Multi-scale study into Fluid-Rock Interactions in reservoir and caprocks for Geological CO2 Storage
Doctoral Candidate: Prescelli Annan
Supervisor: Alba Zapone, ETHZ
Output type: Literature review
Background:
The impacts of anthropogenic CO2 emissions are increasingly evident worldwide, with rising global temperatures and sea levels, and increasingly frequent extreme weather events. Deploying CO2 capture and storage technologies on a large scale is essential to avoid the worst impacts of climate change. Geological CO2 Storage (GCS) offers a way to permanently store CO2 captured from the atmosphere, which is vital for countries to meet the Net-Zero targets of the 2016 Paris Agreement. Storing CO2 in geological formations, like depleted oil and gas fields or deep sedimentary aquifers, helps reduce the impact of greenhouse gas emissions.
Sedimentary aquifers have emerged as a key focus in many recent studies on GCS, highlighting both the potential and the challenges in deploying GCS to meet climate goals [12, 21, 1, 7, 16]. An impermeable caprock, which lies above the reservoir rock, is fundamental in preventing CO2 leakage during carbon sequestration. Caprocks, such as claystones, siltstones, and shales, act as a seal that stops CO2 from migrating upwards, a process known as structural trapping.
The effectiveness of a caprock depends on its ability to maintain a seal to CO2 during high-pressure CO2 injections. Common potential leakage pathways include old wells and up faults. Supercritical CO2 (SC-CO2), being less dense than water, tends to accumulate beneath the caprock, increasing pore pressure at the reservoir-caprock interface. This pressure buildup can potentially cause micro-fractures or trigger fault reactivation, leading to CO2 leakage [13, 4]. These reactivated faults can create pathways for CO2 to escape to the surface, as shown in Fig. 1.
Figure SEQ Figure / *ARABIC 1: Conceptual diagram showing CO2 movement within a sedimentary reservoir and caprock system. The diagram illustrates how CO2 migrates upwards, forming a “plume” and highlights the potential for fault reactivation to comprise caprock integrity, leading to CO2 leakage
Well-monitored field studies that bridge the gap between laboratory and pilot scale, such as those by [14], [20], and in-situ fault reactivation studies [8, 9, 18,10], are crucial for understanding the complexities in how caprocks respond to CO2 injection. In laboratory studies on Opalinus claystone, CO2 injection has been shown to reopen fractures and increase permeability [2, 11]. However, [17] amongst others, found that the clay exhibited sealing behaviour, suggesting that the response of clay-rich caprocks to CO2 injection remains complex and warrants further investigation.
Laboratory studies also show varied results regarding the chemical and physical property changes in claystone, especially under different conditions of CO2 exposure. This variability highlights the significant gaps in our understanding of the mechanical response of claystone, particularly how it deforms, fractures, and changes in strength when interacting with CO2-saturated brine or dry supercritical CO2 [3, 5].
An emerging alternative to traditional GCS in sedimentary reservoirs is the injection of CO2-rich fluids (AQ-CO2) into reactive rocks, such as basalts as seen in Fig. 2, where the CO2 reacts to form solid carbonate minerals—a process known as mineral trapping. Pilot projects in Iceland have successfully demonstrated CO2 injection into basalts [6, 15,19]. However, the efficiency of mineral trapping varies significantly depending on factors such as temperature, pH, and mineral composition. Further laboratory testing is needed to better define effective mineral trapping rates and understand the resulting physical property alterations of the samples.
Research Summary:
This PhD project combines laboratory and field experiments to explore how reactive fluids interact with a caprock and reservoir rock, a critical aspect of effective GCS. Using a multiscale approach that integrates novel laboratory experiments with field studies at the Mont Terri Underground Rock Laboratory, we focus on understanding the structural control of reactive fluid flow, particularly fracture-limited transport processes in both laboratory and field settings.
In the laboratory, CO2 exposure experiments of intact core samples will replicate in situ salinity, pressure and temperature levels using a batch reactor system equipped with continuous pH monitoring. Characterisation of the mechanical and physical properties of the basalt and claystone samples will be conducted before and after CO2-rich seawater exposure, using X-ray computed tomography (XRCT) of cores to provide 3D insights across various rock types and better understand controls to rock alteration. We aim to confine the impact of CO2 exposure on the hydromechanical properties of a range of rock types relevant to CO2 storage. Applications of this research will help interpret results from geophysical field campaigns and assist storage reservoir management strategies.
Scaling this to the decameter scale, we investigate the injection of CO2-saturated brine into a fault zone within Opalinus Claystone at Mont Terri — an analogue caprock. This contributes to a more comprehensive understanding of fluid injection on fault reactivation and up-fault leakage, as well as the mechanisms of claystone fracture self-sealing. Here we target leakage processes at shallow depths, important to CO2 storage security, and will investigate methods to deploy in the case of leakage.
Objective 1: To understand how CO2-rich fluid injections affect fault reactivation, caprock integrity and fault self-sealing using advanced geophysical sensing techniques.
Objective 2: To investigate how CO2 exposure affects the mechanical and physical properties of Opalinus Claystone, focusing on fracture dynamics and overall integrity.
Objective 3: To investigate how CO2 exposure affects the mechanical and physical properties of Icelandic basalt, focusing on the role of fractures in dissolution and precipitation pathways and effective mineral trapping rates.
References:
[2] Matthieu Angeli et al. “Experimental percolation of supercritical CO2 through a caprock”. In:1.1 (2009), pp. 3351–3358. DOI: 10.1016/j.egypro.2009.02.123. (Visited on 01/01/2023).3
[3] Mohammad H. Bhuiyan et al. “Micro- and Macroscale Consequences of Interactions between CO2 and Shale Rocks”. In: Energies 13.5 (2020), p. 1167. DOI: 10.3390/en13051167. (Visited on 01/01/2021).
[4] Jay R. Black, Susan A. Carroll, and Ralf R. Haese. “Rates of mineral dissolution under CO2 storage conditions”. In: Chemical Geology 399 (2015), pp. 134–144. DOI: 10.1016/j.chemgeo. 2014.09.020.
[5] David N. Dewhurst et al. “Interaction of super-critical CO2 with mudrocks: Impact on composition and mechanical properties”. In: International Journal of Greenhouse Gas Control 102(2020), p. 103163. DOI: 10.1016/j.ijggc.2020.103163. (Visited on 01/01/2020).
[6] Sigurdur R. Gíslason et al. “A brief history of CarbFix: Challenges and victories of the project’s pilot phase”. In: Energy Procedia 146 (July 2018), pp. 103–114. DOI: 10.1016/j.egypro.2018.07.014.
[7] Global CCS Institute. GLOBAL STATUS OF CCS 2022 BUILDING MOMENTUM AS WE SHIFT INTO A PHASE OF ACTION CONTENTS. Tech. rep. 2022. URL: https://status22.globalccsinstitute.com / wp – content / uploads / 2022 / 10 / Global – Status – of – CCS – 2022 – Report – Final -compressed.pdf.
[8] Yves Guglielmi et al. “Complexity of Fault Rupture and Fluid Leakage in Shale: Insights From a Controlled Fault Activation Experiment”. In: Journal of Geophysical Research: Solid Earth 125.2 (2020). DOI: 10.1029/2019jb017781. (Visited on 01/01/2020).
[9] Yves Guglielmi et al. “Field-scale fault reactivation experiments by fluid injection highlight aseismic leakage in caprock analogs: Implications for CO2 sequestration”. In: International Journal of Greenhouse Gas Control 111 (Oct. 2021), p. 103471. ISSN: 1750-5836. DOI: 10.1016/j. ijggc . 2021 . 103471. URL: https : / / www . sciencedirect . com / science / article / pii/S1750583621002231 (visited on 07/10/2024).
[10] Chet Hopp et al. “The Effect of Fault Architecture on Slip Behavior in Shale Revealed by Distributed Fiber Optic Strain Sensing”. In: Journal of Geophysical Research: Solid Earth 127.1(2022). DOI: 10.1029/2021jb022432. (Visited on 01/01/2022).
[11] I. R. Kivi, R. Y. Makhnenko, and V. Vilarrasa. “Two-Phase Flow Mechanisms Controlling CO2 Intrusion into Shaly Caprock”. en. In: Transport in Porous Media 141.3 (Feb. 2022), pp. 771–798. ISSN: 1573-1634. DOI: 10.1007/s11242-022-01748-w. URL: https://doi.org/10.1007/s11242-022-01748-w (visited on 05/09/2024).
[12] Eric Oelkers and David Cole. “Carbon Dioxide Sequestration: An Introduction”. In: Elements 4 (Oct. 2008). DOI: 10.2113/gselements.4.5.305.
[13] Philip Ringrose. “Storage of Carbon Dioxide in Saline Aquifers: Building confidence by forecasting and monitoring”. In: Society of Exploration Geophysicists eBooks (Aug. 2023). DOI: 10.1190/1.9781560803959. URL: https://library.seg.org/doi/epdf/10.1190/1.9781560803959 (visited on 12/02/2023).
[14] Dario Sciandra et al. “Hydro-mechanical response of Opalinus Clay in the CO2 long-term periodic injection experiment (CO2LPIE) at the Mont Terri rock laboratory”. en. In: Geomechanics and Geophysics for Geo-Energy and Geo-Resources 8.5 (Sept. 2022), p. 166. ISSN: 2363-8427. DOI: 10.1007/s40948-022-00442-x. URL: https://doi.org/10.1007/s40948-022-00442-x(visited on 05/06/2024).
[15] Sandra Ó Snæbjörnsdóttir et al. “Carbon dioxide storage through mineral carbonation”. In: Nature Reviews Earth & Environment 1.2 (2020), pp. 90–102. DOI: 10.1038/s43017-019-0011-8. URL: https://www.nature.com/articles/s43017-019-0011-8#Abs1.4
[16] Youngsoo Song et al. “Geomechanical challenges during geological CO2 storage: A review”. In: Chemical Engineering Journal 456 (2023), p. 140968. DOI: 10.1016/j.cej.2022.140968. URL: https://www.sciencedirect.com/science/article/pii/S138589472206449X (visited on 01/01/2023).
[17] Quinn C. Wenning et al. “Chemo-Mechanical Coupling in Fractured Shale With Water and Hydrocarbon Flow”. en. In: Geophysical Research Letters 48.5 (2021). _eprint: https://onlinelibrary.wiley.com/de2020GL091357. ISSN: 1944-8007. DOI: 10.1029/2020GL091357. URL: https://onlinelibrary. wiley.com/doi/abs/10.1029/2020GL091357 (visited on 09/02/2024).
[18] Quinn C. Wenning et al. “Fault hydromechanical characterization and CO2-saturated water injection at the CS-D experiment (Mont Terri Rock Laboratory)”. In: (Mar. 2020). DOI: 10.5194/egusphere-egu2020-19243. (Visited on 10/05/2022).
[19] Alba Zappone and Stefan Wiemer. The DemoUpStorage Project: monitoring mineral carbonation in Icelandic basalts. en. Tech. rep. EGU23-14256. Conference Name: EGU23. Copernicus Meetings, Feb. 2023. DOI: 10.5194/egusphere- egu23- 14256. URL: https://meetingorganizer. copernicus.org/EGU23/EGU23-14256.html (visited on 07/08/2024).
[20] Alba Zappone et al. “Fault sealing and caprock integrity for CO2 storage: an in situ injection experiment”. In: Solid Earth 12.2 (2021), pp. 319–343. DOI: 10 . 5194 / se – 12 – 319 – 2021. (Visited on 01/01/2022).
[21] Zhihua Zhang and Donald Huisingh. “Carbon dioxide storage schemes: Technology, assessment and deployment”. In: Journal of Cleaner Production. Special Volume on Improving natural resource management and human health to ensure sustainable societal development based upon insights gained from working within ‘Big Data Environments’ 142 (Jan. 2017), pp. 1055–1064. ISSN: 0959-6526. DOI: 10.1016/j.jclepro.2016.06.199. URL: https://www.sciencedirect.com/science/article/pii/S0959652616308861 (visited on 05/06/2024).