CO2 Injection Rate Research Articles

Determining the Starting Time of CO2 Injection and Its Implications for the CO2-ECBM Process.

Determining the starting time of the CO2 injection is the key factor affecting the effect of CO2 injection and CH4 production. This study uses the Panyidong mine in the Huainan mining area as an example. First, fully coupled mathematical models are established. Second, the evolution law of the reservoir parameters under different starting times of CO2 injection is visualized. Then, the starting time of the CO2 injection is determined, and the transformation process of CH4 displaced by CO2 is discussed. Finally, the connotation of the continuous fluid process during the CO2-ECBM process is analyzed, and constructive suggestions for CO2 injection are presented. The results show that during the CO2-ECBM process, the reservoir pressure and gas content greatly change near the CO2 injection well, and gradually decrease near the CH4 production well. The competitive adsorption of the gas is exothermic, and the reservoir temperature gradually increases. The competitive adsorption of gas causes matrix expansion, which results in a decrease in permeability. The CH4 production rate can be increased by about 2 times, and the evolution law of the CO2 injection rate shows little difference. If the purpose of CO2 injection is to store CO2, the start time of CO2 injection may be set as the 2000th day. The CO2-ECBM process can be divided into three stages to characterize the importance of displacement and replacement effects in each stage. Determining the starting time of CO2 injection and giving more desorption time to CH4 is conducive to the expansion of pore and fracture spaces, and then gives more competitive adsorption time to gas. This study can promote the engineering implementation of the CO2-ECBM technology.

Design of CO2 Huff-n-Puff Parameters for Fractured Tight Oil Reservoirs Considering Geomechanical Effects

CO2-Huff-n-Puff (CO2-HnP) is an effective method for improving oil recovery in conventional reservoirs and has been widely applied to tight oil reservoirs. Recently, there has been a series of studies published on the oil increase mechanism and huff-n-puff parameter optimization of CO2-HnP. However, the understanding of the influence of fracture characterization, threshold pressure gradient (TPG), and geomechanical effects on CO2-HnP in fractured tight oil reservoirs is still limited. In this paper, a numerical model based on the embedded discrete fracture model (EDFM) was constructed to investigate the impact of TPG and geomechanical effects on cumulative oil production (COP). The effects of various huff-n-puff parameters, including bottomhole pressure, oil recovery rate, total CO2 injection amount, number of huff-n-puff cycles, timing of production transfer injection, production time, injection time, CO2 injection rate, and soaking time on the COP and oil replacement ratio were also explored in the paper. The results include the following: (1) The TPG and geomechanical effects led to significantly reduced COP. (2) A positive correlation with COP was found for parameters such as timing of production transfer injection and production time, while negative correlations were found for cycles, soaking time, and injection rate. For oil replacement ratio, soaking time and injection rate were positively correlated, while CO2 injection amount and number of cycles showed negative correlation. (3) With a constant injection volume, it is crucial to avoid an excessive number of cycles that reduce COP. On the basis of this parameter optimization, the oil replacement ratio can be enhanced by advancing the production transfer injection, shortening the injection time, and extending the soaking time. The findings can help optimize CO2-HnP strategies to improve oil recovery and economic benefits from the reservoir. This paper provides an effective numerical simulation method for CO2-HnP in fractured tight oil reservoirs, which has certain reference value.

Experimental study on CO2 flooding within a fractured low-permeability reservoir: Impact of high injection rate

The rapid decay of reservoir energy in the late development of fractured low-permeability reservoir leads to poor development benefit. Injecting CO2 into such reservoir at high pressure and rate can rapidly replenish reservoir energy and fully utilize the advantages of CO2 flooding, which is an efficient approach for CCUS-EOR. Previous laboratory studies have mainly been conducted under conventional low injection rate, with little discussion on the impact of high injection rate (above 20 times the conventional low injection rate) on CO2 flooding, especially regarding the limited reports on the effect of high injection rate on CO2 flooding within a fractured low-permeability reservoir. In this paper, microscopic visualization and fractured-core experiments of CO2 flooding at different injection rates were conducted. The variations in microscopic displacement front and sweep characteristics under different injection rates were clarified. The influence of CO2 injection rate on the macroscopic and pore scale oil production characteristics in fractured low-permeability cores under different injection modes were analyzed. The results indicate that injection rate significantly influences the microscopic displacement characteristics. The final sweep coefficient at 10 μL/min was 25.07 %, and the pre-breakthrough sweep coefficient accounted for approximately 90 %. While for 200 μL/min, the final sweep coefficient was 34.83 %, and the post-breakthrough sweep coefficient accounted for above 50 %. During CO2 flooding in fractured low-permeability core, the oil production before CO2 channeling dominates the final oil recovery. Compared to 0.1 mL·min−1, oil recovery increases by above 20 % at a CO2 injection rate of 4 mL·min−1 at 6 PV. The high-pressure gradient formed by high injection rate enhances CO2 diffusion, promoting the oil mobilization in near-fracture and deep matrix. And it results to a decrease in the minimum pore scale of oil mobilization. Soaking enhances the interaction between CO2 and oil as well as the fluid exchange between fracture and matrix. It further reduces the minimum pore scale of oil mobilization, and the enhancing effect of soaking gradually strengthens with increasing injection rate. The results can provide theoretical reference for application of CO2 flooding within a fractured low-permeability reservoir.

Committee machine learning: A breakthrough in the precise prediction of CO2 storage mass and oil production volumes in unconventional reservoirs

Accurate prediction of CO2 storage mass and cumulative oil production is critical in the context of combining subsurface carbon capture with enhanced oil recovery (CCS-EOR). This study introduces a novel committee machine-learning Gaussian Process Regression (CML-GPR) model, which integrates three well-established machine-learning algorithms—Random Forest (RF), Multi-Layer Extreme Learning Machine (MELM), and Generalized Regression Neural Network (GRNN). The combination of these models leverages the strengths of each algorithm: RF captures nonlinear relationships, MELM enhances computational efficiency, and GRNN provides smooth, generalized predictions. By integrating these complementary techniques, the CML-GPR model demonstrates significant improvements in predictive accuracy over individual models, addressing limitations in their performance. The model predicts CO2 storage mass and cumulative oil production based on nine key reservoir input variables, including depth, porosity, and CO2 injection rate, among others. Utilizing a large dataset of 21,193 data points from reservoir simulations, a Mahalanobis distance-based outlier detection method further refines the input data quality. The CML-GPR model achieves root mean square error (RMSE) values of 0.49 million metric tons for CO2 storage mass and 13.68 million barrels for cumulative oil production, significantly outperforming individual models. The CML-GPR model provides a robust tool for optimizing CO2 storage capacity and oil recovery, with practical implications for real-world reservoir management, ensuring more efficient and reliable CCS-EOR operations. This study represents a pioneering advancement in predictive modeling, offering valuable insights for optimizing both CO2 storage and enhanced oil recovery in complex reservoirs.

Experimental investigation on fracture propagation in shale fractured by high-temperature carbon dioxide

The productivity of shale reservoirs was significantly enhanced by the high-temperature CO2 fracturing technique. The injection of high-temperature CO2 into the formation induced rock fracture propagation, creating advantageous pathways for fluid flow. In this research, a self-developed in situ high-temperature convective heat simulation experimental apparatus was employed to systematically conduct simulated experiments on high-temperature CO2 fractured shale under different influencing factors. The experimental results demonstrated that the permeability of CO2 increased as the injection temperature increased. The rock fracture pressure was effectively reduced by high-temperature CO2 fractured shale. Higher complexity was observed in fracture propagation, accompanied by a substantial increase in microcracks and branching fractures. The shale fracture pressure increased with increasing triaxial stress and CO2 injection rate. The confining pressure restricted the further propagation of fractures under relatively high stress conditions, thereby reducing the width and density of fractures, lowering the fracture complexity. Nevertheless, the thermal shock effect of the fluid was exacerbated as the injection rate of high-temperature CO2 increased. The initiation of microcracks was facilitated by the intensification of local thermal stress in shale, inducing multiple curved fractures and forming a more complex fracture network. Compared to horizontal bedding shale, the fracture pressure of vertical bedding shale was relatively higher during high-temperature CO2 fracturing. In addition, the geometric morphology of fracture propagation was more complex, characterized by rougher fracture surfaces, leading to a greater improvement in reservoir reconstruction volume. This research contributed to the optimization of CO2 resource utilization, provided experimental evidence for the application of high-temperature convection fracturing technology in in situ shale conversion projects.

Effect of CO2 injection pressure on enhanced coal seam gas extraction

The CO2 displacement of coal seam gas can simultaneously promote gas extraction and CO2 sequestration, with gas injection pressure being a key factor influencing both efficiency and safety. This study examined the impact of varying CO2 injection pressure on gas extraction and sequestration. The findings indicated that higher CO2 injection pressures reduced the gas injection and extraction time costs, increased the equilibrium pressure and coal seam temperature, and decreased carbon sequestration efficiency. As the CO2 injection pressure increased, the CH4 cumulative desorption capacity and desorption rate rose by 4.98%, the time to reach the residual gas content critical value (TLV of 2 m3/t) shortened by 62.04 min, and the maximum CO2 storage per unit mass of coal increases by 3.6 m3/t. Increasing the injection pressure enhanced gas desorption and CO2 sequestration. A higher CO2 injection pressure resulted in a higher CH4 yield rate and a reduced CO2 injection rate in the later stages. Therefore, it is advisable to reduce the CO2 injection pressure during the low efficiency desorption stage.

Simulation-Based Optimization Workflow of CO2-EOR for Hydraulic Fractured Wells in Wolfcamp A Formation

Hydraulic fracturing has enabled production from unconventional reservoirs in the U.S., but production rates often decline sharply, limiting recovery factors to under 10%. This study proposes an optimization workflow for the CO2 huff-n-puff process for multistage-fractured horizontal wells in the Wolfcamp A formation in the Delaware Basin. The potential for enhanced oil recovery and CO2 sequestration simultaneously was addressed using a coupled geomechanics–reservoir simulation. Geomechanical properties were derived from a 1D mechanical earth model and integrated into reservoir simulation to replicate hydraulic fracture geometries. The fracture model was validated using a robust production history matching. A fluid phase behavior analysis refined the equation of state, and 1D slim tube simulations determined a minimum miscibility pressure of 4300 psi for CO2 injection. After the primary production phase, various CO2 injection rates were tested from 1 to 25 MMSCFD/well, resulting in incremental oil recovery ranging from 6.3% to 69.3%. Different injection, soaking and production cycles were analyzed to determine the ideal operating condition. The optimal scenario improved cumulative oil recovery by 68.8% while keeping the highest CO2 storage efficiency. The simulation approach proposed by this study provides a comprehensive and systematic workflow for evaluating and optimizing CO2 huff-n-puff in hydraulically fractured wells, enhancing the recovery factor of unconventional reservoirs.

Optimization of Offshore Saline Aquifer CO2 Storage in Smeaheia Using Surrogate Reservoir Models

Machine learning-based Surrogate Reservoir Models (SRMs) can replace/augment multi-physics numerical simulations by replicating the reservoir simulation results with reduced computational effort while maintaining accuracy compared with numerical simulations. This research will demonstrate SRMs’ potential in long-term simulations and optimization of geological carbon storage in a real-world geological setting and address challenges in big data curation and model training. The present study focuses on CO2 storage in the Smeaheia saline aquifer. Two SRMs were created using Deep Neural Networks (DNNs) to predict CO2 saturation and pressure over all grid blocks for 50 years. 18 million samples and 31 features, including reservoir static and dynamic properties, build the input data. Models comprise 3–5 hidden layers with 128–512 units apiece. SRMs showed a runtime improvement of 300 times and an accuracy of 99% compared to the 3D numerical simulator. The genetic algorithm was then employed to determine the optimal rate and duration of CO2 injection, which maximizes the volume of injected CO2 while ensuring storage operations’ safety through constraints. The optimization continued for the reproduction of 100 generations, each containing 100 individuals, without any hyperparameter tuning. Finally, the optimization results confirm the significant potential of Smeaheia for storing 170 Mt CO2.

Optimizing large-scale CO2 pipeline networks using a geospatial splitting approach

CO2 transport infrastructure is the backbone of carbon capture and storage (CCS) technology for the mitigation of carbon emissions and project deployment viability. In conventional large-scale CO2 pipeline network designs, the storage sites are generally assumed as the centroids of the major geologic basins, however, this approach might provide suboptimal solutions since the large extension of some storage formations significantly increases the length of the CO2 transportation networks. To address this situation and obtain optimal pipeline routes, we present a novel geospatial splitting framework that partitions large basins into multiple sub-sinks. In our approach, we used a large number of reservoir models varying petrophysical properties and CO2 injection rates to compute pressure plumes through numerical simulations, leading to the calculation of the number of subregions for each basin as a function of the extension of pressure interference areas and boundaries. Finally, we applied K-means clustering and Voronoi polygon algorithms to partition large basins into subregions and obtain their sink coordinates. To demonstrate the capability of the developed workflow, we investigated two CO2 pipeline network modeling case studies using our splitting approach: one regional case study focusing on the Intermountain West (I-West) region and one nationwide case study covering the lower 48 states in the U.S. In both case studies, we compared the optimal pipeline routes using the original and new storage locations and examined the major differences. The use of the developed geospatial approach resulted in both cases in a shortening of the total pipeline network length by 13% and 10%, compared to the pipeline modeling with the original basins, leading to cost reductions of 25% and 17%, respectively, demonstrating that the location of point sinks has a critical impact on the length and expenses of pipelines to efficiently transport CO2 to distant storage sites. Therefore, the workflow presented here contributes to the proper and realistic modeling of case studies that support decision-making in CCS deployment.

Influence of CO2 injection rate and memory water on depressurization-assisted replacement in natural gas hydrates and the implications for effective CO2 sequestration and CH4 exploitation

This study was conducted to investigate the influence of CO2 injection rate and memory water on guest exchange and hydrate reformation behavior in CH4 hydrate-bearing sediment, using a one-dimensional (1-D) reactor to optimize depressurization-assisted replacement. Increasing the CO2 injection rate facilitated the rapid sweeping of CH4 into the pore space of the hydrate-bearing sediment, inducing immediate hydrate reformation and preventing CH4 re-enclathration in the middle region of the 1-D reactor. Despite dissociating 50 % of the initial CH4 hydrate for depressurization-assisted replacement, the replacement efficiency converged at around 70 % due to drastically reformed gas hydrates hindering mass transfer. Introducing time intervals between depressurization and replacement to reduce the residual memory effect of water led to delayed hydrate reformation, altering the longitudinal distribution of replacement efficiency in the 1-D reactor. An increase in replacement efficiency toward the outlet was seen, suggesting that improved CO2 propagation in the hydrate-bearing sediment resulted in a higher CO2 concentration in the vapor phase at the point of hydrate reformation, in turn enhancing CO2 storage efficiency in the newly formed hydrates. These experimental results highlight the importance of CO2 injection rates and time intervals in determining the hydrate reformation behaviors of hydrate-bearing sediments and optimizing the efficiency of depressurization-assisted replacement.

Carbon dioxide storage and cumulative oil production predictions in unconventional reservoirs applying optimized machine-learning models

To achieve carbon dioxide (CO2) storage through enhanced oil recovery, accurate forecasting of CO2 subsurface storage and cumulative oil production is essential. This study develops hybrid predictive models for the determination of CO2 storage mass and cumulative oil production in unconventional reservoirs. It does so with two multi-layer perceptron neural networks (MLPNN) and a least-squares support vector machine (LSSVM), hybridized with grey wolf optimization (GWO) and/or particle swarm optimization (PSO). Large, simulated datasets were divided into training (70%) and testing (30%) groups, with normalization applied to both groups. Mahalanobis distance identifies/eliminates outliers in the training subset only. A non-dominated sorting genetic algorithm (NSGA-II) combined with LSSVM selected seven influential features from the nine available input parameters: reservoir depth, porosity, permeability, thickness, bottom-hole pressure, area, CO2 injection rate, residual oil saturation to gas flooding, and residual oil saturation to water flooding. Predictive models were developed and tested, with performance evaluated with an overfitting index (OFI), scoring analysis, and partial dependence plots (PDP), during training and independent testing to enhance model focus and effectiveness. The LSSVM-GWO model generated the lowest root mean square error (RMSE) values (0.4052 MMT for CO2 storage and 9.7392 MMbbl for cumulative oil production) in the training group. That trained model also exhibited excellent generalization and minimal overfitting when applied to the testing group (RMSE of 0.6224 MMT for CO2 storage and 12.5143 MMbbl for cumulative oil production). PDP analysis revealed that the input features “area” and “porosity” had the most influence on the LSSVM-GWO model's prediction performance. This paper presents a new hybrid modeling approach that achieves accurate forecasting of CO2 subsurface storage and cumulative oil production. It also establishes a new standard for such forecasting, which can lead to the development of more effective and sustainable solutions for oil recovery.

A workflow for estimating the CO2 injection rate of a vertical well in a notional storage project

A workflow that considers regulatory and technical constraints applicable to subsurface CO2 injection projects was developed to determine fluid injection rates accurately. The constraints considered include, but are not limited to, maximum injection bottomhole pressure, maximum injection pressure at the surface or wellhead pressure, and threshold vibration velocity. The workflow was developed and tested using a reservoir model developed from site characterization data of an Illinois Basin CarbonSAFE Phase II notional storage project. The Nexus® reservoir simulation software suite and the Peng-Robinson equation-of-state were used to perform compositional dynamic simulations. Reservoir modeling results indicated that (1) the regulated and technically feasible CO2 injection rate of a vertical well is predetermined by the most stringent parameter amongst maximum bottomhole pressure, maximum wellhead (surface injection) pressure, and threshold vibration velocity constraints; (2) the threshold vibrational velocity constraint predetermines CO2 injection rate for high-permeability injection zones; and (3) the most stringent constraint for low-permeability injection zones could be either the maximum bottomhole pressure or the maximum wellhead pressure. However, the injection rate may be further reduced if faults or hydraulically conductive fractures are present within the injection zone and adjacent formations because the pressure required to reactivate the faults may be lower than maximum injection bottomhole pressure, maximum wellhead pressure, and vibrational velocity constraints.

Fracture Evolution during CO2 Fracturing in Unconventional Formations: A Simulation Study Using the Phase Field Method

With the introduction of China’s “dual carbon” goals, CO2 is increasingly valued as a resource and is being utilized in unconventional oil and gas development. Its application in fracturing operations shows promising prospects, enabling efficient extraction of oil and gas while facilitating carbon sequestration. The process of reservoir stimulation using CO2 fracturing is complex, involving coupled phenomena such as temperature variations, fluid behavior, and rock mechanics. Currently, numerous scholars have conducted fracturing experiments to explore the mechanisms of supercritical CO2 (SC-CO2)-induced fractures in relatively deep formations. However, there is relatively limited numerical simulation research on the coupling processes involved in CO2 fracturing. Some simulation studies have simplified reservoir and operational parameters, indicating a need for further exploration into the multi-field coupling mechanisms of CO2 fracturing. In this study, a coupled thermo-hydro-mechanical fracturing model considering the CO2 properties and heat transfer characteristics was developed using the phase field method. The multi-field coupling characteristics of hydraulic fracturing with water and SC-CO2 are compared, and the effects of different geological parameters (such as in situ stress) and engineering parameters (such as the injection rate) on fracturing performance in tight reservoirs were investigated. The simulation results validate the conclusion that CO2, especially in its supercritical state, effectively reduces reservoir breakdown pressures and induces relatively complex fractures compared with water fracturing. During CO2 injection, heat transfer between the fluid and rock creates a thermal transition zone near the wellbore, beyond which the reservoir temperature remains relatively unchanged. Larger temperature differentials between the injected CO2 fluid and the formation result in more complicated fracture patterns due to thermal stress effects. With a CO2 injection, the displacement field of the formation deviated asymmetrically and changed abruptly when the fracture formed. As the in situ stress difference increased, the morphology of the SC-CO2-induced fractures tended to become simpler, and conversely, the fracture presented a complicated distribution. Furthermore, with an increasing injection rate of CO2, the fractures exhibited a greater width and extended over longer distances, which are more conducive to reservoir volumetric enhancement. The findings of this study validate the authenticity of previous experimental results, and it analyzed fracture evolution through the multi-field coupling process of CO2 fracturing, thereby enhancing theoretical understanding and laying a foundational basis for the application of this technology.

An Integrated Numerical Study of CO2 Storage in Carbonate Gas Reservoirs with Chemical Interaction between CO2, Brine, and Carbonate Rock Matrix

In light of the burgeoning interest in mitigating anthropogenic CO2 emissions, carbonate reservoirs have emerged as promising sequestration sites due to their substantial storage potentials. However, the complexity of CO2 storage in carbonate reservoirs exceeds that in conventional sandstone reservoirs, predominantly due to the rapid interactions occurring between the injected CO2, brine, and carbonate rock matrix. In this study, a numerical model integrated with the chemical CO2–brine–rock matrix interaction was developed to analyze the carbonate rock dissolution process and the physical property variations of different carbonate gas reservoirs during the CO2 injection and sequestration process. More specifically, a total of twenty scenarios were simulated to examine the effects of lithology, pore size, pore–throat structures, and CO2 injection rate on carbonate rock matrix dissolution and reservoir property variation. Calcite is significantly easier and quicker to react with CO2-solvated brine than dolomite; as a result, limestones exhibit an expedited rock dissolution and pore volume increase, along with a slower pressure buildup in comparison to dolomites. Also, the carbonate reservoir with a smaller pore size has a higher rock dissolution rate than one with a larger pore size. Furthermore, the simulation results show injected CO2 can modify the pore-dominant carbonate reservoir to a more pronounced extent than the fracture-dominant carbonate reservoir. Lastly, the carbonate rock dissolution is more obvious at a lower CO2 injection rate. The insights derived from this research aid evaluations related to CO2 injectivity, storage capacity, and reservoir integrity, thereby paving the way for environmentally and structurally sound carbon sequestration strategies.

A new salt-precipitation-based self-remediation model for CO2 leakage along fault during geological CO2 storage

Salt precipitation occurring in fault zone, due to CO2-brine co-leakage, would create an opportunity to prevent CO2 leakage along fault, i.e., salt-precipitation-based self-remediation model. To investigate the new model, the physical model on salt precipitation was proposed, considering co-leakage of CO2 and brine along fault. Theoretical model was given on salt precipitation, and the numerical model was established to validate the salt precipitation occurring in fault zone. The numerical results indicated that salt precipitation indeed occurred in fault zone, and CO2 leakage rate was obviously decreased after salt precipitation. Importantly, evolution of salt precipitation in fault was concluded, from viewpoint of co-leakage of CO2 and brine along fault, and degree of salt precipitation was characterized, using representative parameters such as the starting time, ending time, lasting time of salt precipitation, and solid saturation. Especially, the self-remediation model for CO2 leakage based on salt precipitation was confirmed feasibly. The self-remediation capacity was closely related to degree of salt precipitation (or lasting time of salt precipitation), and was directly evaluated by the decreasing in CO2 leakage rate before and after salt precipitation. Finally, the parametric analyses showed that: (1) the potential correlation was found among the lasting time of salt precipitation, solid saturation and self-remediation capacity; (2) the higher CO2 injection rate and fault permeability, the smaller fault width and permeability of lower saline aquifer were helpful for salt precipitation and self-remediation capacity; (3) no salt precipitation occurred for the smaller CO2 injection rate and fault permeability, the larger fault width and permeability of lower saline aquifer.

A compositional numerical study of vapor–liquid-adsorbed three-phase equilibrium calculation in a hydraulically fractured shale oil reservoir

The development of carbon capture, utilization, and storage technologies has notably advanced CO2-enhanced oil recovery (EOR) in shale oil reservoirs, which are characterized by abundant nanopores. These nanopores induce unique phase behaviors in hydrocarbons, challenging traditional phase equilibrium calculation methods. This paper presents a novel three-phase thermodynamic model (vapor–liquid-adsorbed three-phase equilibrium calculation) that addresses these challenges by considering the nanopore capillary pressure, critical parameter transitions, and material exchange between the adsorbed and bulk phases. Grounded in the multicomponent Langmuir–Freundlich adsorption equation and the Peng Robinson equation of state, this model is integrated into the MATLAB Reservoir Simulation Toolbox using an embedded discrete fracture model framework, enabling detailed study of CO2 and hydrocarbon phase behaviors within shale oil nanopores. The results reveal that there are significant nano-constrained effects on multicomponent fluid phase behavior, particularly in pores smaller than 20 nm, leading to notable changes in bubble and dew point pressures, as well as critical condensation pressures and temperatures. CO2 injection further complicates the system, enhancing interactions and expanding the coexistence region of the liquid and gas phases on the pressure–temperature diagram, especially across varying pore sizes. Optimization research on CO2 huff and puff technical parameters for shale oil reservoirs suggests the following optimal settings: a CO2 injection rate of 100 t/day, a shut-in time of 30 days, and six huff and puff cycles. The results of this study offer critical insights into CO2-EOR mechanisms in shale oil reservoirs and emphasize the importance of nanopore properties in EOR.

Storing CO2 while strengthening concrete by carbonating its cement in suspension

Cement is a key constituent of concrete and offers a large sequestration potential of carbon dioxide (CO2). However, current concrete carbonation approaches are hindered by low CO2 capture efficiency and high energy consumption, often resulting in weakened concrete. Here, we conceptually develop and experimentally explore a carbonation approach that resorts to injecting CO2 into a cement suspension subsequently used to manufacture concrete, turning the carbonation reaction into an aqueous ionic reaction with a very fast kinetics compared to traditional diffusion-controlled approaches. This approach achieves a CO2 sequestration efficiency of up to 45% and maintains an uncompromised concrete strength. The study shows that the CO2 injection rate influences the polymorph selectivity of mineralized calcium carbonate (CaCO3) depending on the local environmental conditions and impacts the strength of concrete. The technological simplicity of the proposed approach enables a reduced carbon footprint and promising prospects for industrial implementation.

Large-Scale Experimental Investigation of Hydrate-Based Carbon Dioxide Sequestration

Hydrate-based CO2 sequestration is a novel approach that can not only realize permanent CO2 sequestration but can also form an artificial cap to prevent its upward migration. In this work, a self-developed large-scale 3D apparatus was employed to investigate hydrate formation characteristics in hydrate-based CO2 sequestration at a constant liquid CO2 injection rate through a vertical well for the first time. Temperature and pressure evolutions in the sediment were analyzed in detail. Key indicators, including cumulative sequestered CO2, CO2 in hydrate and liquid phases, the instantaneous hydrate conversion, and liquid CO2 retention rates, were calculated. The results show that hydrate continuously forms with increased CO2 injection and exhibits strong heterogeneity due to the variation in hydrate formation rate and quantity. Severe liquid CO2 heterogeneous figuring phenomena occur since hydrate deteriorates the effective pore structure and topology, resulting in relatively small cumulative sequestered CO2 when a large amount of CO2 is released from the outlet. Meanwhile, the instantaneous hydrate conversion and liquid CO2 retention rates have large fluctuations owing to water consumption and variation in the effective contact area between liquid CO2 and water. However, hydrate formation does not cause blockage of wellbore and formation nearby under given experimental conditions, which is beneficial for hydrate formation in deeper sediment. This study provides insights into hydrate formation and liquid CO2 immigration regularity during hydrate-based CO2 sequestration and demonstrates its feasibility at a field scale.

Leakage risk assessment on sealing efficiency of caprock during CO2 huff-n-puff for safe sequestration

CO2 geological sequestration is the most realistic and feasible technology to ensure large-scale carbon emission reduction to achieve the global carbon capping and carbon neutrality goals, and the leakage risk assessment of the sequestration system is the basis of safe sequestration. However, at present, leakage risk assessment mainly focuses on the simulation and research of ultra-long-term (more than 1000 years) storage process, and few scholars has studied the impact of development operations, such as CO2 huff-n-puff, on caprock leakage risk. In this paper, a numerical model of CO2 huff-n-puff that incorporates gas adsorption/desorption, diffusion, and hydrochemical reaction is established, and the leakage risk of caprock during CO2 huff-n-puff in tight reservoir is evaluated. The model's reliability is verified by matching with the production history and CO2 mole fraction of commercial software. Finally, the effects of parameters, including adsorption/desorption, diffusion, hydrochemical reaction, caprock permeability, caprock-to-reservoir thickness ratio, and CO2 injection rate on leakage risk of caprock during CO2 huff-n-puff, are analyzed. The results show that after 15 consecutive cycles of huff-n-puff operations, the escape ratio of CO2 in the caprock is less than 2%, and the injection rate of each cycle is 1 × 105 m3/d for 120 days. It is proved that huff-n-puff operation improves the recovery of tight gas reservoirs and has little effect on the sealing efficiency of caprock sealed for a long time in the later stage. This work provides a theoretical basis for the leakage risk assessment of CO2 geological sequestration after development operations.

Carbon Dioxide Capture under Low-Pressure Low-Temperature Conditions Using Shaped Recycled Fly Ash Particles

Carbon-capture technologies are extremely abundant, yet they have not been applied extensively worldwide due to their high cost and technological complexities. This research studies the ability of polymerized fly ash to capture carbon dioxide (CO2) under low-pressure and low-temperature conditions via physical adsorption. The research also studies the ability to desorb CO2 due to the high demand for CO2 in different industries. The adsorption–desorption hysteresis was measured using infrared-sensor detection apparatus. The impact of the CO2 injection rate for adsorption, helium injection rate for desorption, temperature, and fly ash contact surface area on the adsorption–desorption hysteresis was investigated. The results showed that change in the CO2 injection rate had little impact on the variation in the adsorption capacity; for all CO2 rate experiments, the adsorption reached more than 90% of the total available adsorption sites. Increasing the temperature caused the polymerized fly ash to expand, thus increasing the available adsorption sites, thus increasing the overall adsorption volume. At low helium rates, desorption was extremely lengthy which resulted in a delayed hysteresis response. This is not favorable since it has a negative impact on the adsorption–desorption cyclic rate. Based on the results, the polymerized fly ash proved to have a high CO2 capture capability and thus can be applied for carbon-capture applications.