The work presented in this paper focuses on an integrative 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 events. 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 covering an area of over 18 square miles providing high resolution stimulation monitoring. 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, the modeled fracture volume, the stimulated reservoir volume, 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.
A significant number of microseismic events were detected over 120 days of passive monitoring with a deepwater PRM pilot array offshore Brazil. The array is installed in 1240-1310m water depth and consists of over 700 four-component stations. Recording occurred during two consecutive two-month periods in between active seismic surveys. The passive monitoring detected distinct event swarms that are highly clustered in space and time. These events occur at an estimated depth of about 5 km with moment magnitudes ranging from 0.2 to 1.9. The seismicity occurs in a depth interval near a currently undeveloped deeper reservoir and is possibly of natural origin. The capture of such seismicity is valuable input for longterm risk assessment and development planning of the lower reservoir.
Hydraulic fracture stimulation treatments of 17 wells have been monitored with a shallow buried array for induced microseismicity in the Marcellus Shale in West Virginia, USA. The wide azimuth and large coverage area (18 square miles) of the shallow buried array allowed identification of the source mechanisms of all of the detected events, enabling a statistical analysis of failure mode and associated stress state at failure for all the events in space and time. Detailed analysis of source mechanisms of the largest events revealed heterogeneous failure plane orientations and slip directions, with a combination of dip-slip and strike-slip failure and varying amounts of volumetric failure. Stress inversion analysis of these source mechanisms allowed characterization of the local stress tensor, and how the stress tensor changed from the beginning to the end of the stimulation treatment. The failure mechanisms observed to occur more frequently at the beginnings of the fracture stages were dip-slip and strike-slip failure mechanisms were more common at the ends of the fracture stages. Utilizing the timing of the types of source mechanisms to define temporal groups, the stress inversion analysis showed that the stress state in the stimulated rock changed from being consistent with the regional NE-oriented maximum horizontal stress orientation with sigma1 vertical to a stress state where the maximum horizontal stress becomes sigma1 and is horizontal. The temporal stress state is quantitatively identified and it is demonstrated that the fracture growth directions responds to the temporal stress state. This information can be used by operators to respond to or exploit the expected fracture failure mode and direction, and also to design stimulation treatments that develop complex fracture networks.
The work presented in this paper focuses on the application of an anisotropic velocity model in determining microseismic event locations from surface-acquired passive seismic data. The Thomsen parameters ε and δ were determined to accurately locate calibration shots to their known location. Hydraulic fracture events where then imaged and compared to their locations derived from processing incorporating an isotropic velocity model. Velocity models used in the processing of surface microseismic data are in many cases initially derived from sonic logs and subsequently adjusted based on calibration shots (typically perforations or string shots). A scalar shift is usually applied to the velocity model to locate events at depth. Although calibration shots can be located with sufficient accuracy, this method does not directly account for the anisotropic nature of shales. As determined by Thomsen (1986), anisotropy for nearly vertical wave propagation, is mostly governed by the parameter δ, which is "an awkward combination of elastic parameters" (Thomsen, 1986), and appears to be sensitive to the conformity of the contact regions between clay particles, as well as to the extent of disorder in their orientation (Sayers, 2005). However, the importance of ε increases with with an increasing horizontal component of the propagation path. Event location accuracy in surface microseismic monitoring is known to be fairly robust using the regularly assumed isotropic velocity model (Thornton, 2011), but this can be further improved in some instances by determining ε and δ to account for velocity anisotropy (Eisner et al., 2011). When compared directly to calibration shot locations derived with an isotropic velocity model, we showed that the absolute average error in calibration shot positioning in all directions was improved by almost 30% and hypocenter events from the hydraulic fracturing treatment depicted a more dense and confined zone of microseismic activity.
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