Simulated CO2 storage efficiency factors for saline formations of various lithologies and depositional environments using new experimental relative permeability data

Haeri, Foad; Myshakin, Evgeniy M.; Sanguinito, Sean; Moore, Johnathan; Crandall, Dustin; Gorecki, Charles D.; Goodman, Angela

doi:10.1016/j.ijggc.2022.103720

Cited by 13 publications

(11 citation statements)

References 44 publications

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“…Relative permeability curves were incorporated into TOUGH3 models, by which volumetric and microscopic storage efficiencies were simulated and then implemented as inputs into CO 2 –SCREEN tool to estimate prospective storage resource and efficiency . The methodology is detailed in Haeri et al and Myshakin et al , Storage efficiency reflects the fraction of the total pore volume filled by CO 2 . Storage efficiency is estimated by Monte Carlo sampling based on individual terms such as volumetric and microscope efficiency .…”

Section: Resultsmentioning

confidence: 99%

CO₂-Soluble Nonionic Surfactants for Enhanced CO₂ Storage via In Situ Foam Generation

et al. 2023

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Geologic carbon storage (GCS) is a rapidly evolving technology with the potential to reduce the environmental impact of fossil fuel usage. Saline aquifers, which comprise a sandstone matrix with brine contained in the pores, make up much of the pore space available for CO2 storage in the United States. When CO2 is injected in saline aquifers, however, capillary fingering occurs, and only a small percentage of the pore space is filled with CO2. This fingering effect is due to the low viscosity of CO2, which is roughly ten times less viscous than brine. To address this problem, we tested the ability of inexpensive, commercially available nonionic surfactants to be dissolved in injected CO2 and increase the apparent viscosity of CO2 by generating CO2-in-water foams in situ. We focused our study on nonionic tridecyl ethoxylate surfactants with the number of ethoxylate groups ranging from 11 to 18 (TDA-11, TDA-13, TDA-15, TDA-18). These surfactants exhibited sufficient CO2-solubility and were shown to reduce the CO2-brine interfacial tension (IFT), stabilize bulk CO2-in-brine foams, and reduce the mobility of CO2 during core floods of CO2 in brine-saturated Berea sandstone. The surfactants did not alter the wettability of the Berea sandstone. Modeling results showed that in a reservoir field injection scenario, the presence of TDA-11 (0.1 wt %) increased both the CO2 storage resource and storage efficiency by 17%. Simulations also showed that the lateral extension area of the plume was reduced by 23% and that CO2 saturation within the plume increased by 26%.

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Section: Resultsmentioning

confidence: 99%

CO₂-Soluble Nonionic Surfactants for Enhanced CO₂ Storage via In Situ Foam Generation

et al. 2023

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“…Table 2 shows that if the commercial-scale storage project only targets a single formation, only the Arbuckle formation seems to demonstrate sufficient prospective CO2 storage resource, regardless of the geological realization variations in the CO2 storage efficiency [37]. In other words, CO2 injection into the stacked sequence of the three formations is necessary to maximize the potential use of pore spaces present in the Viola and Osage formation.…”

Section: Large Prospective Co2 Storage Resource and High Injectivitymentioning

confidence: 99%

Spatiotemporal modeling of basin-scale pressure buildup from proximal commercial-scale CO 2 storage in stacked sequence of saline formations

Wijaya,

Morgan,

Vikara

et al. 2024

Preprint

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Commercial scale decarbonization through carbon capture and storage may likely involve many CO2 storage projects located in close proximity. The close proximity could raise concerns over caprock integrity associated with reservoir pressure buildup and interference among adjacent projects. Commercial-scale injection will also require large prospective CO2 storage resource and high injectivity in the targeted storage formations. To accommodate the need for both large resource and high injectivity, project operators could consider injecting CO2 into a stacked sequence of formations. This analysis investigates the benefits of injecting CO2 into a vertically stacked sequence of saline formations, over injecting the same amount of CO2 into a single saline formation, in addressing these challenges. Our analysis shows that injecting into the stacked sequence mitigates the extent of pressure buildup among the stacked formations, while still achieving the same or greater target CO2 storage volumes. Among cases modeled, the resulting pressure buildup front is most reduced when each storage site distributes injection volumes over several wells, each of which injects a portion of the total CO2 mass across the stacked sequence. This favorable case not only results in the smallest CO2 aerial footprint, but also shows the largest reduction in the pressure buildup at the top of perforation at the injection wells (upwards of approximately 46% compared to the single-formation storage), the result of which is crucial to maintain caprock integrity. This analysis provides insights into required decision-making when considering multi-project deployment in a shared basin.

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“…The relative permeability curve of miscible flooding is determined by interfacial tension interpolation. The interpolation equations are shown in equations ( 1)- (3). The values of the 1-D model parameters are shown in Table 3.…”

Section: Slim Tube Experimentsmentioning

confidence: 99%

“…As reservoir exploration continues, the proportion of conventional medium and highpermeability reservoir reserves is gradually decreasing, while the discovery of low-permeability reservoir reserves is steadily increasing [1][2][3][4]. In comparison to water flooding, carbon dioxide (CO2) possesses a lower density and viscosity, enabling it to penetrate even the tiny pores and consequently improving the micro-sweep coefficient [5][6][7].…”

Section: Introductionmentioning

confidence: 99%

Front Movement and Sweeping Rules of CO2 Flooding under Different Oil Displacement Patterns

Qi,

Zhou,

Lyu

et al. 2023

Preprint

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CO2 flooding stands as a pivotal technique for significantly enhancing oil recovery in low-permeability reservoirs. The movement and sweeping rules at the front of CO2 flooding play a critical role in its oil recovery, yet a comprehensive quantitative analysis remains an area in need of refinement. In this study, we have developed 1D and 2D numerical simulation models to explore the sweeping behavior of miscible, immiscible, and partly-miscible CO2 flooding patterns. The front position and movement rules of the three CO2 flooding patterns are determined. A novel approach of the contour area calculation method is introduced to quantitatively characterize the sweep coefficients, and the sweeping rules are discussed regarding geological parameters, oil viscosity, and injection-production parameters. Furthermore, the Random Forest (RF) algorithm is employed to identify the controlling factor of the sweep coefficient, as determined by out-of-bag (OOB) data displacement analysis. The results show that the miscible front is located at the point of maximum CO2 content in the oil phase. The immiscible front occurs at the point of maximum interfacial tension near the production well. Remarkably, the immiscible front moves at a faster rate compared to the miscible front. Geological parameters, including porosity, permeability, and reservoir thickness, significantly impact the gravity segregation effect, thereby influencing the CO2 sweep coefficient. Immiscible flooding exhibits the highest degree of gravity segregation, with a maximum gravity segregation degree (GSD) reaching 78.1. The permeability ratio is a crucial factor, with a lower limit of approximately 5.0 for reservoirs suitable for CO2 flooding. Injection-production parameters also play a pivotal role in sweep coefficient. Decreased well spacing and increased gas injection rates are found to enhance sweep coefficients by suppressing gravity segregation. Additionally, higher gas injection rates can improve the miscibility degree of partly-miscible flooding from 0.69 to 1.0. Oil viscosity proves to be a significant factor influencing the sweep coefficients, with high seepage resistance due to increasing oil viscosity dominating the miscible and partly-miscible flooding patterns. Conversely, gravity segregation primarily governs the sweep coefficient in immiscible flooding. In terms of controlling factors, the permeability ratio emerges as a paramount influence, with a factor importance value (FI) reaching 1.04. these results provide a theoretical foundation for the application of CO2 flooding, enhancing the understanding of the critical factors governing its success.

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Simulated CO2 storage efficiency factors for saline formations of various lithologies and depositional environments using new experimental relative permeability data

Cited by 13 publications

References 44 publications

CO₂-Soluble Nonionic Surfactants for Enhanced CO₂ Storage via In Situ Foam Generation

CO₂-Soluble Nonionic Surfactants for Enhanced CO₂ Storage via In Situ Foam Generation

Spatiotemporal modeling of basin-scale pressure buildup from proximal commercial-scale CO 2 storage in stacked sequence of saline formations

Front Movement and Sweeping Rules of CO2 Flooding under Different Oil Displacement Patterns

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Simulated CO2 storage efficiency factors for saline formations of various lithologies and depositional environments using new experimental relative permeability data

Cited by 13 publications

References 44 publications

CO2-Soluble Nonionic Surfactants for Enhanced CO2 Storage via In Situ Foam Generation

CO2-Soluble Nonionic Surfactants for Enhanced CO2 Storage via In Situ Foam Generation

Spatiotemporal modeling of basin-scale pressure buildup from proximal commercial-scale CO 2 storage in stacked sequence of saline formations

Front Movement and Sweeping Rules of CO2 Flooding under Different Oil Displacement Patterns

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Product

Resources

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CO₂-Soluble Nonionic Surfactants for Enhanced CO₂ Storage via In Situ Foam Generation

CO₂-Soluble Nonionic Surfactants for Enhanced CO₂ Storage via In Situ Foam Generation