Rapid prediction of hydrate condition for promoting CO2 recovery in the oil and gas industry

Gas hydrates may form in the petroleum and gas industry and can lead to significant problems such as plugging the pipelines and increasing velocity movement of the hydrate plugs in the pipelines. In this contribution, a simple strategy based on principal component analysis and partial least square methods has been utilized in order to estimate hydrate formation condition of carbon dioxide and tetra butyl ammonium chloride. In this regard, the developed tool has been evaluated by some reported data points in order to obtain its accuracy. This tool was simple to apply and can be of great help for gas transmission engineers to have an accurate estimation of hydrate conditions.     

Nanofluid-assisted gas to hydrate (GTH) energy conversion for promoting CO2 recovery and sequestration processes in the petroleum industry

In this work the enhancement of gas to hydrate conversion employing the nanographene oxide (NGO)–based nanofluid regarding CO₂ capture and sequestration recovery is investigated. A new series of experiments are carried out at different pressures, temperatures, agitation intensities and NGO promoter concentrations by using a newly developed fully automated GTH (gas to hydrate) energy converter. According to the presented results at the 3 MPa and 275.15 K and in the presence of 30 ppm NGO, it is possible to reach a CO₂ gas to hydrate conversion of 95% at a low impeller speed in less than 2.5 h, which is quite interesting from an energy consumption standpoint. The presented approach can have potential application for development of low cost hydrate-based carbon dioxide recovery plants in petroleum industry.     

Modelling of CO2 separation from gas streams emissions in the oil and gas industries

Sodium glycinate solutions have low vapor pressure, low viscosity, and high chemical reactivity with CO₂. They have remarkable potential for removal of CO₂ from the flue gases, because absorption of CO₂ with an amino acid salt solution such as sodium glycinate is accompanied with precipitation. As the liquid phase contains solid compounds during absorption of CO₂, the reactions move into the production of various materials and a further amount of CO₂ is absorbed. In the current study, a support vector machine algorithm is utilized to predict carbon dioxide solubility in aqueous sodium glycinate solutions over wide ranges of temperature, pressure, and concentration. The proposed model can be of immense value for engineers to have a quick check on the CO₂ solubility in sodium glycinate solutions without opting for any experimental works. Results obtained from the model have shown excellent agreement with reported data in the literature.     

Modelling of CO2 capture and separation from different gas mixtures using semiclathrate hydrates

In this work we present a model for predicting hydrate formation condition to separate carbon dioxide (CO₂) from different gas mixtures such as fuel gas (H₂+CO₂), flue gas (N₂+CO₂), and biogas gas (CH₄+CO₂) in the presence of different promoters such as tetra-n-butylammonium bromide (TBAB), tetra-n-butylammonium chloride (TBAC), tetra-n-butylammonium fluoride (TBAF), tetra-n-butyl ammonium nitrate (TBANO₃), and tetra-n-butylphosphonium bromide (TBPB). The proposed method was optimized by genetic algorithm. In the proposed model, hydrate formation pressure is a function of temperature and a new variable in term of Z, which used to cover different concentrations of studied systems. The study shows experimental data and predicted values are in acceptable agreement.     

Modelling of methane hydrate formation pressure in the presence of different inhibitors

Formation of gas hydrates is one of the problems in the production, processing, and transportation of natural gas. Hence, an understanding of conditions where hydrates form is necessary to overcome hydrate-related issues. The aim of this study was to develop an effective relation between the methane hydrate formation pressure based on the temperature, weight fraction of inhibitor, and molecular weight of inhibitor using the least square support vector machine. This computational model indicates the great ability of predictions for determining hydrate pressure in the presence of different inhibitors such as the methanol, ethylene glycol, diethylene glycol, and triethylene glycol. The values of R-squared (R²) and mean squared error obtained for this model are 0.9925 and 0.2325, respectively. This developed predictive tool can be applied as an accurate estimation of methane hydrate formation pressure.     

A kinetic model for gasification of heavy oil with in situ CO2 capture

Gasification process is being developed to obtain environmentally clean and efficient syngas from solid (coal, biomass, and municipal solid waste) or liquid (heavy oil and waste lubricant oil) fuels for power generation. A gasification kinetic model of heavy oil in the presence of CaO that can predict syngas yield, tar concentration, and performance parameters has been developed. Results showed that the CaO plays a major role for a significant reduction in carbon dioxide during the process. Based on the operating conditions, it was also found that there is an optimum condition for tar yield. Modeling results were validated against experimental data and found to be in good agreement.     

Phase equilibrium modeling of semi-clathrate hydrates of the CO2+H2/CH4/N2+TBAB aqueous solution system

In this study, the semi-clathrate hydrate dissociation pressure for the CO₂+N₂, CO₂+H₂, CO₂+CH₄, and pure CO₂ systems in the presence of different concentrations of TBAB aqueous solutions is predicted using a strong machine learning technique of multi-layer perceptron neural network (MLP-NN). The developed model, with an overall correlation coefficient (R²) of 0.9961 and mean square error (MSE) of 5.96E?02, presented an excellent accuracy in prognosticating experimental data. A complete statistical evaluation performed to promise the strength and generality of the multi-layer perceptron artificial neural network (MLP-ANN). In addition, the applicability of the proposed network and quality of experimental data was assessed through the Leverage approach.     

SDS和THF对水合物法捕集模拟烟气中CO2的影响

采用搅拌式反应釜水合物生成实验装置研究动力学促进剂十二烷基硫酸钠(SDS)和热力学促进剂四氢呋喃(THF)对水合物法捕集CO_2的影响,用摩尔分数为25%的CO_2和75%的N_2混合气模拟烟气,分别探究不同浓度的SDS和THF对分离效果的影响;在此基础上,研究了不同初始压力、反应温度对分离效果的影响。结果表明,SDS和THF的存在都能提高CO_2回收率,但同时会降低分离因子。设定初始温度为3.5℃,初始压力为9.2 MPa时,加入质量分数为0.01%的SDS溶液后,CO_2回收率较纯水中增大了4.3%,分离因子较纯水中降低了44.8%;设定初始温度为6.5℃,初始压力为3.7 MPa时,加入摩尔分数为0.5%的THF溶液后,CO_2回收率较纯水中增大了30.4%,分离因子较纯水中降低了72.8%。在实验条件下,适宜的SDS质量分数为0.01%～0.05%,THF摩尔分数为0.5%～2%,初始压力的增加可以有效缩短水合反应的诱导时间,增大储气密度、CO_2回收率和分离因子,降低温度能有效提高分离效果。     

Influence of pressure and CO2 content on the asphaltene precipitation and oil recovery during CO2 flooding

During CO₂ flooding, the crude oil is treated with CO₂, and meanwhile it is displaced by CO₂. Based on the two processes, the influence of pressure and CO₂ content on the asphaltene precipitation and oil recovery efficiency are systematically investigated by indoor simulation experiment. With the increase of the pressure or CO₂ content during CO₂ treatment, the amount of asphaltene precipitation can be increased to a certain value. Correspondingly, the degrees of the changes of oil-water interface, the compositions of crude oil, and reservoir permeability are positively correlated with the amount of asphaltene precipitation. However, during the process, the oil recovery has an optimal value due to the combined action of asphaltene precipitation and the improvement of flow performance of the crude oil. These conclusions can provide a basis for high efficiency development of low permeability oil reservoirs by CO₂ flooding.     

Post-combustion of mazut with CO2 capture using aspen hysys

There is a wide range of resources for CO₂ emissions. The net amount of CO₂ emissions in the cement industry due to the consumption of fossil fuels and the chemical processes of cement production under heating raw materials is reported to be in the range of 15–25%; this industry, among all the industries and after the power plants and refineries, is the largest CO₂ gas producer throughout the world. Using CO₂ capture and storage (CCS), it can reduce greenhouse gas emissions in a short time. In this study, the technical feasibility study of recycling CO₂ in Abyek Cement Company, with a cement production capacity of about 12,500 tons per day in two production lines, has been studied as one of the largest cement industries throughout the world. Fuel oil (Mazut) is used as the primary fuel for furnaces in this industry. Affected by combustion, the emissions emitted from the five-stage preheater contain 5/24% vol% of CO₂, 7.6% H₂O, 4.8% vol% of O₂, and 63.1% N₂.     

不同压力下冻土区水合物法封存CO2的实验研究

目的水合物法封存CO₂稳定性良好、储气密度高,是一种极具潜力的碳封存方式,利用冻土区的地层条件更具独特优势,将CO₂气体注入冻土区地层中,在一定的温度和压力条件下,形成固态CO₂水合物实现封存。 方法依据国内冻土地区地层深度对应的温度和压力条件,选取不同地层深度(150 m和200 m)对应温度(1.27 ℃和2.72 ℃)和有效孔隙含水率(40%),研究不同注气压力(3.5 MPa、4.5 MPa和5.5 MPa)下的封存特征。分析封存过程的温度和压力变化、封存速率、最终水转化率和最终封存率等动力学规律。 结果封存压力越高,水合物法封存所需的诱导时间越短,压力降幅越大。较高的封存压力导致初期封存速率较慢,缓慢封存期的持续时间减少,且封存压力越高,封存率、最终水转化率和水合物相饱和度越高。封存温度越高,压力对封存率的影响效果越明显。 结论在地层深度150 m(对应地层平均温度1.27 ℃)、5.5 MPa及有效孔隙含水率(40%)的条件下,CO₂封存效果最佳。      

含杂质CO2管道输送水合物形成规律研究

在延长油田产生的CO₂气体输送过程中,管线会发生水合物冰堵,影响气体输送流量,为了探究CO₂水合物在管道输送过程中的形成规律,利用PVTSIM软件生成了CO₂水合物的相平衡曲线,并通过OLGA软件对水平管和弯管输送的水合物形成规律进行了模拟分析。结果表明:在低温高压条件下,水平管和弯管输送过程中均会有水合物形成,其生成过程是一种类似于盐类的结晶过程,通常包括成核和生长两个阶段,然后依靠流体颗粒之间的黏附力致使水合物聚集,与直管段相比,弯管段更容易产生水合物;水合物生成速率均由小到大,然后快速进入稳定阶段,最后趋于0。现场管线的水合物也多发生在弯管处,从而进一步验证了CO₂水合物的形成规律。因此,在管道输送过程中应避免高压出口和低温入口条件,保证管道安全运营。      

An Efficient Methodology for Performance Optimization and Uncertainty Analysis in a CO2 EOR Process

Abstract

A pragmatic technique is proposed and successfully applied to determine the optimal production–injection scheme in a CO₂ flooding reservoir under uncertainty. Well rates of injectors and bottomhole pressures of producers are chosen as the controlling variables. Geological uncertainty is accounted for using the multiple reservoir models. An objective function associated with net present value (NPV) is defined, and a modified genetic algorithm is employed to determine the optimal production–injection scheme. It is shown from a field case study that the optimized scheme can not only increase the expected oil recovery and NPV by 7.8 and 6.6%, respectively, but can also achieve a considerably small range of possible NPVs.     

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.     

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.     

ANFIS modeling of carbon dioxide capture from gas stream emissions in the petrochemical production units

Amino acid salt, especially sodium glycinate, was known as a new class of environment-friendly solution that is now being studied as a favorable alternative to amines. In the present collaboration, the Adaptive Network-based Fuzzy Inference System (ANFIS) was employed to estimate CO₂ loading capacity in the presence of aqueous sodium glycinate solution under broad ranges of temperature and pressure. The outcomes of suggested ANFIS model indicated their brilliant agreement with corresponding experimental values. The calculated values of mean relative error and R-squared were 2.93 and 0.988, respectively. Our suggested model can be of huge value for process engineers to have a simple and accurate tool in order to have rapid estimations of CO₂ solubility as a function of temperature, pressure, and mass composition of sodium glycinate solution.     

Investigation of immiscible CO2 and C1 injection and comparison with water injection for enhanced oil recovery in naturally fractured reservoirs

Reservoir oil and gas content tends to rise up to the surface as long as their potential energy levels are sufficient. In order to amplify this energy, either during the time when oil is uprising on its inherent energy or since after, so as to facilitate the traveling of oil to the surface, enhanced oil recovery (EOR) methods come into play. Furthermore, the increasing demand for oil from one hand, and the shrinkage of producible reserves on the other hand, have made it unavoidable to undertake EOR techniques. Built in this research was a 10-element model of reservoir fluid to simulate its behavior. Furthermore, slim tube simulation was undertaken to determine minimum miscibility pressure for various gases. Then, different scenarios of natural depletion, CO₂ injection, methane injection, and water injection were simulated by ECLIPSE 300 software package with the results of different scenarios compared. The results indicated water injection to be associated with higher recovery factor.     

高温高压条件下CO2 / 原油和N2 / 原油的界面张力

在油藏温度下,采用ADSA（axisymmetric drop shape analysis）技术测定了不同压力下CO₂/原油和N₂/原油体系的平衡界面张力。实验发现,原油与超临界CO₂接触的初始阶段存在强烈的扩散作用,原油中的轻质组分被超临界CO₂溶解抽提,并且随着压力的增加,这种溶解抽提作用增强;原油与N₂接触时,也存在相互扩散作用,但在本实验所测试的压力范围内（小于36 MPa）并不明显。两种体系的平衡界面张力随着压力的升高逐渐降低,其中CO₂/原油体系的平衡界面张力降低的幅度明显大于N₂/原油体系;N₂/原油体系的平衡界面张力随压力基本呈线性变化。在CO₂/原油体系中,当压力低于17.7MPa时,平衡界面张力下降非常快;当压力大于17. MPa时,CO₂/原油体系的平衡界面张力下降较慢。     

Changes in the properties of conventional crude oil before and after CO2 flooding

Abstract

In order to enhance oil recovery of a conventional oil reservoir by CO₂ flooding, the changes in the properties of the crude oil before and after CO₂ flooding are systematically investigated by on-site sampling and experimental testing. The results show that, after CO₂ flooding, the light hydrocarbons of the produced crude oil is increased and the heavy hydrocarbons of the produced crude oil is decreased due to the deposition of resins and asphaltenes in the pores of the formation. In addition, the produced fluid (a mixture of oil and water) has a high water separation rate, the oil- water interface has a high tension value, and the crude oil has a high acid value and a low viscosity. The conclusions can provide a certain guidance for high-efficiency development of a conventional oil reservoir by CO₂ flooding.