Basin-scale Appraisal Strategies for an Unconventional Shale Reservoir in a Small Tectonically Active Basin
As the search for unconventional reservoirs expands to include organic-rich units of more limited extent in smaller more complex basins, new challenges become important in the appraisal of the reservoir’s quality and production potential. In a recent study, a Paleogene source rock in a small Paratethyan foreland basin was evaluated in terms of in-place hydrocarbon volumes, predicted well performance, and the identification of sweet spots for future appraisal drilling. Available data included a small number of well penetrations with modern log suites, an extensive dataset of routine core petrophysical measurements with associated lithologic descriptions, and geochemical measurements (TOC and programmed pyrolysis) on a subset of the core samples. In the course of developing conventional reservoirs in the basin, a number of hydrocarbon shows and tests were known from the Paleogene shale interval, but the results were inconsistent between offset wells and showed no relationship to structural setting. The lithologic descriptions of the core samples can be categorized into three major lithofacies associations: coarse clastics (sandstone, siltstone), fine clastics (argillaceous shale), and carbonate (microfossil lime mudstones, marls, and calcareous shale). There was a strong geographic bias to lithofacies distribution, with the coarse clastics dominant along the basin’s current western margin, fine clastics dominant along the southern margin, and carbonates largely confined to the basin center. The geochemical data exhibited similar map patterns, with the highest TOC and best kerogen quality (in terms of initial Hydrogen Index) closely associated with the area dominated by the carbonate lithofacies. There is a good empirical correlation between gross interval thickness and dominant lithofacies and kerogen type, reflecting the impact of terrigenous dilution on reservoir characteristics. Because of extensive post-depositional tectonic deformation, current burial depths and thermal maturities are not aligned with depositional facies. The identification of the most prospective areas requires the integration of lithofacies and organofacies distributions with petrophysical calculations and results of basin modeling.
AAPG Datapages/Search and Discovery Article #90333©2018 AAPG Middle East Region, Shale Gas Evolution Symposium, Manama, Bahrain, December 11-13, 2018