Optimal activated carbon for separation of CO2 from (H2 + CO2) gas mixture

Seven types of activated carbon were used to investigate the effect of their structure on separation of CO₂ from (H₂ + CO₂) gas mixture by the adsorption method at ambient temperature and higher pressures. The results showed that the limiting factors for separation of CO₂ from 53.6 mol% H₂ + 46.4 mol% CO₂ mixture and from 85.1 mol% H₂ + 14.9 mol% CO₂ mixture were different at 20 C and about 2 MPa. The best separation result could be achieved when the pore diameter of the activated carbon ranged from 0.77 to 1.20 nm, and the median particle size was about 2.07 lm for 53.6 mol% H₂ ? 46.4 mol% CO₂ mixture and 1.41 lm for 85.1 mol% H₂ + 14.9 mol% CO₂ mixture. The effect of specific area and pore diameter of activated carbon on separation CO₂ from 53.6 mol% H₂ ? 46.4 mol% CO₂ mixture was more significant than that from 85.1 mol% H₂ ? 14.9 mol% CO₂ mixture. CO₂ in the gas phase can be decreased from 46.4 mol% to 2.3 mol%–4.3 mol% with a two-stage separation process.     

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.     

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%.     

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.     

延长油田致密砂岩油藏CO2驱油机理研究

CO_2驱是提高低渗透油田产量、缓解温室效应的有效途径。针对鄂尔多斯盆地油藏压力系数低、原油轻质组分含量高的特点,通过PVT和最小混相压力等测试分析方法,揭示了低压、低孔、低渗油藏CO_2驱提高采收率主要机理。开展了CO_2注入储层与无机、有机物作用后的沉淀研究,表明CO_2在无机盐溶液中不会形成沉淀堵塞孔隙,CO_2与有机质作用后沉积点高于油藏压力,且注入压力越高,CO_2在地层原油中的溶解能力越强,目标区块CO_2注入后不易形成沥青质沉淀。物模驱替实验结果表明,均质岩心的采出程度明显高于非均质岩心,且随着岩心非均质性的增加,水驱采出程度、气驱采出程度及最终采出程度均明显下降。     

Exploitation of fractured shale oil resources by cyclic CO2 injection

With shale oil reservoir pressure depletion and recovery of hydrocarbons from formations, the fracture apertures and conductivity are subject to reduction due to the interaction between stress effects and proppants. Suppose most of the proppants were concentrated in dominant fractures rather than sparsely allocated in the fracture network, the fracture conductivity would be less influenced by the induced stress effect. However, the merit of uniformly distributed proppants in the fracture network is that it increases the contact area for the injection gas with the shale matrix. In this paper, we address the question whether we should exploit or confine the fracture complexity for CO₂-EOR in shale oil reservoirs. Two proppant transport scenarios were simulated in this paper: Case 1—the proppant is uniformly distributed in the complex fracture system, propagating a partially propped or un-propped fracture network; Case 2—the proppant primarily settles in simple planar fractures. A series of sensitivity studies of the fracture conductivity were performed to investigate the conductivity requirements in order to more efficiently produce from the shale reservoirs. Our simulation results in this paper show the potential of CO₂ huff-n-puff to improve oil recovery in shale oil reservoirs. Simulation results indicate that the ultra-low permeability shales require an interconnected fracture network to maximize shale oil recovery in a reasonable time period. The well productivity of a fracture network with a conductivity of 4 mD ft achieves a better performance than that of planar fractures with an infinite conductivity. However, when the conductivity of fracture networks is inadequate, the planar fracture treatment design maybe a favorable choice. The available literature provides limited information on the relationship between fracture treatment design and the applicability of CO₂ huff-n-puff in very low permeability shale formations. Very limited field test or laboratory data are available on the investigation of conductivity requirements for cyclic CO₂ injection in shale oil reservoirs. In the context of CO₂ huff-n-puff EOR, the effect of fracture complexity on well productivity was examined by simulation approaches.     

Scaled 3-D model studies of immiscible CO2 flooding using horizontal wells

In this study, a comprehensive laboratory investigation was conducted for the recovery of heavy oil from a scaled three-dimensional (3-D) physical model, packed with 18° API gravity crude oil, brine and crushed limestone. A total of 20 experiments were conducted using the scaled 3-D physical model with 30×30×6 cm³ dimensions. Basically, four different immiscible CO₂–water displacement processes were used for recovering heavy oil: (i) continuous CO₂ injection, (ii) waterflooding, (iii) simultaneous injection of CO₂ and water, and (iv) water alternating gas (WAG) process. Three groups of well configurations were mainly used: (1) vertical injection and vertical production wells, (2) vertical injection and horizontal production wells, and (3) horizontal injection and horizontal production wells. Base experiments were run with water only and carbon dioxide alone and optimum rates for WAG and simultaneous water–CO₂ injection were determined. In continuous CO₂ injection, highest recovery was obtained by vertical injection–horizontal production (VI–HP), followed by vertical injection–vertical production (VI–VP) and the least by horizontal injection–horizontal production (HI–HP). In VI–HP configuration, the best recovery was obtained as 15.1% OOIP. Higher oil recovery was obtained with a VI–HP wells than with a pair of vertical wells and horizontal wells. The WAG 1:5 ratio yielded a final recovery of 34.5% OOIP with VI–VP well configuration and 17.0% OOIP of additional recovery over waterflooding. In turn, the WAG 1:10 ratio was the best with a final recovery of 20.9% of OOIP with VI–HP well configuration. Oil production from WAG injection is higher than that obtained from the injection of continuous CO₂ or waterflooding alone.     

pH值响应性液流转向剂对自生CO2调驱效果优化研究与应用

针对渤海油田多轮次自生CO_2调驱效果逐渐递减的问题,通过室内物理模拟实验分析了原因,并提出一种利用pH值响应性深部液流转向剂优化自生CO_2调驱效果的方法。岩心驱替实验表明:一轮常规自生CO_2调驱采收率可在水驱基础上提高25.61%,二轮调驱已无增油效果;二轮调驱时加入0.1 PV凝胶,采收率可在一轮常规调驱基础上提高6.11%,但驱替压力由0.07 MPa增至0.7 MPa,表明凝胶体系能够改善调驱效果,但注入性差;二轮调驱时加入0.1 PV的pH值响应性堵剂,注入压力在0.05～0.35 MPa波动,最终采收率可在一轮常规调驱基础上增加12.33%,且调驱后注入压力无明显增加,表明堵剂具有良好的注入性,不影响后续注水。2015年和2018年,分别在渤海油田A区块开展了两轮次现场试验,一轮为常规自生CO_2调驱,措施后累计增油1 371 m~3;二轮为自生CO_2优化调驱,措施后累计增油2 317 m~3,较第一轮增油效果明显改善。     

Effect of reactive surface area of minerals on mineralization trapping of CO2 in saline aquifers

The reactive surface area, an important parameter controlling mineral reactions, affects the amount of mineralization trapping of CO2 which affects the long-term CO2 storage. The effect of the reactive surface area on the mineralization trapping of CO2 was numerically simulated for CO2 storage in saline aquifers. Three kinds of minerals, including anorthite, calcite and kaolinite, are involved in the mineral reactions. This paper models the relationship between the specific surface area and the grain diameter of anorthite based on experimental data from literature (Brantley and Mellott, 2000). When the reactive surface areas of anorthite and calcite decrease from 838 to 83.8 m2/m3, the percentage of mineralization trapping of CO2 after 500 years decreases from 11.8% to 0.65%. The amount of dissolved anorthite and the amounts of precipitated kaolinite and calcite decrease significantly when the reactive surface areas of anorthite and calcite decrease from 838 to 83.8 m2/m3. Calcite is initially dissolved in the brine and then precipitates during the geochemical reactions between CO2-H2O and the minerals. Different reactive surface areas of anorthite and calcite lead to different times from dissolution to precipitation. The pH of the brine decreases with decreasing reactive surface areas of anorthite and calcite which influences the acidity of the saline aquifer. The gas saturation between the upper and lower parts of the saline aquifer increases with decreasing reactive surface areas of anorthite and calcite. The mass density distribution of brine solution shows that the CO2+brine solution region increases with decreasing reactive surface areas of anorthite and calcite.     

LNG冷能用于朗肯循环和CO2液化新工艺

针对CO_2排放过量的问题,提出了两种利用液化天然气冷能进行朗肯循环发电和液化CO_2的新工艺流程。流程1在常规朗肯循环的基础上增加了再热循环和回热循环;流程2在保证预冷和液化CO_2所需冷能不变的情况下,在流程1的基础上集成了氮气液化系统,目的是降低蒸发器内冷热物流的品位差,提高蒸发器的火用效率。分析了烟气温度、循环工质压力和流量对流程比功和火用效率的影响。模拟计算得到,流程1、流程2的火用效率分别可达到49.70%和49.80%,对应比功分别为237.70 kJ/kg LNG和235.20 kJ/kg LNG,CO_2的液化率为0.60 kg/kg LNG。结合具体实例进行计算,证明新流程具有良好的经济效益和环境效益。