Microstructural, Geomechanical, and Petrophysical Characterization of Shale Caprocks

Dewhurst, David N.; Piane, Claudio Delle; Esteban, Lionel; Sarout, Joël; Josh, Matthew; Pervukhina, Marina; Clennell, Michael B.

doi:10.1002/9781119118657.ch1

Cited by 8 publications

(7 citation statements)

References 152 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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“…13,25,39,84−86 According to the investigation conducted by the researchers if a rock with higher Young's modulus and lower Poisson's ratio tend to exhibit a higher brittleness index (BI > 0.48), and these are the favorable conditions for shale fracturing. 69,71,72,76,80,83,87,88 To optimize fracturing treatments, it is essential to conduct a characterization of the natural fracture system and determine the in situ stress conditions of rock. Fractures' orientation and propagation are notably influenced by the combination of natural fractures, the differences in in situ stress, and the directions of stress.…”

Section: Data Required For Shale Fracture Analysismentioning

confidence: 99%

Supercritical Carbon Dioxide Utilization for Hydraulic Fracturing of Shale Reservoir, and Geo-Storage: A Review

Gupta,

Verma

2023

Energy Fuels

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Hydraulic fracturing has completely revolutionized how shale resources are exploited to extracthydrocarbons. However, sustainability and environmental issues have fueled the desire for alternate fracturing technologies. Supercritical carbon dioxide (Sc-CO2) fracturing is a new method that uses high-pressure, high-temperature CO2 in its supercritical state (7.38 MPa and 31.1 °C) to generate fractures in shale formations, thereby increasing reservoir permeability. This Review thoroughly analyzes the effects of Sc-CO2 on shale reservoirs during the fracturing process, including the factors that affect fracture breakdown pressure and the complexity and roughness of fracture induced by Sc-CO2. Sc-CO2 can fracture rock at a fracturing pressure lower than that of slick water. CO2, in its supercritical state, shows strong permeability, low viscosity, and extremely low surface tension, like gas, because of which it can infiltrate any space larger than its kinetic diameter (0.330 nm). Many research investigations illustrate how Sc-CO2 affects shales with diverse pore structures, mineral compositions, and mechanical properties when exposed to Sc-CO2 for several hours to days. It is challenging to effectively store CO2 in shale gas reservoirs due to their low permeability and limited storage capacity. To improve the effectiveness of CO2 storage, shale can be fractured to increase the pore space and surface area in reservoirs. Thereby, a certain amount of the CO2 pumped for shale gas production can be securely stored in shale formations, reducing carbon emissions and allowing for a zero-carbon footprint. This paper discusses the pathway and different chemical reactions involved in the storage of CO2 after fracturing over a period. However, fully understanding the interactions between Sc-CO2 and shale rock and the possibility of long-term storage of CO2 in shale formations is quite challenging. It is because of a lack of research and limited knowledge in the above field. Hence, more investigation and development are required in the research area of Sc-CO2 fracturing and the interaction of CO2 with shale rock.

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“…A large amount of natural gas is injected into reservoirs continuously, which will damage the mechanical integrity and sealing of the caprock [7]. Therefore, it is necessary to quantitatively characterize the degree of deformation and damage of the caprock during the processes of injection and production and to correctly evaluate its mechanical integrity [8].…”

Section: Introductionmentioning

confidence: 99%

Coupled Large Scale Hydromechanical Modelling for Caprock Failure Risk Assessment of Gas Storage in Aquifer

et al. 2021

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The rapidly increasing demand for the consumption of natural gas has attracted the interests to store natural gas in aquifer reservoir. However, natural gas injected into the aquifer reservoir, which could cause ground surface deformation and mechanical integrity destruction of caprock. Taking the aquifer gas storage of S trap as the research object, according to the geological structure and hydrogeological information, a coupling large-scale hydromechanical model is established to evaluate the damage risk of the gas reservoir in S aquifer. The proposed methodology is based on the development of fluid-solid coupling and application of FEM. The different failure mechanisms of S aquifer gas storage caprock can be evaluated on the basis of the tensile failure criterion and Mohr-Coulomb shear failure criterion. To analyze the change of caprock in gas injection and production process more clearly, a reference model is defined as an ideal calculation condition to discuss the mechanical response, pore pressure variation, and surface deformation characteristics of the caprock during injection and production. On this basis, the second scheme of sensitivity analysis is defined. The pressure injection rate, reservoir parameters, in situ stress, and other factors are considered, respectively, and the influence of different input parameters on mechanical stability and surface deformation of caprock is analyzed. Finally, the mechanical stability is analyzed and combined the above two criteria to predict the upper limit injection pressure of S. Simulation results show that the permeability and in situ stress have a significant influence on ground surface deformation and mechanical integrity of caprock, but Young’s modulus and Poisson’s ratio can be ignored; the upper limit pressure coefficient of S is 1.908.

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Microstructural, Geomechanical, and Petrophysical Characterization of Shale Caprocks

Cited by 8 publications

References 152 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

Supercritical Carbon Dioxide Utilization for Hydraulic Fracturing of Shale Reservoir, and Geo-Storage: A Review

Coupled Large Scale Hydromechanical Modelling for Caprock Failure Risk Assessment of Gas Storage in Aquifer

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