--> Abstract: Hydrocarbon Production and Microseismic Monitoring — Treatment Optimization in the Marcellus Shale, by Neuhaus, Carl W.; #90163 (2013)

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Hydrocarbon Production and Microseismic Monitoring — Treatment Optimization in the Marcellus Shale

Neuhaus, Carl W.

An integrated analysis of hydraulic fracturing treatments in the Marcellus Shale monitored by a permanently installed array of buried geophones was conducted to investigate the relationship between reservoir geology, wellbore completion and stimulation design, and microseismic data. Available data from other sources (such as well logs and well cores, information on reservoir properties, regional and local geology and other sub-surface structural information) was utilized to determine how factors related to the specific geology in the Marcellus and to the variability of hydraulic fracture treatments impacted the microseismic response of the formation. These findings were then used to evaluate the correlation between hydrocarbon production and microseismic results relative to changes in geology and variability of the stimulation approach. The observed variability in the microseismic response under the footprint of the array was used to derive and extrapolate regional trends to optimize field development. The initial production was compared to reservoir and engineering parameters, such as treatment pressures, sequence of treatments (toe-to-heel vs. zipper-frac), net pressures, and stage spacing, to determine if the variability in the microseismic results is due to engineering differences or to spatially-varying reservoir properties.

A stress inversion based on focal mechanisms was used to explain the asymmetry of the microseismicity about the wellbore and calculate the magnitudes and directions of the three principal stresses. Fracture orientations defined by failure planes from source mechanisms were used to build a discrete fracture network (DFN) representing the existing unstimulated fracture network in the Marcellus Shale. Simulations then calculated where failure is likely to occur in the DFN during the stimulation using data obtained from the stress inversion comparing the results to the microseismic event locations. Finally, a calibrated model was used to determine the effect of changes in treatment parameters, such as flow rate, treatment pressure, and volume of fluid pumped as well as completion parameters such as stage length, number of perforations, and perforation cluster spacing, in order to optimize the hydraulic fracture design.


AAPG Search and Discovery Article #90163©2013AAPG 2013 Annual Convention and Exhibition, Pittsburgh, Pennsylvania, May 19-22, 2013