Microseismic Monitoring of the B-Sand Hydraulic-Fracture Experiment at the DOE/GRI Multisite Project
- N.R. Warpinski (Sandia Natl. Laboratories) | T.B. Wright (Resources Engineering Systems) | J.E. Uhl (Sandia Natl. Laboratories) | B.P. Engler (Sandia Natl. Laboratories) | P.M. Drozda (Sandia Natl. Laboratories) | R.E. Peterson (Branagan & Assocs. Inc.) | P.T. Branagan (Branagan & Assocs. Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- September 1999
- Document Type
- Journal Paper
- 242 - 250
- 1999. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 4.3.4 Scale, 6.5.2 Water use, produced water discharge and disposal, 3 Production and Well Operations, 2.4.3 Sand/Solids Control, 5.6.5 Tracers, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.2.2 Perforating, 5.5.8 History Matching, 3.3.2 Borehole Imaging and Wellbore Seismic, 5.6.6 Cross-well Tomography, 5.6.4 Drillstem/Well Testing, 1.14 Casing and Cementing, 5.4.2 Gas Injection Methods
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Six hydraulic-fracture injections into a fluvial sandstone at a depth of 4,500 ft were monitored with multilevel, 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 regardless of volume and fluid type.
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 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.
Fracture diagnostics have a long history that includes production history matching, postfrac well testing, radioactive tracers, temperature logs, pressure decline analysis, treatment pressure analysis and modeling, surface tiltmeters, surface electromagnetic techniques, and various seismic techniques. Most 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, the inversion process can introduce large uncertainties.
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,1-6 one of several seismic technologies, is an indirect technique in that it maps the locations of microseisms (small shear slippages on natural fractures, bedding planes or other weak features) occurring in the vicinity of the fracture (rather than the fracture itself). However, these microseisms can be accurately located and they do not require any inversion algorithms that suffer from uniqueness and resolution questions. With a proper understanding of the microseismic activity expected for the reservoir under consideration, the relationship of the microseisms to the fracture can generally be clearly established. For example, in reservoirs with highly compressible fluids (e.g., gas reservoirs), the envelope of microseisms approximates the fracture dimensions, 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 map hydraulic fracture geometry at the M-Site — the focus of this paper. Microseismic imaging technology, conducted in several elaborate field experiments,1,7-10 has evolved to the point where a wireline-run, fracture-imaging service is practical. In the process of conducting these field experiments, verification that the imaged fracture geometry closely approximates the actual fracture geometry has been an essential objective to build confidence in this technology. The M-Site experiments have been designed to provide that validation, particularly through the application of downhole inclinometers and intersecting wells used as independent techniques to confirm fracture geometry. In addition to improving fracture diagnostics, a secondary goal of the M-Site experiments has been to improve and validate fracture models and to better understand fracture-growth mechanisms. This goal was accomplished by performing tests in a reservoir with measured properties, fully monitoring the fracture treatments, obtaining time-imaged fracture geometries, comparing the diagnostic results with various models, and using specialized fracture monitoring technology (i.e., an intersecting well) to provide previously unavailable information.
In depth details of the M-Site layout and fracture treatments are given by Peterson et al.11 and are only briefly repeated here. The M-Site field experiments, located at the previous Multiwell Experiment site in the Piceance basin of Colorado, are co-funded by the Gas Research Institute (GRI) and the US Department of Energy. The reservoirs undergoing testing are fluvial Mesaverde sand-shale sequences, so the technologies developed in this difficult environment are easily translatable to many other reservoirs throughout the world. Details of previous work can be found in several papers and reports.9-12
A schematic of the well, instrument, and sandstone-reservoir layout are shown in Fig. 1. The site consists of one treatment well (MWX-2), one monitor well with cemented-in triaxial seismic receivers and biaxial inclinometers, and one cased observation well for wireline run tools (MWX-3). Not shown in the figure are deviated lateral intersection wells that penetrate through the created hydraulic fractures in each sandstone.
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