Abstract
A large hydraulic fracture diagnostic project was undertaken in the summer of 2001, which integrated fracture diagnostic technologies including tiltmeter (surface and downhole) and microseismic mapping. The extensive data gathered resulted in a much clearer understanding of the highly complex fracture behavior in the Barnett Shale of North Texas. The detailed fracture mapping results allowed construction of a calibrated 3-D fracture simulator that better reflects the observed mechanics of fracturing in this fractured-shale reservoir. More than just simple calibration was required. Indeed, a whole new understanding of fracture growth was developed.
The Barnett Shale has seen a rebirth of drilling and refracturing activity in recent years due to the success of waterfrac or "light sand" fracturing treatments. This extremely low permeability reservoir benefits from fracture treatments that establish long and wide fracture fairways, which result in connecting very large surface areas of the formation with an extremely complex fracture network.
Understanding the created fracture geometry is key to the effectiveness of any stimulation program or infill-drilling program, particularly in this area with its non-classical fracture networks. Integrated fracture diagnostics have led to the identification of new fracturing techniques as well as additional refrac and infill drilling candidates. A new method for evaluating large microseismic data sets was developed. Combining the microseismic analysis with surface and downhole tilt fracture mapping allowed characterization of the created fracture networks. Correlations between production response and various fracture parameters will be presented along with a discussion of methods for calibrating a fracture model to the observed fracture behavior.
