The purpose of this paper is to quantify the importance of lateral heterogeneity of permeability and porosity when modeling horizontal, multi-fractured tight unconventional wells exhibiting layer-wise fluid heterogeneity. Fluid and petrophysical properties are taken from the Eagle Ford basin.
A numerical simulation model of a horizontal well drainage volume with multiple planar fractures is created for two layers having distinct fluids (e.g. solution GORs). The model is populated with laterally-heterogeneous, correlated porosities and permeabilities (k=aφb) ranging from 4 to 14 %, and 59 to 2600 nd, respectively. The layer petrophysical properties can map differently for each layer, but the arithmetic average properties are equal for each layer. For all cases studied we assume the initial solution GOR to be areally homogeneous in a given layer; the solution GORs considered range from 1000 to 8000 scf/STB. The petrophysical heterogeneous cases are compared with homogeneous cases (no lateral property variation), both models with the same average petrophysical properties.
Results show that for a heterogeneous-petrophysical case with varying lateral contrast between the petrophysical properties in the two layers, individual fractures produce with distinct GORs, even showing a variation of producing GOR (Rp) from different locations within a single hydraulic fracture. However, the total, well-producing GOR behavior is very similar for the heterogeneous- and homogeneous-petrophysical cases, regardless of the fluid contrast in the two layers, when the maximum-to-minimum permeability ratio kmax/kmin<10.
These observations apply when flowing bottomhole pressure (BHP) is above (single-phase) or below (two-phase) in-situ saturation pressure. These results indicate that lateral petrophysical heterogeneity can often be ignored when modeling tight unconventional wells. The explanation for this non-intuitive result is that the producing surface area from many hydraulic fractures is so extensive that the well-average GOR is very close to the GOR of a well producing from two petrophysically-homogeneous layers having arithmetic-average porosity and permeability. This finding reduces considerably the simulation run time (CPU) using a single "average" hydraulic fracture element, where the key fluid heterogeneity is solution GOR in each layer.
Another important finding is that significant time-variation of producing well GOR may result even when flowing BHP remains higher than in-situ saturation pressures (i.e. single-phase flow). This behavior is caused by differential depletion of the individual layers with fluid contrast in viscosity and compressibility, i.e. without any contrast in layer permeabilities.