Submitted Successfully!
To reward your contribution, here is a gift for you: A free trial for our video production service.
Thank you for your contribution! You can also upload a video entry or images related to this topic.
Version Summary Created by Modification Content Size Created at Operation
1 -- 2009 2022-06-14 15:25:39 |
2 format correct Meta information modification 2009 2022-06-15 03:20:38 |

Video Upload Options

Do you have a full video?

Confirm

Are you sure to Delete?
Cite
If you have any further questions, please contact Encyclopedia Editorial Office.
Sheng, Y.; Ameh, P.; , .; Eshiet, K.I.I. CO2–Brine–Rock Interaction in Geological Storage Process. Encyclopedia. Available online: https://encyclopedia.pub/entry/24021 (accessed on 15 June 2024).
Sheng Y, Ameh P,  , Eshiet KII. CO2–Brine–Rock Interaction in Geological Storage Process. Encyclopedia. Available at: https://encyclopedia.pub/entry/24021. Accessed June 15, 2024.
Sheng, Yong, Peter Ameh,  , Kenneth Imo-Imo Israel Eshiet. "CO2–Brine–Rock Interaction in Geological Storage Process" Encyclopedia, https://encyclopedia.pub/entry/24021 (accessed June 15, 2024).
Sheng, Y., Ameh, P., , ., & Eshiet, K.I.I. (2022, June 14). CO2–Brine–Rock Interaction in Geological Storage Process. In Encyclopedia. https://encyclopedia.pub/entry/24021
Sheng, Yong, et al. "CO2–Brine–Rock Interaction in Geological Storage Process." Encyclopedia. Web. 14 June, 2022.
CO2–Brine–Rock Interaction in Geological Storage Process
Edit

CO2–brine–rock interaction impacts the behavior and efficiency of CO2 geological storage; a thorough understanding of these impacts is important. A lot of research in the past has considered the nature and impact of CO2–brine–rock interaction and much has been learned. Given that the solubility and rate of mineralization of CO2 in brine under reservoir conditions is slow, free and mobile, CO2 will be contained in the reservoir for a long time until the phase of CO2 evolves.

phase CO2 CO2 geological storage CO2–brine–rock interaction

1. Long Term Changes in CO2, Brine, and the Reservoirs

Once CO2 is injected into a reservoir for storage, it mixes with the fluid in the reservoir, and the properties of CO2, brine, and the reservoir change over time. The density of CO2-bearing brine is higher than brine; thus, CO2-saturated brine sinks to the bottom. This process of density settling creates hydrodynamic processes that are necessary for CO2–brine mixing and dissolution. The undissolved CO2 is lighter and rises to the top of the mix by buoyancy.
It is seen that the transport and reservoir properties in a geosequestration site are intricately dependent on each other. Any change in a property will affect a chain of other properties. For instance, Jeong et al. [1] showed that permeability depends on viscosity ratio and interfacial tension. Other factors that have been shown to affect permeability are capillary heterogeneity, fingering, and miscibility. This shows that geosequestration sites are sites of complex hydro-chemo-mechanical processes that require careful study. It is also shown that properties of CO2–brine such as density, viscosity, and solubility are massively affected by temperature, pressure, and salinity of the brine [2][3][4][5]. The pressure and temperature conditions of the reservoir are dynamic, and the salinity of brine changes depending on the amount of dilution at any given time. This means that the flow properties of CO2–brine in the saline reservoir will change over time. It is very important to be able to evaluate the density and viscosity of CO2–brine under the changing reservoir conditions. Models proposed by Ali and Ahmadi [6], Tatar et al. [7], Mao and Duan [8], and Mao et al. [9] have been successful at predicting the density and viscosity of CO2–brine under different temperatures, pressure, and salinity, with each model having varying levels of accuracy.

2. Effect of Different Phases of CO2–Brine on the Different Properties of Rocks

The rocks range from sandstone, mudrocks, claystone, shale to Carbonates. This is because each of these rocks has been used in CO2 geological storage. The fine-grained and less permeable rocks such as shale, claystone, and mudrocks serve as stratigraphic traps, whereas the permeable sandstones and pervious Carbonates serve as the reservoirs in CO2 geological storage. The effect of CO2–brine on caprock is different from the effect on reservoir rocks because of the geological difference in their origin and difference in chemical composition and physical properties. There can be layers of claystone, mudrocks, or shale within a thick layer of sandstone or Carbonate rocks, and this makes the study of the CO2–brine response of the fine-grained and less permeable rocks necessary. There is evidence to suggest that sandstones are better reservoirs for CO2 geological storage compared with Carbonate rocks; for example, Hangx et al. [10] and Lamy-Chappuis et al. [11] showed that Carbonate rocks have a greater change in bulk modulus, strength, and porosity compared with siliciclastic rocks; they argued rocks that are rich in Quartz show minor changes due to the strong grain to grain contact, whereas calcites undergo significant dissolution and microstructural changes. Similarly, Alemu et al. [12] showed that carbonate-rich shale is more reactive compared with clay-rick shales while observing the dissolution of plagioclase, illite, and chlorites, the precipitation of Carbonates, and the formation of Smectite in Carbonate-rich rocks flooded with CO2–brine. In their experiment, the clay-rich rocks did not show significant changes, but Analcime was deposited on the clay-rich shale that was flooded with CO2–brine. Furthermore, Han et al. [13] confirmed that the capability of flow and storage in Carbonate rocks are significantly altered by chemical and physical reactions with CO2–brine. Their experiment showed the disintegration of grains by dissolution and precipitation of minerals particles in contact with the CO2–brine stream. These call for caution when Carbonates and calcite-bearing rocks are to be used for CO2 geological storage.
Primacy triggers of changes in the properties of rocks are temperature, pressure, and stress [14][15], Other triggers include dissolution, precipitation and pores stress corrosion. A change in one property of the rock leads to change in other properties, such as the coupled nature of changes that can occur in a geosequestration site. For instance, Fuchs et al. [16] showed that an increase in the porosity of sandstone led to a reduction in fracture toughness, Xiao et al. [17] showed that decreased porosity due to precipitation led to a reduced risk of induced fracture, this is thought to be the case when a more stable mineral is precipitated. Additionally, Lamy-Chappuis et al. [18] showed that a 10% increase in porosity led to a corresponding change in the sonic velocity, the sonic velocity is indicative of the strength of the rock. Vialle and Vanorio [19] observed that increase in porosity and permeability of rocks flooded with CO2–brine was matched with a decrease in P and S wave velocity. This knowledge implies that for any geosequestration site, there can be an index property that should be constantly monitored, from which the changes in other properties of the rocks can be evaluated. However, the index property is accurately measured and the relationship between the index property and the other properties that will be evaluated must be well understood and interpreted.
All researchers reported a decrease in strength, bulk modulus, and elastic modulus, but an increase in porosity and permeability of the rocks due to CO2–brine activity. However, researchers such as Peter et al. [20] and Xiao et al. [17] reported a decrease in porosity due to CO2–brine activity, they explained that the CO2–brine–rock reaction led to precipitation of minerals that clogged the pores and thus reduced the porosity. Han et al. [13], Olabode and Radonjic [21], and Delle and Sarout [22] also reported that induced precipitation leads to the closing of pores and micro-fracture. The difference in the change in strength, porosity, permeability, and elastic and bulk modulus recorded for the rocks used in the research reviewed may be due to the nature of the original rock and the minerals [23][24], the nature of the pore fluid [23], physico-chemical condition [25][26][27] and the duration of chemical interaction between CO2–brine–rock [28]. Pimienta et al. [29] found that dissolution of minerals in CO2–brine increased with residence time, and Olabode and Radonjic [21] noted that with a long time of exposure, precipitation of minerals became dominant over dissolution in shales saturated with CO2–brine. The duration of CO2–brine residency is a very important factor that deserves more research.
Undissolved and mobile CO2 is predicted to be in the reservoir for thousands of years [30]. However, most experiments have been completed within days or weeks, due to experimental limitations. It is necessary to determine the resident time needed for the different Phase CO2–brine to have an impact on the properties of the rocks. Peter et al. [31] saturated samples of rocks with different Phase CO2–brine for 7 days and concluded that the impact of the resulting CO2–brine on the properties of the rock started gradually from the first day and increased as the concentration of the acidic brine increased. Pimienta et al. [29] studied the effect of residence time on the dissolution and integrity of rocks flooded with CO2 and found that the pore brine acidifies just after 2 h of exposure leading to calcite dissolution, a significant increase in the calcium ions of the brine concentration and commensurate changes in rock physical properties such as porosity and permeability. In a scCO2 fracturing experiment, Zou et al. [32] observed that the CO2–brine–rock reaction occurs rapidly (less than 0.5 h). Olabode and Radonjic [21] had reported a substantial change in the pH of effluent from shale flooded with CO2–brine only after 3 days of flooding; the change in pH of the effluent was higher in the earlier days. Results from Pimienta et al. [29], Peter et al. [31]; Zou et al. [32] and Olabode and Radonjic [21] are short-termed and show that the impact of CO2 on the properties of rock starts immediately and progresses with time. There is a need to carry out a long-term investigation. Hangx et al. (2015) and Espinoza et al. (2018), used samples from natural CO2 analog sites, and provide insights into the long-term effect of CO2 on rocks. Both studies report a reduction in strength and agreed on the role of cement size alteration as a control for chemo-mechanical changes, the dissolution of cement led to an alteration of cement size and consequent increase in porosity, reduction in strength, vertical compaction, and lateral stress. However, the conditions at CO2 analog sites may not apply to geological CO2 storage. This entry indicates that CO2–brine–rock interaction is site-specific as the process can be easily affected by many factors that are bound to be different at different reservoirs.
Supercritical CO2 is the most popular phase of CO2 that has been used in geological storage research. This is because CO2 is injected in supercritical conditions into the reservoir. Given the dynamic pressure-temperature condition of the reservoir, the phase of CO2 will change; therefore, there is a need to investigate the impact of other phases of CO2 in geological CO2 storage. Peter et al. [20] and Peter et al. [31] evaluated the effect of different Phase CO2–brine on deformation rate, deformation behavior, bulk modulus, compressibility, strength, stiffness, porosity, and permeability of reservoir rocks. Changes in pore geometry properties, porosity, and permeability of the rocks under CO2 storage conditions with different Phase CO2–brine were also evaluated using digital rock physics techniques.
Microscopic rock image analysis was also applied to provide evidence of changes in micro-fabric, the topology of minerals, and the elemental composition of minerals in saline rocks resulting from different Phase CO2–brine that can exist in saline CO2 storage reservoirs. In this paper, ScCO2 refers to supercritical CO2, whereas gCO2 refers to gas-phase CO2. It was seen that the properties of the reservoir that are most affected by the scCO2–brine state of the reservoir include an increase in secondary fatigue rate, decrease in bulk modulus and shear strength, change in the topology of minerals caused by precipitation of fines, and agglomeration of grains, as well as change in shape and flatness of pore surfaces. The properties of the reservoir that is most affected by the gCO2–brine state of the reservoir include an increase in primary fatigue rate, stress-induced decrease in permeability, porosity, and change in the topology of minerals. For all samples, the roundness and smoothness of grains as well as smoothness of pores increased after compression, whereas the roundness of pores decreased. Change in elemental composition in rock minerals in CO2–brine–rock interaction was seen to depend on the reactivity of the mineral with CO2 and/or brine and the presence of brine accelerates such change. Additionally, Lei and Xue [33] reported that the highest reduction in P-velocity and strength was seen in the sandstone sample saturated with supercritical CO2 compared with those saturated with gaseous, liquid CO2. These results show that the phase of CO2 affects the nature of the impact of CO2–brine on the properties of the rocks.
All CO2 geological storage research that has been reported in this entry is conducted under defined conditions and for a short time, different reservoirs have different conditions, and the condition of the reservoir changes over a long time, this imposes a limitation on experimental geological storage research as a slight change in reservoir condition can have far-reaching impact on the storage process. It is advised that CO2 geological storage research be conducted as a dynamic process in which different possible scenarios can be examined. Additionally, CO2 geological storage sites need to be explicitly studied and continuous monitoring of changes is recommended.

References

  1. Jeong, G.S.; Ki, S.; Lee, D.S.; Jang, I. Effect of the Flow Rate on the Relative Permeability Curve in the CO2 and Brine System for CO2 Sequestration. Sustainability 2021, 13, 1543.
  2. Enick, R.M.; Klara, S.M. CO2 Solubility in Water and Brine under Reservoir Conditions. Chem. Eng. Commun. 1990, 90, 23–33.
  3. Song, Z.; Shi, H.; Zhang, X.; Zhou, T. Prediction of CO2 solubility in ionic liquids using machine learning methods. Chem. Eng. Sci. 2020, 223, 115752.
  4. Jamshidi, T.; Zeng, F.; Tontiwachwuthikul, P.; Torabi, F. Laboratory measurements of solubility and swelling factor for CO2/Brine and CO2/heavy oil binary systems under low-medium pressure and temperature. Can. J. Chem. Eng. 2019, 97, 2137–2145.
  5. Mohammadian, E.; Hamidi, H.; Asadullah, M.; Azdarpour, A.; Motamedi, S.; Junin, R. Measurement of CO2 Solubility in NaCl Brine Solutions at Different Temperatures and Pressures Using the Potentiometric Titration Method. J. Chem. Eng. Data 2015, 60, 2042–2049.
  6. Ahmadi, M.A.; Ahmadi, A. Applying a sophisticated approach to predict CO2 solubility in brines: Application to CO2 sequestration. Int. J. Low-Carbon Technol. 2015, 11, 325–332.
  7. Tatar, A.; Naseri, S.; Sirach, N.; Lee, M.; Bahadori, A. Prediction of reservoir brine properties using radial basis function (RBF) neural network. Petroleum 2015, 1, 349–357.
  8. Mao, S.; Duan, Z. The P,V,T,x properties of binary aqueous chloride solutions up to T = 573K and 100MPa. J. Chem. Thermodyn. 2008, 40, 1046–1063.
  9. Mao, S.; Duan, Z.; Hu, J.; Zhang, D. A model for single-phase PVTx properties of CO2–CH4–C2H6–N2–H2O–NaCl fluid mixtures from 273 to 1273 K and from 1 to 5000 bar. Chem. Geol. 2010, 275, 148–160.
  10. Hangx, S.; van der Linden, A.; Marcelis, F.; Bauer, A. The effect of CO2 on the mechanical properties of the Captain Sandstone: Geological storage of CO2 at the Goldeneye field (UK). Int. J. Greenh. Gas Control 2013, 19, 609–619.
  11. Lamy-Chappuis, B.; Angus, D.; Fisher, Q.J.; Yardley, B.W. The effect of CO2 -enriched brine injection on the mechanical properties of calcite-bearing sandstone. Int. J. Greenh. Gas Control 2016, 52, 84–95.
  12. Alemu, B.L.; Aagaard, P.; Munz, I.A.; Skurtveit, E. Caprock interaction with CO2: A laboratory study of reactivity of shale with supercritical CO2 and brine. Appl. Geochem. 2011, 26, 1975–1989.
  13. Han, J.; Han, S.; Kang, D.H.; Kim, Y.; Lee, J.; Lee, Y. Application of digital rock physics using X-ray CT for study on alteration of macropore properties by CO2 EOR in a carbonate oil reservoir. J. Pet. Sci. Eng. 2020, 189, 107009.
  14. Ilgen, A.G.; Newell, P.; Hueckel, T.; Espinoza, D.N.; Hu, M. Coupled chemical-mechanical Processes Associated With the Injection of CO2 into Subsurface. In Science of Carbon Storage in Deep Saline Formations; Elsevier: Amsterdam, The Netherlands, 2019; pp. 337–359.
  15. Rutqvist, J. The Geomechanics of CO2 Storage in Deep Sedimentary Formations. Geotech. Geol. Eng. 2012, 30, 525–551.
  16. Fuchs, S.J.; Espinoza, D.N.; Lopano, C.L.; Akono, A.-T.; Werth, C.J. Geochemical and geomechanical alteration of siliciclastic reservoir rock by supercritical CO2-saturated brine formed during geological carbon sequestration. Int. J. Greenh. Gas Control 2019, 88, 251–260.
  17. Xiao, T.; Xu, H.; Moodie, N.; Esser, R.; Jia, W.; Zheng, L.; Rutqvist, J.; McPherson, B. Chemical-Mechanical Impacts of CO2 Intrusion Into Heterogeneous Caprock. Water Resour. Res. 2020, 56, e2020WR027193.
  18. Orlic, B. Geomechanical effects of CO 2 storage in depleted gas reservoirs in the Netherlands: Inferences from feasibility studies and comparison with aquifer storage. J. Rock Mech. Geotech. Eng. 2016, 8, 846–859.
  19. Vilarrasa, V.; Makhnenko, R.Y.; Laloui, L. Potential for fault reactivation due to CO2 injection in a semi-closed saline aquifer. Energy Procedia 2017, 114, 3282–3290.
  20. Peter, A.; Jin, X.; Fan, X.; Eshiet, K.I.-I.; Sheng, Y.; Yang, D. Microscopy and image analysis of the micro-fabric and composition of saline rocks under different phaseCO2-Brine states. J. Pet. Sci. Eng. 2021, 208, 109411.
  21. Olabode, A.; Radonjic, M. Experimental Investigations of Caprock Integrity in CO2 Sequestration. Energy Procedia 2013, 37, 5014–5025.
  22. Piane, C.D.; Sarout, J. Effects of water and supercritical CO2 on the mechanical and elastic properties of Berea sandstone. Int. J. Greenh. Gas Control 2016, 55, 209–220.
  23. Zhang, G.; Zhou, D.; Wang, P.; Zhang, K.; Tang, M. Influence of supercritical CO2-water on the micromechanical properties of sandstone. Int. J. Greenh. Gas Control 2020, 97, 103040.
  24. Makhnenko, R.; Vilarrasa, V.; Mylnikov, D.; Laloui, L. Hydromechanical Aspects of CO2 Breakthrough into Clay-rich Caprock. Energy Procedia 2017, 114, 3219–3228.
  25. Vilarrasa, V.; Rinaldi, A.P.; Rutqvist, J. Long-term thermal effects on injectivity evolution during CO2 storage. Int. J. Greenh. Gas Control 2017, 64, 314–322.
  26. Grombacher, D.; Vanorio, T.; Ebert, Y. Time-lapse acoustic, transport, and NMR measurements to characterize microstructural changes of carbonate rocks during injection of CO2-rich water. Geophysics 2012, 77, WA169–WA179.
  27. Bemer, E.; Lombard, J. From injectivity to integrity studies of CO2 geological storage-chemical alteration effects on carbonates petrophysical and geomechanical properties. Oil Gas Sci. Technol. Rev. Inst. Fr. Pét. 2010, 65, 445–459.
  28. Olabode, A.; Radonjic, M. Geochemical Markers in Shale-CO2 Experiment at Core Scale. Energy Procedia 2017, 114, 3840–3854.
  29. Pimienta, L.; Esteban, L.; Sarout, J.; Liu, K.; Dautriat, J.; Piane, C.D.; Clennell, M.B. Supercritical CO2 injection and residence time in fluid-saturated rocks: Evidence for calcite dissolution and effects on rock integrity. Int. J. Greenh. Gas Control 2017, 67, 31–48.
  30. Blunt, M.J.; Bijeljic, B.; Dong, H.; Gharbi, O.; Iglauer, S.; Mostaghimi, P.; Pentland, C. Pore-scale imaging and modelling. Adv. Water Resour. 2013, 51, 197–216.
  31. Peter, A.; Jin, X.; Sheng, Y.; Fan, X.; Yang, D. Static fatigue of saline rocks under different CO2 phase conditions. J. Pet. Sci. Eng. 2020, 195, 107940.
  32. Zou, Y.; Li, S.; Ma, X.; Zhang, S.; Li, N.; Chen, M. Effects of CO2-brine-rock interaction on porosity/permeability and mechanical properties during supercritical-CO2 fracturing in shale reservoirs. J. Nat. Gas Sci. Eng. 2018, 49, 157–168.
  33. Lei, X.; Xue, Z. Ultrasonic velocity and attenuation during CO2 injection into water-saturated porous sandstone: Measurements using difference seismic tomography. Phys. Earth Planet. Inter. 2009, 176, 224–234.
More
Information
Contributors MDPI registered users' name will be linked to their SciProfiles pages. To register with us, please refer to https://encyclopedia.pub/register : , , ,
View Times: 416
Entry Collection: Environmental Sciences
Revisions: 2 times (View History)
Update Date: 15 Jun 2022
1000/1000
Video Production Service