The purpose of this paper is to present the producing GOR-time behavior of horizontal, multi-fractured tight unconventional wells exhibiting layer-wise fluid heterogeneity given by a two-layer system with each layer having contrasting in-situ solution GORs. Fluid and petrophysical properties are uniform within each layer and usually differ between the two layers. Eagle Ford basin fluid and petrophysical properties are used as a basis for this study, but the observations made should be general to any tight unconventional system with layer-wise fluid and rock properties.

A numerical reservoir simulation model is used to represent a horizontal well drainage volume with multiple planar fractures producing from two layers having distinct and contrasting fluid and petrophysical (k-φ) properties. The model is populated with layer-wise average porosity and permeability (no lateral heterogeneity in petrophysical or fluid properties for each layer), ranging from 4 to 9 % porosity, and 70 to 700 nd permeability. Each layer has a constant initial solution GOR (i.e. in-situ composition). GOR-time performance is shown for a wide variety of scenarios. Assigned layer in-situ-GOR values are 1000 scf/STB ("oil"), 3000 scf/STB (near-critical oil), 6000 scf/STB ("gas") or 8000 scf/STB ("gas"). The lower-GOR layer may have layer petrophysical properties that are lower, higher, or equal to the petrophysical properties in the layer with higher GOR.

We compare the GOR(t) performance using fluid PVT described by black-oil tables which are compared with a model using the EOS that has been used to create the black-oil tables. Both PVT formulations give very similar production & GOR(t) performance. Our previous study has shown that for a layered system with each layer having a uniform but contrasting solution GOR, and with lateral petrophysical property variations in each layer, GOR(t) performance is very similar with a two-layer model having arithmetic-average porosity and permeability. This observation allows the modeling of a single horizontal well with many hydraulic fractures to be modeled accurately with a single hydraulic fracture symmetry element – yielding production performance similar to that shown when modeling all hydraulic fractures in a well with lateral variation in petrophysical properties.

Depending on the layer-wise contrast in GOR and the layer-wise contrast in permeability and porosity, a wide range of GOR(t) performance can result. We show that fluid contrast in the two layers alone, with equal layer permeabilities and layer porosities, also leads to differential depletion with associated well produced GOR(t) variation; the layer with highest solution GOR almost always depletes faster. Similar results, observations and conclusions are found whether flowing bottomhole pressure remains above initial saturation pressures of the two layers, or drops below the layer saturation pressures. Differential depletion caused only by contrasting fluids in each layer can lead to layer-rate contribution variation that leads to significant and non-intuitive well GOR(t) behavior.

The composite effect of differential depletion with individual-layer GOR(t) performance yields a complex myriad of well GOR(t) behavior that is difficult to reconcile based on a single-layer system with uniform fluid, porosity, and permeability.

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