Production of unconventional wells frequently deviate from the expected linear flow behavior of parallel fracture models. These deviations are commonly attributed to stress-dependent reservoir properties in oil wells or to gas desorption processes in gas wells. We propose alternative production mechanisms to explain unconventional well behavior that are based exclusively on fracture geometry and conductivity. The selection of the correct model requires characterizing the well as sub-linear, linear or sub-radial with rate transient analysis (RTA) (Acuña, 2017). In this paper as well as in Acuña (2018), we propose that wells that exhibit sub-linear flow are connected to complex networks of highly conductive fractures in varying orientations that form matrix fragments of different size. We show how the effect of different matrix fragment sizes acting simultaneously may produce the large initial production, large production decline and increased gas-oil ratio (GOR), in oil wells, commonly seen in wells of this type. Sub-radial well behavior can be explained by the simultaneous presence of infinite-conductivity and low-conductivity fractures. Networks like this may form when there are short highly conductive fractures connected to pre-existing natural fractures. This fracture geometry reproduces well behavior comparable to that produced by desorption in gas reservoirs. Our alternative production mechanisms do not need changes in fracture conductivity with pressure, enhanced permeability regions or desorption to explain well behavior. They provide a new way to understand well performance in unconventional reservoirs that may lead to improved reservoir characterization and better resource recovery.
Recent investigations in cores drilled in the Eagle Ford formation with the objective of exploring the fracture characteristics inside the SRV (Raterman et al., 2017) reveal that fracture networks created by multistage fracturing process are highly complex, with many more fractures than perforation clusters. Fractures frequently deflect and branch at heterogeneities such as natural fractures and bedding planes. Surprisingly, very few fractures show evidence of proppant. The location of the core with respect to the wellbores make possible to determine that the distance traveled by the proppant is remarkably small, limited to less than 200 ft. from the wellbore.
Another observation provided by Raterman et al. (2017) is that the matrix next to hydraulic fractures does not show microscopic evidence of off-fracture damage that may enhance matrix permeability. Actual permeability measurements made in plugs reveal no statistical difference for regions close to hydraulic fractures and away from them. This observation contradicts the common assumption about the existence of enhanced permeability regions close to the hydraulic fractures (Wang and Karaoulanis, 2016).
