CO2 Residual Trapping Research Articles

Zeta Potential of Supercritical CO2‐Water‐Sandstone Systems and Its Correlation With Wettability and Residual Subsurface Trapping of CO2

AbstractAlthough CO2 geological storage (CGS) is thought to be one of the most promising technologies to sequester the anthropogenic CO2 to mitigate the climate change, implementation of the method is still challenging due to lack of fundamental understanding of controls of wettability, which is responsible for residual trapping of the gas and its flow dynamics. One of the key parameters that controls the wetting state is the zeta potential, ζ, at rock‐water and CO2‐water interfaces. ζ in systems comprising rocks, carbonated aqueous solutions and immiscible supercritical CO2 have not been measured prior to this study, where we detail the experimental protocol that enables measuring ζ in such systems, and report novel experimental data on the multi‐phase ζ. We also demonstrate for the first time that ζ of supercritical CO2‐water interface is negative with a magnitude greater that 14 mV. Moreover, our experimental results suggest that presence of multi‐valent cations in tested solutions causes a shift of wettability toward intermediate‐wet state. We introduce a new parameter that combines multi‐phase ζ and relative permeability endpoints to characterize the wetting state and residual supercritical CO2 saturation. Based on these results, we demonstrate that ζ measurements could serve as a powerful experimental method for predicting CGS efficiency and/or for designing injection of aqueous solutions with bespoke composition prior to implementing CGS to improve the residual CO2 trapping in sandstone formations.

A pore-network modeling perspective on the dynamics of residual trapping in geological carbon storage

This study presents the application of an efficient and robust Dynamic Pore-Network Modeling (DPNM) framework for accurate prediction of carbon dioxide (CO2) trapping behavior under the dynamic flow conditions prevalent in subsurface applications. Residual trapping of CO2 is crucial in the context of geological sequestration, serving as a constitutive relationship that controls relative permeability hysteresis and thereby determining the magnitude of CO2 trapping within formations over varying timescales. Utilizing our DPNM framework, we study the complexities of residual trapping in miniature-core-sized digital replicate of a sandstone. We systematically conduct series of two-phase flow simulations to examine the relationships between total residual CO2 amount, trapping efficiency, and initial saturations across a spectrum of capillary numbers and wettability states. Dynamic simulation results lead to a simple power-law scaling equation correlating CO2 trapping efficiency with initial saturation across various capillary numbers. Further analysis explores the morphological and topological characteristics of fluids during primary drainage and various imbibition displacements within the pore network. This work contributes an essential tool and deepens our understanding of CO2 trapping dynamics, driving progress towards more effective and safer strategies for carbon capture and storage.

Microscopic characteristics of CO2 residual trapping in saline aquifers: Experimental study based on X-ray microtomography

The occurrence form and migration characteristics of CO2 in pores have a direct impact on CO2 residual trapping and the safety of CO2 sequestration. In this work, we conduct core flooding and CT scanning experiments at different permeabilities, brine salinities, and sodium dodecyl sulfate (SDS) concentrations. We measure the CO2-brine-rock contact angles in situ and quantitatively analyze the microscopic characteristics of CO2 residual trapping in the pores. The experimental results indicate that CO2 primarily occurs in the form of network, cluster, and droplet. The efficiency of CO2 residual trapping is closely linked to the pore structure, with a higher permeability resulting in less effective trapping. Furthermore, an increase in salinity weakens the hydrophilicity of the sandstone, while the addition of SDS enhances it. The higher the SDS concentration, the greater the sandstone hydrophilicity. When the sandstone hydrophilicity is enhanced, the efficiency of CO2 residual trapping also increases. Additionally, a low permeability, low salinity, and high SDS concentration all result in 20%–35% increase in the frequency of CO2 network formed in the pores, which is advantageous for CO2 residual trapping. These findings clarify the possible occurrence forms of gaseous CO2 in the pores and their variations under different conditions and are also expected to help establish methods for improving CO2 residual trapping efficiency to enhance the long-term safety of CO2 sequestration in shallow saline aquifers.

Evolution of CO2 Storage Mechanisms in Low-Permeability Tight Sandstone Reservoirs

Understanding the storage mechanisms in CO2 flooding is crucial, as many carbon capture, utilization, and storage (CCUS) projects are related to enhanced oil recovery (EOR). CO2 storage in reservoirs across large timescales undergoes the two storage stages of oil displacement and well shut-in, which cover multiple replacement processes of injection–production synchronization, injection only with no production, and injection–production stoppage. Because the controlling mechanism of CO2 storage in different stages is unknown, the evolution of CO2 storage mechanisms over large timescales is not understood. A mathematical model for the evaluation of CO2 storage, including stratigraphic, residual, solubility, and mineral trapping in low-permeability tight sandstone reservoirs, was established using experimental and theoretical analyses. Based on a detailed geological model of the Huaziping oilfield, calibrated with reservoir permeability and fracture characteristic parameters obtained from well test results, a dynamic simulation of CO2 storage for the entire reservoir life cycle under two scenarios of continuous injection and water–gas alternation were considered. The results show that CO2 storage exhibits the significant stage characteristics of complete storage, dynamic storage, and stable storage. The CO2 storage capacity and storage rate under the continuous gas injection scenario (scenario 1) were 6.34 × 104 t and 61%, while those under the water–gas alternation scenario (scenario 2) were 4.62 × 104 t and 46%. The proportions of storage capacity under scenarios 1 and 2 for structural or stratigraphic, residual, solubility, and mineral trapping were 33.36%, 33.96%, 32.43%, and 0.25%; and 15.09%, 38.65%, 45.77%, and 0.49%, respectively. The evolution of the CO2 storage mechanism showed an overall trend: stratigraphic and residual trapping first increased and then decreased, whereas solubility trapping gradually decreased, and mineral trapping continuously increased. Based on these results, an evolution diagram of the CO2 storage mechanism of low-permeability tight sandstone reservoirs across large timescales was established.

Exploring in-situ combustion effects on reservoir properties of heavy oil carbonate reservoir

Laboratory modeling of in-situ combustion is crucial for understanding the potential success of field trials in thermal enhanced oil recovery (EOR) and is a vital precursor to scaling the technology for field applications. The high combustion temperatures, reaching up to 480 °C, induce significant petrophysical alterations of the rock, an often overlooked aspect in thermal EOR projects. Quantifying these changes is essential for potentially repurposing thermally treated, depleted reservoirs for CO2 storage.In this study, we depart from conventional combustion experiments that use crushed core, opting instead to analyze the thermal effects on reservoir properties of carbonate rocks using consolidated samples. This technique maintains the intrinsic porosity and permeability, revealing combustion's impact on porosity and mineralogical alterations, with a comparative analysis of these properties pre- and post-combustion. We characterize porosity and pore geometry evolution using low-field nuclear magnetic resonance, X-ray micro-computed tomography, and low-temperature nitrogen adsorption. Mineral composition of the rock and grain-pore scale alterations are analyzed by scanning electron microscopy and X-ray diffraction.The analysis shows a significant increase in carbonate rocks’ porosity, pore size and mineral alterations, and a transition from mixed-wet to a strongly water-wet state. Total porosity of rock samples increased in average for 15%–20%, and formation of new pores is registered at the scale of 1–30 μm size. High-temperature exposure results in the calcite and dolomite decomposition, calcite dissolution and formation of new minerals—anhydrite and fluorite. Increased microporosity and the shift to strongly water-wet rock state improve the prospects for capillary and residual CO2 trapping with greater capacity. Consequently, these findings highlight the importance of laboratory in-situ combustion modeling on consolidated rock over tests that use crushed core, and indicate that depleted combustion stimulated reservoirs may prove to be viable candidates for CO2 storage.

The effect of methylene blue on stearic acid-aged quartz/CO2/brine wettability: Implications for CO2 geo-storage

Carbon dioxide sequestration in geological formations has been proposed as a promising solution to reach net zero carbon emissions but the success of underground CO2 storage in sandstone formations depends on the brine/CO2 wettability of sandstone. Research evidence showed that natural geological formation is hydrophobic even in the presence of minute concentration of inherent organic acids. This study investigates the effect of methylene blue (MB) on CO2 wettability of organic-acid contaminated quartz through the tilted plate contact angle measurement method. Pure quartz substrates were aged in a stearic acid/n-decane solution for one week and subsequently modified with different concentrations of MB (ranging from 10 to 100 mg/L) at a temperature of 60 °C. Advancing (θa) and receding (θr) contact angles were measured under varying conditions of temperature (25 °C and 50 °C), pressure (ranging from 10 to 20 MPa), and salinity (0–0.3 M). The experimental results indicate that pure quartz, when aged in a stearic acid solution, becomes CO2-wet at all temperature, pressure, and salinity conditions. However, at any physio-thermal condition, the wettability of the quartz surfaces was reversed when treated with different concentrations of MB, transitioning to a water-wet state. The findings of this research demonstrate the potential of MB to modify the wetting behaviour of quartz surfaces and enhance CO2 residual trapping in sandstone formations.

Uncertainty Quantification in CO2 Trapping Mechanisms: A Case Study of PUNQ-S3 Reservoir Model Using Representative Geological Realizations and Unsupervised Machine Learning

Evaluating uncertainty in CO2 injection projections often requires numerous high-resolution geological realizations (GRs) which, although effective, are computationally demanding. This study proposes the use of representative geological realizations (RGRs) as an efficient approach to capture the uncertainty range of the full set while reducing computational costs. A predetermined number of RGRs is selected using an integrated unsupervised machine learning (UML) framework, which includes Euclidean distance measurement, multidimensional scaling (MDS), and a deterministic K-means (DK-means) clustering algorithm. In the context of the intricate 3D aquifer CO2 storage model, PUNQ-S3, these algorithms are utilized. The UML methodology selects five RGRs from a pool of 25 possibilities (20% of the total), taking into account the reservoir quality index (RQI) as a static parameter of the reservoir. To determine the credibility of these RGRs, their simulation results are scrutinized through the application of the Kolmogorov–Smirnov (KS) test, which analyzes the distribution of the output. In this assessment, 40 CO2 injection wells cover the entire reservoir alongside the full set. The end-point simulation results indicate that the CO2 structural, residual, and solubility trapping within the RGRs and full set follow the same distribution. Simulating five RGRs alongside the full set of 25 GRs over 200 years, involving 10 years of CO2 injection, reveals consistently similar trapping distribution patterns, with an average value of Dmax of 0.21 remaining lower than Dcritical (0.66). Using this methodology, computational expenses related to scenario testing and development planning for CO2 storage reservoirs in the presence of geological uncertainties can be substantially reduced.

Unraveling residual trapping for geologic hydrogen storage and production using pore-scale modeling

Residual trapping is an important process that affects the efficiency of cyclic storage and withdrawal and in-situ production of hydrogen in geological media. In this study, we have conducted pore-scale modeling to investigate the effects of pore geometry and injection rate on the occurrence and efficiency of residual trapping via dead-end bypassing. We begin our theoretical and numerical analyses using a single rectangular pore to understand the key controls in bypassing. We further investigated two factors affecting bypassing: (a) a continuous cycle of injection-extraction of H2, and (b) variable pore geometry. Based on our pore-scale simulations, we found that: (a) a higher pore height/width ratio (h/w) and a higher injection rate cause more residual trapping, which is unfavorable for withdrawal of H2; (b) the trapping percentage increases with the h/w first and then decreases after h/w reaches 0.5; (c) and a converging-shaped pore can result in less trapping volume. Based on a theoretical comparison of the residual trapping behavior of H2 and CO2, we discuss the mechanisms that are applicable to CO2 residual trapping and the possibility of developing engineering controls of H2 storage and production.

Influence of carbon nanodots on the Carbonate/CO2/Brine wettability and CO2-Brine interfacial Tension: Implications for CO2 geo-storage

Understanding the interfacial and wettability phenomena of the CO2-brine and rock-CO2-brine system plays a key role in the geo-storage of CO2 and in their security containment. Carbon nanodots (CNDs) have been identified as a promising surface-active agent for altering the wettability from strongly oil-wet into water-wet in the carbonate reservoirs, thus it contributed for the oil recovery increment in the carbonate formations. However, no consideration was given to the application of CNDs for the enhancement of CO2 geological storage and containment security in the carbonate formations. In the current study, we assessed the impact of CNDs on the residual and structural trapping of CO2 in the carbonate reservoir. The contact angles (θ) of the CO2-brine-carbonate rock system were studied before and after the treatment of CNDs for both the clean and crude oil-aged samples. Subsequently, we also investigated the CO2-seawater interfacial tensions (IFT) with and without CNDs addition. All these measurements were performed as a function of CNDs concentration (0–1000 ppm), temperature (20–80 °C) and pressure (14.7–3000 psi). The results showed that the clean carbonate rock remained strongly water-wet before and after CNDs-treatment. The oil-wet carbonate sample was turned into CO2-wet at all investigated temperatures when the pressures increased to 1000 psi, however, it turns to be weakly water-wet upon treatment with CNDs at the highest pressure (3000 psi). Specifically, at 3000 psia and 20 °C, the contact angle of oil-wet carbonate reduced from 122° to 86° with the addition of CNDs at the increased concentration of 1000 ppm. Such wettability modifications in carbonate formations will enhance the efficacy of CO2 storage potential, and eventually, this will help to de-risk their security containment. The θ generally demonstrated a declining trend with the increase of CNDs concentration but it slightly increased with the rise in temperature and pressure. These results suggest that warmer reservoirs and increased storage depth could be unfavorable for CO2 storage in carbonate formations. Thus, the pre-injection of a minimal concentration of CNDs in the formation would improve CO2 storage effectively. Also, no significant change was observed in the CO2-seawater IFT in the presence of CNDs, which indicates that the capillary trapping of CO2 could be favorable due to their lower contact angle and high CO2-brine IFT as the most suitable condition to maintain the high capillarity. The study demonstrates that the highly stable, freely soluble, easy detectable, scalable, and economically viable CNDs has the potency to enhance the containment security of CO2 in carbonate formation.

Residual trapping of CO2, N2, and a CO2-N2 mixture in Indiana limestone using robust NMR coreflooding: Implications for CO2 geological storage

Carbon capture and sequestration (CCS) in geological formations is a prominent solution for reducing anthropogenic carbon emissions and mitigating climate change. The capillary trapping of CO2 is a primary trapping mechanism governed by the pressure difference between the wetting and nonwetting phases in a porous rock, making the latter a key input parameter for dynamic simulation models. During the CCS operational process, however, the CO2 is prone to contamination by impurities from various sources such as surfaces (e.g., pipelines and tanks) and the subsurface (e.g., existing natural gas). Such contamination can strongly influence the overall CO2 wettability, storage capacity, and containment security. Hence, the present study uses the nuclear magnetic resonance (NMR) core flooding technique to investigate and compare the residual saturations of pure CO2, pure N2, and a 50:50 CO2/N2 mixture in an Indiana limestone. The longitudinal and transverse relaxation times (T1 and T2) are measured to examine the displacement process of the pore network, and the trapping mechanism is evaluated at the pore scale as a determinant of the field-scale flow behavior. The NMR T1-T2 and 2D maps are used to observe the fluid configurations in the pore network, and the T1/T2 ratios are used to evaluate the microscopic wettability of the limestone grains by the pore-space fluids following each drainage/imbibition process step. The results indicate substantial residual gas trapping in the rock for the CO2-brine, N2-brine, and CO2/N2-brine systems, corresponding to gas saturations of 25%, 27%, and 26%, respectively. In the CO2-brine system, the intermolecular interplay between the CO2-enriched brine and limestone grains results in a higher T1/T2 ratio and significantly reduces the hydrophilicity of the limestone. Furthermore, the NMR T2 distribution reveals the occurrence of preferential water displacement into the large pores (r > 1 µm) and from the intermediate pores (0.03 µm < r < 1 µm), whereas water remains immobile in the smaller pores (r < 0.03 µm). The insignificant difference in residual trapping saturation between pure CO2 and the CO2-N2 mixture indicates the potential to allow for impurities in the CO2 phase in CCS without reducing the residual trapping capacity. Thus, the present work provides comprehensive information on the impact of gas injection on residual gas trapping in subsurface geological formations at the pore scale, thereby aiding in the development of CCS and other potential applications in enhanced oil recovery (EOR).

Pore‐Scale Determination of Residual Gas Remobilization and Critical Saturation in Geological CO2 Storage: A Pore‐Network Modeling Approach

AbstractRemobilization of residually trapped CO2 can occur under pressure depletion, caused by any sort of leakage, brine extraction for pressure maintenance purposes, or simply by near wellbore pressure dissipation once CO2 injection has ceased. This phenomenon affects the long‐term stability of CO2 residual trapping and should therefore be considered for an accurate assessment of CO2 storage security. In this study, pore‐network modeling is performed to understand the relevant physics of remobilization. Gas remobilization occurs at a higher gas saturation than the residual saturation, the so‐called critical saturation; the difference is called the mobilization saturation, a parameter that is a function of the network properties and the mechanisms involved. Regardless of the network type and properties, Ostwald ripening tends to slightly increase the mobilization saturation, thereby enhancing the security of residual trapping. Moreover, significant hysteresis and reduction in gas relative permeability is observed, implying slow reconnection of the trapped gas clusters. These observations are safety enhancing features, due to which the remobilization of residual CO2 is delayed. The results, consistent with our previous analysis of the field‐scale Heletz experiments, have important implications for underground gas and CO2 storage. In the context of CO2 storage, they provide important insights into the fate of residual trapping in both the short and long term.

The influence of irreducible water for enhancing CH4 recovery in combination of CO2 storage with CO2 injection in gas reservoirs

CO2 flooding to enhance gas recovery (CO2-EGR) with CO2 storage offers the prospects of significant environmental and economic benefits by increasing CH4 recovery while simultaneously storing CO2. Most studies ignored the interaction of water with CO2 and the formation rocks and the influence of irreducible water to enhance CH4 recovery combined with CO2 storage were poorly understood by core-flooding experiments. In this research, a numerical model of a five-spot well pattern was developed by benchmarking against the existing literature, and the model was further modified to investigate the effects of irreducible water on CO2-EGR and CO2 storage in gas reservoirs. The injected CO2 preferentially moved horizontally and gradually flowed vertically to flood CH4, making the displacement front an inclined CO2-CH4 mixing zone. The model with irreducible water changed from 0% to 40%, the CO2 sweep efficiency improved and the CH4 recovery increased by 4.37%. This could be attributed to the narrowing of the CO2-CH4 mixing zone and the change in displacement front from an inclined horizontal plane to a near arc plane with better stability. The cumulatively stored CO2 decreased by 21.24%, due to the early CO2 breakthrough and shut-in times. However, because more CO2 was dissolved in water and trapped in residual gas, the contribution of CO2 solubility trapping and CO2 residual trapping increased by 12.01% and 10.34% respectively, while CO2 structural trapping decreased by 22.86%, resulting in a significant increase in long-term storage security. Mineral reactions had a negligible influence on CO2-EGR and CO2 sequestration in the CO2 flooding process. The higher the salinity, the lower the amount of dissolved CO2, and the lower the CH4 recovery and cumulatively stored CO2, with decreased security of CO2 storage with limited impact. The higher the irreducible water saturation (Swi), the more CO2 dissolved, and the CH4 recovery and long-term storage security of CO2 improved with a reduction of cumulatively stored CO2. Changing the gas relative permeability (Krg) has a small effect for CH4 recovery and CO2 storage. This research may provide new insights into analyzing the mechanism of irreducible water on the influence of CO2-EGR and CO2 storage, laying a foundation for the optimization of CO2-EGR schemes and the implementation of field applications in water-bearing gas reservoirs with CO2 injection in the future.

Wettability variation and its impact on CO2 storage capacity at the Wyoming CarbonSAFE storage hub: An experimental approach

Meeting global and national net zero carbon emission targets will require geologic carbon disposal. The U.S. Department of Energy (DOE) has accordingly funded significant research in this area, including the Wyoming CarbonSAFE project at Dry Fork Station (DFS) in Campbell County, Wyoming. This work studied wettability on micro- and macro-scales, CO2 storage potential, and the correlation between the two to support the Wyoming CarbonSAFE project’s subsurface assessment. During the study, a target formation’s wettability was found to affect how much CO2 can be stored in a given formation.In this study, representative rock samples were selected from the target storage formations— Lakota, Hulett, and Minnelusa—based on the heterogeneity of the lithology, permeability, and porosity of the respective formations. The rock samples are all fine-grained sandstone with variable cementation and bedding structure, including different scales of laminated bedding. The porosity and permeability vary within the range of 9.0–14.3% and 0.1–28.9 mD, respectively. These rock samples were prepared for the micro-scale wettability (contact angle measurement), macro-scale wettability (wettability index derived from unsteady-state flow characterization for the core plugs), and CO2 storage evaluation. The macro-scale experiments suggested that wettability appeared to dominate the CO2 storage potential performance during the drainage process, where less water-wet behavior promoted higher CO2 storage potential. The micro-scale wettability tests showed that the rock samples at the studied reservoir conditions behaved water-wet and became more water-wet as pressure increased. This kind of wettability change discourages further CO2 storage potential yet benefits the CO2 residual trapping as the CO2 injection proceeds for the studied area. The results allow the recommendation of the best reservoir candidate for storage based on wettability that affects CO2 storage. The work presented in this study provides valuable insights into wettability’s effect on the CO2 storage capacity and wettability’s importance when identifying the optimal CO2 storage formation to meet the project’s goals.

Effect of Organic Acids on CO2 Trapping in Carbonate Geological Formations: Pore-Scale Observations Using NMR

Stearic acid is an example of a carboxylic compound naturally present in geological formations (deep saline aquifers and depleted hydrocarbon reservoirs), which renders the rock hydrophobic (CO2-wet) over a geological time scale. Such hydrophobic surfaces are detrimental to residual CO2 trapping. There is, however, a lack of comprehensive dataset about how traces of these organic molecules affect the rock′s CO2 wettability and residual CO2 trapping. We, thus, used in situ NMR T1–T2 2D images to visualize fluid configurations in the pore network and used T1/T2 ratios to assess the microscopic wettability of the rock to pore space fluids subsequent to each process step. The T2 relaxation time was measured to demonstrate displacement processes and evaluate the trapping behavior at the pore scale, which is closely correlated to reservoir-scale flow functions. The trapping in the CO2-wet sample (14%) was significantly lower than that of the analogous water-wet sample (18%). This reduction in CO2 trapping is due to surface macroscopic flow layers acting as conduits allowing slow desaturation of CO2. Importantly, in the CO2-wet sample, trapping predominately occurred in meso- and micropores, whereas trapping in the analogous water-wet rock primarily occurred in macropores. This work thus provides a comprehensive dataset on the impact of organic acids on residual trapping at the pore scale, which ultimately helps to advance industrial-scale implementation of CGS and EOR project schemes in carbonate reservoirs.

Residual Trapping of CO2 and Enhanced Oil Recovery in Oil-Wet Sandstone Core – A Three-Phase Pore-Scale Analysis Using NMR

HypothesisCombining Carbon Geo-sequestration (CGS) with Enhanced Oil Recovery (EOR) in three-phase flow oil reservoirs is an effective and economically attractive technology to mitigate global warming caused by emission of anthropologic CO2 from fossil fuel combustion, as it offsets some of the costs of CO2 extraction. The targeted oil reservoirs display oil-wet characteristics, primarily because of the strong affinity of polar molecules present in oil; a mixture of a large number of chemical compounds to the rock's surface; and oil-wet surfaces that drastically reduce storage capacity of geological trapping mechanisms and increase the vertical migration of CO2. Thus, it is essential to characterise the effect of wettability of rock on pore-scale physics in a pore network that dominate three-phase flow, which in turn control overall reservoir‐scale fluid dynamics and; thus, determine residual CO2 trapping and the success of CO2‐EOR projects. ExperimentalTo fully examine this, we present the first in situ NMR T1-T2 2D images and transverse relaxation time (T2) to quantify residual CO2 (capillary) trapping for an oil-wet core at reservoir conditions, representative of virgin oil reservoirs at around 1000-meter depth. We also systematically measure how much additional oil can be produced, where we compared the results with measurements performed on an analogous water-wet core. ResultsThe results show a significant residual CO2 saturation (12%) can be stored, which is similar to the values found in analogue two-phase flow for oil-wet sandstone samples, although some details are different and displacements are significantly complex, and a substantial amount of oil (51%) was recovered. In contrast, results of similar tests conducted on an identical analogous water-wet core show a higher CO2 trapping (20%), where oil production was substantially higher (77%). We have also presented the oil displacement efficiency (η) versus CO2 injection (PV), showing the percentage oil displacement efficiency of water-wet (0.6%) to be significantly higher than that of analogue oil-wet core (0.4%). Interpretation of the findingThese results significantly improve geo-storage integrity; i.e. capacities and containment security, over reservoir-scale implementations, in addition to having a substantial impact on outlining CO2-EOR projects in term of budgets and storage capacities for CO2-EOR and CO2 geo-sequestration.

Impact of wettability and injection rate on CO2 plume migration and trapping capacity: A numerical investigation

Rock wettability at prevailing subsurface conditions plays an important role in the fate of injected CO2 in terms of the trapping capacity and containment security. While several laboratory investigations evidenced the influence of wettability on CO2 storage potential, still the associated field-scale storage capacity predictions received little or no attention and thus remain poorly understood. This is particularly true for sandstone formations where recent evidence has shown a remarkable variability in their wetting behavior e.g. ranging from strongly water-wet to even CO2-wet (in the presence of naturally occurring organic acids). In this work, we perform a series of field-scale numerical simulations to examine the impact of variable sandstone/CO2/brine system wettability on residual and solubility trapping of CO2. Furthermore, the influence of injectivity on the CO2 plume migration behavior and trapping capacity is also analyzed and reported. The results indicate that CO2 plume migration and storage efficiency are a strong function of wettability and injection rate. The water-wet sandstone system demonstrated 42 % higher residual trapping compared to CO2-wet sandstone – suggesting a notable impact. Moreover, 94 % lower mobile CO2 and ∼ 20 % less dissolved CO2 were observed in water-wet sandstones – attributed to strong residual trapping capacity and smaller interfacial brine/CO2 area. An increase in injection duration resulted in a monotonous decrease in residual trapping and an increase in the solubility trapping and plume migration distance. Higher injection rates led to increases in migration distances and trapping capacities.

Role of critical gas saturation in the interpretation of a field scale CO2 injection experiment

Residual trapping of CO2, typically quantified by residual gas saturation (Sgr), is one of the main trapping mechanisms in geological CO2 storage (GCS). An important additional characteristic parameter is critical gas saturation (Sgc). Sgc determines at what saturation the trapped gas remobilizes again if gas saturation increases due to exsolution from the aqueous phase, rather than from further gas injection. In the present study, a pilot-scale CO2 injection experiment carried out at Heletz, Israel, in 2017, is interpreted by taking critical saturation into account. With regards to this experiment, the delayed second arrival peak of the partitioning tracer could not be captured by means of physical models. In this work, the hysteretic relative permeability functions were modified to account for Sgc. The results showed that accounting for the effect of Sgc during the secondary drainage indeed captured the observed delayed peak. The difference between the values of Sgr and Sgc, influenced both the time and peak height of the tracer arrival. To our knowledge this is first time that critical gas saturation has been considered in field scale analyses related to GCS. Accounting for Sgc is relevant where gas saturation during secondary drainage increases due to gas phase expansion or exsolution from the aqueous phase. This will happen in situations where pressure depletion occurs, e.g. due to gas leakage from fracture zones or wells or possibly because of pressure management activities. The findings also have implications for other applications such as underground gas storage as well as for geothermal reservoir management.

Using Direct Numerical Simulation of Pore-Level Events to Improve Pore-Network Models for Prediction of Residual Trapping of CO2

Direct numerical simulation and pore-network modeling are common approaches to study the physics of two-phase flow through natural rocks. For assessment of the long-term performance of geological sequestration of CO2, it is important to model the full drainage-imbibition cycle to provide an accurate estimate of the trapped CO2. While direct numerical simulation using pore geometry from micro-CT rock images accurately models two-phase flow physics, it is computationally prohibitive for large rock volumes. On the other hand, pore-network modeling on networks extracted from micro-CT rock images is computationally efficient but utilizes simplified physics in idealized geometric pore elements. This study uses the lattice-Boltzmann method for direct numerical simulation of CO2-brine flow in idealized pore elements to develop a new set of pore-level flow models for the pore-body filling and snap-off events in pore-network modeling of imbibition. Lattice-Boltzmann simulations are conducted on typical idealized pore-network configurations, and the interface evolution and local capillary pressure are evaluated to develop modified equations of local threshold capillary pressure of pore elements as a function of shape factor and other geometrical parameters. The modified equations are then incorporated into a quasi-static pore-network flow solver. The modified model is applied on extracted pore-network of sandstone samples, and saturation of residual trapped CO2 is computed for a drainage-imbibition cycle. The modified model yields different statistics of pore-level events compared with the original model; in particular, the occurrence of snap-off in pore-throats is reduced resulting in a more frontal displacement pattern along the main injection direction. Compared to the original model, the modified model is in closer agreement with the residual trapped CO2 obtained from core flow experiments and direct numerical simulation.

Residual Co2 Trapping and Enhanced Oil Recovery in Carbonate Reservoirs: Three-Phase Flow Dynamics Examined Via Nmr

Residual Co2 Trapping and Enhanced Oil Recovery in Carbonate Reservoirs: Three-Phase Flow Dynamics Examined Via Nmr

Enhancing CO2 storage capacity and containment security of basaltic formation using silica nanofluids

The affinity of the basalt surfaces towards CO2, quantified as wettability functions, is one of the most important driving factors for CO2 trapping capacity and containment security. SiO2 is a minor constituent, often found in traces in the seawater and formation brine injected or reinjected into the sub-surface formations. This work, thus, evaluates the effect of nano-sized SiO2 (100, 1000, and 2000 mg. L−1) on the wettability of the basalt rock surface in the pressure range of 5-20 MPa. The results from brine/CO2/rock wettability measurements show that SiO2 nanoparticles turn the CO2-wet basalt surface to weakly water-wet upon aging with nanofluids. About 40% reduction in the measured brine contact angle takes place upon treatment of the rock sample with 1000 mg. L−1 nanoparticles. We hypothesize that this change in wettability may facilitate enhanced capillary or residual trapping of CO2 in the basalt formation having adequate porosity and permeability to enhance the basalt CO2 trapping capacity.