Production mechanisms and reservoir characteristics differentiate significantly in the exploitation of shale gas and other tight gas formations. In both cases, the use of massive hydraulic fracturing is essential and the reservoir characteristics, which include low to very low permeability (0.1 to 0.0001 md or even less), suggest very long and narrow fractures. It is clear that the choice of slick-water as fracturing fluid and the use of very small mass of proppant by the industry are the appropriate practices.

However, in tight reservoirs, gas is found in the pore space, requiring adequate porosity, and the initial gas-in-place (IGIP) can be readily calculated. Given the fractured well flow characteristics, recovery can then be estimated. Fracture design, taking into account the reservoir permeability, can be optimized to maximize the productivity index and ultimate recovery.

For shale gas, the IGIP is primarily in the form of adsorbed gas and far less of it is in the pore space. The volume of gas depends on sorption constants which describe the Langmuir adsorption/desorption isotherms. Because these constants are given in terms of gas per reservoir volume, the "stimulated volume," in other words, the volume contacted by the induced fractures, becomes critical. That is why horizontal wells with multiple transverse fractures, the latter with branches, have become the obvious geometry for shale gas production.

We present predictive models for production of both tight and shale gas reservoirs which include appropriate fracture designs taking into account reservoir characteristics. We also forecast well performance by considering well deliverability and ultimate recovery. The recovery for shale gas primarily depends on desorption. The results show distinct differences in production characteristics between tight gas and shale gas wells with the latter exhibiting far larger recoveries and sustainable production for far longer periods for similar reservoir permeabilities.

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