Activating solution gas drive as an extra oil production mechanism after carbonated water injection

Enhanced oil recovery (EOR) methods are mostly based on different phenomena taking place at the interfaces between fluid–fluid and rock–fluid phases. Over the last decade, carbonated water injection (CWI) has been considered as one of the multi-objective EOR techniques to store CO₂ in the hydrocarbon bearing formations as well as improving oil recovery efficiency. During CWI process, as the reservoir pressure declines, the dissolved CO₂ in the oil phase evolves and gas nucleation phenomenon would occur. As a result, it can lead to oil saturation restoration and subsequently, oil displacement due to the hysteresis effect. At this condition, CO₂ would act as in-situ dissolved gas into the oil phase, and play the role of an artificial solution gas drive (SGD).In this study, the effect of SGD as an extra oil recovery mechanism after secondary and tertiary CWI (SCWI-TCWI) modes has been experimentally investigated in carbonate rocks using coreflood tests. The depressurization tests resulted in more than 25% and 18% of original oil in place (OOIP) because of the SGD after SCWI and TCWI tests, respectively. From the ultimate enhanced oil recovery point of view, the efficiency of SGD was observed to be more than one-third of that of CWI itself. Furthermore, the pressure drop data revealed that the system pressure depends more on the oil production pattern than water production.     

Safe storage of Co2 together with improved oil recovery by Co2-enriched water injection

The 2007 IEA's World Energy Outlook report predicts that the world's energy needs will grow by 55% between 2005 and 2030, with fossil fuels accounting for 84% of this massive projected increase in energy demand. An undesired side effect of burning fossil fuels is carbon dioxide (CO₂) emission which is now widely believed to be responsible for the problem of global warming. Various strategies are being considered for addressing the increase in demand for energy and at the same time developing technologies to make energy greener by reducing CO₂ emissions.One of these strategies is to ‘capture’ produced CO₂ instead of releasing it into the atmosphere. Capturing CO₂ and its injection in oil reservoirs can lead to improved oil recovery as well as CO₂ retention and storage in these reservoirs. The technology is referred to as CCS (carbon capture and storage). Large point sources of CO₂ (e.g., coal-fired power plants) are particularly good candidates for capturing large volumes of CO₂. However, CO₂ capture from power plants is currently very expensive. In addition to high costs of CO₂ capture, the very low pressure of the flue gas (1 atm) and its low CO₂ content (typically 10-15%) contribute to the high cost of CO₂ capture from power plants and the subsequent compression. This makes conventional CO₂ flooding (which requires very large volumes of CO₂) uneconomical in many oil reservoirs around the world which would otherwise be suitable candidates for CO₂ injection. Alternative strategies are therefore needed to utilize smaller sources of CO₂ that are usually available around oil and gas fields and can be captured at lower costs (due to their higher pressure and higher CO₂ concentration).We investigate the potential of carbonated (CO₂-enriched) water injection (CWI) as an injection strategy for improving recovery from oil reservoirs with the added benefit of safe storage of CO₂. The performance of CWI was investigated by conducting high-pressure flow visualization as well as coreflood experiments at reservoir conditions. The results show that CWI significantly improves oil recovery from water flooded porous media. A relatively large fraction of the injected CO₂ was retained (stored) in the porous medium in the form of dissolved CO₂ in water and oil. The results clearly demonstrate the huge potential of CWI as a productive way of utilizing CO₂ for improving oil recovery and safe storage of potentially large cumulative quantities of CO₂.     

注CO2气驱提高采收率效果影Ⅱ向因素分析

目前油田常规注水开发难度不断增加,应用注CO2气驱技术能够有效解决注水困难等问题,提高了原油采收率。在室内实验研究的基础上,应用数值模拟技术优化了注气方式及注气时机;分析了油藏地质参数对注CO2气驱提高采收率的影响。研究表明：水气交替注入方式更优;非均质性越强,开发效果越差;油藏渗透率越大、含油饱和度越高、原油粘度越低,注CO2驱油效果越好。     

Improving oil recovery in the CO2 flooding process by utilizing nonpolar chemical modifiers☆

By means of experiments of CO2 miscibility with crude oil, four nonpolar chemicals were evaluated in order to enhance the miscibility of CO2 with crude oil. Through pre-slug injection and joint injection of toluene in CO2, crude oil displacement experiments in the slim-tube were conducted to investigate effects of the toluene-enhanced CO2 flooding under simulated subterranean reservoir conditions. Experimental results showed that toluene can enhance extraction of oil into CO2 and dissolution of CO2 into oil with the increment of 251%and 64%respectively. Addition of toluene can obviously improve the oil recovery in either pre-slug injection or joint injection, and the crude oil recovery increased with the increase of the toluene concentration. The oil recov-ery can increase by 22.5%in pre-slug injection with the high toluene concentration. Pre-slug injection was recom-mended because it can consume less toluene than joint injection. This work could be useful to development and application of the CO2 flooding in the oil recovery as wel as CO2 emission reduction.     

Conformance control by a microgel in a multi-layered heterogeneous reservoir during CO2 enhanced oil recovery process

Injecting CO₂ into the underground for oil displacement and shortage is an important technique for carbon capture, utilization and storage (CCUS). One of the main problems during the CO₂ injection is the channeling plugging. Finding an effective method for the gas channeling plugging is a critical issue in the CO₂ EOR process. In this work, an acid-resistance microgel named dispersed particle gel (DPG) was characterized and its stability was tested in the CO₂ environment. The microgel size selection strategies for the homogeneous and heterogeneous reservoirs were respectively investigated using the single core flooding and three parallel core flooding experiments. Moreover, the comparison of microgel alternate CO₂ (MAC) injection and water alternate CO₂ (WAC) injection in the dual core flooding experiments were presented for the investigation of the role of microgel on the conformance control in CO₂ flooding process. The results have shown that the microgel featured with —NH and C—N groups can keep its morphology after aging 7 days in the CO₂ environment. Where, the small microgel with unobstructed migration and large microgel with good plugging efficiency for the high permeability zone were respectively featured with the higher recovery factor in homogeneous and heterogeneous conditions, which indicate they are preferred used for the oil displacement and conformance control. Compared to WAC injection, MAC injection had a higher incremental recovery factor of 12.4%. It suggests the acid-resistance microgel would be a good candidate for the conformance control during CO₂ flooding process.     

The effect of mixed surfactants on enhancing oil recovery

Micelles composed of mixed surfactants with different structures (mixed micelles) are of great theoretical and industrial interest. This work pertains tomaximizing interfacial tension (IFT) reduction via surfactant pairs. In this respect, four types of fatty acid amides based on lauric, myristic, palmitic, and stearic acids were blended with dodecyl benzene sulfonic acid at a molar ratio of 4∶1 and designated as A₁, A₂, A₃, and A₄, respectively. The IFT was measured for each blend at different concentrations using Badri crude oil. The most potent formula (A₄) was evaluated for using in enhanced oil recovery (EOR). The IFT was tested in the presence of different electrolyte concentrations with different crude oils at different temperatures. Finally several runs were devoted to study the displacement of Badri crude oil by A₄ surfactant solution using different slug sizes of 10, 20, and 40% of pore volume (PV). The study reveled that Badri crude oil gave ultra-low IFT at lowest surfactant concentration and 0.5% of NaCl. The recovery factor at a slug size of 20% PV was 83% of original oil in place compared with 59% in case of conventional water flood.     

超临界CO2法再生油气回收用活性炭机理研究进展

储油罐中的原油及汽油等轻质油品在储存或运输过程中,部分轻组分蒸发产生多种对大气有毒、有害的挥发性有机物（VOCs）。在油气回收的终端环节,常采用活性炭对VOCs进行充分吸附达标后排放至大气。对吸附VOCs饱和的活性炭进行脱附再生,既可延长活性炭使用寿命,又可减少固体废弃物处理量。超临界CO₂再生活性炭方法较好地克服了传统的热再生法固有的缺陷,被认为是目前有前途的再生活性炭方法。本文详细阐述了超临界CO₂再生活性炭的机理研究现状,总结了机理研究的关键点及存在的问题,指出了VOCs在超临界CO₂作用下脱附的微观机理及脱附后的VOCs在活性炭中相关传质系数的计算模型为今后机理研究的关键突破口,为超临界CO₂再生活性炭基础理论的进一步完善指明了研究方向。     

Stable CO2/water foam stabilized by dilute surface-modified nanoparticles and cationic surfactant at high temperature and salinity

CO₂ enhanced oil recovery and storage could see widespread deployment as decarbonization efforts accelerate to meet climate goals. CO₂ is more efficiently distributed underground as a viscous foam than as pure CO₂; however, most reported CO₂ foams are unstable at harsh reservoir conditions (22 wt% brine, 2200 psi, and 80°C). We hypothesize that silica nanoparticles (NP) grafted with (3-trimethoxysilylpropyl)diethylenetriamine ligands (N3), to improve colloidal stability, and dimethoxydimethylsilane ligands (DM), to improve CO₂-phillicity, combined with the cationic surfactant N¹-alkyl-N³, N³-dimethylpropane-1,3-diamine (RCADA), will develop viscous, stable CO₂ foams at reservoir conditions. We grafted NP with N3 and DM ligands. We verified NP stability at reservoir conditions with measurements of zeta potential, amine titration curves, and NP diameter. We measured NP water contact angles (θ_w) at the water–air and water–liquid CO₂ interfaces. In a high-temperature, high-pressure flow apparatus, we calculated the viscosity of CO₂ foams across a beadpack and determined static foam stability with microscope observations. Modified NP were colloidally stable at reservoir conditions for 4 weeks, and had higher θ_w in liquid CO₂ than in air. Addition of at least 0.5 μmol/m² DM silane (0.5DM) greatly improved foam stability. RCADA-only foam coarsening rates (dD_SM³/dt) decreased 16–17× after adding 1 wt/vol% 8N3 + 1.5DM NP, and 5–10× with a 0.1–1 vol/vol% increase in RCADA concentration (with or without NP). 1 vol/vol% RCADA foam exhibited coarsening rates of 900 and 2400 μm³/min with 1 and 0.2 wt/vol% 8N3 + 1.5DM NP, respectively. These results demonstrate impressive foam stabilities at harsh reservoir conditions.     

Reducing heavy oil carbon footprint and enhancing production through CO2 injection

The world's dependence on heavy oil production is on the rise as the existing conventional oil reservoirs mature and their production decline. Compared to conventional oil, heavy oil is much more viscous and hence its production is much more difficult. Various thermal methods and particularly steam injection are applied in the field to heat up the oil and to help with its flow and production. However, the thermal recovery methods are very energy intensive with significant negative environmental impact including the production of large quantities of CO₂. Alternative non-thermal recovery methods are therefore needed to allow heavy oil production by more environmentally acceptable methods. Injection of CO₂ in heavy oil reservoirs increases oil recovery while eliminating negative impacts of thermal methods.In this paper we present the results of a series of micromodel and coreflood experiments carried out to investigate the performance of CO₂ injection in an extra-heavy crude oil as a method for enhancing heavy oil recovery and at the same time storing CO₂. We reveal the pore-scale interactions of CO₂-heavy oil-water and quantify the volume of CO₂ which can be stored in these reservoirs.The results demonstrate that CO₂ injection can provide an effective and environmentally friendly alternative method for heavy oil recovery. CO₂ injection can be used independently or in conjunction with thermal recovery methods to reduce their carbon footprint by injecting the CO₂ generated during steam generation in the reservoirs rather than releasing it in the atmosphere.     

Solution Properties and Displacement Characteristics of in situ CO2 Foam System for Enhanced Oil Recovery

Carbon dioxide (CO₂) foam flooding has been shown to enhance oil recovery. However, large-scale adoption has been restricted by issues with transportation of CO₂ and equipment corrosion. In situ CO₂ foam generation can possibly overcome these issues. In this article, a CO₂ sustained-release system was first optimized for the CO₂ production rate and production efficiency. Then, the dissolution capacity and plug-removing ability of the sustained-release system were evaluated. Visual experiment and parallel sand pack flooding tests were conducted to verify the formation, propagation of in situ CO₂ foam, and the feasibility of this technique. The results indicated that the sustained-release system had benign ability to lower injection pressure and improve injectability. Moreover, in situ CO₂ foam flooding could obtain high oil recovery due to favorable mobility control ability, interfacial tension reduction capacity, and heterogeneity improvement. All the experiments demonstrated that the in situ CO₂ foam technique has great potential for enhanced oil recovery in the Bohai oilfield.     

CO_2驱油提高采收率技术的研究现状与分析

针对化石能源利用过程中排放CO_2引起的温室效应问题,同时为满足油藏高效开发的要求,介绍一种CO_2驱油提高采收率技术,分析其驱油机理,并总结目前国内外EOR技术的应用与开发现状,指出目前我国EOR应用的前景。     

封存CO2的泄漏过程预测与泄漏速率的影响因素特性

地下封存CO₂泄漏的评估方法和风险控制是碳捕集和封存（CCS）技术亟待解决的核心问题。为了揭示封存CO₂泄漏过程的影响因素及其特性,本文建立两相流驱替过程数学模型描述封存CO₂的泄漏过程,采用COMSOL Multiphysics 3.5a软件进行数值模拟。通过对基准问题及其解的拓展,分别对注入井与泄漏通道之间距离、泄漏通道半径、泄漏通道渗透率、CO₂注入速率和CO2注入深度等因素对封存CO2泄漏过程的影响特性进行研究,通过过程模拟和数据分析得到了影响因素的定量函数关系。研究表明：封存CO₂的渐近泄漏速率与注入井与泄漏通道之间距离倒数呈对数线性关系,与泄漏通道半径呈抛物线型关系,与注入速率呈线性关系;泄漏通道的绝对渗透率是CO₂泄漏速率控制的关键因素,而CO₂注入深度的增加并不能有效地降低CO₂泄漏速率。本文的计算模型和数值模拟结果不仅揭示了地下封存CO₂泄漏过程的影响因素与泄漏速率之间的定量关联规律,还可为地下封存CO₂的封存地点选择、泄漏速率估计和泄漏风险评估提供工程分析方法和计算工具。     

燃煤电厂CO2捕集与咸水层封存全过程经济性模型

碳捕集与封存技术（即CCS技术）通过对CO₂进行捕集、压缩、运输与封存,可实现CO₂大规模减排,近年来受到广泛关注。CCS技术的经济成本是其商业化的关键因素,但目前多数研究都集中在捕集过程,CCS全过程的经济成本分析鲜见报道。针对CO₂捕集与咸水层封存系统,给出了捕集封存全过程投资运行总成本和捕集封存整体系统CO₂减排成本的计算公式,建立了CO₂捕集、压缩、管道运输与咸水层封存全过程的成本估算模型,并对典型的600 MW超临界燃煤电厂捕集封存CO₂的投资运行成本和减排成本进行了案例研究。     

磷矿选矿废水中浮选药剂的回收与水深度处理的研究

以国内某磷矿选矿废水为处理对象,采用“隔油—超滤—反渗透”工艺对其进行处理.研究发现,隔油工艺可有效回收水中近90％的浮选药剂,超滤膜可有效去除水中绝大部分与水发生乳化作用的浮选药剂,反渗透可进一步去除选矿废水中的残余浮选药剂和离子.实验结果表明,处理后的选矿废水,产水可以满足排放水的要求,同时回收了大部分的浮选药剂.     

神华咸水层CO2封存监测安全评价体系的研究

神华CO₂咸水层封存项目是中国第一个全流程CCS项目,封存的安全性是评价该项目成功与否的重要标志。为了说明封存项目的安全性,该项目采用了包括Vertical Seismic Profile（VSP）地震监测等各种监测手段。但是目前得到的各种监测数据散乱、没有条理性,缺乏系统科学的归纳与解释。本文基于神华CO₂咸水层封存项目采用的监测手段,开发了CO₂地质封存过程中的多指标安全评价等级体系。采用该体系对某时间典型监测数据进行评估的结果表明,该封存项目属于非常安全的状态,没有CO₂泄漏风险。