Effects of Anisotropy and CO<sub>2</sub> Wettability on CO<sub>2</sub> Storage Capacity in Sandstone

Song, Jun Young; Jeong, Yeon Jong; Yun, Tae Sup

doi:https://doi.org/10.1155/2022/5900255

Geofluids

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Abstract Introduction Materials and Methods Results and Discussion Conclusions Data Availability Additional Points Conflicts of Interest Acknowledgments References Copyright Related Articles

Research Article | Open Access

Volume 2022 | Article ID 5900255 | https://doi.org/10.1155/2022/5900255

Effects of Anisotropy and CO₂ Wettability on CO₂ Storage Capacity in Sandstone

Jun Young Song,¹Yeon Jong Jeong,²and Tae Sup Yun³

Academic Editor: Evgeniy M. Myshakin

Received23 Dec 2021

Revised13 Jun 2022

Accepted08 Jul 2022

Published21 Jul 2022

Abstract

The geological sequestration of carbon dioxide (CO₂) is an alternative strategy for mitigating global warming. The CO₂ storage capacity is often characterized by the capillary pressure curve, which in turn depends on the pressure and temperature of the injected CO₂ and the internal structure of the reservoir rocks. The key structural feature that influences the storage capacity in porous rocks is their inherent anisotropy. An experimental study was performed to investigate the optimal conditions for CO₂ injection into an anisotropic sandstone. The capillary pressure curve and the residual CO₂ saturation were determined by injecting three CO₂ phases into the directionally cored sandstone specimens with different flow rates. The CO₂ saturation in sandstone increased with increasing flow rate, resulting in asymptotic values. The storage capacity of CO₂ was the highest in the order of liquid CO₂ (LCO₂), supercritical CO₂ (scCO₂), and gaseous CO₂ (gCO₂). It was also the highest when the direction of CO₂ injection was normal in relation to the embedded sandstone layers. The in situ cored sandstone from the Janggi Basin in Korea was further tested to examine the effect of its pore size on the capillary pressure of CO₂.

1. Introduction

The 2015 Paris Agreement was aimed at reducing CO₂ emission levels by restraining the increase average temperature to 1.5°C and achieving net-zero emissions in the next century [1, 2]. Climate change largely caused by the emission of carbon dioxide (CO₂) has severely impacted ecosystems by shifting seasonal weather patterns, changing territorial range boundaries of many species, and spreading diseases [3]. The geological sequestration of CO₂ (GSC; i.e., storage of captured and pressurized CO₂ in deep saline rock formation covered by the impermeable cap rock) is not only a potential alternative and reliable solution to mitigate climate change [4–7] but has also been applied to increase hydrocarbon production in enhanced oil recovery [8, 9] and geothermal extraction [10, 11]. However, the use of GCS needs to be further examined as it is associated with potential risk of CO₂ leakage, i.e., a discontinuity in the rock structure, deteriorated well integrity, and long-term seismicity [7, 12–15]. Therefore, the accurate estimation of CO₂ storage capacity is crucial for the long-term security of a successful and effective sequestration strategy.

Three phases of CO₂ (e.g., scCO₂, LCO₂, and gCO₂) can be stored in reservoir rocks depending on temperature and pressure with depth. In general, the reservoir rock, saturated with brine solution, tends to be located around 1000 m below the ground surface (~45°C and >10 MPa) where CO₂ achieves its supercritical state (scCO₂) upon injection, as investigated in the previous studies [16–19]. The wettability of CO₂ highly influences the characteristic capillary pressure curve which in turn determines the fate of injection of CO₂, while experimentally observed CO₂ wettability effect is still limited [20]. Therefore, the estimation of storage efficiency of different CO₂ phases is crucial for the long-term successful and effective sequestration strategies.

The sedimentary rocks play important roles in global CO₂ reduction by capturing and storing it. The geological stratification of sedimentary rocks inherently causes the anisotropy of their internal structure which may affect the fluid penetration due to interlayered structures. The anisotropic rocks can be classified into two types depending on their apparent layer inside: (1) rocks with visible evidence of anisotropy and (2) rocks with anisotropic mechanical properties but not having visible indication. The rocks with visible evidence (e.g., shale, gneiss, and schist) have symmetric planes, easily observed and well-matched with experimentally collected properties, while further effort is needed to find the symmetry planes in the rocks with nonvisible evidence (e.g., granite and sandstone) [21–23]. However, the influence of rock anisotropy on CO₂ storage capacity has rarely been reported, unlike the influence of other physiomechanical properties such as strength, stiffness, thermal, and conductivity of storage rocks [22, 24].

This study presents the storage capacity of anisotropic sandstone in relation to different CO₂ phases injected with varying rates during a series of experimental tests. The 3D X-ray computed tomographic imaging clarified the directionally of the layer embedded in the cored specimens. Three phases of CO₂ were injected with varying flow rates, and the measured capillary pressure values were correlated with the level of CO₂ saturation for each anisotropic case. The effect of pore-size distribution on capillary pressure and thus on storage capacity was also examined for in situ reservoir rock.

2. Materials and Methods

2.1. Porous Sandstone

The Berea sandstone (Cleveland Ltd., 200–300 mD and 0.2 of porosity), often used for migration of CO₂ owing to its well-sorted pore structure [25, 26], was cored into a cylindrical shape (38 mm in diameter, 80 mm in length). The coring was conducted every 30° from the perpendicular to the parallel direction to the bedding plane for obtaining four directionally cored specimens. The top and bottom surfaces of the specimen were trimmed and polished flat to ensure coupling with the flow cell. Before the injection experiments, the pore space of the core was thoroughly cleaned using a Soxhlet extraction method involving a solution of 99.8% toluene and methyl alcohol, which was followed by oven-drying for 48 h.

2.2. Anisotropy by 3D X-Ray Computed Tomography

To examine the anisotropy of the Berea sandstone, the directionally cored specimens were subjected to 3D X-ray computed tomography (SEC Co., X-EYE PCT-G3) with a resolution of 9.7 μm. The applied current and voltage were 100 μA and 150 kV, respectively. A CCD (charged-coupled device) camera was used to capture the X-ray energy penetrating the object, and its radiation was represented by the CT number, mostly dependent on the sample density as stated by the Beer-Lambert law. 16-bit digital images were obtained by rotating a specimen for 30 minutes. Figure 1 shows the vertically sliced images of each specimen. The bright color in the image indicates the high-density constituents, whereas the dark color denotes the low-density constituents and the pore space. The faint outline of the layered structure visible in the images can be used to determine the orientation of the constituent layers by the slicing plane method [27]. The slicing plane method is explained as follows: the obtained X-ray CT image was reconstructed in 3D domain, and the virtual vector was arranged with respect to the trend and plunge angles. Then, the average of CT value from the plane perpendicular to the virtual vector was calculated, and the standard deviation of each plane’s average CT value along the normal vector was defined as the coefficient of variation (COV). The COV was continuously plotted on the stereonet with the different trend and plunge angles. Therefore, dense layer in 3D domain can be presented on the stereonet with high COV value. For example, the horizontal planes are represented by the red color at the center by their pole direction, while the poles of the vertical planes are mostly concentrated near the periphery in Figure 1. The orientation of bedding planes in Berea sandstone is also corroborated by the profile of the CT number, where the periodic peaks are predominant for specimens cored at 0° and 90° along the horizontal and vertical direction, respectively.

2.3. Injection of Carbon Dioxide

Figure 2(a) shows the experimental setup for the CO₂ injection test. The specimen was saturated with brine solution (1 M NaCl, Sigma-Aldrich) for 24 h within a vacuum chamber under the pressure of 10^-4 Torr. Then, the core was placed on a pedestal and sealed with a sleeve jacket made of ethylene propylene diene monomer rubber. A confining pressure of 5 MPa was applied to erect the specimen. The brine was circulated at 40 pore volume prior to injection. Then, each phase of CO₂ with the designated pressure and temperature (shown in Table 1) was separately injected from the top to the bottom of the specimen with varying flow rates (i.e., 1, 2.5, 5, 10, 25, and 50 ml/min) using a syringe pump (Teledyne ISCO 500D). The contact angle increases as the CO₂ phase changes from gas to liquid, while the interfacial tension and wettability change opposite to the contact angle. The injection rate at the geologic carbon storage site is generally 1.9 ml/min (typical benchmark of CO₂ injection rate is 1000 kg/yr, and scCO₂ density is 996 kg/m³) [28] such that the flow rates in this study are higher than the injection rate at the carbon storage site. The designated flow rates follow the previous study to obtain the capillary pressure characteristic curve instead of using injection rate at the carbon storage site [29]. 5 MPa was maintained between the injection pressure and confining pressure that confining pressures were 15 MPa for LCO₂ and scCO₂ and 10 MPa for gCO₂. The entire system was controlled by a heat exchanger to maintain the conditions optimal for a given CO₂ phase during the test. The CO₂-brine mixture from the bottom was discharged into the separator, where the brine was separated by gravity. The corresponding CO₂ saturation was continuously measured in syringe pump 3 during the whole process. In addition, every second, the pressure transducers (Omega, PX302-KGV) located near the inlet and outlet monitored the CO₂ pressure values as illustrated in Figure 2(a). The corresponding capillary pressure () was calculated using equation , where is the pressure of CO₂ and is the pressure of brine [30]. The injection of CO₂ was stopped when the volume of brine in the separator did not change (i.e., only CO₂ was discharged). The pore-size distribution of the Berea sandstone was measured using mercury intrusion porosimetry (MIP), as shown in Figure 2(b). The capillary pressure () increased with the saturation of mercury () until it reached 0.2. Then, there was a sharp increase in with a minor increase in , implying that the pore size corresponding to ~100 kPa was uniformly distributed within the sandstone sample, as corroborated by the results of Pini and Benson [30].

(a)

(b)

3. Results and Discussion

3.1. Effects of Anisotropy on CO₂ Storage Capacity

Figures 3(a) and 3(b) show the experimentally measured capillary pressure () and CO₂ saturation () for Berea sandstone cored at 0° with scCO₂ injection and an injection rate of 25 ml/min. The inlet pressure sharply increased at the onset of injection by overcoming the capillary pressure. The capillary pressure reached its peak when one pore volume was injected, and then, its value gradually decreased (Figure 3(a)). The CO₂ saturation continuously increased toward a quasiconstant value as the brine was displaced (Figure 3(b)). Both and converged to the asymptotic value after five pore volumes of continuously injected CO₂, beyond which no brine solution was displaced. The values of and at the residual state ( and ) were obtained by using exponential fitting equations. Both values computed for the directionally cored specimens with the use of exponential regression were plotted against the increasing flow rate. As shown in Figure 3(c), the capillary pressure increased along with the increasing flow rate. There was no noticeable difference in the coring direction at low flow rates, whereas specimen cored at 0° was characterized by a higher capillary pressure when compared to other coring directions. When the specimen was cored at 0°, the injected CO₂ was expected to penetrate both loose and dense layers overcoming the smaller pore size that the inlet pressure would be high. On the other hand, the injected CO₂ tended to preferentially migrate through the loose layers when the flow direction was parallel to the layers, resulting in a lower capillary pressure (i.e., in specimen cored at 90°). A similar observation was made for CO₂ saturation, as shown in Figure 3(d). The residual CO₂ saturation increased toward asymptotic values beyond a flow rate of 20 ml/min. It was also shown that the specimen cored at 0° stored the highest amount of CO₂ at a flow rate of 50 ml/min, which was 13% higher than the corresponding amount stored by the specimen cored at 90°. The storage capacity decreased as the flow direction became parallel to the layers.

(a)

(b)

(c)

(d)

The capillary pressure curve with varying CO₂ phases and coring directions was constructed by combining together the capillary pressure and the residual CO₂ saturation as shown in Figures 4(a)–4(c). It should be noted that the inlet pressure was not experimentally defined because the controlled parameter during the injection test was the flow rate. The solid lines obtained by using the Brooks-Corey equation in regression analysis have shown that the experimentally gathered results were well-fitted [30–32]. where is the residual capillary pressure, is the capillary entry pressure, is the effective water saturation, is pore-size distribution index, is the residual saturation of brine, and is the irreducible residual water saturation.

(a)

(b)

(c)

(d)

As observed earlier, the residual CO₂ saturation increased with increasing capillary pressure regardless of the CO₂ phases. High values were predominant in the flow direction normal to the layers. In the case of gCO₂ injection, when the specimen was cored at 90°, the maximum capacity of CO₂ storage was 0.657 (calculated from ), while the specimen with horizontal layers (in specimen cored at 0°) had a maximum CO₂ storage capacity of 0.679. For scCO₂, the storage capacity increased only slightly compared to that of gCO₂. The liquid CO₂ contributed to the highest storage capacity, while the effect of the coring direction on the storage capacity was identical for each phase. The storage capacity of each CO₂ phase was characterized by a certain range depending on the sample coring direction. The obtained results from 0^o to 90^o of each phase correlate with the research conducted by Pini and Benson [30], which is illustrated in Figure 4(d). Considering the wettability of each phase in Table 1, the evolution of the capillary pressure curve shifted to the right-hand side as the wettability of CO₂ increased. All in all, it is evident that the anisotropy in sandstone and wettability of CO₂ significantly influences the CO₂ storage capacity [33].

3.2. Brooks-Corey Parameters

The Brooks-Corey parameters estimated for the directionally cored specimens were compared for each CO₂ phase, as shown in Figure 5. The capillary entry pressure decreased as CO₂ was injected from normal to parallel to the bedding layer and the wettability of CO₂ decreased. The value in Berea sandstone ranged from 3.9 kPa to 5.2 kPa depending on the phase of injected CO₂ (LCO₂, scCO₂, or gCO₂). Al-Menhali et al. [29] suggested a correlation between and interfacial tension (IFT; i.e., ). The range of entry pressure determined from this correlation was from 3.2 kPa to 5.5 kPa, considering that the average interfacial tension was 29 mN/m and 44.5 mN/m for LCO₂ and gCO₂, respectively (Table 1).

(a)

(b)

(c)

Figure 5(b) shows that the irreducible residual water saturation, , varied from 0.287 to 0.321 and increased along with increasing CO₂ wettability for the specimens cored at 0°. The estimated range of slightly increased as the direction of the CO₂ injection became parallel to the bedding layers. The measured results seemed reasonable compared with the previous studies conducted on the Berea sandstone (0.325–0.342 in Pini and Benson [30] and >0.25, in Craig [34]).

The pore-size distribution index () increased as the CO₂ wettability and coring direction decreased (Figure 5(c)). The range of , considering three phases of CO₂ and the specimen cored at 0°, was also similar to the 2.36-2.74 range obtained by Pini and Benson [30]. When gCO₂ was injected into specimens cored at different angles, the value varied from 1.14 to 2.34. This range of values was broader when compared to other CO₂ phases injected into the same specimen. Although the value is known to be dependent solely on the rock type [30, 32], our results have shown that it also varies depending on the direction of the bedding plane, even in samples derived from the same rock.

3.3. Effect of Pore-Size Distribution on CO₂ Storage for In Situ Reservoir Rocks

The in situ reservoir rocks were recovered from the Janggi Basin, located in the southeastern part of Korea. The Korean government has considered this region a promising CO₂ storage site for decades. The Neoseongsan block located at the western part of the basin was considered a particularly promising CO₂ reservoir because it mainly consists of rudaceous sandstone lithofacies and conglomerate layers, and the dacitic tuff (i.e., low-permeability layer) acted as a cap rock [18, 35]. Because of the Miocene basaltic volcanism, considerable intrabasinal faults were not found; however, the basin is characterized by a disturbed geometry near the surface [36].

Two core samples with a diameter of 60 mm were collected from the borehole at depths of 890 m (Janggi_890) and 920 m (Janggi_920). For the CO₂ injection experiments, each sample was trimmed to a diameter of 38 mm and a height of 80 mm. The X-ray CT imaging revealed that the specimen collected at 890 m had an inclined layered structure (i.e., the highest covariance at ~30° in the stereonet), while the sample collected at 920 m exhibited a wide vertical anisotropy in the NW-SE direction (i.e., high covariance values along the periphery in the stereonet) along with large and high-density particles as shown in Figure 6. The particle size and orientation of the bedding planes were different, despite a 30 m difference in depth. The porosity measured by MIP tests was 0.112 and 0.12 for Janggi_890 and Janggi_920 specimens, respectively. The CT number distribution showed that the internal constituents of Janggi_920 were evenly distributed and had a lower CT number compared to Janggi_890.

(a)

(b)

Figure 7(a) shows the pore-size distribution curves determined by mercury injection porosimetry tests performed on the Janggi_890 and Janggi_920 specimens. In the Janggi_890 specimen, more than 90% of the pores were smaller than 1 μm (red solid symbol), while the Janggi_920 specimen showed well-graded pore sizes (blue solid symbol). The median pore diameter of these in situ specimens was one to two orders of magnitude smaller than that of the Berea sandstone.

(a)

(b)

Given that CO₂ achieves a supercritical state upon the injection at the depth of ~1 km, scCO₂ was injected into the in situ cored specimens by a pressure-controlled method to obtain the capillary pressure curve (Figure 7(b)). The experimentally measured entry pressures were 120 kPa for Janggi_920 and 390 kPa for Janggi_890. The obtained values were two orders of magnitude higher than that of Berea sandstone. Since Janggi_890 had a much smaller pore size than Janggi_920, the entry pressure of Janggi_890 is 3 times higher than that of Janggi_920. The Janggi_920 specimen exhibited a gradual increase in the CO₂ storage capacity () up to 0.846 at 2500 kPa. Meanwhile, in the case of the Janggi_890 specimen, gradually increased to 0.154 showing an incremental gradient change. This tendency of bilinearity was observed when the poorly sorted conglomerate contained large rock fragments with densely distributed small pores (e.g., Tuscaloosa sandstone) [31]. The of Janggi_890 at 3000 kPa was 0.6, which was 30% smaller than that of Janggi_920 despite the similar bulk porosity.

The pore-size distribution was the dominant factor for the tendency of the capillary pressure curve rather than the effect of anisotropy. The result of Berea sandstone showed a difference up to ~0.2 CO₂ storage capacity between 0^o and 90^o cored Berea sandstone at the same capillary pressure. In contrast, while the result of extracted Janggi Basin rocks showed ~0.6 CO₂ storage capacity gap despite being extracted from the same place with similar depth, CO₂ storage efficiency would be estimated based on the pore-size distribution of field rocks and the anisotropy inside the rocks. Since 0^o cored Berea sandstone showed maximum storage capacity, CO₂ should be injected vertically into the bedding layer in the field to enhance the storage efficiency. Therefore, it would be necessary to evaluate CO₂ storage capacity by extracting field rocks at various depths and places and the orientation of anisotropy prior to the CO₂ injection in the field.

4. Summary and Conclusions

In this study, we present the experimental results regarding capillary pressure characteristics of Berea sandstone when injected with different phases of CO₂ (e.g., gCO₂, scCO₂, and LCO₂) and cored at different angles (e.g., 0^o, 30°, 60°, and 90°). In addition, the capillary pressure of in situ rocks (i.e., Janggi Basin rocks) was analyzed. The X-ray CT images of each specimen quantitatively revealed the anisotropy of the layered structure. The experiment involving core flooding with the use of temperature and pressure controllers for maintaining different phases of CO₂ allowed for the measurement of the capillary pressure in the brine-saturated specimens. In turn, the properties of the Berea sandstone were characterized using the Brooks-Corey parameters.

The statistical method, the slicing plane method, based on 3D X-ray CT images, was implemented to validate the orientation of the bedding plane not only for the Berea sandstone but also for the in situ Janggi Basin rocks. The CO₂ injection test showed that the CO₂ storage capacity converged to the asymptotic line above a certain CO₂ flow rate. The direction of the bedding plane and the phase of the injected CO₂ affected the CO₂ storage capacity of the rock. The storage capacity increased as the normal vector of the dense layer was closer to the flow direction, and the wettability of CO₂ decreased.

From the results obtained by examining the Janggi Basin rocks, we derived different capillary pressure curves. This was despite the fact that these in situ rocks were characterized by a similar porosity and were extracted from the same borehole at similar depths. The pore-size distribution had a more prevalent effect on the evolution of capillary pressure and storage capacity than the orientation of anisotropy. This study highlighted the fact that the wettability of CO₂ with different phases and orientation of the bedding plane layer plays an important role in the CO₂ storage capacity.

Data Availability

The X-ray CT data used to support the findings of this study have been deposited in the Digital Rocks Portal.

Additional Points

Highlights. Anisotropy of reservoir rocks influences CO₂ storage capacity. High injection pressure increased CO₂ storage capacity. Pore size of in situ sandstone and CO₂ wettability affected the capillary pressure

Conflicts of Interest

The authors declare that there are no conflicts of interest regarding the publication of this paper.

Acknowledgments

This work was supported by the National Research Foundation of Korea (NRF) Grant funded by the Korea Government (Ministry of Science and ICT, South Korea) (No. NRF-2021R1A5A1032433).

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Copyright © 2022 Jun Young Song et al. This is an open access article distributed under the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

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Geofluids

Effects of Anisotropy and CO2 Wettability on CO2 Storage Capacity in Sandstone

Abstract

1. Introduction

2. Materials and Methods

2.1. Porous Sandstone

2.2. Anisotropy by 3D X-Ray Computed Tomography

2.3. Injection of Carbon Dioxide

3. Results and Discussion

3.1. Effects of Anisotropy on CO2 Storage Capacity

3.2. Brooks-Corey Parameters

3.3. Effect of Pore-Size Distribution on CO2 Storage for In Situ Reservoir Rocks

4. Summary and Conclusions

Data Availability

Additional Points

Conflicts of Interest

Acknowledgments

References

Copyright

Effects of Anisotropy and CO₂ Wettability on CO₂ Storage Capacity in Sandstone

3.1. Effects of Anisotropy on CO₂ Storage Capacity

3.3. Effect of Pore-Size Distribution on CO₂ Storage for In Situ Reservoir Rocks