Developing a predictive reservoir model involves determination or estimation of key reservoir components, which can vary through the rock volume. Sophisticated, 3-D grid models usually require significant input data and are built for conventional reservoirs producing in Darcy flow.
Production from the Barnett shale is not conventional. Shale-rock gas flow involves a complex mixture of free and adsorbed storage and production mechanisms. Free gas can be stored in the microporosity, natural fractures, or thin lamination existing or created during hydraulic fracturing. Adsorbed gas is contained in the organic material randomly distributed in the bulk rock.
Horizontal, multistage-fractured wellbores add another level of complexity. Massive hydraulic fracturing of horizontal shale has shown complex fracture networks are created along the wellbore. Mapped data suggests multiple fracture planes are created during injection. These fracture planes can be irregular in length and are not always symmetrical. Conventional reservoir models can not handle this level of complexity.
A new, 3-D, four-phase, nonisothermal, multiwell black oil and "Pseudo-compositional" simulator that allows placement of multiple transverse fractures along the horizontal has been developed. Its ability to model horizontal, multiwing, transverse fractures and account for all three reservoir phases, including injected fluid, makes this model more predictive of production.
This paper uses mapped fracture dimensions of horizontal wells in the north Texas Barnett (NTB) to build a reservoir model. Comparisons of model production to real production are made to demonstrate the model's predictive ability.