Miscible Injection Research Articles

Buoyant miscible viscoplastic injections

Buoyant miscible viscoplastic injections

Monte Carlo Simulation of the CO2 Flooding Efficiency at a Core Scale for Different Oil Compositions

The evaluation of water-alternating-gas (WAG) efficiency and profitability is complicated by a large number of reservoir, operating, and economic parameters and constraints. This study aims at understanding the influence of the oil composition on different WAG injections. By employing compositional reservoir modeling and the Monte Carlo method to characterize the diversity of oils occurring in nature, we simulate the microscopic displacement efficiency of CO2 flooding when it is applied to both light- and heavy-oil reservoirs. We find that the economic performance of WAG in both miscible and immiscible scenarios is mainly characterized by the dimensionless injection rate and the oil density at surface conditions. Neither the bubble point pressure nor the minimum miscibility pressure can be used for the quantification of the optimal WAG parameters. We present our estimates of the best strategies for the miscible and immiscible injections and verify some of our previous results for randomly sampled oils. In particular, we demonstrate that CO2 flooding is better to apply at higher-dimensionless injection rates. We show that the injection of CO2 organized at a light-oil reservoir results in a higher profitability of WAG, although this comes at the cost of lower carbon storage efficiency.

The characteristics of produced oils in the miscible CO2 displacement process

CO2 flooding is an effective technique for enhancing oil recovery by changing the hydrocarbon fluid’s characteristics. One of the fundamental mechanisms of the interaction between CO2 and hydrocarbon fluid by miscible CO2 injection is the extraction phenomenon of the hydrocarbon components by CO2. It results in altered produced and residual oil characteristics. This study aims to examine the characterizations of produced oil during the process of CO2 displacement. It is critical to anticipate any issues that can arise from miscible CO2 flooding, such as asphaltene deposition. A light-dead oil sample from an Indonesian oil field was used in this investigation. The miscible CO2 displacement process was conducted by a slim tube experiment at operating temperature of 90°C and 70°C, which represents the reservoir and surface temperature, respectively. The properties of produced oil were further characterized by analyzing the composition based on its polarity, including saturate, aromatic, resin, and asphaltene. The results show that increasing injection pressures decrease resin and asphaltene fractions in produced oil. Furthermore, the proportions of asphaltene and resin fractions in the crude sample exhibit a significant decrease when conducted at a lower temperature in comparison to when carried out at a higher temperature. This study helps to explain how the displacement process by CO2 affects the properties of the produced oil.

A One-Dimensional Convolutional Neural Network for Fast Predictions of the Oil-CO2 Minimum Miscibility Pressure in Unconventional Reservoirs

Summary Miscible carbon dioxide (CO2) injection has proven to be an effective method of recovering oil from unconventional reservoirs. An accurate and efficient procedure to calculate the oil-CO2 minimum miscibility pressure (MMP) is a crucial subroutine in the successful design of a miscible CO2 injection. However, current numerical methods for the unconventional MMP prediction are very demanding in terms of time and computational costs which result in long runtime with a reservoir simulator. This work proposes to employ a one-dimensional convolutional neural network (1D CNN) to accelerate the unconventional MMP determination process. Over 1,200 unconventional MMP data points are generated using the multiple-mixing-cell (MMC) method coupled with capillarity and confinement effects for training purposes. The data set is first standardized and then processed with principal component analysis (PCA) to avoid overfitting. The performance of the proposed model is evaluated with testing data. By applying the trained model, the unconventional MMP results are almost instantly produced and a coefficient of determination of 0.9862 is achieved with the testing data. Notably, 98.58% of predicting data points lie within 5% absolute relative error. This work demonstrates that the prediction of unconventional MMP can be significantly accelerated, compared with the numerical simulations, by the proposed well-trained deep learning model with a slight impact on the accuracy.

Adsorption effects on CO2-oil minimum miscibility pressure in tight reservoirs

CO2 miscible injection holds immense potential for enhancing tight oil recovery, where achieving the minimum miscibility pressure (MMP) is pivotal. Adsorption of CO2 and oil in pores affects the CO2-oil MMP in tight reservoirs, necessitating precise nanoscale MMP calculations and understanding influencing factors. Here, we applied a modified Peng-Robinson equation of state (PR-EOS) for nanoscale MMP calculations, incorporating adsorption layers and effective molar volume to describe adsorption effects. Validation against molecular simulations and nanofluidic experiments shows a maximum deviation of 4.6 %. We found that in nanopores, achieving miscibility demands less CO2 than in bulk. The CO2-oil MMP reduces as pore size decreasing, influenced by adsorption, critical point shift and capillarity. At 5 nm, the MMP is 11.12 MPa, 27.8 % lower than the bulk value (15.4 MPa). Adsorption intensifies this reduction by curtailing free molecules and effective pore radius, and becomes more pronounced for lighter hydrocarbon mixtures. However, the nanoscale CO2-oil MMP is equal to the bulk value when rp ≥ 350 nm. Furthermore, a maximum MMP and the corresponding transition temperature exist for each pore size, and increase as pore size increasing. This method provides a valuable tool for optimizing CO2 miscible injection and carbon storage in challenging nanoscale-pore reservoirs.

Permeability impairment and oil recovery changes in porous media due to asphaltenes deposition during natural gas injection: An experimental study

Injection of natural/associated gas is widely used as an efficient method of enhanced oil recovery in carbonate oil reservoirs in both miscible and immiscible conditions. Due to reservoir oil compositional changes by injected gas, asphaltenes instability may occur. In spite of the broad reported studies on gas injection process, the effect of miscible gas injection phenomenon on asphaltenes precipitation and deposition at reservoir conditions has not been well attended. The aim of this study is to recognize the effect of miscible and immiscible injection of natural gas on the asphaltenes deposition, permeability alteration and oil recovery. Additionally, the impact of different live and recombined oil samples on asphaltenes instability is investigated. Permeability alteration by the formation of asphaltenes is analyzed through the permeability measurements before and after gas flooding. Permeability reduction is found to be function of miscibility state, injection pressure and type of oil samples. It is observed that experiments conducted with live oil and at lower injection pressures show more permeability reduction. It is assumed an additional oil recovery associated with fluid path diversion caused by asphaltenes deposition in miscible and immiscible conditions. The miscible gas flooding causes the lower asphaltenes deposition and lower recovery enhancement. These effects are due to the fluid path diversion, nevertheless, miscible natural gas injection has high potential of oil recovery. Due to miscible bank development, the composite core along with higher injection pressure respect to minimum miscibility pressure shows higher recovery in comparison to the short core sample.

An experimental study of CO2 injection strategies for enhanced oil recovery and geological sequestration in a fractured tight sandstone reservoir

Carbon dioxide enhanced oil recovery has been considered and tested in unconventional oil reservoirs due to its additional environmental benefits from simultaneous CO2 geological sequestration. However, it will require a proper injection strategy to overcome unfavorable sweep efficiency in CO2 displacement, which is even magnified in unconventional oil reservoirs due to strong heterogeneity caused by natural and artificial fractures. In this study, we investigated three immiscible CO2 injection strategies at reservoir conditions using tight fractured sandstone cores from the Ordos Basin, China: water alternative gas injection, cyclic CO2 injection, and CO2 foam/surfactant alternative gas injection. A pressurization and miscible CO2 injection were then added after each injection strategy to examine the influence of residual liquid distributions on the miscible displacement efficiency after the tested injection schemes. The core plugs with comparable porosity and permeability were selected, and all cores reached a similar recovery factor (∼11%) after primary CO2 flooding. We found that the cyclic CO2 injection had best performance, with the highest incremental and accumulative oil recovery at 23.6% and 32.26%. Its relatively higher sweep efficiency indicated a uniform CO2 distribution at the end of the cyclic injection, which further led to the highest incremental recovery of 4.94% in the following miscible injection. Comparable CO2 storage capacities were observed in the three fractured core samples (12.21%, 12.98%, and 9.71%, respectively) after completing the miscible displacements. In general, cyclic CO2 injection is recommended as an effective CO2 EOR and geo-storage in tight fractured rocks.

Prediction of Key Parameters in the Design of CO2 Miscible Injection via the Application of Machine Learning Algorithms

The accurate determination of key parameters, including the CO2-hydrocarbon solubility ratio (Rs), interfacial tension (IFT), and minimum miscibility pressure (MMP), is vital for the success of CO2-enhanced oil recovery (CO2-EOR) projects. This study presents a robust machine learning framework that leverages deep neural networks (MLP-Adam), support vector regression (SVR-RBF) and extreme gradient boosting (XGBoost) algorithms to obtained accurate predictions of these critical parameters. The models are developed and validated using a comprehensive database compiled from previously published studies. Additionally, an in-depth analysis of various factors influencing the Rs, IFT, and MMP is conducted to enhance our understanding of their impacts. Compared to existing correlations and alternative machine learning models, our proposed framework not only exhibits lower calculation errors but also provides enhanced insights into the relationships among the influencing factors. The performance evaluation of the models using statistical indicators revealed impressive coefficients of determination of unseen data (0.9807 for dead oil solubility, 0.9835 for live oil solubility, 0.9931 for CO2-n-Alkane interfacial tension, and 0.9648 for minimum miscibility pressure). One notable advantage of our models is their ability to predict values while accommodating a wide range of inputs swiftly and accurately beyond the limitations of common correlations. The dataset employed in our study encompasses diverse data, spanning from heptane (C7) to eicosane (C20) in the IFT dataset, and MMP values ranging from 870 psi to 5500 psi, covering the entire application range of CO2-EOR. This innovative and robust approach presents a powerful tool for predicting crucial parameters in CO2-EOR projects, delivering superior accuracy, speed, and data diversity compared to those of the existing methods.

A Systematic Experimental Study to Understand the Performance and Efficiency of Gas Injection in Carbonate Reservoirs

Summary Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoir that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, carbon dioxide (CO2) enhanced oil recovery (EOR) has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artifacts, long cores were used in the experiments, and to observe the effect of gravity, both 2 in. diameter and 4 in. diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by aging the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores, and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are as follows: The effect of miscibility on oil recovery for both continuous gas injection and water alternating gas (WAG). The effect of gravity on gas sweep efficiency compared to waterflooding. The effect of gas-oil interfacial tension (IFT) on oil recovery when using the same oil. The effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions. The effect of immiscible gas injection on subsequent miscible gas injection performance. Impact of CO2 cycle length on ultimate oil recovery. The impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are as follows: As expected, miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas. A significant variation in oil recovery is observed for miscible gas injection (i.e., more than 10 saturation units difference) depending on the minimum miscibility pressure (MMP) between the injected gas and crude oil, even when both experiments are performed at miscible conditions using the same injected gas. The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. During WAG experiments, starting the injection cycles with water or gas did not have any impact on the ultimate oil recovery for both miscible and immiscible cases for one of the reservoirs, while WAG_G (WAG starting with gas injection) recovered more oil for another reservoir. Gravity has a significant impact on oil recovery for both miscible and immiscible gas injections. A significant difference is observed in oil recovery when comparing CO2 injection on 2-in.- and 4-in.-diameter core samples or when comparing horizontal vs. vertical immiscible gas injection and WAG experiment. The longer the CO2 slug size, the higher the oil recovery observed in gas injection experiments. The results of this study provide a rich and rarely available set of experimental data that can help improve and optimize gas and WAG injection in oil-wet carbonates.

Buoyant fluid injections at high viscosity contrasts in an inclined closed-end pipe

This paper studies the buoyant miscible injection of a high-viscosity fluid in a pipe filled with a low-viscosity fluid. The injection is carried out via an eccentric inner pipe inside an inclined closed-end outer pipe. A heavy fluid is injected into a light fluid at a constant density difference. Although the density difference is small, the buoyancy force, quantified via the Archimedes number (Ar), remains large. Our research relies on non-intrusive experimental methods, via a mix of high-speed camera imaging, ultrasound Doppler velocimetry, planar laser induced fluorescence, and particle image velocimetry techniques, accompanied by complementary numerical simulations. The effects of the viscosity ratio (M), the Reynolds number (Re) and the inclination angle (β) are analyzed on the injection/placement flow dynamics. Accordingly, a detailed description of the flow is presented, in terms of the concentration and velocity fields, the average front velocity of the heavy fluid (V¯f), the mixing index, and the flow regimes. The findings reveal that V¯f is mainly governed by an inertial-buoyant balance, allowing us to develop a correlation for V¯f vs Ar, M, Re and β. The results also show that a heavy fluid front separation occurs when M is small, β is large (i.e., near-vertical inclinations), and Re is large. This observation permits us to classify the flows into separation and non-separation regimes, in a dimensionless group plane based on a combination of the aforementioned dimensionless numbers.

Physics guided data-driven model to estimate minimum miscibility pressure (MMP) for hydrocarbon gases

Local or regional availability of hydrocarbon gases, and being associated with the native fluids makes them a reliable candidate for gas injection processes. As the achievement of miscibility leads to higher recoveries (see the comprehensive review on miscibility by Dindoruk et al., 2021), miscible hydrocarbon injection will be preferred where it is feasible. Using hydrocarbon gases for miscible injection has additional benefits 1) High outlet pressures from the separators (using gas compressors) (Griffith et al., 1970) leading to lesser gas volume to transport, 2) Reduction of flaring: in many places where there is no or not enough infrastructure capacity to transport these gases, such gases are simply flared (Worldbank, 2022; USCUSA, 2022), 3) Being associated with the in-situ fluids, less likely to have issues such as corrosion, or other potential problems. Methane (dominant component in hydrocarbon gas streams) and other live HC blends is classified greenhouse gases (GHG) which are harmful to the environment and such actions do not comply with the tighter carbon/emission reduction policies that are being implemented, especially considering the fact that resulting in the emission of methane, which has 28 to 36 times the global warming potential (GWP) compared to CO2 (EPA2, 2022; Turner et al., 2016; Turner et al., 2019). From the recovery point of view and as well as tuning the equation of state (EOS) for gas injection processes, minimum miscibility pressure (MMP) is a pivotal parameter estimating the recovery factor during gas injection processes. In this study we developed a methodology using Light Gradient Boost (Light GBM) (Ke et al., 2017) based model to estimate: 1) Minimum Miscibility Pressure (MMP) for the injected stream of hydrocarbon (HC) gas, and 2) minimum heavy HC gas (C2H6, C3H8 or their equivalence like CO2 and H2S) that is required to be added for a target MMP into the light HC gas stream. This is also known as minimum miscible enrichment, MME to achieve a prescribed MMP if the pressure requirements for a given lean gas are too high to implement in the field, usually due to compression cost and/or reservoir/well integrity reasons. We validate our MMP model using Leave-One-Out-Cross-Validation (LOOCV) (Shao, 1993) method which is the least unbiased cross -validation method and therefore proves the robustness of the proposed model. We compared the accuracy of the proposed model (AARE = 3.83%) with the leading correlations in the industry, and the proposed model significantly outperforms all the relevant models in the literature as shown in this study (Maklavani et al., 2010; Eakin and Mitch, 1988; Glaso, 1985; Kuo, 1985). The proposed model fully considers the underlying physics of miscibility and takes into consideration all the key and easy to obtain input parameters that influence the miscibility pressure of the injected gas.

Asphaltene Precipitation and Deposition during Nitrogen Gas Cyclic Miscible and Immiscible Injection in Eagle Ford Shale and Its Impact on Oil Recovery

Asphaltene Precipitation and Deposition during Nitrogen Gas Cyclic Miscible and Immiscible Injection in Eagle Ford Shale and Its Impact on Oil Recovery

A new empirical model for predicting flue gas miscibility for light oils

It is typical to observe a decline in production rate and a decrease in reservoir pressure after oil reservoirs have been allowed to produce for a long time. Miscible flooding is a tertiary recovery method for enhancing the reservoirs’ sweep efficiency. During miscible injection, gasses such as carbon dioxide, natural gas, and nitrogen are employed to increase production levels. Carbon dioxide is commonly used as a miscible gas, but less abundant and more expensive than nitrogen. Flue gas, a mixture of carbon dioxide and nitrogen gas, is often used to replace pure carbon dioxide. For this study, flue gasses with the compositions, 15% of carbon dioxide, 85% of nitrogen gas and 30% of carbon dioxide,70% of nitrogen gas, are used as the injection gas to develop an empirical correlation for minimum miscibility pressure (MMP) for candidate light oil reservoirs that have been previously waterflooded. In data analysis and data analytics, the dataset was separated into two groups at random: the training set, which consists of 80% of the entire dataset, and the testing set, which made up 20% of the total dataset. The independent variables employed for model development include temperature, oil sample oil gravity, molecular percentage of carbon dioxide in the injection gas, the molecular weight of hexane plus in the oil, and the molecular percentage of intermediates. The findings reveal that the newly built model is more accurate and delivers better predictions than the existing correlations. For the testing dataset, the new model predicts flue gas MMP with an average absolute percentage error of 5.5519% and a correlation coefficient of 0.92.

Heat transfer analysis of immiscible slug flow-based microchannels: Study of channels with extended surfaces

Immiscible injection of slug(s) into a microchannel with square blocks attached to the bottom surface of the channel is studied using the phase-field approach for interface tracking. It is confirmed that immiscible injection enhances heat transfer by up to 85% compared to miscible injection considering identical thermophysical properties. The differences in the rate of heat removal between immiscible and miscible injection are explained by the hydrodynamics of the system. It is also found that larger injected slug size does not necessarily result in greater heat removal and causes the average Nusselt number to behave non-monotonically, reaching an optimum value at a specific slug length. This non-monotonic trend has been explained by analyzing the hydrodynamics of the system. The effect of the inter-block distance generally showed a monotonic increasing trend for the average Nusselt number, except for a single slug length. This behavior has been explained by the vorticity and Fourier transform analysis. An alternating slug injection configuration has also been analyzed. The analysis of this configuration reveals a non-monotonic behavior of the average Nusselt number vs the number of injected slugs. This non-monotonic behavior shows that for each value of the selected slug length, there is a critical number of slugs, and consequently, a critical slug length for which the average Nusselt number reaches a maximum. The hydrodynamics of the system justifies this non-monotonic behavior. Finally, the friction factor and performance evaluation criterion are presented as a guideline for the design of the microchannels based on flow configuration.

Scaling analysis for a 3-D CO[formula omitted] plume in a sloping aquifer at a late stage of injection

We investigate supercritical CO2 injection into a sloping saline aquifer and propose a simple relationship to estimate the maximum gas migration distance in the updip direction. The estimate is derived from the system of governing equations for immiscible flow of gas and formation brine. By writing the equations in non-dimensional form, we guess the scaling law for the migration distance at a late stage of CO2 injection. Then, we verify the scaling law by means of 3-D reservoir simulations of miscible CO2 injection with account for the residual and solubility trapping. We derive an estimate that relates the maximum migration distance with the dip angle, the porosity, the anisotropic permeability, and the end-points of saturation functions. We show that the estimate is rather accurate for different reservoir temperatures and brine salinity and in the case of a flue gas injection. The proposed scaling is useful for a quick assessment of the risk of CO2 reaching a potential leakage site in a large regional aquifer. It can also be applied to estimate the propagation of the uncertainties of reservoir parameters to the uncertainty of the migration distance.

The potential and mechanism of nonionic polyether surfactants dissolved in CO2 to improve the miscibility of CO2–hydrocarbon systems

Certain unique reservoir conditions and technical difficulties have greatly limited the use of CO2 miscible injection in unconventional reservoirs. Lowering the miscibility pressure to realize the miscibility of CO2 and crude oil is critical for achieving the most efficient recovery process. In this study, we investigated whether nonionic polyether surfactants could improve the miscibility of CO2 and hydrocarbons. And an improved experimental method for a quantitative evaluation of additive efficiencies in lowering the miscibility pressure was introduced for the first time. The dissolution behaviors of nonionic polyether surfactants in CO2 and phase behaviors of CO2–hydrocarbon systems with and without surfactant additives were conducted. The effects of surfactant structure and concentration and temperature on the solubility of nonionic polyether surfactants in CO2 along with the efficiency of miscibility pressure reduction for CO2–hydrocarbon systems were analyzed. The results showed that the polyoxypropylene alkyl ethers exhibited excellent potential for improving the miscibility of the CO2 and hydrocarbons, especially when low molecular weight surfactant molecules with high polyoxypropylene group content were used. The first-contact miscibility pressure (FCMP) of the mixed oil and CO2 could be reduced by as much as 22.51% with 3 wt% C4(PO)3 addition. Furthermore, a mechanistic understanding showed that the solubilization of the CO2 caused by polyether reverse micelles resulted in a reduction of miscibility pressures for CO2–hydrocarbon systems. The study results and the novel evaluation method provided guidance for designing and selecting appropriate additive structures to reduce miscibility pressures of CO2–oil systems and meet the CO2 miscible injection technology requirements.

Asphaltene Precipitation and Deposition under Miscible and Immiscible Carbon Dioxide Gas Injection in Nanoshale Pore Structure

Summary Asphaltene precipitation and deposition is considered one of the prevailing issues during carbon dioxide (CO2) gas injection in gas enhanced oil recovery techniques, which leads to pore plugging, oil recovery reduction, and damaged surface and subsurface equipment. This research provides a comprehensive investigation of the effect of immiscible and miscible CO2 gas injection in nanopore shale structures on asphaltene instability in crude oil. A slimtube was used to determine the minimum miscibility pressure (MMP) of the CO2. This step is important to ensure that the immiscible and miscible conditions will be achieved during the filtration experiments. For the filtration experiments, nanocomposite filter paper membranes were used to mimic the unconventional shale pore structure, and a specially designed filtration apparatus was used to accommodate the filter paper membranes. The uniform distribution (i.e., same pore size filters) was used to illustrate the influence of the ideal shale reservoir structure and to provide an idea on how asphaltene will deposit when utilizing the heterogeneous distribution (i.e., various pore size filters) that depicts the real shale structure. The factors investigated include immiscible and miscible CO2 injection pressures, temperature, CO2 soaking time, and pore size structure heterogeneity. Visualization tests were undertaken after the filtration experiments to provide a clear picture of the asphaltene precipitation and deposition process over time. The results showed an increase in asphaltene weight precent in all experiments of the filtration tests. The severity of asphaltene aggregations was observed at a higher rate under miscible CO2 injection. It was observed that the miscible conditions have a higher impact on asphaltene instability compared to immiscible conditions. The results revealed that the asphaltene deposition was almost equal across all the paper membranes for each pressure used when using a uniform distribution. Higher asphaltene weight percent were determined on smaller pore structures of the membranes when using heterogeneous distribution. Soaking time results revealed that increasing the soaking time resulted in an increase in asphaltene weight precent, especially for 60 and 120 minutes. Visualization tests showed that after 1 hour, the asphaltene clusters started to precipitate and could be seen in the uppermost section of the test tubes and were fully deposited after 12 hours with less clusters found in the supernatant. Also, smaller pore size of filter membranes showed higher asphaltene weight percent after the visualization test. Chromatography analysis provided further evaluation on how asphaltene was reduced though the filtration experiments. Microscopy and scanning electron microscopy (SEM) imaging of the filter paper membranes showed the severity of pore plugging in the structure of the membranes. This research highlights the impact of CO2 injection on asphaltene instability in crude oil in nanopore structures under immiscible and miscible conditions. The findings in this research can be used for further research of asphaltene deposition under gas injection and to scale up the results for better understanding of the main factors that may influence asphaltene aggregation in real shale unconventional reservoirs.

Microscopic transport and phase behaviors of CO2 injection in heterogeneous formations using microfluidics

CO2 injection into the geological formations is a promising option to enhance oil recovery while simultaneously contributing to carbon storage. Conventional core tests provide critical insights but still leave ambiguous transport mechanisms due to the limitation of real-time visualization. This study aims to directly observe the multiphase flow behaviors and phase change in CO2 injection at pore-scale using microfluidics. Our all-in-one chip design provides a universal platform to reproduce various CO2 injection strategies in the formation with permeability contrast, including flooding and huff-n-puff processes, and integrated a rapid measurement of minimum miscibility pressure (MMP). Miscible injection eliminates the capillary force in immiscible scenario, and promotes stable film-wise displacement with a higher recovery rate and an attenuated heterogeneity impact. We find that effective huff-n-puff operations require a sufficient gas concentration to generate bubbles and an adequate pressure gradient to push the dissolved gas displacement, which supports the importance of high depressurization rate from both physical phenomenon and inherent mechanism. Huff-n-puff re-energizes the reservoir after immiscible flooding through deep gas-oil interactions and induces a considerable growth in cumulative recovery. These micromodel results can significantly improve our fundamental understanding on detailed multiphase transport phenomena in CO2 injection and help to optimize implementation schemes.

Experimental investigation of CO2 storage and oil production of different CO2 injection methods at pore-scale and core-scale

The CO2 storage and oil production of different CO2 injection schemes via laboratory experiments was investigated in this study. Microfluidic equipment was upgraded to increase its working pressure above the miscible pressure of the CO2/oil system. Microfluidic experiments of immiscible CO2 injection, miscible CO2 injection, water injection, and water alternating CO2 (WAG) injection were conducted. Affected by buoyancy subject to gas phase, apparent gas overriding and flow stratification were observed under immiscible conditions in porous media. Miscible CO2 injection eliminated the influence of buoyancy, thereby expanding the CO2 storage area and enhancing oil production. Non-uniform miscibility was observed during miscible CO2 injection, caused by connate water, tiny pores, and differential pressure. Water flooded most areas in the porous media, but small dispersed oil such as droplet oil and film oil remained in the water-flooded pores, resulting in low oil washing efficiency. The strong Jamin effect in the water-flooded area, caused by the dispersion of the remaining oil, inhibited the gas overriding and expanded the scope of CO2 flow in WAG, thereby increasing the oil production. However, the water slug occupied a large pore volume and drove out the CO2 stored at the beginning stage, resulting in low CO2 storage. The core flooding experiments were conducted to quantitatively evaluate the CO2 storage and oil recovery of different CO2 injection methods. Miscible injection produced 20.5%, 12.2%, and 2.9% more oil than immiscible CO2 injection, water flooding, and WAG. Besides, the produced gas by miscible CO2 injection was 46.5% and 47.6% lower than that of immiscible CO2 injection and WAG, respectively.

Storage Ratio of CO2 Miscible Flooding in Chang 8 Reservoir of H Block in Ordos Basin Under Different Injection Methods

Carbon dioxide is a typical kind of greenhouse gases, and the oil and gas field recovery ratio could be significantly improved by injecting it into the formation. The main goal is to increase the recovery ratio in the early stage of studying gas injection miscible flooding. With the advancement of the “carbon neutral” strategy in China, the application of CO2 miscible flooding technology, which aims to enhance the oil recovery ratio in Chinese oilfields, has been further expanded. The development concept needs to change from simply improving the recovery ratio to improving both the recovery ratio and the CO2 storage ratio. In the current CO2 flooding research, people mainly focus on the improvement of the recovery factor, and less attention is paid to the underground storage of CO2. In order to further study the relationship between the displacement efficiency of CO2 and the storage situation, this paper innovatively combines the storage ratio and storage amount of CO2 with the recovery factor. A number of parameters under different injection methods in the study area were calculated, providing a new research angle for the study of CO2 displacement. Take Chang 8 reservoir in Block H of Ordos Basin as an example. Firstly, the minimum miscibility pressure (MMP) of CO2 at formation temperature was measured by the slim tube experiment according to the reservoir pressure status to judge the CO2 flooding status in the study area. Then, the numerical simulation model of the study area was established, and the historical fitting was completed according to the existing CO2 flooding test wells. The reservoir numerical simulation is used to study the recovery ratio and CO2 storage ratio under different CO2 miscible flooding, including different injection rates, injection sequences, and bottom hole pressures. The results show that the MMP of CO2 in the study area is between 12.65 and 14.80 MPa, which means the CO2 flooding state in this area is miscible flooding with high oil displacement efficiency. The CO2 storage ratio at 5–40 t/d CO2 injection rate is between 54.02% and 64.38% after 20 years, and the CO2 storage ratio is larger when the gas injection rate is 10 t/d. In combination with CO2 storage capacity and the oil recovery factor, it is recommended that the gas injection rate of a single well in the study area is 20–30 t/d. The CO2 storage ratio after 20 years under different gas injection sequences is 57.69%–61.27%. It is suggested that the study area should be injected with water and gas alternately after 2 years of gas injection. When continuous gas injection is used, the CO2 storage ratio under different production well bottom hole pressures is between 54.95% and 59.82%. It is recommended that the bottom hole flow pressure in the study area be maintained at between 9 and 10 MPa. The results show that the main factor that affects the annual CO2 storage ratio in the study area is the CO2 injection rate. Gas injection rate, injection sequence, and bottom hole pressure of production wells will all have an impact on the overall storage ratio. And alternate water and gas injection is quite significant. From the perspective of storage ratio, the optimal CO2 miscible flooding injection method has been optimized for the study area, which provides a reference for the implementation of CO2 underground storage technology in mines.