Chemo-hydro-mechanical effects of CO2 injection on reservoir and seal rocks: A review on laboratory experiments

Vafaie, Atefeh; Cama, Jordi; Soler, Josep M.; Kivi, Iman Rahimzadeh; Vilarrasa, Víctor

doi:10.1016/j.rser.2023.113270

Cited by 41 publications

(8 citation statements)

References 265 publications

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“…Seal rocks are an essential element of active petroleum systems (Magoon and Dow 2009 ). However, while existing hydrocarbon accumulations previously often served as indirect proof for a working top seal in mature hydrocarbon provinces such as the Vienna Basin, fundamental research on low-permeable barrier layers became even more important in recent years in the context of nuclear waste disposal and underground gas storage in non-hydrocarbon reservoirs (Norris 2014 ; Espinoza and Santamarina 2017 ; Dewhurst et al 2019 ; Ringrose and Meckel 2019 ; Tarkowski 2019 ; Heinemann et al 2021 ; Bensing et al 2022 ; Kivi et al 2022 ; Nhabanga and Ringrose 2022 ; Vafaie et al 2023 ). In addition, changes in top seal quality may affect hydrocarbon migration pathways particularly in vertically drained basins (Misch et al 2021 , 2022 ).…”

Section: Discussionmentioning

confidence: 99%

Regional mudstone compaction trends in the Vienna Basin: top seal assessment and implications for uplift history

Skerbisch

Misch

Drews

et al. 2023

Int J Earth Sci (Geol Rundsch)

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Seal quality assessment is not only essential in petroleum systems studies but also in the context of other geo energy applications such as underground hydrogen storage. Capillary breakthrough pressure controls top seal capacity in the absence of faults or other discontinuities. In basins that lack measured capillary pressure data (e.g., from drill cores), regional compaction-porosity trends can be used as a first prediction tool to estimate the capillary properties of mudstones. Mathematical compaction models exist but need to be calibrated for each basin. This study aims to establish a compaction trend based on theoretical models, then compare it with theoretical maximum hydrocarbon column heights inferred from true measured capillary pressure curves. Middle to upper Miocene mudstone core samples from the Vienna Basin, covering a broad depth interval from 700 to 3400 m, were investigated by X-ray diffractometry, with an Eltra C/S analyzer, and by Rock–Eval pyrolysis for bulk mineralogy, total organic carbon, and free hydrocarbon contents. Broad ion beam—scanning electron microscopy, mercury intrusion capillary porosimetry, and helium pycnometry were applied to obtain pore structural properties to compare the mathematical compaction models with actual porosity data from the Vienna Basin. Clear decreasing porosity depth trends imply that mechanical compaction was rather uniform in the central Vienna Basin. Comparing the Vienna Basin trend to global mudstone compaction trends, regional uplift causing erosion of up to ~ 500 m upper Miocene strata is inferred. A trend of increasing Rock–Eval parameters S1 and production index [PI = S1/(S1 + S2)] with decreasing capillary sealing capacity of the investigated mudstones possibly indicates vertical hydrocarbon migration through the low-permeable mudstone horizons. This observation must be considered in future top-seal studies for secondary storage applications in the Vienna Basin.

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Section: Discussionmentioning

confidence: 99%

Regional mudstone compaction trends in the Vienna Basin: top seal assessment and implications for uplift history

Skerbisch

Misch

Drews

et al. 2023

Int J Earth Sci (Geol Rundsch)

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“…Two‐phase flow in fractured porous media plays an important role in natural processes such as infiltration into fractured rock and engineered processes such as enhanced oil/gas recovery (Karpyn et al., 2009; Rangel‐German & Kovscek, 2002), geological CO 2 sequestration (Vafaie et al., 2023), and remediation of groundwater contaminated by non‐aqueous phase liquids (Dearden et al., 2013). Related two‐phase flow processes can be broadly categorized as either drainage (non‐wetting phase displaces the wetting phase) or imbibition (wetting phase displaces the non‐wetting phase).…”

Section: Introductionmentioning

confidence: 99%

Quantitative Visualization of Two‐Phase Flow in a Fractured Porous Medium

Liao,

Detwiler,

Cookson

et al. 2024

Water Resources Research

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Two‐phase fluid flow in fractured porous media impacts many natural and industrial processes but our understanding of flow dynamics in these systems is constrained by difficulties measuring the exchange of water between fracture and adjacent porous matrix. We present a novel experimental system that allows quantitative visualization of the air and water phases in a single analog fractured porous medium. The fracture system consists of a sintered‐glass porous plate in contact with an impermeable glass plate. A reservoir connected to the porous plate allows control of pore pressure within the porous medium. The fracture fills and drains through the porous matrix and flow manifolds along two edges of the fracture. The fracture is mounted in an imaging system that includes a controlled light‐emitting diode panel and a charge‐coupled‐device camera. Flow and pressure are controlled and monitored by a computer during experiments. To demonstrate this system, we carried out a series of cyclic drainage and imbibition experiments in fractures bounded by porous media with different pore‐size distributions in the porous matrix. Images of the drainage process demonstrate that the air‐water distribution within the fracture evolves differently than has been observed in non‐porous fractured systems. Specifically, we observed limited trapping of water within the fracture during drainage. Conversely, during imbibition, because air cannot exit through the porous matrix, significant regions of air became entrapped once pathways to the fracture boundaries became water filled. The differences in phase evolution led to substantial differences in the evolution of estimated relative permeability with saturation.

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“…This rise in pressure occurs because the injected CO 2 occupies pore spaces that were previously filled with other fluids, such as brine or hydrocarbons [18]. Consequently, understanding how this increased pore pressure propagates through the subsurface and interacts with surrounding rocks and fluids is crucial for assessing the long-term viability and safety of CO 2 injection projects [19,20].…”

Section: Introductionmentioning

confidence: 99%

“…Energies 2024, 17, x FOR PEER REVIEW 3 of 31 spaces that were previously filled with other fluids, such as brine or hydrocarbons [18]. Consequently, understanding how this increased pore pressure propagates through the subsurface and interacts with surrounding rocks and fluids is crucial for assessing the long-term viability and safety of CO2 injection projects [19,20]. The viability of CCS extends beyond emission reduction; it also facilitates the concept of "negative emissions", wherein more CO2 is removed from the atmosphere than is emitted [21].…”

Section: Introductionmentioning

confidence: 99%

Impact of Regional Pressure Dissipation on Carbon Capture and Storage Projects: A Comprehensive Review

Hawez,

Asim

2024

Energies

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Carbon capture and storage (CCS) is a critical technology for mitigating greenhouse gas emissions and combating climate change. CCS involves capturing CO2 emissions from industrial processes and power plants and injecting them deep underground for long-term storage. The success of CCS projects is influenced by various factors, including the regional pressure dissipation effects in subsurface geological formations. The safe and efficient operation of CCS projects depends on maintaining the pressure in the storage formation. Regional pressure dissipation, often resulting from the permeability and geomechanical properties of the storage site, can have significant effects on project integrity. This paper provides a state-of-art of the impact of regional pressure dissipation on CCS projects, highlights its effects, and discusses ongoing investigations in this area based on different case studies. The results corroborate the idea that the Sleipner project has considerable lateral hydraulic connectivity, which is evidenced by pressure increase ranging from <0.1 MPa in case of an uncompartmentalized reservoir to >1 MPa in case of substantial flow barriers. After five years of injection, pore pressures in the water leg of a gas reservoir have increased from 18 MPa to 30 MPa at Salah project, resulting in a 2 cm surface uplift. Furthermore, artificial CO2 injection was simulated numerically for 30 years timespan in the depleted oil reservoir of Jurong, located near the Huangqiao CO2-oil reservoir. The maximum amount of CO2 injected into a single well could reach 5.43 × 106 tons, potentially increasing the formation pressure by up to 9.5 MPa. In conclusion, regional pressure dissipation is a critical factor in the implementation of CCS projects. Its impact can affect project safety, efficiency, and environmental sustainability. Ongoing research and investigations are essential to improve our understanding of this phenomenon and develop strategies to mitigate its effects, ultimately advancing the success of CCS as a climate change mitigation solution.

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Chemo-hydro-mechanical effects of CO2 injection on reservoir and seal rocks: A review on laboratory experiments

Cited by 41 publications

References 265 publications

Regional mudstone compaction trends in the Vienna Basin: top seal assessment and implications for uplift history

Regional mudstone compaction trends in the Vienna Basin: top seal assessment and implications for uplift history

Quantitative Visualization of Two‐Phase Flow in a Fractured Porous Medium

Impact of Regional Pressure Dissipation on Carbon Capture and Storage Projects: A Comprehensive Review

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