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.
Hydraulic fracture monitoring from microseismic allows operators to optimize completions through a clear understanding and correlation of the reservoir response to stimulation. Furthermore it helps operators to improve production and avoid out of zone growth by identifying patterns of fluid movement, fracture growth and connectivity. These critical insights allow refinements to the treatment plan, and provide useful insights for long-term improvements regarding well spacing, well design, and completion design. Shale reservoirs with very low permeability in the nano darcy range require a large fracture network to increase well performance. In these reservoirs, unless natural pre-existing fractures and faults have been reactivated and hydraulically opened to create a complex and well-connected network, pore pressure changes do not permeate far from the fractures. As a result, the microseismic pointset roughly corresponds to the size of the real fracture network which offers a means to estimate the stimulated rock volume (SRV). Although the producing fracture network could be smaller than the total SRV by a substantial percentage, it is expected that the effective network and the total SRV show a positive correlation. However, SRV is not the only indicator of well productivity. In a given SRV, the quality of the reservoir and parameters such as fracture conductivity and fracture spacing will affect production and can have a major impact on recovery calculations. In this study, stimulated rock volumes obtained from microseismic pointsets are correlated with actual field production. The correlations are used to illustrate how this concept can optimize treatment design, well spacing, and stage spacing through correlation of the reservoir response to hydraulic fracturing and production data. The correlation between production and SRV for each well shows that larger SRVs result in higher well production regardless of the percentage of the SRV that contains proppant filled fractures. The direct relationship of the microseismic pointsets and production can be used to predict a new well's potential productivity immediately upon completion of the stimulation job. This suggests that a key completion strategy is to create a large and effective SRV to provide maximum recovery and well performance monitored microseismically to provide production prediction.
The work presented in this paper analyzes surface and downhole microseismic data for a horizontal well in the Woodford Shale in Oklahoma and compares those results with calibrated hydraulic fracture modeling. Hydraulic fracture models were created for each of five stages with a three-dimensional modeling software, incorporating available petrophysical data in order to match the recorded treatment pressure and the fracture geometry obtained from the microseismic data. Further analysis investigated the congruency of the downhole and the surface microseismic data, what differences they produced in a match if used exclusively, the influence of the number of events on the fracture geometry obtained from the microseismic data, the error of event location, the degree of complexity of the created fracture network, and the relationship between the magnitude of events and the time and location of their occurrence. The fracture models produced good matches for both pressure and fracture geometry but showed problems matching the fracture height due to cross-stage fracturing into parts of the reservoir that were already stimulated in a previous stage. Surface and downhole microseismic data overlapped in certain regions and picked up on different occurrences in others, giving a more complete picture of microseismic activity and fracture growth if used together. However, they deviated in terms of vertical event location with surface data showing more upward growth and downhole data showing more downward growth. In general, the downhole microseismic data showed that the stimulation treatment was successful in creating a fairly complex hydraulic fracture network for all stages, with microseismic recordings making flow paths visible governed by both paleo and present day stresses. Plots showing the speed of event generation, the cumulative seismic moment, and the event magnitude versus the event-to-receiver-distance identified interaction with pre-existing fault structures during Stages III and V.
In this case study we outline how microseismic analysis can be used to optimize treatment design and determine the portion of the stimulated rock volume that should be productive. To begin, microseismic data was acquired with a permanently installed shallow buried array of geophones during the hydraulic fracturing of 17 wells in the Marcellus Shale. The processed results were used to conduct a multi-disciplinary study integrating geology, geomechanics, reservoir and completion engineering, and ultimately, production data. A stress inversion from focal mechanisms was performed, and correlations were made between hydrocarbon production and microseismic results. That work, in conjunction with the variability in the stimulation approach, was used to optimize the treatment design on an individual wellbore and on a field development scale. Treatment design analysis indicated optimum wellbore spacing, stage spacing and length as well as evaluated the vertical coverage of the treatment within the Marcellus. Incorporating information from source mechanisms, an event magnitude calibrated discrete fracture network (DFN) was modeled taking into account the seismic energy of the events, rock properties, the injected fluid volume and efficiency. Evaluating the placement of proppant inside the DFN enables distinction between the part of the stimulated rock volume (SRV) that contributes to production in the long term, and the part of the reservoir that was affected by the treatment but may not be hydraulically connected over a longer period of time. Finally, the permeability of the stimulated fracture system was calculated from the microseismic results. This allows for the evaluation of the drainage volume and estimation of production.
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