--> Abstract: Integration of New Fracture Observation, Characterization, and Fluid-flow Modeling Technology, by R. Marrett, S. Laubach, W. Rossen, J. Olson, and L. Lake; #90937 (1998).

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Abstract: Integration of New Fracture Observation, Characterization, and Fluid-flow Modeling Technology

MARRETT, RANDALL, Department of Geological Sciences; STEPHEN LAUBACH, Bureau of Economic Geology; WILLIAM ROSSEN, JON OLSON and LARRY LAKE, Department of Petroleum and Geosystems Engineering; all at University of Texas at Austin

Ongoing research is aimed at enhancing exploration and production for fractured clastic reservoirs, by development and integration of emerging and existing technologies for the observation, prediction, and fluid-flow modeling of natural fractures. Macroscopic fractures produce the largest impact on fluid flow through fractured rock, however they are orders of magnitude less abundant than microscopic fractures. Macrofractures in subsurface reservoirs typically are poorly represented by data acquired with conventional techniques. Due to the abundance of microfractures, they can be well studied even in small samples from the subsurface. We are exploring the hypotheses that micro- and macrofractures are different size fractions of the same fracture sets, and that microfractures can be used to predict the critical characteristics (in terms of fluid flow) of associated macrofractures.

Previously invisible quartz-filled microfractures are readily observed and characterized when their cathodoluminescence is imaged using scanning electron microscopy. This facilitates determination of the orientations, timing (relative to diagenetic events), and sizes of the numerous microfractures typically present in prospective fractured clastic reservoirs. These observations may be made systematically on a bed-by-bed basis. Orientations and timing of microfractures commonly compare favorably with those of associated conductive macrofractures.

Microfractures are sufficiently abundant in the numerous fractured clastic units we have studied, that the size distributions can be readily quantified. Under special circumstances, the sizes (i.e., mechanical apertures and/or lengths) of both micro- and macrofractures can be reliably measured in the same fractured rock volume. The spatial frequency of fractures, as a function of fracture size, follows power-law distributions over at least 4-5 orders of magnitude in these cases. This confirms that microfracture sizes can be used to quantitatively predict the spatial frequencies of associated macrofractures.

The orientations, diagenetic timing, and sizes of macrofractures are the most important factors for understanding fluid flow in fractured rock. Although discrete-fracture modeling provides the most realistic portrayal of fluid flow through fractured rock, this technique is computationally infeasible for simulation of the large volumes in a fractured hydrocarbon field. Dual-porosity simulation is the dominant technique for this reason. We are developing a blended approach to simulation that is both cost effective and grounded on local fracture observation.

On a bed-by-bed basis, microfracture observations are used to make statistical predictions of the key macrofracture attributes. From these predictions, multiple discrete-fracture models are generated for each bed, representing volumes comparable to those of the cells in dual-porosity simulations. Fluid-flow simulations in the discrete-fracture models provide a quantitative, observation-based understanding of the fluid-flow characteristics and spatial heterogeneity for each bed. These results can then be used to construct a dual-porosity simulation for large regions in the subsurface. Quantitative testing of this approach with subsurface flow data is ongoing.

AAPG Search and Discovery Article #90937©1998 AAPG Annual Convention and Exhibition, Salt Lake City, Utah