Microseismic Monitoring of the B-Sand Hydraulic Fracture Experiment at the DOE/GRI Multi-Site Project
Authors: Warpinski N.R. , Wright T.B. , Uhl J.E. , Engler B.P , Drozda P.M. , Peterson R.E. , Branagan P.T. 
Published: December 2007

Six hydraulic-fracture injections into a fluvial sandstone at a depth of 4500 ft were monitored with multi-level triaxial seismic receivers in two wells, resulting in maps of the growth and final geometry of each fracture based upon microseismic activity. These diagnostic images show that the hydraulic fractures are highly contained for smaller-volume KCl-water injections, but height growth is significant for the larger-volume, higher-rate, higher-viscosity treatments. Fracture lengths for most injections are similar. Final results are also compared with fracture models.

Introduction

The imaging of hydraulic fractures at depth has been a long-sought goal of the petroleum industry. Fracturing is an expensive, yet essential, element of production for many gas reservoirs and has significantly improved economics for many oil reservoirs as well. The Gas Research Institute and the US Department of Energy have long funded diagnostics programs and have achieved a slow but steady progress toward the realization of such technology. Fracture imaging is now attainable due to the improved capabilities of advanced receiver technology, advanced telemetry, and portable high-power computing. It is only characteristics of the reservoir and the well configurations which limit the potential of the technique. This paper describes the results of a series of fracturing experiments in a single reservoir interval that demonstrates the capabilities of this technology and its value to related issues of modeling and fundamental model mechanisms.

Background

Fracture diagnostics have a long history that includes production history matching, post-frac well testing, radioactive tracers, temperature logs, pressure decline analysis, treatment pressure analysis and modeling, surface tiltmeters, surface electromagnetic techniques, and various seismic techniques. All of these diagnostics are indirect, in the sense that they measure some parameter associated with the hydraulic fracture and infer fracture characteristics from the parameter or its changes. As with most indirect techniques, problems with uniqueness and inversion abound.

One of these techniques is different, however; and is capable of producing a highly accurate image of the fracture without the processing difficulties inherent in inversion problems. The microseismic method, one of several seismic technologies, is an indirect technique in that it monitors small faults or slippages that occur in the vicinity of the fracture (rather than the fracture itself), but is fully capable of producing an image of these microearthquakes. With proper interpretation models for the reservoir under consideration, the relation of the microseisms to the fracture can be clearly established. More importantly, for reservoirs with highly compressible fluids (e.g., gas reservoirs), the envelope of microseisms is approximately the same as the fracture size, with the exception of the width. Thus the microseismic method can produce relatively accurate images of the fracture length, height, and azimuth.

The microseismic technique is the primary diagnostic method employed to monitor fractures at the M-Site. It builds upon a technology proven in several elaborate field experiments, but with a focus of developing a viable, wireline-run, fracture-diagnostic service. As such, validation is an essential element of building confidence in this technology, and the M-Site experiments have been designed to provide that validation, particularly through the application of downhole inclinometers and intersecting wells.

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