Mass Transfer of CO2 Into Water and Surfactant Solutions

The mass transfer of CO₂ into water and aqueous solutions of sodium dodecyl sulphate (SDS) is experimentally studied using a pressure, volume, temperature (PVT) cell at different initial pressures and a constant temperature (T = 25°C). It is observed that the transfer rate is initially much larger than expected from a diffusion process alone. The model equations describing the experiments are based on Fick's Law and Henry's Law. The experiments are interpreted in terms of two effective diffusion coefficients—one for the early-stages of the experiments and the other one for the later stages. The results show that at the early stages, the effective diffusion coefficients are one order of magnitude larger than the molecular diffusivity of CO₂ in water. Nevertheless, in the later stages the extracted diffusion coefficients are close to literature values. It is asserted that at the early stages, density-driven natural convection enhances the mass transfer. A similar mass transfer enhancement was observed for the mass transfer between a gaseous CO₂ rich phase with an oil (n-decane) phase. It is also found that at the experimental conditions studied addition of pure SDS does not have a significant effect on the mass transfer rate of CO₂ in water.     

Modeling of CO2 capture from gas stream emissions of petrochemical industries by membrane contactor

Abstract

Process optimization of CO₂ removal from natural gas by a polyvinylidene fluoride hollow-fiber membrane contactor is a major goal of many computational fluid dynamics (CFD) simulations in this area. In this study, a 2D CFD model based on mass transfer equation inside the tube, the membrane, and the shell section of a HMFC at steady state and laminar conditions is developed and solved by COMSOL Multiphysics with finite element approach. Simulation results show an excellent agreement with experimental data. The model predicts that higher liquid velocity and membrane porosity results in higher CO₂ removal, because of enhancement of effective diffusion coefficient. Also, taller fiber length results in higher contact area and higher mass transfer of CO₂ from natural gas into distilled water. Although higher temperature will decrease the CO₂ removal.     

Study of the hydrodynamics and mass transfer on a tangential plate

Summary The hydrodynamics and mass transfer during desorption of CO₂ by air from water on a tangential plate have been studied at gas flow rates ranging from 0.6 to 3.5 m/sec and irrigation densities ranging from 6 to 22 m³/m²·h; these experiments have shown that the mass transfer and plate efficiency coefficients of the plate considered are high up to 3.5 m/sec air flow rate (referred to the empty column).Translated from Khimiya i Tekhnologiya Topliv i Masel, No. 8, pp. 36–39, August, 1966.     

Modeling CO2 miscible flooding for enhanced oil recovery

The injection of fuel-generated CO2 into oil reservoirs will lead to two benefits in both enhanced oil recovery (EOR) and the reduction in atmospheric emission of CO2. To get an insight into CO2 miscible flooding performance in oil reservoirs, a multi-compositional non-isothermal CO2 miscible flooding mathematical model is developed. The convection and diffusion of CO2-hydrocarbon mixtures in multiphase fluids in reservoirs, mass transfer between CO2 and crude, and formation damages caused by asphaltene precipitation are fully considered in the model. The governing equations are discretized in space using the integral finite difference method. The Newton-Raphson iterative technique was used to solve the nonlinear equation systems of mass and energy conservation. A numerical simulator, in which regular grids and irregular grids are optional, was developed for predicting CO2 miscible flooding processes. Two examples of one-dimensional (1D) regular and three-dimensional (3D) rectangle and polygonal grids are designed to demonstrate the functions of the simulator. Experimental data validate the developed simulator by comparison with 1D simulation results. The applications of the simulator indicate that it is feasible for predicting CO2 flooding in oil reservoirs for EOR.     

Kinetics of (TBAF + CO2) semi-clathrate hydrate formation in the presence and absence of SDS

In this communication, the impacts of adding SDS (sodium dodecyl sulfate), TBAF (tetra-n-butylammonium fluoride) and the mixture of SDS + TBAF on the main kinetic parameters of CO₂ hydrate formation (induction time, the quantity and rate of gas uptake, and storage capacity) were investigated. The tests were performed under stirring conditions at T = 5 ℃ and P = 3.8 MPa in a 169 cm³ batch reactor. The results show that adding SDS with a concentration of 400 ppm, TBAF with a concentration of 1–5 wt%, and the mixture of SDS + TBAF, would increase the storage capacity of CO₂ hydrate and the quantity of gas uptake, and decrease the induction time of hydrate formation process. The addition of 5 wt% of TBAF and 400 ppm of SDS would increase the CO₂ hydrate storage capacity by 86.1% and 81.6%, respectively, compared to pure water. Investigation of the impact of SDS, TBAF and their mixture on the rate of gas uptake indicates that the mixture of SDS + TBAF does not have a significant effect on the rate of gas uptake during hydrate formation process.     

Effects of the compound system of alkali and alkyl glycosides on the stability of oil-in-water emulsions

Abstract

The effects of Na₂CO₃, nonionic surfactant octyldecyl glucoside (APG0810), and inorganic salt addition on the water separation ratio and apparent viscosity of oil-in-water (O/W) emulsions were investigated. The influences of this compound system on the stability of the emulsion and its synergistic mechanism were also analyzed. Results revealed that in the first compound situation, when APG was selected as the main surfactant and had a concentration of 0.1%, the mass concentration of Na₂CO₃ was 0.4%, the emulsion exhibited the strongest stability, and the water separation ratio at 30?°C for 120?min was 20.3%. In the second compound situation, when Na₂CO₃ was used as the main surfactant and had a concentration of 0.1%, the mass concentration of APG was 0.4%, the emulsion displayed the strongest stability, and the water separation ratio at 30?°C for 120?min was 57.8%. The stability of the O/W emulsion increased with increased NaCl addition, and a higher salt concentration corresponded to a lower water separation ratio. After CaCl₂ addition, the apparent viscosity of the emulsion increased sharply, and the O/W emulsion underwent phase inversion to become an water-in-oil (W/O) emulsion. Within the set mass concentration range, increased salt concentration caused the apparent viscosity of the W/O emulsion measured at 50?°C and 30?rpm to decrease gradually but still exceeded 1500?mPa·s.     

Coupled THMC modeling of CO2 injection by finite element methods

Geological CO₂ sequestration has been proposed to mitigate greenhouse gas emissions. Massive CO₂ injection into subsurface formation involves interactions among pressure and temperature change, chemical reactions, solute transport, and the mechanical response of the rock; this is a coupled thermal–hydraulic–mechanical–chemical (THMC) process. Numerical modeling of CO₂ injection around the wellbore area can provide information such as changes in rock properties as well as stress and pressure changes, and this helps better predict injectivity evolution and leakage risk. In this paper, a fully coupled THMC model based on finite element methods is presented to analyze the transient stress, pressure, temperature and chemical solute concentration changes simultaneously around an injection well. To overcome these numerical oscillations in solving the transient advection–diffusion equations involved in the heat transfer and solute transport processes, we employ a stabilized finite element approach, the subgrid scale/gradient subgrid scale method (SGS/GSGS). A hypothetical numerical experiment on CO₂ saturated water injection into a carbonate aquifer is conducted and preliminary results show that the fully coupled model can successfully analyze stress and pressure changes in the rock around a wellbore subjected to thermal and chemical effects.     

Co-Mo/γ-Al2O3加氢脱硫催化剂的吸附扩散性能

用智能质量分析仪(Intelligent Gravimetric Analyser)测得了不同温度下异戊二烯(Isoprene)、戊烯-1(Pentene-1)及噻吩(Thiophene)在Co-Mo/γ-Al2O3选择性加氢脱硫催化剂上的吸附-脱附等温线及程序升温脱附曲线(TPD),并研究了三者在该催化剂上的扩散性能。结果表明,噻吩、异戊二烯、戊烯-1在Co-Mo/γ-Al2O3选择性加氢脱硫催化剂上的饱和吸附量依次降低;噻吩与该催化剂存在2种吸附作用,即物理吸附和化学吸附,化学吸附形成Co-Mo-S相,可有效地提高加氢脱硫催化剂的脱硫效果,而戊烯-1和异戊二烯在该催化剂上只存在1种弱吸附作用;3种吸附质中,戊烯-1相对扩散系数最大,噻吩和异戊二烯的相对扩散系数较小且相近。     

Operation Parameters on CO2-Foam process

Abstract

Reducing the mobility of CO₂ by means of generating in situ foam is an effective method for improving the oil recovery in CO₂ flooding processes. Implementation of the CO₂-foam technique typically involves the co-injection of CO₂ and surfactant solution into the porous medium. The surfactant molecules form bubble films that trap the flowing CO₂ molecules. The effectiveness of the CO₂-foam process is measured in terms of foam mobility. The mobility of CO₂-foam is affected by different operation parameters, such as pressure, temperature, foam quality, and brine concentration. However, surfactant type governs the overall efficiency of the CO₂-foam process. This paper presents the results of a series of experiments conducted to study the effect of various parameters on the CO₂-foam process. Bottle tests were conducted for four commercially available surfactants and among them, Chaser CD-1045 was found to be the most effective surfactant for CO₂-foam flow under reservoir conditions. It was observed that an increase in pressure from 1, 200 psi to 1, 500 psi leads to increase of the mobility of CO₂-foam, and an increase in temperature from 72 to 122°F reduces the mobility. Also, as the foam quality increases from 20 to 80%, the mobility decreases. It was observed that there was no significant effect on the mobility with an increase in brine concentration from 1 to 3 wt%.     

Effects of ultrasonic waves on carbon dioxide solubility in brine at different pressures and temperatures

The adverse impacts of CO₂ emission on the global warming highlight the importance of carbon capture and storage technology and geological storage of CO₂ under solubility trapping mechanisms. Enhancing the solubility of CO₂ in formation water has always been the focus of research in the area of CO₂ sequestration. Ultrasound techniques are one of the environmentally friendly methods that use high-intensity acoustic waves to improve gas solubility in liquids. Ultrasonic waves can alter the properties of different phases that lead to chemical reactions and provide a means to increase the solubility of CO₂ in connate water. In this study, we investigated the effects of ultrasound on the solubility of CO₂ in connate water under different conditions of pressure, temperature, and salinity. The results showed that the solubility of CO₂ was improved with increasing pressure under ultrasonic effects. However, the solubility of CO₂ was inversely proportional to the increase in brine salinity and temperature. Therefore, it was concluded that the solubility of CO₂ might be enhanced in the presence of ultrasound.     

Study on the blockage in pores due to asphaltene precipitation during different CO2 flooding schemes with NMR technique

CO₂ flooding is an effective way in the tertiary oil recovery. While asphaltene often precipitates from the crude oil during the CO₂ flooding, and the mechanisms of blockage resulting from asphaltene precipitation is still unclear in different CO₂ flooding schemes. In this work, pure-CO₂ flooding, water-alternating-CO₂ flooding (WAG), and CO₂-foam flooding were applied to conduct the core-flooding experiments. Then, as for each flooding scheme, we quantitatively investigated the blockage degree in different pores due to asphaltene precipitation with nuclear magnetic resonance (NMR) technique. Tests results show that CO₂-foam flooding has a relatively higher blockage degree both in the smaller pores and the larger pores than WAG and pure-CO₂ flooding. Although pure-CO₂ flooding has the least asphaltene precipitation and blockage degree among three flooding schemes, its oil recovery degree is far less than the other two flooding schemes. Compared with pure-CO₂ flooding and CO₂-foam flooding, WAG flooding has the highest oil recovery and an acceptable asphaltene precipitation.     

Gas Injection Into Fractured Reservoirs Above Bubble Point Pressure

Abstract

Among all enhanced oil recovery (EOR) scenarios, gas injection seems to be promising for implementation in naturally fractured reservoirs. The use of CO₂ has received considerable interest as a method of EOR but a major drawback is its availability and increasing cost. Therefore, an alternative gas like CH₄ or N₂ must be considered to meet the economic considerations. To investigate the efficiency of oil recovery by CO₂, N₂, and CH₄ injection in fractured carbonate rock, a series of experiments was designed. Both miscible and immiscible schemes for gas injection were carried out on a low-permeable outcrop carbonate rock that was surrounded by fracture, established with a novel experimental method. The experiments aimed to investigate the potential of oil recovery by secondary and tertiary gas injection under high-temperature conditions. The matrix block was saturated using a recombined mixture of Iranian live oil, and by pumping water into the annular space, the space between rubber sleeve and outer jacket, high overburden pressure was exerted to obtain the desired homogeneous saturation. Using a back-pressure regulator, the pressure was kept above the bubble point pressure. The inlet was attached to a constant pressure pump injecting gas or water above the bubble point pressure, and the overburden pressure was removed gradually and the inlet fluid inflated the rubber sleeve. The amount of produced water from the annular space was recorded to estimate the distance between the rubber sleeve and sand face. This distance creates the fracture surrounding the core. Gas was injected into the fracture at pressures above the bubble point of the oil. Oil recovery as a function of time was monitored during the experiments. Results from both secondary and tertiary gas injection experiments indicate that CO₂ injection at elevated pressure and temperature is more efficient than N₂ and CH₄ injection.     

超重力CO2吸收过程的Aspen模拟计算

目的 模拟超重力CO₂的吸收过程,从而为实验工艺参数的优化提供指导。方法 建立了超重力NaOH碱液吸收CO₂的Aspen计算模型,考查了多个影响因素对CO₂脱除率的影响。结果 通过对比可知,将超重力反应器等价转化为常规填料塔后,NaOH质量分数、碱液进料量和压力对CO₂脱除率的影响与超重力实验室的变化规律一致,但模拟值仅为实验值的1/2左右。对传质参数进行进一步修正,修正后的模拟计算结果与实验值接近,平均偏差仅为0.77%。结论 建立的超重力CO₂吸收模型准确可靠,可为后续实验提供一定的方向性指导。     

Carbon Dioxide Desorption from Amine Solution in a Nonporous Membrane Contactor

Long-term testing of a membrane contactor based on a blend of the nonporous polymers polytrimethylsilylpropyne (PTMSP) and polyvinyltrimethylsilane (PVTMS) has been carried out. The flat-sheet membrane contactor has been tested for CO₂ desorption from an aqueous methyldiethanolamine solution at 100°C. It has been found that the mass transfer parameters (CO₂ flux and stripping efficiency) of the 95%PTMSP/5%PVTMS membrane stabilize after the 7th day of testing. The CO₂ mass transfer coefficient in the membrane contactor has been evaluated, and optimal desorption parameters have been determined.     

CCUS井水泥环腐蚀预测模型及影响因素

目的CCUS井的水泥环长期处于CO₂腐蚀环境中,水泥环将被腐蚀导致CO₂泄漏,需对腐蚀速率进行预测。然而目前的腐蚀预测模型以井眼和半经验公式为主,导致水泥环腐蚀预测不准确,制约了CCUS井水泥环腐蚀防治技术的研究。 方法针对这一问题,基于CO₂和钙质量守恒定律,建立了CO₂腐蚀深度预测模型,并利用该模型分析了腐蚀时间、温度、CO₂分压、水灰比和耐腐蚀材料加量对腐蚀深度的影响规律,并建立了评价模型,对影响因素的影响程度进行排序。 结果CO₂腐蚀深度随腐蚀时间、温度、Cl—浓度、CO₂分压、水灰比及含水饱和度增加而增大,随着水泥环密度、耐腐蚀材料加量增加而减少;水泥环中CO₂含量随腐蚀深度呈非线性降低。影响因素由强到弱为:含水饱和度>耐腐蚀材料>水灰比>CO₂分压>腐蚀时间>水泥环密度>Cl—浓度>温度。 结论研究成果对于CCUS井控制CO₂对水泥环的碳化腐蚀保障井筒完整性具有指导意义。      

液态CO2干法加砂压裂增稠剂技术现状及展望

CO_2干法加砂压裂是低压、低渗透、强水敏等非常规储层高效开发的有效措施之一。系统分析了目前国内外液态CO_2干法加砂压裂技术中增稠剂现状,对现有增稠剂分子结构进行分析归类,指出了增稠剂存在的主要技术问题和开发的难点。通过对目前国内液态CO_2干法压裂技术现状和现场试验情况梳理发现:国内液态CO_2增稠剂技术滞后于现场应用,压裂液携砂效率低,影响了压裂施工效果;分析国内外液态CO_2增稠剂研究存在的问题,借鉴现有研究成果,依据CO_2分子结构特征和理化特性,构建能使液态CO_2高效增黏的新型增稠剂分子结构,合成高质量的液态CO_2增稠剂,是实现液态CO_2干法加砂压裂的技术关键。在现有技术条件下,建议将液态CO_2干法压裂技术与常规无水压裂技术结合,既发挥了液态CO_2干法压裂技术优势,又实现了高砂比对压裂施工技术要求,满足非常规储层压裂开发需要。     

Understanding aqueous foam with novel CO2-soluble surfactants for controlling CO2 vertical sweep in sandstone reservoirs

The ability of a novel nonionic CO₂-soluble surfactant to propagate foam in porous media was compared with that of a conventional anionic surfactant (aqueous soluble only) through core floods with Berea sandstone cores. Both simultaneous and alternating injections have been tested. The novel foam outperforms the conventional one with respect to faster foam propagation and higher desaturation rate. Furthermore, the novel injection strategy, CO₂ continuous injection with dissolved CO₂-soluble surfactant, has been tested in the laboratory. Strong foam presented without delay. It is the first time the measured surfactant properties have been used to model foam transport on a field scale to extend our findings with the presence of gravity segregation. Different injection strategies have been tested under both constant rate and pressure constraints. It was showed that novel foam outperforms the conventional one in every scenario with much higher sweep efficiency and injectivity as well as more even pressure redistribution. Also, for this novel foam, it is not necessary that constant pressure injection is better, which has been concluded in previous literature for conventional foam. Furthermore, the novel injection strategy, CO₂ continuous injection with dissolved CO₂-soluble surfactant, gave the best performance, which could lower the injection and water treatment cost.     

Influence of injection pressure and injection volume of CO2 on asphaltene deposition

To further improve the oil displacement effect by CO₂ flooding, the trends and conditions of asphaltene deposition under different injection pressures and injection volumes of CO₂ were studied by SDS solid phase deposition testing system, high temperature and high pressure microscope, and P-X phase diagram. When the mole fraction of CO₂ in crude oil increases to a certain value, asphaltene deposition appears. The lower the pressure, the lower the mole fraction of CO₂ in crude oil causing the asphaltene deposition there is. After the onset of asphaltene deposition, the degree of deposition increases with an increase in pressure. The amount of the deposited asphaltene under miscible displacement is the highest, under near-miscible displacement is the second highest, and under immiscible displacement is the lowest. When the dissolution of CO₂ in crude oil reaches the saturation point, the asphaltene deposition becomes slow. Besides, it is feasible to prevent or reduce the asphaltene deposition by adjusting the thermodynamic parameters according to the phase behaviors of the CO₂-crude oil system. The experimental results can provide theoretical basis for optimization design of the parameters of CO₂ flooding.     

Laboratory investigation of carbon dioxide separation from methane using a PES/Pebax 1657 composite membrane

Removal of carbon dioxide from methane is a critical issue in the gas sweetening and treatment units. The aim of this study is to investigate the capability of PES/Pebax composite membrane in order to CO₂ removal from the CH₄. In this regard, permeability values of both carbon dioxide and methane have been measured. The ranges of temperature and pressure used for pure gases experiments were 20–50°C and 2.5–10 bar, respectively. Moreover, influence of CO₂ concentration on the CH₄ permeability and its selectivity was studied. Results indicated that the pressure and temperature have significant influence on permeability and selectivity. In addition, for the gas mixtures, experiments were carried out at 5 bar and 35°C. Results also indicated that at higher CO₂ concentrations the CO₂ permeability increased significantly.     

Gas separation characteristics of new membrane materials based on poly(ethylene glycol)-crosslinked polymers and ionic liquids

Gas transport characteristics (permeability and diffusion and solubility coefficients for CO₂, O₂, N₂, H₂) of new crosslinked membrane materials synthesized by copolymerization of poly(ethylene glycol) dimethacrylate and poly(ethylene glycol) methyl ether methacrylate in the presence of various ionic liquids have been studied. Comparison of the characteristics of specimens with and without ionic liquids has revealed that the presence of ionic liquids enhances the permeability of the membranes, especially to CO₂. It has been shown that the enhancement of the CO₂ permeability of films incorporating ionic liquid is due to an increase in CO₂ solubility and the increase in selectivity for pairs of gases containing CO₂ is determined by thermodynamic selectivity of separation.