CO2 Solubility In Oil Research Articles

Machine learning methods for predicting CO2 solubility in hydrocarbons

The application of carbon dioxide (CO2) in enhanced oil recovery (EOR) has increased significantly, in which CO2 solubility in oil is a key parameter in predicting CO2 flooding performance. Hydrocarbons are the major constituents of oil, thus the focus of this work lies in investigating the solubility of CO2 in hydrocarbons. However, current experimental measurements are time-consuming, and equations of state can be computationally complex. To address these challenges, we developed an artificial intelligence-based model to predict the solubility of CO2 in hydrocarbons under varying conditions of temperature, pressure, molecular weight, and density. Using experimental data from previous studies, we trained and predicted the solubility using four machine learning models: support vector regression (SVR), extreme gradient boosting (XGBoost), random forest (RF), and multilayer perceptron (MLP). Among four models, the XGBoost model has the best predictive performance, with an R2 of 0.9838. Additionally, sensitivity analysis and evaluation of the relative impacts of each input parameter indicate that the prediction of CO2 solubility in hydrocarbons is most sensitive to pressure. Furthermore, our trained model was compared with existing models, demonstrating higher accuracy and applicability of our model. The developed machine learning-based model provides a more efficient and accurate approach for predicting CO2 solubility in hydrocarbons, which may contribute to the advancement of CO2-related applications in the petroleum industry.

Investigation of CO2 storage and EOR of alternating N2 and CO2 injection using experiments and numerical simulation

The feasibility of N2 alternating CO2 injection was investigated for improving CO2 storage and oil production. Schemes of continuous CO2 injection and N2 alternating CO2 injection were evaluated using laboratory experiments and numerical simulation. According to the core flooding experiments, the CO2 storage factor and enhanced oil recovery of N2 alternating CO2 flooding were 2.1% and 7.1% lower than continuous CO2 injection. The larger the N2 slug volume in N2 alternating CO2 injection, the lower the EOR and CO2 storage factor due to the reduction of CO2 concentration in the gas phase and CO2 solubility in oil and water. However, the N2 slugs in N2 alternating CO2 injection significantly reduced mobility differences between different flowing zones, and thus can increase the gas swept area in an oil reservoir. The gas swept area of the oil reservoir under N2 alternating CO2 injection mode is 1.78 times that of continuous CO2 injection, resulting in a 44% higher cumulative oil production. Besides, the scheme of N2 alternating CO2 injection was optimized and resulted in 19.6% more CO2 storage than continuous CO2 flooding at a field scale. This study provides valuable experimental and theoretical support for improving CO2 storage and oil production in an oil reservoir.

Laboratory investigation of the influence of fractures on CO2 flooding

CO2 injection is a promising method for low-permeability reservoirs. CO2 is much easier to inject underground compared with water. The solubility of CO2 in oil decreases the oil density and viscosity, leading to an enhancement of the oil recovery. CO2 flooding could achieve the dual purpose of developing oil effectively and reducing greenhouse gas. Therefore, this technique has both economic and social benefits and is an essential technology for achieving green development. Natural fractures are widely developed in low-permeability reservoirs, and artificial fractures are often used to improve oil development. These fractures have a significant influence on flow patterns during CO2 flooding. In addition, fractures are also one of the key factors of CO2 channeling. Therefore, the influence of fractures on CO2 flooding pressure distribution, fluid composition, and displacement efficiency needs to be studied. In this work, a CO2 flooding experiment was implemented to test the pressure distribution and outlet composition changes during CO2 flooding under different fracture lengths and apertures. The experiment shows that a long and wide fracture could effectively reduce the injection-production pressure difference. However, fractures also had a negative effect on oil development. Fracture length and aperture had a significant effect on the gas phase composition at the outlet, but had little effect on the oil phase composition.

Recovery of viscous and heavy oil by CO2-saturated brine

Fast economic growth in Oman coupled with its climatic conditions have led to an energy-intensive lifestyle that has resulted in high levels of carbon dioxide (CO2) emissions. The injection of CO2 produced by cement plants into oil reservoirs combined with carbon capture is seen as an option to reduce CO2 in the air in order to curb climate change. The potential of CO2-saturated brine to recover oil is investigated using two samples of viscous oil (13 and 21 cP) and one sample of heavy oil (1471 cP) from Oman in water flooding experiments followed by CO2-saturated brine injection at 25 °C and 3.45 MPa. CO2 solubility in oil and brine, changes of their viscosity and density, oil swelling and other parameters are investigated.Irrespective of early water breakthrough, the greatest incremental recovery of 25.6% after injection of CO2-saturated brine through oil saturated core is obtained for heavy oil, as compared to 8.2% and 15% for viscous oils. Higher recovery from heavy oil sample is explained by the greater viscosity reduction in addition to the density reduction of CO2-saturated oil that is similar for all three types of oil of about 50% on average. The greatest reduction of oil viscosity of 87% is obtained for the heavy oil and 59% on average for viscous oil samples. Thus, different mechanisms contribute more into the oil recovery: density reduction due to oil swelling for viscose oil and viscosity reduction for heavy oil.The injection of CO2-saturated brine demonstrates a great potential in addressing both issues, curbing of climate change and energy supply by enhanced recovery of viscous and heavy oil.

Acoustic investigation of CO2 mass transfer into oil phase for vapor extraction process under reservoir conditions

Generally, researchers to study mass transfer of gas phase into liquid use pressure decay method, visual cell or pendant drop technique. Despite available data about CO2 solubility in oil, there are limited methods which allow to study interactions between fluids. In this paper, a newly developed acoustic pulse-echo (APE) technique was applied to measure oil volume expansion factors in the presence of carbon dioxide in a pressure range of 2–6 MPa at a temperature of 297 K to cover most practical cases of interest for the vapor extraction process. With the APE technique, a wave is emitted from a piezoelectric transducer, and its reflection from the boundary is detected at a later time. As CO2 becomes soluble in the oil, the boundary between the fluids moves upward, thus affecting the travel time of the reflected wave from the fluid interface. Since volume changes are registered, the expansion factor can be evaluated. The experimental results show that the oil swelling factor increases with pressure; this clearly indicates that there are certain correlations between the oil swelling factor and the solubility of an oil-solvent system. The evidence for the validity of the acoustic technique was provided by comparing measured values with literature data. Compared to other investigatory approaches, the main advantage of this newly developed method is its ability to provide highly accurate swelling factor values for CO2/oil system. The method developed in this study can be serviceable for further and more complex investigations on gas-EOR experiments.

Effects of gas relative permeability hysteresis and solubility on associated CO2 storage performance

CO2 enhanced oil recovery (EOR) has been carried out in the Bell Creek oil field since 2013. Together with the encouraging oil production results, a considerable quantity of CO2 has also been trapped in the reservoir as a normal part of the EOR process, also referred to as associated storage. Because of the complex geologic conditions in the field, a series of experimental and modeling work have been conducted to better understand the CO2 EOR and associated storage performance in the reservoir. Effects of gas relative permeability hysteresis and solubility on associated CO2 storage performance are thoroughly investigated in this study.A proportion of injected CO2 remains behind through residual and solubility trapping mechanisms when CO2 flows through a reservoir during a CO2 EOR process. Over 50 core plugs were collected from the reservoir to characterize the rock properties. Mineralogical analysis and capillary pressure measurements showed that the mineral composition and pore-size distribution in the reservoir are favorable for residual trapping of CO2. The hysteresis of gas relative permeability was measured to assess the effect of residual trapping on associated CO2 storage using steady-state relative permeability tests and reservoir simulation. The reservoir oil was characterized based on pressure–volume–temperature experiments and Peng–Robinson equation of state modeling, which showed that CO2 solubility in oil is much greater (≥5 times) than in water. Results indicated that depleted oil reservoirs have great potential to store a huge quantity of CO2 associated with EOR operations, as residual oil saturation is 0.3 or greater in most conventional oil reservoirs after water flooding.

Impact of field development strategies on CO2 trapping mechanisms in a CO2–EOR field: A case study in the permian basin (SACROC unit)

This paper presents field-scale compositional reservoir flow modeling in the SACROC (Scurry Area Canyon Reef Operators Committee) unit, Permian Basin, to demonstrate the relative partitioning of CO2 during and after CO2 injection. The model was developed to study the effect of structural trapping, solubility trapping, and residual trapping on the partitioning of CO2 in oil, gas (free or residual), and brine phases over time. Furthermore, we investigated the impact of various injection scenarios, such as CGI (Continuous Gas Injection) and WAG (Water Alternating Gas), on the different trapping mechanisms. First, we used a high-resolution geocellular model, which was constructed from wireline logs, seismic surveys, core data, and stratigraphic interpretation. As the initial distribution of fluids plays an important role in CO2 partitioning, a comprehensive pressure-production history matching of primary, secondary, and tertiary recovery was completed. The hysteresis model was used to calculate the amount of CO2 trapped as residual. CO2 solubility into brine was verified based on previous experiments. The model results show a new understanding of relative CO2 partitioning in porous media. Although it was believed that structural trapping is the largest of the trapping mechanisms during CO2 injection and the first years of post-inject ion, our results show that in a carbonate field like SACROC, which contains a light oil, the solubility of CO2 in oil plays a very important role, even in the first stage of CO2 injection. Running a comprehensive history matching shows the deficiency of previous models to estimate the amount of trapped CO2 during and after the injection period. Among the various scenarios explored, WAG seems to be a promising operational approach to balance both storage and oil production. The present work provides valuable insights for optimizing oil production and CO2 storage in carbonate reservoirs like SACROC unit. In addition, this work helps decision makers to set storage goals based on optimized project risks.

Applying SVM framework for modeling of CO2 solubility in oil during CO2 flooding

CO2 solubility is one of the most important parameters that affects CO2 flooding, because gas dissolution into crude oil results in oil swelling, viscosity reduction, IFT reduction, oil mobilization, and oil recovery improvement. Therefore, a better understanding of CO2 solubility mechanisms and its influence on physical properties of crude oil are essential to any effective CO2 flooding process. In this study, Least-Square Support Vector Machine (LSSVM) as a newly established soft computing algorithm is applied for developing a new correlative model for CO2 solubility in both dead and live oil systems. CO2 solubility in dead oil is basically affected by the oil saturation pressure (Ps), oil specific gravity (γ), oil molecular weight (MW), and reservoir temperature (T). Moreover, the impact of bubble point pressure is considered in constructing the LSSVM model for the live oil. A number of statistical quality measures are utilized to assess and demonstrate the superior capability of the newly developed LSSVM model in comparison with the previous empirically derived correlations. The average absolute relative deviation (AARD) and coefficient of determination (R2) of 2.2783% and 0.9933 for the dead oil system, and 1.7432% and 0.9958 for the live oil system, respectively, verify the acceptable accuracy and efficient performance of the proposed LSSVM model over a wide range of dataset used in this study within the range of the used databank. However, the impact of CO2 liquefaction pressure is ignored, the LSSVM model gives the best result. In conclusion, it is worth mentioning that the proposed LSSVM model can serve as an accurate correlative tool for fast and effective estimation of CO2 solubility in both dead and live crude oils.

Stability of CO2 Displacement of an Immiscible Heavy Oil in a Reservoir

Summary Miscibility is not reached in carbon dioxide (CO2) flooding for recovery of heavy oils. Thus, an important advantage of no gas/oil surface tension is lost. Nevertheless, some CO2 continues to dissolve in oil and reduces the oil viscosity, which makes the displacement easier. This is an asset that remains. However, the viscosity of heavy crude is much higher than the viscosity of CO2, causing the displacement process to be unstable and leading to fingering or channeling. We have undertaken the linear-stability analysis of the displacement process, which is that of immiscible displacement but includes mass-transfer effects. All stabilizing/destabilizing mechanisms of both immiscible displacement and miscible displacement are included. A number of stabilizing mechanisms related to mass transfer have been identified. We are able to provide a numerical evaluation of the results that show the lowering of viscosity that is considered only in miscible displacement leads to a partial stabilizing effect that overcomes a large destabilizing effect of the adverse mobility ratio. There is a restricted form of instability that would only give rise to a mushy zone at the front. The two regions are separated at a wavenumber determined numerically as 0.531 cm−1. We are also able to show that in the limit that the solubility of CO2 in oil drops to zero, the above window of instability becomes infinite.

Interactions of CO2 with formation waters, oil and minerals and CO2 storage at the Weyburn IEA EOR site, Saskatchewan, Canada

The Weyburn oil field in Saskatchewan, Canada, is hosted in Mississippian carbonates and has been subject to injection of CO2 since 2000. A detailed mineralogy study was completed as the basis for modeling of mineral storage of injected CO2. Combining the mineralogy with kinetic reaction path models and water chemistry allows estimates of mineral storage of CO2 over 50 years of injection. These results, combined with estimates of pore volume, solubility of CO2 in oil and saline formation waters, and the initial and final pore volume saturation with respect to oil, saline water and gas/supercritical fluid allow an estimate of CO2 stored in saline water, oil and minerals over 50 years of CO2 injection. Most injected CO2 is stored in oil (6.5×106–1.3×107t), followed closely by storage in supercritical CO2 (7.2×106t) with saline formation water (1.5–2×106t) and mineral storage (2–6×105t) being the smallest sinks. If the mineral dawsonite forms, as modeling suggests, the majority of CO2 dissolved in oil and saline formation water will be redistributed into minerals over a period of approximately 5000 years. The composition of produced fluids from a baseline sampling program, when compared to produced fluids taken three years after injection commenced, suggest that dawsonite is increasingly stable as pH decreases due to CO2 injection. The results suggest that hydrocarbon reservoirs that contain low gravity oil and little or no initial gas saturation prior to CO2 injection, may store the majority of injected CO2 solubilized in oil, making such reservoirs the preferred targets for combined enhanced oil recovery-CO2 storage projects.

Oil recovery mechanisms and asphaltene precipitation phenomenon in immiscible and miscible CO2 flooding processes

In this paper, oil recovery mechanisms and asphaltene precipitation phenomenon of immiscible and miscible CO2 flooding processes in the tight sandstone reservoir core plugs are experimentally studied. First, the vanishing interfacial tension (VIT) technique is applied to determine the minimum miscibility pressure (MMP) between the original light crude oil and CO2. Second, a total of five coreflood tests are performed at the actual reservoir temperature. It is found that the oil recovery factor (RF) increases monotonically as the injection pressure increases during the immiscible CO2 flooding. The increased oil RF is attributed to the increased CO2 solubility in oil, reduced oil viscosity, increased CO2 viscosity, and reduced equilibrium interfacial tension (IFT) of the light crude oil–CO2 system. Once the injection pressure exceeds the MMP, the oil RF increases slightly and will reach an almost constant maximum value. In this case, it is the multi-contact miscibility (MCM) and the extremely low equilibrium IFT that jointly make the ultimate oil RF high and unchanged. Moreover, the oil RF after CO2 breakthrough (BT) increases slightly in the immiscible case but substantially in the miscible case. This is due to the strong light-hydrocarbons extraction by CO2 and the miscible displacement in the second case. On the other hand, the measured average asphaltene content of the produced oil and the measured oil effective permeability reduction are found to be higher in the immiscible flooding process. They both reach some lower values in the miscible case. Finally, the experimental results obtained in this study at the actual reservoir temperature of Tres=53.0°C are compared with those attained previously at the laboratory temperature of Tlab=27.0°C to examine the temperature effect on the CO2-based oil recovery process.

A Genetic Algorithm-Based Model to Predict CO-Oil Physical Properties for Dead and Live Oil

Abstract A key parameter in a CO2 flooding process is the CO2 solubility as it contributes to oil viscosity reduction and oil swelling which together, in turn, enhance the oil mobility and oil relative permeability. Often CO2-oil solubility parameters are established through time-consuming experimental means or using models or correlations available in the literature. However, one must recognize that such models or correlations to predict CO2-oil physical properties are valid usually for certain data ranges or site-specific conditions. Furthermore, it is to be noted that there is no reliable model available to predict CO2-live oil physical properties, as most of the available correlations are developed based on dead oil data. In this study, a genetic algorithm (GA)-based technique has been used to develop more reliable correlations to predict CO2 solubility, oil swelling factor, CO2-oil density and CO2-oil viscosity for both dead and live oils. These correlations recognize not only all major parameters that affect each physical property, but also take into account the effects of CO2 liquefaction pressure and oil molecular weight (MW). These correlations have been successfully validated with published experimental data and compared against several widely used correlations. The GA-based correlations have yielded more accurate predictions with lower errors than other correlations tested. Furthermore, unlike these correlations, which are applicable to only limited data ranges and conditions, GA-based correlations can be applied over a wider range and conditions. Another important and useful aspect is that GA-based correlations can also be integrated into any reservoir simulator for CO2 flooding design and simulation. Introduction Knowledge of the physical and chemical interactions between CO2 and reservoir oil, other than for study of the prospective recovery, are very important for any CO2 flooding project. The major parameter that affects CO2 flooding is CO2 solubility in oil because it results in oil viscosity reduction and oil swelling increase which, in turn, enhances the oil mobility, the oil relative permeability and increases oil recovery efficiency. Therefore, a better understanding of this parameter is vital to any successful CO2 flooding project. The effects of CO2 on oil physical properties are determined by laboratory studies and available modelling or correlation packages. It is very expensive and time consuming to conduct a laboratory study, which covers a wider range of data. On the other hand, for the available correlation packages, they can only be used in certain situations. They are not applicable in many situations as they have many limitations in their application. Furthermore, most of the available packages are developed for dead oil and there is no reliable model to predict the effect of CO2 on live oil physical properties. The objective of this study was to develop a more reliable model to predict the effects of CO2 on crude oil properties (CO2 solubility in oil, oil-swelling factor and CO2-oil mixture density and viscosity) for both dead and live oils. The new genetic algorithm (GA)-based modelling technique used in this study is based on GA software developed in an earlier work(1).

Prediction of CO2 Solubility in Oil and the Effects on the Oil Physical Properties

CO2 solubility in oil is a key parameter in CO2 flooding process. It results in oil swelling, increased oil density, and decreased oil viscosity. Laboratory studies needed to cover a wider range of data, and are time consuming, costly, and may be not available or possible in many situations. On the other hand, although various models and correlations are useful in certain situations, they may are not be applicable in many situations. In this study, a new genetic algorithm- (GA)-based technique has been used to develop more reliable correlations to predict CO2 solubility, oil swelling factor (SF), CO2-oil density, and viscosity of CO2-oil mixtures. Based on the Darwinian theory, the GA technique mimics some of the natural process mechanisms. Furthermore, GA-based model correlations recognize all the major parameters that affect each physical property and also well address the effects of CO2 liquefaction pressure. Genetic algorithm-based correlations have been successfully validated with published experimental data. In addition, a comparison of these correlations has been made against widely used correlations in the literature. It has been noted that the GA-based correlations yield more accurate predictions with lower errors than all other correlations tested. Furthermore, unlike other correlations that are applicable to limited data ranges and conditions, GA-based correlations have been validated over a wider range of data.

Why Scale Forms in the Oil Field and Methods To Predict It

Summary Predicting potential scaling problems can be difficult, and numerous saturation indices and computer algorithms have been developed to determine if, when, and where scaling will occur. The Langelier, Stiff-Davis, and the Oddo-Tomson saturation indices, all widely used in the oil field, are compared and contrasted relative to calcium carbonate scale. New saturation indices for barium, strontium, and calcium sulfate scale formation are introduced and discussed, along with an updated version of the Oddo-Tomson calcium carbonate index. An updated version of the CaCO3 saturation index is presented that includes correction terms for fugacity effects and changes in the solubility of CO2 in oil and gas wells as functions of temperature, pressure, water cut, and hydrocarbons present. The CaCO3 saturation index does not require a measured pH and can accommodate the presence of weak acids, such as H2S, and weak organic acids in the system. The sulfate scale prediction methods (for gypsum, hemihydrate, and anhydrite) are easy to use, reliable, and designed for field use by an operator who may be untrained in chemistry. The prediction methods can be applied to any production well where calcium carbonate, calcium sulfate, strontium sulfate, or barium sulfate scale occurs.

Evolution of the Carbon Dioxide Flooding Processes

Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering. Summary. Carbon dioxide flooding has become one of the major EOR processesin the U.S., with potential recovery of billions of barrels of oil thatotherwise would be left as residual in known U.S. reservoirs. Extensivecommercial-scale CO2 projects are under way, and other new projects andexpansions are planned for the future. This paper briefly reviews the evolutionof the CO2 flooding processes as they are most commonly applied today. Theimportant features of CO2 flooding, which have been defined by extensivelaboratory research and field testing, are summarized. Included are summariesof (1) early developments in the use of CO2, (2) oil displacement mechanisms ofCO2, and (3) other factors involved in the design of CO2 floods-i.e., CO2availability, CO2 injection requirements, mobility control, reservoirconditions, safety, CO2 reinjection, corrosion, and solids precipitation. Early CO2 Studies CO2 is one of the most plentiful and useful compounds on, in, and aroundthis planet. So it is not surprising that the idea to use it to recover oilfrom underground reservoirs originated early in EOR history. Investigators inthe laboratories began to look at CO2 flooding in the 1950's. Their mostimportant observations were the high solubility of CO2 in oil at pressuresabove about 700 psi (4.9 MPa) and the resultant dramatic reduction in oilviscosity, making the oil much easier to flow (Fig. 1). Fluid injectionprocesses using continuous CO2 or a single slug of CO2 followed by water orcarbonated water were suggested. As it was noted that CO2 was soluble in water, other publications appeared at that time recommending the injection of onlywater saturated with CO2. Several field tests were conducted with carbonatedwater, but these floods failed to produce significant amounts of extra oil, mainly because not enough CO2 was available at the flood front to saturate theoil and reduce its viscosity. CO2 transfers chromatographically from theinjected water to the oil. However, substantial volumes of carbonated water arerequired to saturate the residual oil, reduce its viscosity, and cause it toflow. Large volumes of CO2-denuded water precede this mobilized oil. An early field test of the injection of a single CO2 slug followed by waterwas conducted during this early period in the Allegheny field in New York.* Anattempt to make this a miscible flood failed, but, as shown in Fig. 2performance of laboratory model studies. Calculations indicated that viscosityreduction was the major mechanism for EOR. Reduced sweep efficiency was thoughtto account for the lower oil recovery obtained in the field compared to that inthe laboratory. The well defined phase behavior of CO2 (Fig. 3) shows that in mostapplications as an oil recovery agent, it exists as a supercritical fluid, above its critical temperature (89 deg F (32 deg C)) and pressure (1,070 psi(7.4 MPa)). The increased density of CO2 at these high pressures revealed itssolvency power for various liquids. Recognition of these facts, and notationthat very high oil recoveries were obtained in the laboratories, led to a fieldtrial at high pressures. The Mead Strawn field test begun in 1964 involved the injection of a largeslug of CO2 (25 % HCPV at reservoir conditions) followed by carbonated water atreservoir conditions of 125 deg. F and as high as 2,000 psi (52 deg C and 13.8MPa). The results of this test showed an incremental oil recovery for the CO2flood of more than 35% above that from conventional waterflooding. Even moreencouraging were the residual oil saturations determined from pressure coresobtained from this sandstone reservoir in the CO2 swept zones as far as 400 ft(122 m) away from the CO2 injection wells. Measured Sor values of less than 5%PV throughout the cored pay zone indicated recovery of residual oil that couldnot be accounted for by oil-viscosity reduction and oil swelling alone. Similarpressure cores recently recovered from the North Crossett flood, a carbonatereservoir, have shown the same ( less 5% PV) oil saturation behind the CO2displacement front. Displacement Mechanisms The high oil displacement efficiency of CO2 in the Mead Strawn field testled to further laboratory investigations of the suggested miscible effects ofthe process. Miscible displacement and the resultant very high recovery of oilfrom a reservoir require the injection of a fluid that either will form asingle phase with oil or will generate from the oil a solvent that forms asingle phase with oil, eliminating capillary retention of the oil by water androck. P. 1337^