Operation Parameters on CO2-Foam process

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%.     

Experimental Investigation of Miscible CO2 Flooding

Abstract

Management of water alternating gas (WAG) injection projects requires making decisions regarding the WAG ratio, half-cycle-slug size, and ultimate solvent slug size. The impact of these decisions affects the capital cost and ultimate incremental oil recovery. Core flooding runs were conducted on 2 and 4 ft core samples. Injection scheme (continuous gas injection [CGI] vs. WAG), WAG ratio, and slug size were investigated. In addition, miscible WAG flooding as a secondary process was investigated and its efficiency was compared to the conventional tertiary miscible gas flooding. Miscible gas flooding at different miscible WAG parameters (WAG ratio and slug size) indicate that 1:2 WAG ratio at 0.2 PV slug size is the best combination yielding the highest recovery and tertiary recovery factors. Miscible WAG flooding as a secondary process indicated a higher ultimate recovery compared to the conventional tertiary WAG flooding. However, a larger amount of gas injection is consumed particularly in the early stages of the injection process. Miscible CGI mode conducted using n-Decane as oleic phase appears to have better performance than miscible WAG injection in term of recovery. When light Arab crude oil was used as oleic phase, higher recovery was obtained for miscible WAG flooding. The reversal trend seen in is believed to be due to the presence of crude oil, which alters the rock wettability toward an oil-wet condition, preventing the water blockage during the WAG process.     

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.     

Oil recovery and CO2 storage in CO2 flooding

In this study, the interfacial tension (IFT) of crude oil-carbon dioxide mixtures was measured to determine the minimum miscibility pressure. CO₂ flooding with sand packs, long cores, and heterogeneous cores was conducted to investigate the oil recovery and storage efficiency. The experiment results show that the interfacial tension decreases linearly with increasing pressure at two different pressure ranges. Under immiscible condition, the oil recovery and storage efficiency are increased by 30.1% and 52.4% when the injection pressure is increased from 13 to 22 MPa, and improved by 16.3% and 22.04% when the permeability is decreased from 270 to 10 mD, respectively. Under miscible condition, increase of injection pressure can only lead to much slower increase of oil recovery and storage efficiency, and permeability almost has no influence on oil recovery and storage efficiency. The oil recovery and storage efficiency can be remarkably reduced by heterogeneity. Water alternating CO₂ injection can improve the oil recovery and storage efficiency by 35.5% and 13.55%, respectively, compared with continuous injection.     

The Effects of Miscible CO2 Injection on Oil Biomarker Parameters

The purpose of this research was to study the effect of CO₂ injection on the geochemistry of crude oil in order to determine the probability of using geochemical parameters for monitoring CO₂ injection. In this process, four oil samples from different offshore oil fields were collected, synthetic steady state oil reservoir (porous media) were made by slim tube apparatus, then CO₂ injection process was done in different pressures. Various geochemical analyses were also carried out on the injected oil before and after the injection. The results show that the bulky changes on oil sample by CO₂ injection. CO₂ injection is more likely to precipitate complex and large molecules such as asphaltenes-resins and also large normal alkanes. In this case, the percentage of aromatic molecules was increased during injection. In general view on chromatograms, the height and abundance of all saturated compound peaks after CO₂ injection were significantly decreased. However, biomarker analysis shows that CO₂ injection has a tendency to change source and maturity biomarker parameters.     

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.     

Screening of Oil Pools on Alaskan North Slope and Phase Behavior Study of Viscous Oil and CO2 System in Conjunction with CO2 Sequestration

Abstract

Carbon dioxide gas, a greenhouse gas (GHG), is released in the atmosphere by combustion of solid waste, wood, and fossil fuels for energy generation. Due to conspicuous absence of CO₂ sequestration studies for Alaska, the study of CO₂ sequestration options on North Slope has a very important role to play. The screening of the oil reservoirs to evaluate the technical feasibility with respect to their CO₂-EOR potential was performed by calculating the rank of the oil reservoirs with parametric approach. CMG-WinProp® simulator was used to predict phase behavior for CO₂ injection in viscous oil by tuning the equation-of-state.     

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.     

Influence of H2S Content on CO2 Corrosion Behaviors of N80 Tubing Steel

Abstract

The corrosion behaviors of N80 steel in pure CO₂ and at different partial pressure ratios of CO₂/H₂S were tested by high-temperature and high-pressure autoclave. At 90°C, with the additional H₂S to pure CO₂, the surface corrosion condition improved greatly and the corrosion rates were lower than in pure CO₂ condition. With the increase of partial pressure ratio, the corrosion rate reached a peak value at pCO₂/pH₂S = 100 and then declined. The corrosion products of the samples in different conditions were analyzed by scanning electron microscopy (SEM), energy-dispersive spectroscopy (EDS), and X-ray diffraction (XRD) methods. The inner film is finer and denser than the outer scale.     

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.     

Prediction of Oil Recovery Factor in CO2 Injection Process

In this study, prediction of recovery factor (RF) for CO₂ injection into oil reservoirs based on artificial neural networks (ANNs) and mathematical models were investigated. To design the optimum ANN model, number of neurons, hidden layers, and training function were studied. Finally, efficiency of the models was evaluated using new data. As a result of this work, it can be concluded that it is possible to predict RF in CO₂ injection process by ANN and mathematical model. However, values that obtained from ANN were in the best agreement with the actual values than regression model. The proposed artificial neural network predicted RF during CO₂ injection with error about 0.396%.     

Economical Evaluation of CO2-EOR Projects in the Middle East

Abstract

Recently, there is a growing interest the in oil industry to utilize carbon dioxide (CO₂) to enhance oil production from mature reservoirs. Conversely, there is a rising global attention to reduce CO₂ emissions from burning fossil fuels due to environmental concerns. Synchronization between these two objectives is promising through CO₂ Capture and Storage (CCS) projects where CO₂ is captured from large emission sources and then storedin safe geological structures. Economical evaluation of CO₂-EOR projects is a crucial measure in order to ensure a project's viability.

In this study, an efficient model was developed to predict the economics of CO₂-EOR projects. The developed model consists of five modules that are linked together to allow for fast prediction of CO₂-EOR economics.

The model was used to predict the economics of a case study where CO₂-EOR application is considered for a Middle Eastern reservoir. Moreover, the case study was subjected to sensitivity analyses to evaluate the effects of several parameters on the various economical components of CO₂-EOR projects.     

CO2 miscible flooding in low permeability sandstone reservoirs and its influence on crude oil properties

Miscible CO₂ injection process has become widely used technique for the enhanced oil recovery in low permeability reservoirs. Core flooding experiments and field test of CO₂ miscible flooding in low permeability sandstone reservoirs and its influence on crude oil properties was studied. The results showed that CO₂ miscible flooding in low permeability sandstone reservoirs can enhance oil recovery both in laboratory study and field test. The permeability of sandstone reservoirs decreased during CO₂ miscible flooding due to the precipitation of asphaltene of crude oil. The precipitation of asphaltene lead to a reduction of asphaltene content and the apparent viscosity of crude oil. A further study on inhibitors and removers for asphaltene deposits from crude oil should be investigated to prevent and remove asphaltene deposits in low permeability sandstone reservoirs.     

CO2泡沫驱体系筛选与评价

吉林油田CO₂驱油藏物性差,渗透率差异较大,裂缝相对发育,注入CO₂过程中出现气窜,严重影响气驱效果。为此开展CO₂泡沫体系研究,扩大气驱波及体积,提高气驱开发效果。室内建立泡沫体系的性能评价手段,优选一种由阴离子表面活性剂与非离子表面活性剂复配而成的CYL泡沫体系,确定现场CYL泡沫体系的最佳加量为0.3%、气液比1:1。物模试验结果表明：裂缝性低渗透岩心中CO₂泡沫驱采收率最高53.67%,CO₂气驱采收率次之（35.74%）,水驱采收率最低（23.42%）。CO₂泡沫驱的效果明显好于水驱、CO₂驱,现场开展CO₂泡沫驱试验,注气压力由措施前的6.0 MPa上升到措施后的8.1 MPa,井组日产油由措施前的7.7 m³增至措施后的10.8 m³,措施效果明显,有效提高气驱开发效果。     

模拟延长油田CO_2驱油过程原油结蜡特性研究

通过对某CO2驱油区块的不同CO2分压条件下原油结蜡倾向和原油结蜡特性评价,计算出原油的结蜡速率、结蜡率及蜡含量,分析了原油的析蜡曲线特性。结果表明,CO2分压增大时原油的结蜡速率和结蜡率提高,蜡含量降低,蜡析出更明显;经CO2处理作用后原油析蜡点向低温方向移动,其蜡含量也相应地比未处理油样的蜡含量降低。     

国外CO2驱流度控制进一步扩大波及体积方法

CO₂驱油是一种有效的提高采收率方法,矿场成功应用已有60多年。理论上微观驱油效率接近100%,但相对原油,CO₂的低黏度低密度与储层的非均质性导致的黏性指进和重力分离两大典型问题大大降低了气体波及系数。本文综述了国外各种流度控制方法,包括气水交替、聚合物直接稠化CO₂、CO₂泡沫驱、气-化学剂联合方法及气体辅助重力泄油,简要介绍了CO₂驱扩大波及体积的其他方法,分析了每种方法的机理及优缺点,力图为我国CO₂驱油进一步扩大波及体积这一难题积累先进做法和经验。     

The Evaluation of Variable-Injection Rate Waterflooding,Immiscible CO2 Flooding,and Water-alternating-CO2 Injection for Heavy Oil Recovery

Abstract

Despite the existence of studies for separate evaluation of waterflooding, immiscible CO₂ flooding, and CO₂ water-alternating gas (WAG) for heavy oil recovery, there is a lack of an experimental, comparative evaluation of these three methods. The authors conducted tests for comparative evaluation of variable-injection rate waterflood (VIWF), immiscible CO₂ flood, and CO₂ WAG. The results illustrate the (a) effectiveness of VIWF, immiscible CO₂ flood, and CO₂ WAG; (b) effect of permeability and oil viscosity on VIWF, immiscible CO₂ flood, and CO₂ WAG; (c) effect of injection rate on VIWF; and (d) effect of slug ratio on CO₂ WAG.     

二氧化碳驱采出井缓蚀剂筛选与评价流程研究

添加缓蚀剂是油气田控制井筒腐蚀的主要手段,如何筛选出合适的缓蚀剂是预防井筒腐蚀的关键。以某油田CO_2驱采出井(井筒内温度60~120℃,CO_2分压为0.2 MPa)缓蚀剂筛选评价为例,首先利用配伍性试验初步评价缓蚀剂的理化性能,然后采用电化学方法进一步筛选出缓蚀率大于90%的缓蚀剂,最后利用高温高压釜模拟现场工况(90℃和120℃,CO_2分压为0.2MPa),对拟选用的缓蚀剂进行腐蚀失重评价实验,并辅以SEM分析缓蚀剂的防腐效果。实验结果表明:7种待评价缓蚀剂中,4种缓蚀剂可与现场采出液良好配伍;缓蚀剂质量浓度为200mg/L时,有两种缓蚀剂在常压下的缓蚀率大于90%;在加注浓度为1 mol/L、模拟实际生产工况下,筛选出的最优缓蚀剂可将D级杆和N80的腐蚀速率降至油田腐蚀控制指标0.076mm/a以内。研究表明,先以配伍性评价,后通过电化学评价进一步筛选,最后采用高温高压釜模拟工况测试验证,可以快速筛选出适用于CO_2驱采油井的缓蚀剂。     

CO2 adsorption on systems involving ethylenediamine impregnated on nanoporous materials

Abstract

MCM-41 and MCM-48 materials were synthesized by the hydrothermal method, calcined and modified with ethylenediamine (EDA) by wet impregnation method. The X-ray diffraction patterns showed characteristic peaks of highly ordered MCM-41 and MCM-48 nanoporous materials, even after impregnation with amine. The MCM-41 and MCM-48 materials showed N₂ adsorption isotherms type IV and BET surfaces areas higher than 1000?m² g^?1. The carbon dioxide adsorption tests were carried out at room temperature in a magnetic suspension microbalance. The materials presented good performance for CO₂ capture, being favorable for applications where medium and high pressures are required.