Hydraulic Fracture Monitoring as a Tool to Improve Reservoir Management

Abstract

Abstract We present the results of a multi-stage hydraulic fracture monitoring campaign performed during 2004 on one of Dominion Exploration and Production, Inc. producing well in the mature tight gas Sawyer field, Sutton County, Texas. The purpose of these microseismic monitoring surveys was to determine the overall geometry of the hydraulically induced fractures in the Canyon Sand formation. Information and results derived from the microseismic interpretation were used to provide the operator with recommendations for reservoir management (e.g., drilling patterns, new well placement, completion practices, etc.) An initial borehole seismic survey confirmed optimum tool positioning to accommodate background noise and acoustic coupling. Additionally, calibration of sonic velocities was performed. All these factors led to an unprecedented level of understanding of the treated formations. All available pieces of information pertaining to the monitoring and treatment wells were combined to give a calibrated velocity model, which lead to the accurate processing of the microseismic data acquired during the one-day long hydraulic fracture operation. The stimulation treatments utilized a titanate fracturing fluid system assisted with carbon dioxide. All six stages, except one that was surface pressure limited, were successfully placed with very little or no adjustment to the treatment design. All imaged fracture systems were oriented along the same azimuth. Larger than anticipated fracture heights were generated, and the acoustically-defined effective lateral extent of the various fracture systems was less than anticipated. Higher than designed fracture heights illustrate that it may be beneficial prior to the next design to measure specific formation mechanical parameters (e.g., in-situ stress, Young's modulus, Poisson's ratio, etc.) for simulation purposes. To minimize height development, fracturing fluids exhibiting lower fluid viscosity, injection rate adjustments, etc. have been recommended. Imaged fracture systems, all oriented along the same azimuth, suggested that present drilling pattern was inadequate for optimum drainage. Therefore, new locations for increased density drilling have been decided. Such wells are currently being drilled. To further complement the added value of the information obtained with this data, we are performing a prorated production analysis. This will help determining effective permeability, effective fracture half-length, fracture conductivity, and skin damage factors. As well as it will allow the design, execution and evaluation cycle to be complete and provide us with lessons learned and best practices to implement in upcoming wells and operations.