Fractures Can Come Into Focus

Fracture Properties and Azimuthal Seismic Data — Part 1

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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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:

  • How do fractures influence these data?
  • Geologically, what should this newly imageable level of fracture heterogeneity look like?
  • How do we interpret this new data for fracture properties?
  • How do we then make the link between fracture properties and reservoir performance?

In this first of a two-part series we will examine the first two issues, with an example from the Wind River Basin.

Theory of Seismic Response To Fractures

The 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).

The complex effects of multiple, non-vertical fracture sets will be covered next month. Thus, an important interpretative step still remains between the seismic data and using it to predict fracture orientation and intensity.

Fracture Orientation In Rocky Mountains

A 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, 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 2).

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 3 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 3 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 4). 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 anisotropy can be influenced by the presence of natural fractures — and that a high degree of variability in fracture orientation and intensity is to be expected in a Rocky Mountain compressional setting — interpretation of seismic data requires a sound link with knowledge of the fracture geology in a region.

Next month: How the seismic data is interpreted for multiple fracture sets, and how fracture data is then linked to reservoir performance.