Abstract
Recent work has shown that flow units characterized by process or delivery speed (the ratio of permeability and porosity) provide a continuum between conventional, tight gas, shale gas, tight oil and shale oil reservoirs (Aguilera, 2014). The link between the various hydrocarbon fluids is provided by the word ‘petroleum’ in ‘Total Petroleum System’ (TPS) which encompasses liquid and gas hydrocarbons found in conventional, tight and shale reservoirs. The work also shows that, other things being equal, the smaller pores lead to smaller production rates.
There is, however, a positive side to smaller pores that under favorable conditions can lead to larger economic benefits from organic-rich shale reservoirs. This occurs in the case of condensate fluids that behave as dry gas in the smaller pores of organic-rich shale reservoirs. Flow of this dry gas diminishes the amount of liquids that are released and lost permanently in a shale reservoir. Conversely this dry gas can lead to larger recovery of liquids in the surface from a given shale reservoir and consequently more attractive economics. This study shows how the smaller pores and their associated dry gas can be recognized with the use of process speed (flow-units) and modified Pickett plots. Data from the Niobrara and Eagle Ford shales are used to demonstrate these crossplots.
It is concluded that there is significant practical potential in the use of process speed as part of the flow unit characterization of shale condensate reservoirs. This in turn can help locating sweet spots for improved liquid production. The main contribution of this work is the association of flow units and different scales of pore apertures for improving recovery of liquids from shale reservoirs.
