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GC3-D Seismic Data in Imaging Fracture Properties for Reservoir Development*
By
Bob Parney1 and Paul LaPointe2
Search and Discovery Article #40098 (2003)
*Adapted for online presentation from the Geophysical Corner column in AAPG Explorer October and November, 2002, entitled “Fractures Can Come Into Focus”and “Simple Seismic, Complex Fractures,” respectively, and prepared by the authors. Appreciation is expressed to the authors, to R. Randy Ray, Chairman of the AAPG Geophysical Integration Committee, and to Larry Nation, AAPG Communications Director, for their support of this online version.
1Axis Geophysics, Denver, Colorado ([email protected])
2Golder Associates, Redmond, Washington ([email protected])
It has long been recognized that the presence of naturally occurring fracture networks can lead to unpredictable heterogeneity within many reservoirs. Conversely, fractures provide high permeability pathways that can be exploited to extract reserves stored in otherwise low permeability matrix rock. One of the primary difficulties in managing fracture heterogeneity and the consequent uncertainty is that production rates and volumes are controlled by fracture network connectivity between the producing wells, while the primary sources of data on fracture properties are measured only in the vicinity of wells. In some ways this is like trying to predict the size of a schoolyard by close examination of a single link in the surrounding fence.
Recent advances in the processing of 3-D seismic data,
however, are providing valuable new tools for the imaging of fracture properties
between wells. Those tools are the analysis of seismic velocities as affected by
raypath direction and offset distance. Specifically, adjusting velocities as a
function of azimuth (velocity 
anisotropy
) to improve reflection imaging has
produced by-product data volumes of seismic velocity anisotropy (ANMO) and
improved data volumes of azimuthal changes in amplitude as a function of offset
(AVAZ).
These seismic advances raise the following questions:
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How do fractures influence these data?
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Geologically, what should this newly imageable level of fracture heterogeneity look like?
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How do we interpret this new data for fracture properties?
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How do we then make the link between fracture properties and reservoir performance?
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uTheory of seismic response to fractures uFracture orientation in Rocky Mountains uInterpreting multiple fracture set properties
uTheory of seismic response to fractures uFracture orientation in Rocky Mountains uInterpreting multiple fracture set properties
uTheory of seismic response to fractures uFracture orientation in Rocky Mountains uInterpreting multiple fracture set properties
uTheory of seismic response to fractures uFracture orientation in Rocky Mountains uInterpreting multiple fracture set properties
uTheory of seismic response to fractures uFracture orientation in Rocky Mountains uInterpreting multiple fracture set properties
uTheory of seismic response to fractures uFracture orientation in Rocky Mountains uInterpreting multiple fracture set properties
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Theory of Seismic Response To FracturesThe underlying theory behind the ANMO and AVAZ processing is quite simple: Most geophysical processing algorithms assume that all fractures are approximately vertical, and are locally oriented in a single dominant direction (Figure 1). The maximum detectable seismic effect is when the seismic raypath travels perpendicular to the open fractures, crossing the slow velocity, possibly fluid-filled, open fracture. A maximum and minimum direction of fracture influence on P-wave and S-wave velocity can be determined and used to indicate the dominant fracture orientation. The difference between the maximum and minimum effect gives some measure of the fracture intensity. This same process can be applied in a number of data volumes where the change in Vp or Vs as a function of azimuth is measured by the change in stacking velocities (azimuthal NMO) or the change in reflection coefficients (azimuthal AVO).
Fracture Orientation in Rocky MountainsA critical feature of recently processed AVAZ and ANMO data volumes has been that the dominant fracture orientation can change dramatically over short distances. Recent work on a project sponsored by the U.S. Department of Energy (www.fracturedreservoirs.com) shows that these changes are not only possible, but also highly likely in a Rocky Mountain compressional setting where the stress field is complex. The Circle Ridge Field, in Wyoming’s Wind River Reservation, Wind River Basin (Figure 2), was characterized through a combination of 2-D cross-sections and 3-D structural reconstructions based on well and surface data, and fracture data from surface outcrops and subsurface image logs. The fracture and structural data were supplemented with data from several transient well tests, a bromide tracer test and a nitrogen injection test. The structure is primarily determined by NE-SW compression, which caused the formation of a series of imbricate fault blocks along the Red Gully Fault, including several imbricates to the north (Figure 3). The entire structure has been characterized as a fault-breached, fault-propagation fold. Development of the structure is likely to have produced the fracturing within the reservoir units. Fracture development was predicted using strain calculated through a 3-D palinspastic reconstruction of the field. Figure 4 shows differences in extensional strain magnitude and orientation throughout a block of the Tensleep Formation in the hanging wall of the field’s Red Gully Fault. The contours and line lengths represent the magnitude of the maximum extensional strain due to the initial folding of the reservoir formations. The figure’s red lines represent the strike orientation of extensional fractures that would develop perpendicular to the local direction of maximum extensional strain. The red lines also show the dominant set; it is likely that a secondary joint set perpendicular to the set shown might also develop. Ninety-degree changes in dominant fracture orientation across fracture fairways seen in Figure 4 are consistent with orientation patterns predicted by AVAZ data in nearby reservoirs. These orientation variations arise due to inhomogeneities in the stress field and the resulting fracture networks are consistent with well image log and tracer data. Similar changes in fracture orientation occur in nearby outcrop at a much smaller scale (Figure 5). The black fractures occur only on the left portion of the outcrop, nowhere else. Red fractures dominate over blue fractures in the left portion, while blue fracture intensity increases markedly on the right hand side.
Since seismic
Interpreting Multiple Fracture Set PropertiesThe determination of fracture azimuth and intensity is usually based on the assumption that there is a single dominant fracture orientation, typically vertical. Frequently, fractures occur in several sets with cross-cutting orientations (Figure 6), and generally multiple sets are necessary in order to get well-connected plumbing for long-term productivity in the absence of high matrix permeability.
A number of attributes can be extracted from the seismic data. They can be grouped into two major categories:
Orientation attributes such as the fast P or S wave velocity azimuth were initially interpreted as the dominant fracture orientation. In the case of multiple fracture sets, the seismically sampled orientation is a function of the relative intensity of each fracture set. The net effect of multiple sets appears to be an average azimuth weighted toward the dominant set, although some data appear to show the seismic azimuth switching from one set orientation to another with no intermediate orientations apparent. For example, in an area characterized by a single dominant regional fracture trend orientation, any additional second fracture set may cause the attribute to appear to rotate away from regional trend, although there is no actual rotation of either of the fracture set orientations.
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Figure 1. A maximum and minimum direction of
seismic 
Figure 3. Outline of structural geometry for
Circle Ridge Field looking from north to south.
Figure 4. Magnitude and orientation of
fracturing in the overthrust block based on extensional strain
calculated through a three dimensional Palinspastic reconstruction.
Figure 5. Outcrop of Jurassic Nugget
Sandstone, Circle Ridge Field, Wind River Reservation, Wyoming, looking
to the north.
Figure 6. Example of multiple fracture sets
and the resulting velocity 
Figure 7. Examples of fracture networks that
would have similar seismic attributes over the volume delineated by the
square, but very different network permeability values.
Figure 8. Conversion of a DFN model of
fracturing into a finite element mesh for use in simulating flow and
transport through the fracture network.
Figure 9. Snapshot of pressure in the
fractures after injection. The colors indicate the pressure variations
in the network (Blue colors indicate high pressure, orange indicates low
pressure). Orange arrows show direction of flow out from the injector into
the fracture network. 
Figure 10. A DFN model with fractures curling
around the structure of a plunging anticline.