Carbon Dioxide Flooding Research Articles

Displacement characteristics of CO2 flooding in extra-high water-cut reservoirs

Carbon dioxide (CO2) flooding is a widely applied recovery method during the tertiary recovery of oil and gas. A high water saturation condition in reservoirs could induce a ‘water shielding’ phenomenon after the injection of CO2. This would prevent contact between the injected gas and the residual oil, restricting the development of the miscible zone. A micro-visual experiment of dead-end models, used to observe the effect of a film of water on the miscibility process, indicates that CO2 can penetrate the water film and come into contact with the residual oil, although the mixing is significantly delayed. However, the dissolution loss of CO2 at high water-cut conditions is not negligible. The oil-water partition coefficient, defined as the ratio of CO2 solubility in an oil-brine/two-phase system, keeps constant for specific reservoir conditions and changes little with an injection gas. The NMR device shows that when CO2 flooding follows water flooding, the residual oil decreases—not only in medium and large pores but also in small and micro pores. At levels of higher water saturation, CO2 displacement is characterized initially by a low oil production rate and high water-cut. After the CO2 breakthrough, the water-cut decreases sharply and the oil production rate increases gradually. The response time of CO2 flooding at high water-cut reservoirs is typically delayed and prolonged. These results were confirmed in a pilot test for CO2 flooding at the P1-1 well group of the Pucheng Oilfield. Observations from this pilot study also suggest that a larger injection gas pore volume available for CO2 injection is required to offset the dissolution loss in high water saturation conditions.

CO2 capture and sequestration in porous media with SiO2 aerogel nanoparticle-stabilized foams

Enhanced oil recovery (EOR) via carbon dioxide (CO2) flooding has been considered an economically feasible method for carbon sequestration. However, due to premature gas channeling that results in escape of a great deal of CO2, the degree of crude oil recovery is low, and the carbon sequestration effect is poor. In this paper, the process of CO2 sequestration was studied from a novel perspective by combining a SiO2 aerogel and a foam for oil displacement to reduce carbon emissions. The CO2 absorption capacities of aerogel nanofluids were tested with different concentrations (0.5–1.0 wt%) and rotational speeds (140–525 r/min). The effects of hindering gas channeling and carbon sequestration in three different flooding modes were evaluated via one-dimensional sandpack flooding experiments. The mechanism for CO2 capture by aerogels in porous media was explored through microscopic visualizations of displacement experiments. The results showed that the CO2 absorption capacity of aerogel nanofluids far exceeded those of water and conventional nanofluids. The CO2 + nanofluid displacement evidently controlled gas channeling and improved CO2 sequestration by forming stable foams, and the final sequestration rate was 60.8%. Moreover, compared with conventional foams, a model was proposed to describe different states of CO2 (dissolved, adsorbed, and free) in aerogel nanoparticle-stabilized foam displacement.

The combined effects of the minimum miscibility pressure and injection rate variations on recovery of co2 flooding in sandstone reservoir

One of the most effective enhanced oil recovery techniques is carbon dioxide (CO2) flooding. It is because of its high oil recovery rate and associated advantage on the environment. CO2 flooding has been broadly used and commercially proven. Depending on the reservoir and operational conditions, it can be implemented either in immiscible or miscible modes. Determining the injection mode depends on the minimum miscibility pressure (MMP). The conventional ways of determining the MMP (slim-tube experiments, supercritical extractor, etc.) are costly and time-consuming. A simulation approach has been deployed to determine the MMP of a synthetic reservoir model using a one-dimension compositional slim-tube model in ECLIPSE300. The MMP was also determined using the group method of data handling (GMDH) and other existing correlations. The MMP determined by slim-tube simulation was ~ 4176 psia. Comparing the MMPs of the correlations to the slim-tube simulation, the correlation by Maklavani et al. (Braz J Pet, 2010) was the most accurate with a mean absolute percentage error (MAPE) of 0.79%. The GDMH and the correlation of Firoozabadi and Khalid had MAPEs of 4.96% and 6.06%, respectively. The GMDH model introduced in this study was not as accurate as the correlation by Maklavani et al. (Braz J Pet, 2010) . The model could be improved, or other machine learning models with improved training and prediction could be deployed to estimate MMP more accurately. A synthetic reservoir model based on literature data was used to investigate the effect of the MMP and injection rate on oil recovery by CO2 flooding. The impact of MMP was investigated by the miscible and immiscible flooding scenarios. The injection rate was varied in each scenario to determine the optimum injection rate. However, the scenarios with optimum injection rates for both miscible and immiscible CO2 injection were compared to a waterflood scenario. The optimum injection rates for miscible and immiscible flooding were 2800 and 2200 Mscf/day, respectively. The oil recovery efficiencies for the optimum miscible and immiscible injection were 48% and 46%, respectively. In this study, miscible flooding proved to be the more effective method in oil recovery. However, considering the difference in oil recovery and the difficulty in achieving miscibility, the immiscible CO2 flooding proves to be the feasible option for improving oil recovery.

Petrophysical changes of carbonate rock related to CO2 injection and sequestration

Efficient carbon dioxide injection and potential effects on injection costs require an understanding of the rock-fluid geochemical interactions during a CO2 storage operation. Dissolution and/or precipitation of minerals during carbon dioxide injection is believed to be the main reason for changes in the formation properties affecting flow and injectivity, particularly within carbonate rock. In this study, we designed four distinct experiments to investigate changes in porous media due to carbon dioxide injection. We used cores with a range of features to conduct core flooding experiments that explored the effect of rock mineralogy and distance from the injection point, as this knowledge is crucial to estimate the success of future storage operations. Qualitative and quantitative measurements such as the XRD, CT scanning, porosity, and permeability, were performed before, during, and after the core floods as a means of studying the effect of carbon dioxide flooding using 55 to 100 pore volumes of throughput. The core floods resulted in a significant increase in permeability (400-fold) and porosity of the sample composed of minerals that were soluble in an acidic environment and a 50% decrease in permeability in the sample composed of acid-insoluble minerals. The most significant changes are the result of forming wormholes through the samples, confirmed by CT scanning, but the details of their formation are more complex than this general statement and are discussed in this paper.

Study on Minimum Miscibility Pressure of CO2–Oil System Based on Gaussian Process Regression and Particle Swarm Optimization Model

Abstract Injecting CO2 into the reservoir can not only improve crude oil recovery but also achieve the goal of CO2 geological storage. It can not only reduce the greenhouse effect but also obtain additional economic benefits. From the perspective of minimum miscible pressure, carbon dioxide flooding can be divided into miscible flooding and immiscible flooding, and miscible flooding is widely used in the oil field. The most important condition for miscible flooding is to achieve the minimum miscible pressure (MMP). In the study, combining the particle swarm optimization (PSO) with Gaussian process regression (GPR), a novel intelligent GPR and particle swarm optimization (GPR-PSO) method was proposed to establish the model of predicting the MMP of the CO2 and oil system. The model uses the database with more data than in the previous literature, with 365 data points, and the value range of the data is also wider. Moreover, the accuracy of GPR-PSO model was evaluated by statistical error and graph error and compared with the prediction results of existing models. The results show that compared with other models, the GPR-PSO model has higher accuracy and wider application range, the mean absolute relative error is only 1.66%. Meanwhile, the reliability of the model is verified by the sensitivity analysis of parameters. The results show that the most influential parameter on the prediction results is the reservoir temperature, and the least influential parameter is the critical temperature of injected gas. The GPR-PSO model can be used not only to predict the MMP of CO2 and oil system but also to predict the MMP of other gases and crude oil system.

Microscopic Oil Displacement Mechanism of CO2 in Low-Permeability Heterogeneous Glutenite Reservoirs in the Junggar Basin.

Carbon dioxide (CO2) flooding is a promising method for developing low-permeability heterogeneous glutenite reservoirs (LPHGRs) featured with low natural energy. Herein, the focus of this work was to study the microscopic oil displacement mechanism of CO2 in LPHGRs. First, the micropore structure and mineral composition of LPHGRs were analyzed, and the effect of CO2 on low-permeability reservoirs was then studied. Also, the mechanism of CO2 displacement in low-permeability reservoirs on a pore scale was analyzed using nuclear magnetic resonance technology in different dimensions. The experimental results showed that the mineral composition of the rock mainly included quartz, feldspar, and clay minerals. The core pores were poorly developed and highly heterogeneous. The clay and other mineral particles produced by the dissolution reaction of rocks and minerals migrated and deposited with formation fluid to damage the reservoir. On the contrary, it also improved the pore structure, increased pore space, and increased reservoir permeability. The miscible interaction between CO2 and crude oil formed a stable displacement front, which enabled crude oil to be well displaced from the macropores and medium pores. However, this interaction generated negligible effects on the small pores. The experimental results provided important indicators for CO2 development in LPHGRs.

Hybrid surfactant-nanoparticles assisted CO2 foam flooding for improved foam stability: A review of principles and applications

Miscible carbon dioxide (CO2) flooding is a well-established and promising enhanced oil recovery (EOR) technique whereby residual oil is recovered by mixing with injected CO2 gas. However, CO2, being very light and less viscous than reservoir crude oil, results in inefficient sweep efficiency. Extensive research is ongoing to improve CO2 mobility control such as the development and generation of CO2/water foams. The long-term stability of foam during the period of flooding is a known issue and must be considered during the design stage of any CO2 foam flooding project. The foam stability can be improved by adding surfactants as stabilizers, but surfactants generated foams have generally a shorter life because of an unstable interface. Furthermore, surfactants are prone to higher retention and chemical degradation in the porous media, particularly under harsh reservoir conditions. Research has shown that nanoparticles (NPs) can act as an excellent stabilizing agent for CO2/water foams owing to their surface chemistry and high adsorption energy. The foams generated using NPs are more stable and provide better mobility control compared to surfactant-stabilized foams. One limitation of using NPs as foam stabilizers is their colloidal stability which limits the use of low-cost NPs. Combining surfactants and NPs for CO2 foam stabilization is a novel approach and has gained interest among researchers in recent years. Surfactants improve the dispersion of NPs in the aqueous phase and minimize particle aggregation. NPs on the other hand create a stable barrier at the CO2/water interface with the help of surfactants, thus generating highly stable and viscous foams. This paper presents a comprehensive review of the basic principles and applications of stabilized CO2 foams. A brief overview of CO2 foam flooding is discussed first, followed by a review of standalone surfactant-stabilized and NPs-stabilized CO2/water foams. The application of hybrid surfactant-NPs stabilized CO2 foams is then presented and areas requiring further investigation are highlighted. This review provides an insight into a novel approach to stabilize CO2/water foams and the effectiveness of the method as proved by various studies.

Experimental evaluation of tight sandstones reservoir flow characteristics under CO2–Brine–Rock multiphase interactions: A case study in the Chang 6 layer, Ordos Basin, China

By the end of 2020, tight oil production accounted for 65% of total U.S. crude oil production (EIA, 2020). Carbon dioxide flooding is widely recognized as an efficient way of developing tight oil reservoirs. The flow characteristics of host rocks may be changed by CO2-Brine-Rock interactions during CO2 injection. It is necessary to reveal the impact of CO2-Brine-Rock interactions on tight oil recovery, which is critical in understanding the fundamental mechanisms of CO2 flooding for enhanced tight oil recovery. However, the flow characteristics alteration behavior and mechanism during CO2 flooding are still unclear. In this study, outcrop sandstone samples from the Chang 6 layer of Triassic Yanchang formation in Ordos Basin were used. First, CO2 solubility in formation water was measured. Then, the corrosion rate due to carbonic acid on rock minerals was evaluated under reservoir conditions. The porosity, pore throat diameter for the movable fluid, liquid permeability, mineral composition and cast thin sections in tight sandstones were compared before and after corrosion. The corrosion was found to have enhanced both porosity and liquid permeability, with liquid permeability exhibiting the highest increment. Pore and throat diameter for movable fluids in tight sandstones decreased after the reaction, implying reduced irreducible water saturation. XRD results showed that calcite, dolomite and feldspar were main corrosion minerals. The corrosion pores significantly increased after corrosion. These findings indicate improved formation petrophysical properties associated with CO2 flooding in tight sandstones. This study provides a theoretical basis for the efficient development of tight oil reservoirs during CO2 flooding.

Carbon Dioxide Flooding Technology for Ultra-Low Permeability Reservoirs to Greatly Enhance oil Recovery

Low-permeability reservoir pressure is difficult to maintain, CO2 miscible flooding is difficult to achieve for low-permeability reservoirs, and near-miscible flooding is a promising technology for enhancing oil recovery for low-permeability reservoirs. Aiming at the complex geological and development characteristics of China’s continental low-permeability reservoirs, the system elaborated Sinopec’s CO2 flooding theory, reservoir engineering optimization design, injection and production engineering and anti-corrosion technology, production CO2 recovery and utilization, and other technical developments and field tests. Happening. Based on the research of CO2 flooding mechanism, this paper takes a well-known oil field H 28 reservoir as the target, and conducts an indoor evaluation of CO2 flooding methods through core physical simulation experiments. The pilot test of CO2 flooding field shows that CO2 flooding can significantly increase the productivity of ultra-low permeability oil wells, improve the development effect of oil wells, and meet the needs of ultra-low permeability reservoir development, and has broad application prospects.

Key geological factors controlling oil displacement efficiency of CO2 injection in low-permeability reservoirs

Carbon dioxide (CO2) flooding is an effective method to enhance oil recovery in low-permeability reservoirs. Studying key geological factors controlling oil displacement efficiency is of great significance to the CO2 injection scheme design in low-permeability reservoirs. Focusing on low-permeable H reservoir in Songliao Basin, China, this paper describes the contact and connection of sand bodies, natural fractures and high-permeability zones with core samples, log data and experiment firstly. After that, the impact of interaction of sand body connection, natural fracture and high-permeability zone on oil displacement efficiency is determined by using geological and dynamic data in CO2 injection area. Results indicate that the connection of single sand bodies between injectors and producters wells primarily controls CO2 flooding in low-permeability reservoirs. Furthermore, coupling of sand body connection, natural fractures and high-permeability zones is the key geological factor governing oil displacement efficiency of CO2 injection in low-permeability reservoirs, where well or generally-connected sand bodies can improve the efficiency significantly. Meanwhile, the dominant seepage channels in other directions have no influence on producers, which is beneficial to improve CO2 flooding efficiency.

A study on the fuzzy evaluation system of carbon dioxide flooding technology

AbstractThe research and application of carbon dioxide (CO2) flooding to improve enhanced oil recovery (EOR) technology has been carried out vigorously all over the world, because it not only helps meet the needs of oilfield development but also solve the problem of carbon sequestration. A comprehensive evaluation of the application of CO2 flooding technology is necessary. In this paper, the maximum membership degree method is used to construct a comprehensive evaluation model to evaluate the CO2 gas injection effect of the P1‐1 well group in the P city reservoir to verify the development effect of CO2 flooding. The factors that affect the effect of CO2 flooding include technology, management, and economic benefits. The final evaluation index system is obtained by decomposing the evaluation factors in the effect of CO2 flooding in the waterdrive petroleum reservoir and combining the relevant literature. The analytic hierarchy process (AHP) method is used to weight CO2 injection evaluation factors in the P1‐1 well group, and the results show that the CO2 flooding development effect is excellent; it is better in terms of the management and economic effect, but the score is not high.

Characterizing Pore-Scale Geochemical Alterations in Eagle Ford and Barnett Shale from Exposure to Hydraulic Fracturing Fluid and CO2/H2O

As demand increases for an affordable energy source that is tied to an environmental obligation to reduce greenhouse gas emissions and water usage, there is a growing consideration in shale production utilizing processes such as (1) enhancing hydrocarbon recovery via carbon dioxide (CO2) flooding, (2) using CO2 as a fracturing agent to minimize water use, and (3) storing CO2 in depleted shale formations to mitigate emissions to the atmosphere. Understanding the geochemical reactions and alterations that occur as shale is exposed to fluids and CO2 is necessary to develop and optimize each of these processes for field applications. Although the majority of shale formations are stimulated using a traditional fracturing fluid, some may be fractured using CO2 or other nontraditional means. We examine the effect the fracturing fluid has on shale and how it behaves with secondary exposure to dry CO2 or CO2-saturated water using in situ Fourier transform infrared (FTIR) spectroscopy, feature relocation scanning electron microscopy (SEM), and surface area and pore size analysis using volumetric gas sorption. These techniques were performed on Eagle Ford and Barnett shale samples that were exposed to the fracturing fluid and unexposed (as received). Shales that have been exposed to the traditional fracturing fluid experienced two reaction fronts. The first reaction front was formed during exposure to the fracturing fluid (pH of ∼1.4). A secondary reaction front was formed as a result of CO2-saturated fluid exposure in the form of carbonic acid (pH ∼ 5.6). These two different reaction mechanisms drove multiple dissolution and precipitation cycles which altered petrophysical properties of the shale and could lead to a significant impact on flow pathways. FTIR spectroscopy showed that equilibration of carbonate dissolution and precipitation cycles could take as long as 35 days. Samples exposed to the fracturing fluid showed significantly less carbonate reactivity compared to those exposed to water. Pore size analysis results indicate that exposure to the fracturing fluid blocked small nanopores (0.7–10 nm) reducing BET surface area and total pore volume. SEM results show barite precipitated heavily during exposure to the fracturing fluid. It appeared that carbonic acid was able to extract sulfur from organic matter to form gypsum evaporites. The mineralogical (barite precipitation and calcite dissolution/precipitation) and pore-scale alterations observed in these samples may lead to enhancement of flow pathways for injected CO2 or produced hydrocarbons.

Review on Pore Structure Characterization and Microscopic Flow Mechanism of CO2 Flooding in Porous Media

Understanding of pore structure and microscopic flow mechanism at pore‐scale is significant for enhancing oil recovery by carbon dioxide (CO2) flooding. Herein, the pore structure characterization and the microscopic flow mechanism of CO2 flooding are analyzed and compared. The pore structure can be captured using experimental analysis, image analysis, and digital core technique. The digital core approach shows broad applications for pore structure characterization as it is reusable and visible. Pore‐scale flow can be directly observed using visual models; however, the pressure and temperature that visual models can withstand need to be improved. Use of X‐ray computed tomography (CT) and nuclear magnetic resonance (NMR) is preferred to monitor the fluid transport and distribution during CO2 displacement in actual cores. The flow in porous media can be also modeled by molecular dynamics (MD) and the lattice Boltzmann method (LBM). The LBM is efficient in simulating multiphase fluid flow in porous media because it achieves parallel computing and can deal with complex boundaries. Herein, detailed analysis for pore structure characterization and of the microscopic flow mechanism of CO2 flooding in porous media is presented, which can further help to design and optimize CO2 flooding schemes to improve oil recovery.

Gas/water foams stabilized with a newly developed anionic surfactant for gas mobility control applications

Carbon dioxide (CO2) flooding is one of the most globally used EOR processes to enhance oil recovery. However, the low gas viscosity and density result in gas channeling and gravity override which lead to poor sweep efficiency. Foam application for mobility control is a promising technology to increase the gas viscosity, lower the mobility and improve the sweep efficiency in the reservoir. Foam is generated in the reservoir by co-injection of surfactant solutions and gas. Although there are many surfactants that can be used for such purpose, their performance with supercritical CO2 (ScCO2) is weak causing poor or loss of mobility control. This experimental study evaluates a newly developed surfactant (CNF) that was introduced for ScCO2 mobility control in comparison with a common foaming agent, anionic alpha olefin sulfonate (AOS) surfactant. Experimental work was divided into three stages: foam static tests, interfacial tension measurements, and foam dynamic tests. Both surfactants were investigated at different conditions. In general, results show that both surfactants are good foaming agents to reduce the mobility of ScCO2 with better performance of CNF surfactant. Shaking tests in the presence of crude oil show that the foam life for CNF extends to more than 24 h but less than that for AOS. Moreover, CNF features lower critical micelle concentration (CMC), higher adsorption, and smaller area/molecule at the liquid–air interface. Furthermore, entering, spreading, and bridging coefficients indicate that CNF surfactant produces very stable foam with light crude oil in both deionized and saline water, whereas AOS was stable only in deionized water. At all conditions for mobility reduction evaluation, CNF exhibits stronger flow resistance, higher foam viscosity, and higher mobility reduction factor than that of AOS surfactant. In addition, CNF and ScCO2 simultaneous injection produced 8.83% higher oil recovery than that of the baseline experiment and 7.87% higher than that of AOS. Pressure drop profiles for foam flooding using CNF was slightly higher than that of AOS indicating that CNF is better in terms of foam–oil tolerance which resulted in higher oil recovery.

СО2-воздействие: из истории мировых и отечественных исследований

СО2-воздействие: из истории мировых и отечественных исследований

Reduced variables method for four-phase equilibrium calculations of hydrocarbon-water-CO2 mixtures at a low temperature

Carbon dioxide (CO2) flooding has been widely applied to enhance oil recovery. In low temperature reservoirs, CO2 injection may result in the formation of three hydrocarbon phases at thermodynamic equilibrium. In addition, an aqueous phase is always present in the reservoir. The aqueous phase can coexist with three hydrocarbon phases to form a four-phase equilibrium system. To evaluate CO2 utilization and storage in these low temperature petroleum reservoirs, a robust and efficient four-phase equilibrium calculation framework involving water is necessary for a compositional reservoir simulator. This is challenging not only because the number of variables increases but also because stability analysis becomes much complicated as the number of phases increases.In this research a novel four-phase equilibrium calculation framework is proposed for compositional reservoir simulation. A reduced variables method is used to solve four-phase flash problems efficiently and robustly. Multiphase flash calculations using reduced variables (RV) can converge to the equilibrium solution faster than formulations using conventional variables (Petitfrere and Nichita, 2015). Secondly, RV does not suffer from numerical problems in the Newton iterations when trace components are present in the aqueous phase. In addition to the implementation of the RV formulation, a systematic procedure consisting of stability analysis and flash calculations is proposed without any prior knowledge of initial K-values. Sets of different initial K-values are appropriately tested in each stability analysis.We performed comprehensive testing using characterized fluids found in the literature in order to validate the robustness of the proposed procedure. The four-phase regions in pressure-composition (Px) space could be accurately identified using our procedure. On the other hand, in some instances mixtures were incorrectly evaluated as three-phase when using existing approaches such as Li and Firoozabadi (2012). Our approach proposed in this paper is a promising four-phase equilibrium calculation framework for compositional reservoir simulation. The procedure achieved excellent robustness and efficiency with minimal modification to the conventional two or three-phase equilibrium calculation framework.

Ionic liquid in stabilizing asphaltenes during miscible CO2 injection in high pressure oil reservoir

The potential of ionic liquids to prevent asphaltene precipitation during miscible Carbon dioxide (CO2) flooding was investigated. Asphaltene dispersion tests were performed to compare the effectiveness of commercial inhibitors and the ionic liquids at ambient conditions. Based on the results 1-Butyl-3-methyl-imidazolium bromide [BMIM][Br], Ionic Liquid was selected and asphaltene onset pressure (AOP) was determined at high-temperature high-pressure conditions through isothermal depressurization experiments in PVT cell. The effect of CO2, organic solvents and [BMIM][Br] on AOP were documented and correlated with nodal pressure analysis of the reservoir/wells.The results show a 21% decrease in AOP compared to the untreated oil and about 46% decrease when 35 mol% of CO2 is solubilized in oil. [BMIM][Br] is seen to have higher activity when injected in solution with isopropanol-n-heptane compared to direct addition. The application of [BMIM][Br]in miscible CO2 flooded reservoir is found to have good potential in inhibiting asphaltene deposition within the reservoir and near wellbore nodal conditions.

Laboratory Study of Ultrasonic Velocity Variations During CO2 Flooding in Tuscaloosa Sandstone

SummarySurface seismic technology offers a promising technique for monitoring carbon dioxide (CO2) flood fronts during the enhanced-oil-recovery (EOR) process. Changes in the seismic signature have been observed with CO2 flooding, but its quantification with respect to subsurface saturation is still in its infancy. This study is focused on quantifying variation in the seismic parameters (velocity and impedance) as a function of subsurface fluid type and saturation.We present results of a laboratory study in which velocity and density were monitored as the pore fluids (formation brine and oil, and CO2) were replaced sequentially. All the experiments were performed at in-situ pressure conditions on core plugs (Tuscaloosa Sandstone) recovered from a well in a field currently undergoing CO2 flooding. These plugs are characterized as fluvial (quartz ≈87%, clay ≈10%) and distributary channels (quartz ≈75%, clay ≈17%).When dry samples were flooded with brine, a decrease in compressional-wave (P-wave) velocity (≈2%) was observed until 95% saturation of brine was achieved. For the remaining 5% of saturation, the velocity increased by 7 to 12.5%. After attaining 100% brine saturation, oil was pumped to displace the brine until irreducible water saturation was achieved. A linear drop of 3 to 4% in velocity to oil saturation was observed during this step. Thereafter, liquid CO2 was injected to displace the oil/brine system and a drop of 5 to 10% in P-wave velocity was observed. Biot-Gassmann modeling shows good agreement with experimental results for the gas/brine and oil/brine systems, but not for liquid-CO2 flooding.An empirical relationship was derived from the experimental results, and was applied to sonic logs and used for sensitivity analysis of 4D-seismic data. Post-flooded sonic data were compared to a theoretical sonic curve estimated from an empirical and ‘patchy’ model. Also, a significant increase in seismic amplitude difference was observed when CO2 saturation was greater than 50%.

Analysis of the Law of Organic Solid Phase Precipitation and Deposition during Carbon Dioxide Displacement Process

Carbon Capture, Utilization and Storage (CCUS) has been regarded as an indispensable, strategic and pressing technology to reduce anthropogenic carbon dioxide emissions, and mitigate the severe consequences of climate change. Its utilization and storage play important roles in this system and they can be applied for oceanic and underground geological sequestration especially for the oil gas reservoir that needs to improve recovery. For the carbon dioxide flooding process, the crude oil displacement generally shows a better performance with the increase of the pressure. However, carbon disposal is always complex. It could encounter organic solid phase precipitation and deposition in near miscibility environment. The law of multiphase and multicomponent diversification in the whole processes is still poorly understood. We thus used the method of slim tube to get dynamic data during the process. Indeed, the interval of near minimum miscibility pressure was determined. Analysis results of injectivity index and productivity index show that the reservoir blockage primarily appears as the displacement pressure is higher than the near minimum miscibility lower limit pressure and plays an important role in the production capacity. Extortionate or low pressure is not conducive to carbon dioxide displacement.

Identification of CO2 sequestration opportunities: CO2 miscible flooding guidelines

Carbon dioxide (CO2) flooding has been demonstrated as an economically feasible technique for carbon capture and storage (CCS) via enhanced oil recovery (EOR). In the oil industry, most of the CO2-EOR projects were implemented in miscible phase (CO2 miscible flooding), and it has become the most productive EOR method in the United States since 2012. Successful implementation of CO2 miscible flooding requires comprehensive guidelines about where CO2 can be applied. With the development of new technology, the suitable conditions for CO2-EOR have changed. Therefore, updating the guidelines for CO2-EOR is necessary. In this study, we updated the guidelines for field CO2 miscible applications in the United States by collecting valuable information from about 100 publications. Significant parameters for CO2 miscible flooding such as minimum miscibility pressure (MMP) and pay zone net thickness were considered for the first time in comparison with existing research studies. After data processing/cleaning, 207 projects have remained in the dataset. Combination plots were created to explore the ranges, distributions, and cumulative frequencies of each property. Meanwhile, descriptive values were calculated based on statistical methods. The guidelines for CO2 miscible flooding were presented with important parameters, including porosity, permeability, depth, reservoir temperature, net thickness, oil saturation, oil gravity, oil viscosity, and MMP. The analyzed results show that the reservoir pressure should be greater than 1020 psi to achieve miscibility, and CO2 miscible flooding project could be successfully applied in a reservoir with an oil gravity greater than 25 °API, oil viscosity less than 4 cp, and a reservoir temperature less than 120 °F.