Recent Innovations in Chemical Engineering (Formerly Recent Patents on Chemical Engineering) - Volume 16, Issue 2, 2023

Background: With the constant development and growth of the world’s economy, the demand for energy continues to rise. However, rising oil prices, increasing carbon emissions, and energy shortages will limit economic development and affect living standards. Therefore, further exploitation and utilization of natural gas are of great significance for the sustainable development of national economies and the improvement of civil life. Objective: Natural gas contains acidic gas, such as hydrogen sulfide (H2S), and can lead to physical safety issues, environmental pollution, equipment corrosion, and catalyst poisoning. Therefore, a desulfurization process, which has practical significance, must be carried out to reduce the H2S content to less than 20 mg•m⁻³. Methods: Currently, the main desulfurization processes involve dry and wet desulfurization methods. The wet desulfurization methods include physical, chemical, and physico-chemical solvent methods, which have a large processing capacity and involve a continuous operation sequence applied to the purification of natural gas containing a high sulfur content. The dry desulfurization methods, which use a solid as the desulfurizer, have high precision, easy operation, and low energy consumption. This method has been widely applied to advanced treatment. Activated carbon, which has a large surface area, large pore volume, and complex porous structure, is widely used as an adsorbent for desulfurization. When compared with other adsorbents, activated carbon has several advantages, such as a high adsorption capacity and low cost. The H2S removal performance of the adsorbent can be significantly improved after modification. In this study, using a low concentration of H2S and nitrogen to simulate raw fuel gas, cupric nitrate-modified activated carbon was used as the main adsorbent for desulfurization. The effect of the preparation conditions on the H2S removal performance was studied, and the adsorbents were characterized using a series of methods. Results: In this study, a low concentration of H2S and nitrogen were used to simulate raw fuel gas, and cupric nitrate-modified activated carbon was used as an adsorbent. The results from structural analysis indicated a significant change in the surface structure of AC by introducing Cu(NO3)2. Cu(NO3)2 promoted the transformation of micropores into mesopores or macropores and active substances into the pores of AC for desulfurization. The effects of the preparation conditions on the H2S removal performance were studied using a fixed-bed adsorption column. The best preparation conditions for the Cu(NO3)2 modified activated carbon adsorbent involved: a Cu(NO3)2 impregnation concentration of 5%, impregnation time of 24 h, calcination temperature of 300 °C, and calcination time of 2 h. The H2S saturation capacity and desulfurization rate reached 55.4 mg·g⁻¹ and 98.92%, respectively. The H2S saturation capacity was improved by 38.2 mg·g⁻¹ compared with unmodified activated carbon. Conclusion: In this study, a low concentration of H2S and nitrogen were used to simulate raw fuel gas, and cupric nitrate-modified activated carbon was used as an adsorbent. The experimental results showed that the H2S removal performance of the adsorbent was significantly improved using Cu(NO3)2 impregnated activated carbon.

Background: In recent years, CO2 composite fracturing technology has been widely used in unconventional reservoirs. Compared to conventional hydraulic fracturing, CO2 fracturing can create complex fractures, replenish formation energy and reduce oil flow resistance. For shale oil reservoirs with natural fractures, CO2 composite fracturing can not only give full play to the advantages of complex fracture networks created by CO2 but also make use of water-based fracturing fluid to create long fractures with high conductivity. Methods: Based on fracture fluid flow, stress interference, natural fracture description, and CO2 phase change equation, a CO2 composite fracture propagation model was established in this paper to simulate the effects of fracturing fluid type, CO2 proportion, construction scale, natural fracture development, fracturing fluid injection rate and other factors on the propagation morphology of CO2 injection fracture network in shale oil reservoirs. Results: The results show that the water-based fracturing fluid is beneficial to the formation of long main fractures, but the overall complexity of the fracture network and the effective stimulated volume of the fracture network are significantly lower than that of CO2 fracturing. The application of the appropriate proportion of CO2 composite fracturing fluid can give full play to the comprehensive advantages of CO2 and water-based fracturing fluid and realize the full stimulation of the reservoir. CO2 fracturing in shale oil reservoirs with low principal stress difference and high natural fracture development extent can communicate natural fractures in a large range and form a complex fracture network. For shale oil reservoirs with natural fractures, a high fracturing fluid injection rate can significantly improve the complexity of the fracture network. Conclusion: The CO2 composite fracturing technology is applied to horizontal wells in X shale reservoir, and the production after fracturing is significantly higher than that of offset wells, which can be applied in the same type of reservoir and has broad application prospects.

Aims: The current study aimed to investigate the CO2 absorption capacity of the aqueous alkanolamine, including primary, secondary, tertiary, and sterically hindered amines and polyamines, i.e., monoethanolamine (MEA), diethanolamine (DEA), triethanolamine (TEA) and 2-amino-2-methyl-1-propanol (AMP), tetraethylenepentamine (TEPA), triethylenetetramine (TETA), 3-(Methylamino)propylamine (MAPA), and diethylenetriamine (DETA) at 40, 60, and 80°C at 1.1 bar. Methods: An increase in reaction temperature caused a decrement in CO2 loading across the board for all solvents. The trend of CO2 loading was TEA < MEA < DEA < AMP < MAPA < DETA < TETA < TEPA at 40 ºC, TEA < DEA < MEA < AMP < MAPA < DETA < TETA < TEPA, at 60ºC and TEA < DEA < AMP < MEA < MAPA < DETA < TETA < TEPA at 80ºC. Results: The results indicated that TEPA has great potential to be utilized as an energy-efficient and non-corrosive solvent for CO2 capture since it has outperformed all other aqueous amine solvents in this present study. Furthermore, the CO2 loading of sterically hindered amine (AMP) at the same temperature was found to be higher than primary, secondary, and tertiary amines. Heat of absorption (ΔHabs) was also determined to gauge the energy requirement to regenerate absorbents for cyclic loading from an economic viewpoint. Conclusion: DETA has the highest ΔHabs = 84.48 kJ/mol. On the contrary, the long-chain tertiary amine TEA resulted in the least ΔHabs = 40.21 kJ/mol, among all other solvents. Whereas the sterically hindered amine (AMP) was observed to possess mid-range ΔHabs, i.e., 58.76 kJ/mol. Among all selected solvents, polyamines showed higher ΔHabs than other conventional amines pertaining to the precedence of TEA

Objective: This study aims to understand the mixing phenomenon and the mass transfer occurring simultaneously by simulating the system using Ansys Fluent. Methods: Taking liquid-liquid mixing into account, a simple agitated mixing system can be compared to a CSTR, utilizing the impeller to provide forced convection mixing conditions. The same forced convection can be achieved using high flow rates in smooth vessels instead of mechanical impellers to produce the convection current. The systems are then stimulated using Ansys Fluent software to calculate the mass transfer coefficient and several dimensionless numbers, such as the Reynolds number, Sherwood number, and Schmidt number, in order to understand the underlying mechanism of mass transfer in mixing systems. Results: It has been observed that a 90° pitch impeller tends to have a higher NP value as compared to a 45° pitch impeller. Overall performance can be compared by the time taken to achieve homogeneity at the same angular rotational speed of 100 rpm. Thus, in terms of performance, it can be concluded that 45° pitch is (inclined) > 90° pitch is (in-centre) > 45° pitch (in-centre) is > 90° pitch (inclined). Conclusion: The simulation model used in this study is useful for a combination of CFD model predictions using the sliding mesh approach and the VOF model. It can be applied to study the effect of different designs on the flow pattern and mixing time for a set of axial flow impellers.

Introduction: Crude oil is a complex mixture consisting of different hydrocarbons such as resins, asphaltenes, aromatics and paraffins. Wax deposition in oil pipelines is considered to be one of the most serious flow assurance problems. Method: In order to obtain a pour point depressant with a better effect on Daqing waxy crude oil, a model oil containing Daqing paraffin was investigated. Polyoctadecyl acrylate was prepared by taking polymerization of octadecyl acrylate monomer under the corresponding reaction conditions. The pour point and viscosity were measured after adding the pour point depressant into the waxy model oil. Results: The experimental results showed that the best pour point reduction effect of polyoctadecyl acrylate was achieved when the mass of octadecyl acrylate monomer was 40wt% of the total mass (the sum of the mass of solute octadecyl acrylate and solvent toluene), the reaction temperature was 80 °C, the reaction time was 6 h, and the amount of initiator was 0.15wt% under the condition that toluene was used as the solvent. The addition of polyoctadecyl acrylate effectively inhibits the appearance of wax crystals and makes the distribution of wax crystals more dispersed. Conclusion: The optimal pour point depressant concentration was found to be 800 mg/kg. The alkyl side chains of polyoctadecyl acrylate allow co-crystallization with the waxy crystals and thus their dispersion, while its polar groups can weaken the interactions between the wax crystals.