Mutual Interactions of CO2/Oil and Natural Gas/Oil Systems and Their Effects on the EOR Process

Mutual interactions between oil and gas are critical factors affecting the gas enhancing oil recovery (EOR) process. Focusing on CO₂/oil and natural gas/oil systems, their interactions are researched and compared by extraction capacity and solubility measurement experiments. Core flood tests are also implemented to determine the effects of interactions on oil recovery. Results show that CO₂ can extract more light oil from the original and its extraction efficiency can reach 59.3% at 46 MPa, whereas that of natural gas is only 7.3%. However, heavy components content and viscosity of the residual oil processed by CO₂ increases significantly because of extraction, while natural gas does not affect the composition of the residual so remarkably. With increased pressure, solubility of CO₂ and natural gas in a light oil present a linear growth trend with similar rate, but the former is greater than the latter by about 130m³/m³. Core flood tests show that, for the continuous gas injection in the secondary oil recovery process, recovery of CO₂ flood is about 20% higher than that of natural gas due to the late breakthrough of CO₂, as most of the crude oil is produced before breakthrough.     

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.     

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.     

The Impact of CO2 Injection and Pressure Changes on Asphaltene Molecular Weight Distribution in a Heavy Crude Oil: An Experimental Study

Abstract

This work concerns observing the pressure as well as CO₂ mole percentage effects on asphaltene molecular weight distributions at reservoir conditions. A high-pressure, high-temperature asphaltene measurement setup was applied, and the amount of precipitated asphaltene at different pressures as well as CO₂ mole percentage in an Iranian heavy crude oil was measured. Moreover, the asphaltene molecular weight distributions during titration of crude oil with different n-alkanes were investigated. The gel permeation chromatography (GPC) apparatus was used for characterization of asphaltene molecular weight under different conditions. It has been observed that some thermodynamic changes such as pressure depletion above the bubble point increase the average molecular weight of asphaltene and cause the asphaltene molecular weight distributions changes from a bimodal curve with two maxima to a single maxima curve. One the other hand, below the bubble point, pressure reduction causes a decrease in the average molecular weight of asphaltene and also causes the shape of asphaltene molecular weight distributions to restore, which might be due to dissolution of asphaltene aggregates. An interesting result is that asphaltene molecular weight distribution at the final step of pressure reduction tests, ambient condition, shows approximately the same trend as the distribution of asphaltene molecular weight obtained at reservoir condition. This behavior explains the reversibility of the asphaltene precipitation process under pressure depletion conditions. In the case of CO₂ injection, the graphs of asphaltene molecular weight distributions always show a single modal trend and shift toward larger molecular weight values when CO₂ mole percentage increases. The results of this work can be imported to thermodynamic models that use polydisperse data of heavy organic fractions to enhance their performance at reservoir conditions. The distributions obtained by this method are good indicators of asphaltene structures at reservoir conditions.     

A numerical simulation study of CO 2 injection for enhancing hydrocarbon recovery and sequestration in liquid-rich shales

Less than 10% of oil is usually recovered from liquid-rich shales and this leaves much room for improvement, while water injection into shale formation is virtually impossible because of the extremely low permeability of the formation matrix. Injecting carbon dioxide (CO₂) into oil shale formations can potentially improve oil recovery. Furthermore, the large surface area in organicrich shale could permanently store CO₂ without jeopardizing the formation integrity. This work is a mechanism study of evaluating the effectiveness of CO₂-enhanced oil shale recovery and shale formation CO₂ sequestration capacity using numerical simulation. Petrophysical and fluid properties similar to the Bakken Formation are used to set up the base model for simulation. Result shows that the CO₂ injection could increase the oil recovery factor from 7.4% to 53%. In addition, petrophysical characteristics such as in situ stress changes and presence of a natural fracture network in the shale formation are proven to have impacts on subsurface CO₂ flow. A response surface modeling approach was applied to investigate the interaction between parameters and generate a proxy model for optimizing oil recovery and CO₂ injectivity.     

Rigorous modeling of solubility of normal alkanes in supercritical CO2

In this contribution, ANFIS approaches are developed for the prediction of normal alkane solubility in supercritical carbon dioxide. Regarding the economic and environmental benefits of carbon dioxide injection, it introduced as a well-known procedure of EOR. With this in mind that solubility of normal alkanes followed by CO₂ injection affected by various operational condition, in this article functionality of solubility of normal alkanes in supercritical carbon dioxide from operational condition was investigated using Adaptive Neuro Fuzzy Interface System (ANFIS). Results demonstrate that the model is precise. The model shows an overall R² and AARD% estimations of 0.9921 and 0.89%, respectively.     

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.     

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.     

An Investigation of Asphaltene Precipitation During Natural Production and the CO2 Injection Process

Some of Iranian oil reservoirs suffer from operational problems due to asphaltene precipitation during natural depletion, so widely investigation on asphaltene precipitation is necessary for these reservoirs. In this study, a reservoir that is candidate for CO₂ gas injection process is selected to investigate asphaltene precipitation with and without CO₂ injection. In this case, asphaltene precipitation is monitored at various pressures and reservoir temperature. Then, a series of experiments are carried out to evaluate the amount of precipitated asphaltene by injection different molar concentrations (25%, 50%, and 75%) of CO₂. The results show that during primary depletion the amount of precipitated asphaltene increases with pressure reduction until bubble point pressure. Below the bubble point the process is reversed (i.e., the amount of precipitated asphaltene at bubble point pressure is maximum). The behavior of asphaltene precipitation versus pressure for different concentrations of CO₂ is similar to primary depletion. Asphaltene precipitation increases with CO₂ concentration at each pressure step. In the modeling part, solid model and Peng-Robinson equation of state are employed which show a good match with experimental results.     

Modelling of gas to hydrate conversion for promoting CO2 capture processes in the oil and gas industry

In this contribution, equilibrium conditions of clathrate hydrates containing mixtures of carbon dioxide and tetra-n butylammonium bromide and tetra-n butylammonium chloride are modeled by a combination of particle swarm optimization algorithm with least square support vector machine intelligent approach. The evaluation of aforementioned model has been conducted by statistical analyses between experimental and predicted values. The obtained results show excellent performance of proposed model.     

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.     

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.     

不同注采方式下CO2埋存与驱油效果优化评价

工业和人类生活过程中产生的温室气体CO₂排放量日益增加,由此导致的空气污染和温室效应正在严重地威胁着人类赖以生存的环境。实行CO₂高效利用与地质埋存相结合的一体化技术思路是缓解环境污染压力、提高石油采收率的有效途径。针对这一问题,建立了目标函数,并应用商业软件对注CO₂驱的9套注采方案进行了数值模拟对比研究。结果表明：溶剂驱比纯CO₂驱的采收率更高,但减少了CO₂的埋存量;进行溶剂驱或水气交替驱到CO₂驱的转换可以使目标函数值更大;井控方法是CO₂埋存与EOR的最优方法,该方法累计产油量最大,储集的CO₂也最多。这些结论为油田三次采油提供了技术参考,也为减排CO₂提供依据。     

层内自生CO2提高采收率技术在海上油田的研究及应用

针对海上某油田储层非均质性强、注水强度大,注水突进严重导致储量动用程度低,而常规调剖措施无法有效开展的问题,通过物模驱替实验考察了层内自生CO_2提高采收率技术在该油田的可行性,并对注入量、注入方式、注入速度和稳定剂用量等参数进行优化研究。实验结果表明,层内自生CO_2技术提高采收率的效果显著,储层渗透率在(200～10 000)×10~(-3)μm~2范围内,采收率可在常规水驱基础上提升28.70%～32.29%,原油黏度在10～500 mPa·s范围内,对层内自生CO_2驱油效果基本无影响。技术的最优工艺参数为:注入量1.0 PV,8段塞注入,生气剂和释气剂注入速度比为1∶1,稳定剂用量为0.10 PV。现场试验表明,层内生成CO_2提高采收率技术对渤海油田稳油控水起到了显著效果,措施后井组日产油量最高增加100 m~3,含水率下降12%,有效期内净增油3826 m~3。     

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.     

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%.     

An Integrated Decision Support System for Management of CO2 Geologic Storage in the Weyburn Field

Abstract

Geologic storage of CO₂ in depleted oil reservoirs is considered to be an effective approach for both facilitating GHG sequestration and enhancing oil recovery. However, as a potential problem in the long run, risks associated with geological storage of CO₂, such as leakage to the groundwater and atmosphere, might pose significant threats to local communities and surrounding environment. Identification and evaluation of such risks are essential for the long-term management of CO₂ storage. Doing so requires a set of advanced technologies in order to well understand the long-range transportation of CO₂ and its impact mechanisms. This study developed an integrated decision support framework for the Weyburn Field. This system included modules of data management, inexact hybrid numerical simulation, optimization for CO₂ EOR processes, hybrid fuzzy-stochastic risk assessment, and post-modeling analysis. A user-friendly interface was designed through visual language programming. Such an effort would provide project managers with a collection of measures for analyzing and visualizing operations and development of different applicable technologies. Valuable information can be provided to EOR project operators about what might be required for new projects or project expansions and how to go about gathering and using the data they will need.     

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.     

Mass Transfer of CO2 Into Water and Surfactant Solutions

Abstract

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.     

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.