The differences in thermal maturity of migrated, conventional oil vs in situ shale oil can be recognized by standard petroleum geochemical methods. Thermal maturity of the oils was assessed in this study using both gas chromatography (GC) and GC-mass spectrometry (GCMS), often referred to as biomarker analysis.
We present results from a vertical pilot well from the Midland Basin, drilled with water-based mud, which illustrate how to assess the thermal maturity of the oil in rock samples (extracted from cuttings, SWC and conventional core) from the source rock units (notably the Lower Spraberry and Wolfcamp A units here) and the sandstone in the Dean Formation. These results show that the oil in the Dean sandstone is more mature than the in situ shale oil in the Lower Spraberry and Wolfcamp A, and has therefore migrated in to the reservoir at the well location from a deeper, more mature source.
We are also able to recognize the presence of very local oil migration within source rock units into silty layers, which does not result in thermal maturity differences but does cause bulk compositional fractionation, reflected in the SARA data.
We will then use this approach on two produced oils from nearby lateral wells in the Lower Spraberry and Wolfcamp A, to show that they are similar in thermal maturity, whereas the extracted oil from the Lower Spraberry is less mature than the produced oil from the same unit. We infer therefore that the Lower Spraberry produced oil contains a contribution from a more mature source than the in situ oil, and the most likely source for this more mature oil is the underlying Dean sandstone.
Petroleum geochemical methods demonstrate that so-called unconventional source rock, or shale, oils may be a mixture of both conventional migrated oil in sandstone and in situ oil in source rocks, due to the fractures penetrating into the sandstone. This may also help to explain bulk properties, such as API gravity, of the oils.