Well-to-well hydraulic fracture conductivity tests were performed in a fluvial sandstone reservoir at the M-Site project in Colorado. These field-scale conductivity measurements involved pumping water between two test wells and through one wing of a previously induced propped hydraulic fracture system. The length of the tested fracture interval was 126 ft. Analysis of the measured data yields an average fracture conductivity, kfwf, of 650 md-ft. This is in sharp contrast to laboratory studies that predict a frac conductivity of 2000 md-ft.

Although the existing fracture system was somewhat complex, including as many as 11 induced fractures, the proppant appears to have been confined to only one or two of them. Reduced frac conductivity can be attributed to several parameters, all of which tend to surreptitiously increase pressure losses within the frac system. Fracture stranding, corners, localized width reductions, and other complexities inherent in multiple frac systems can be the root cause of this reduced conductivity.

This study to the best of our knowledge marks the first in-situ, field-scale, frac conductivity measurements and supports the axiom, nature may be simple but manifests itself in complex ways.


Field-scale imaging and characterization of hydraulic fractures are critical elements in accurately assessing the performance and effectiveness of such treatments. A great deal of emphasis has been placed on the use of various hydraulic fracture modeling techniques in both the treatment design and evaluation process. However, recent advances in remote fracture imaging techniques employing microseismic and vertical inclinometer arrays have now added a new dimension to this evaluation process. These emerging diagnostic technologies provide independent information that can be used in directly mapping and imaging a specific fracture. Further they also provide calibration points for fracture model designers from which to assess their models and further improve the accuracy used in defining explicit fracture mechanisms.

Fracture diagnostics research conducted during the past several years at the Gas Research Institute (GRI)/Department of Energy (DOE) Multi-Site Project (M-Site) was designed to provide industry with just such a technological boost. A series of fracturing experiments were conducted at the M-Site to provide researchers with a field-scale laboratory from which to assess and develop various diagnostic methods. The microseismic imaging technique was the primary diagnostic method used, verified and improved at the M-Site.

One of the verification techniques employed at the M-Site to validate both the microseismic and vertical inclinometer results involved the drilling of a remote intersection well. This intersection well was designed to crosscut the hydraulic fracture system that had been previously defined by the microseismic and inclinometer diagnostic interpretations. In addition to providing far-field fracture dimension, azimuth and other related fracture characteristics, the intersection well provided a unique opportunity to measure in-situ hydraulic fracture conductivity on a field scale. This paper will present the field data and results from well-to-well frac conductivity tests performed at the M-Site in the B Sand.


A series of experimental hydraulic fracture injections and associated fracture diagnostic activities were conducted at the M-Site in a gas-bearing fluvial sandstone reservoir, designated the B Sand. The depth to the top of this 30-ft-thick sandstone is 4527 ft.

Figure 1 provides a plan view of the M-Site detailing project-related well locations and the predicted hydraulic frac azimuth for the B-Sand fracture experiments. Data analyses of microseismicity associated with the fracture process zone provided plan and profile map views of the fracture, while FRACPRO 6 simulations and inclinometer results yielded correlative dimensional frac characteristics, e.g., length, height, and width.

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