Microseismic monitoring has been used to image hydraulic fracture growth in the Barnett Shale. The Barnett is a naturally fractured shale reservoir, which causes significant complexity in fracture growth during well stimulation operations. Several Barnett treatments have been successfully imaged between March 2000 and December 2001. In this paper, examples will be given to illustrate the complexity and variability which is developed during the treatment as the slurry interacts with the pre-existing fracture sets. The microseismic images explain why the stimulations occasionally grow at an angle to the assumed fracture orientation and into neighboring wells. Differences in production rates from various wells could also be related to the fracture geometry. The implications of the images to reservoir management highlight the benefit of imaging individual fracture networks to avoid overlapping and for targeting potential new well locations. Introduction Fracture diagnostics is critical in understanding the details of actual subsurface fracture growth, especially in cases of fracture complexity. Several diagnostic techniques exist, although microseismic imaging perhaps offers the best resolution to image fracture complexity. Even with relatively simple fracture geometries (i.e. a Perkins-Kern type fracture geometry), fractures can grow asymmetrically, have variable confinement across geologic interfaces, and change orientation. However, fracture growth in a naturally fractured reservoir can exhibit additional complexities associated with interaction between the hydraulic fracture and the pre-existing fracture network. In this paper, we describe the results of microseismic imaging of hydraulic fractures in Devon Energy's (formerly Mitchell Energy) Barnett Shale Gas Field, Texas1–4. The images are the first successful microseismic images in the Barnett, recorded between March 2000 and December 2001. The field is in the Fort Worth Basin, comprising the Mississippian shale lying between the Viola Limestone and the Marble Falls Limestone. The shale varies between 300' to 1000' thick, and is extremely low permeability (approximately 0.0001 millidarcies). Large scale hydraulic fracturing is required to stimulate production in the field to economic levels1. The objective of the microseismic imaging was to define the fracture growth characteristics during these well stimulations. The large scale hydraulic fractures, combined with infill drilling on spacing as tight as 27 acres and apparenent fracture complexity related to interaction with pre-existing fractures, resulted in a need to better understand the fracture geometry5. To image the actual fracture behavior in the field, a series of stimulations have been imaged using passive microseismic imaging to determine the fracture geometry and growth characteristics. Here, we present selected examples from images collected during numerous stimulations over a period of two years, which demonstrate substantial fracture complexity resulting from interaction with the natural fractures in the field. The paper reports the fracture geometry and complexity, comparisons with the final well production, and implications for field management.

An extensive microseismic data set was collected during three hydraulic fracture operations in the Cotton Valley gas field of East Texas. Two 48-level, 3-component geophone arrays were deployed. We have mapped the microseismicity of the Stage 2 completion interval using data from 9 or fewer geophone stations. Gross fracture dimensions obtained from the 9-station data were the same as determined from the full-array data. Seismic velocities and station corrections were estimated via a joint hypocenter-velocity inversion. Master-event relative mapping applied to the most populous cluster of located seismicity improved location precision 10-fold and resolved a 150-ft-length, horizontal linear feature with width and depth dimensions of less than 10 ft. The linear cluster lies near the upper boundary of the treatment interval and implies that the majority of mapped seismicity is constrained to about 4% of the total injection depth interval. Fine-scale temporal growth patterns were revealed as well.

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