case where each was used alone. It should be noted that the optimal concentration of nanoparticles is equal to 0.1% (w/w), and the optimal concentration of surfactant is equal to 200 ppm. In general, a stable state was obtained in 50% water-cut with MgCl 2 salt at a concentration of 10,000 ppm and in the presence of SiO 2 nanoparticles at a concentration of 0.1% and span 80 surfactants at a concentration of 200 ppm. The results obtained from this study provide important insights for optimal selection of the water-based EOR operation parameters. Viscosity showed a similar trend with stability and droplet size. As the average particle size decreased (or stability increased), the emulsion viscosity increased., (© 2023. The Author(s).)

The increase in oil production from hydrocarbon reservoirs has always been of interest due to the increase in global oil consumption. One of the effective and useful methods for enhancing oil recovery from hydrocarbon reservoirs is gas injection. Injectable gas can be injected into two modes, miscible and immiscible. However, to inject more efficiently, different factors, including Minimum Miscibility Pressure (MMP) in the gas near-miscible injection mode, should be investigated and determined. In order to investigate the minimum miscible pressure, different laboratory and simulation methods have been prepared and developed. This method uses the theory of multiple mixing cells to simulate, calculate and compare the minimum miscible pressure in gas injection enriched with Naptha, LPG, and NGL. Also vaporizing and condensing process is also considered in the simulation. The constructed model is presented with a new algorithm. This modeling has been validated and compared with laboratory results. The results showed that dry gas enriched by Naphta due to having more intermediate compounds at lower pressure (16 MPa) is miscible. In addition, dry gas, due to very light compounds, needs higher pressures (20 MPa) than all enriched gases for miscibility. Therefore, Naptha can be a good option for injecting rich gas into oil reservoirs to enrich gas., (© 2023. The Author(s).)

This article presents the results of a numerical experiment and an analysis of temperature fields (coolers for gas) using cooling elements in the case study gas pipeline. An analysis of the temperature fields demonstrated several principles for the formation of a temperature field, which indicates the need to maintain a relative temperature for gas pumping. The essence of the experiment was to install an unlimited number of cooling elements on the gas pipeline. The purpose of this study was to determine at what distance it is possible to install cooling elements for the optimal gas pumping regime, regarding the synthesis of the control law and the determination of the optimal location and assessment of control error depending on the location of the cooling elements. The developed technique allows for the evaluation of the developed control system's regulation error., (© 2023. The Author(s).)

One of the most important problems that the drilling industry faces is drilling cost. Many factors affect the cost of drilling. Increasing drilling time has a significant role in increasing drilling costs. One of the solutions to reduce drilling time is to optimize the drilling rate. Drilling wells at the optimum time will reduce the time and thus reduce the cost of drilling. The drilling rate depends on different factors, some of which are controllable and some are uncontrollable. In this study, several smart models and a correlation were proposed to predict the rate of penetration (ROP) which is very important for planning a drilling operation. 5040 real data points from a field in the South of Iran have been used. The ROP was modelled using Radial Basis Function, Decision Tree (DT), Least Square Vector Machine (LSSVM), and Multilayer Perceptron (MLP). Bayesian Regularization Algorithm (BRA), Scaled Conjugate Gradient Algorithm and Levenberg-Marquardt Algorithm were employed to train MLP and Gradient Boosting (GB) was used for DT. To evaluate the accuracy of the developed models, both graphical and statistical techniques were used. The results showed that DT-GB model with an R 2 of 0.977, has the best performance, followed by LSSVM and MLP-BRA with R 2 of 0.971 and 0.969, respectively. Aside from that, the proposed empirical correlation has an acceptable accuracy in spite of simplicity. Moreover, sensitivity analysis illustrated that depth and pump pressure have the highest effects on ROP. In addition, the leverage approach approved that the developed DT-GB model is valid statistically and about 1% of the data are suspected or out of the applicability domain of the model., (© 2022. The Author(s).)

High water production in oil fields is an area of concern due to economic issues and borehole/wellhead damages. Colloidal gels can be a good alternative to polymers to address this as they can tolerate harsh oil reservoir conditions. A series of bottle tests with different silica and NaCl concentrations were first conducted. The gelation time, cation valence, rheology, and viscosity were investigated to characterize the gels. The applicability of solid gels in porous media was finally inspected in a dual-patterned glass micromodel. Bottle test results showed that increasing NaCl concentration at a constant silica concentration can convert solid gels into two-phase gels and then viscous suspensions. Na + replacement with Mg 2+ resulted a distinctive behaviour probably due to higher coagulating ability of Mg 2+ . Rheology and viscosity results agreed with gelation times: gel with shortest gelation time had the highest viscosity and storage/loss modulus but was not the most elastic one. Water injection into glass micromodel half-saturated with crude oil and solid gel proved that the gel is strong against pressure gradients applied by injected phase which is promising for water conformance controls. The diverted injected phase recorded an oil recovery of 53% which was not feasible without blocking the water zone., (© 2022. The Author(s).)