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Integrated Microseismic Monitoring for Field Optimization in the Marcellus Shale – A Case Study

Carl W. Neuhaus¹, Sherilyn Williams-Stroud¹, Christine Remington¹, William Barker¹, Keith Blair², Garrett Neshyba², and Taylor McCay²
¹MicroSeismic, Inc., Houston, TX,
[email protected], [email protected], [email protected], [email protected]
²Gastar Exploration Ltd., Houston, TX,
[email protected], [email protected], [email protected]

The work presented in this paper focuses on an integrative and interdisciplinary analysis of hydraulic fracture treatments conducted in the Marcellus Shale. The treatments have been monitored by a permanently installed array of buried geophones used to detect microseismic event sets. These event sets were analyzed in conjunction with available data from other sources, such as well logs and well cores, as well as information on reservoir properties, regional and local geology and other sub-surface structural information. Passive seismic data was acquired by an array of 101 permanently installed geophones buried and cemented in place at a depth of 150 ft in purpose-drilled boreholes. The array has an east-west span of approximately 5.25 miles and a north-south span of approximately 3.5 miles providing high resolution stimulation monitoring for a total area of over 18 square miles. The permanent installation of geophones below the surface allows for significant increase in signal-to-noise ratio and consistent comparison of hydraulic fracture treatments for any given number of wells under the array footprint.

This integrative analysis determined how various factors related to the specific reservoir geology in the Marcellus and to what extent the variability of hydraulic fracture treatments impacted the microseismic results. The next step of the evaluation investigated the relationship between hydrocarbon production and the microseismic results, relative to changes in geology and variability of the stimulation approach.

Analysis of stress changes indicated by the microseismic source mechanisms was used to explain the asymmetry of microseismicity about the wellbore. Relationships and statistics of treatment options with respect to the monitoring results were investigated, including the modeled discrete fracture network (DFN), the modeled fracture volume, the stimulated reservoir volume (SRV), and the cumulative microseismic moment of the event set. The initial production (IP) 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. Simple well test simulations were performed to investigate different fracture and flow models, and compare results to the IP and available reservoir properties. Observed correlations between hydrocarbon production and microseismicity were then used predictively to determine the impacts of changes in various parameters.


AAPG Search and Discovery Article #90154©2012 AAPG Eastern Section Meeting, Cleveland, Ohio, 22-26 September 2012