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.
Repurposing depleted oil and gas reservoirs for secondary storage may play an important role in the transition to low-carbon energy. The integrity of the cap rocks overlying the reservoirs is an important factor for gas storage and needs to be understood prior to repurposing. In some cases, old cap-rock cores collected during exploration and development of oil and gas fields may be available for characterization using modern techniques but after being stored for decades these cores are likely to have experienced many changes in moisture, which can lead to physical changes. A comparative study of samples taken from old, unpreserved mudstone core and samples from a recently acquired and preserved core taken from the same formation shows that the mineralogy, porosity and permeability results are relatively similar between the two cores. The differences in the porosity measurements between the old and new core samples are primarily due to natural variations in grain size, rather than the preservation status of the cores. Geomechanical data, however, show significant and non-systematic differences between the old samples and the new samples, suggesting that old core samples are not suitable for geomechanical characterization. In the absence of new, well-preserved core, old core samples may provide suitable porosity, permeability and mineralogical data, whereas the old, unpreserved core is unlikely to provide reliable geomechanical data.
Supplementary material:
Individual BIB-SEM porosity measurements for each sample are available at
https://doi.org/10.6084/m9.figshare.c.6725765
Thematic collection:
This article is part of the Fault and top seals 2022 collection available at:
https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022
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