Our method to characterize a stimulated reservoir is a two-step process. In the first step, we match a microseismic (MS) pattern using a geomechanics model, which gives injection permeability and porosity. In the second step we match gas rate versus time using Production Data Analysis, which gives a much lower production permeability and a reduced size of the SRV (stimulated reservoir volume). Data from five wells in the Fayetteville shale have been analyzed using new software. Two perm-based diagnostics (injection and production perm) have been correlated to various fracture treatment parameters, to try to characterize and to potentially improve fracture stimulations.
The injection permeability and porosity can provide information on average fracture spacing and aperture width during fracture stimulation. One way to retain more of the injection permeability, and the size of the SRV, is to tailor the proppant to the width and spacing of the induced fracture network. The spreading of the proppant depends on the spacing and aperture width of the network fractures, as well as the diameter and density of the proppant. All these factors have been included in a conceptual model for proppant spreading away from a horizontal well.
Results and conclusions of the five-well analysis are:
Potential horizontal fracture components in three wells may act to reduce breadth and height of the MS cloud (i.e., less outward and height spread of fracture fluid).
Proppant volume is a very small fraction (<4%) of fracture network volume.
Created fractures are further apart and open wider in deeper wells. This reflects the degree of compaction of the formation. This depth trend is consistent with fracture spacing from MS events in other fields.
Average fracture width in the network increases with depth, which suggests that increasing the proportion of 40-70 sand with depth is plausible. In two of the studied wells, it may have even been possible to use 30-50 sand.
A regression equation enables a prediction of the SRV productivity. When effective stress increases, SRV productivity decreases. This is expected: it is harder to sustain a fracture network in a formation with larger effective stress (i.e. deeper wells).
When amount of proppant (40-70 or 100-mesh) increases, SRV productivity increases. This is expected if proppant is needed to stop fractures in the network from closing due to in-situ stress. But an increase in 100-mesh proppant will be more beneficial as compared with 40-70 proppant.
The MS matching provides new information on spacing and aperture width of fractures in a network. Using a model for proppant spreading built around this information should help operators optimize proppant transport in shale gas and oil wells, to retain a larger SRV, and greater permeability enhancement within the SRV (SRV sizes from transient analysis of gas rates are much less than MS volumes). Our fracture widths are generally consistent with proppant sizes used in shales (100-mesh and 40-70), and this supports the geomechanics model which determines the fracture widths by matching microseismic data.