Fizz-gas and commercial-gas reservoirs look identical in stacked P-P seismic data and in migrated P-P images – and the failure of traditional post-stack P-P data to distinguish between these two gas saturations has frustrated efforts by operators to avoid drilling fizz-gas targets for decades.
A solution now appears to be available through the use of multicomponent seismic technology.
Specifically, when multicomponent seismic data are used to illuminate gas reservoirs, the converted-shear (P-SV) image constructed from these data can distinguish between fizz-gas and commercial-gas reservoirs.
Key petrophysical properties that need to be considered when applying multicomponent seismic technology to gas exploration are summarized in figure 1. This figure shows a reservoir interval (labeled 1) overlying a water accumulation (labeled 2).
Variations in bulk density ρ, P-wave velocity VP, and S-wave velocity VS are tabulated for three reservoir conditions: water, fizz gas and commercial gas.
The comments in the table describe the changes in these rock properties that occur within the target layer as the seismic imaging moves along horizon AA´ and crosses the fluid contact boundary that separates region 1 (reservoir) from region 2 (non-reservoir).
If equations for P-P and P-SV reflectivities are reduced to their simplest forms, P-P reflectivity is found to be a function of ∆ρ, ∆VP and ∆VS, the parameters tabulated in figure 1. In contrast, P-SV reflectivity is a function of only ∆ρ and ∆VS, and ∆VP is not involved.
This distinction between the petrophysical parameters that influence P-P and P-SV reflectivites is important.
Seismic reflectivity along interface AA´ shown in figure 1 is critical to interpreting pore fluid conditions within the reservoir unit. For both commercial-gas and fizz-gas conditions, the lateral change in P-wave reflectivity along horizon AA´ will be large where the seismic image transitions from reservoir to non-reservoir conditions because the lateral change in P-wave velocity (∆VP) is large across the fluid contact boundary for both high and low gas saturations.
As a result, both commercial-gas and fizz-gas targets look identically bright in stacked and migrated P-P seismic images.
Keeping in mind that P-SV reflectivity is influenced by only ∆ρ and ∆VS, a second concept documented in figure 1 is that the lateral change in P-SV reflectivity will be rather large across the fluid contact boundary only if the reservoir contains a commercial saturation of gas.
Of the three reservoir options listed in figure 1, there is a significant lateral change in bulk density ∆ρ across the fluid contact boundary only for a high-gas saturation condition. For a fizz-gas reservoir, the lateral variation in P-SV reflectivity will be small or nonexistent because neither bulk density ρ nor
S-wave velocity VS varies significantly as the pore-fluid conditions change laterally from fizz water to 100 percent pore water. Commercial gas should thus appear brighter in P-SV images than fizz gas does.
To confirm these principles, P-P and P-SV images across a fizz-gas reservoir are shown in a side-by-side display in figure 2. The reservoir is a bright spot in the P-P image, but there is no anomaly in the P-SV image.
P-P and P-SV images of a commercial-gas reservoir are shown in figure 3. Again, the reservoir is a bright spot in the P-P image, illustrating it is not possible to use only the stacked and migrated P-P data in figures 2 and 3 to distinguish fizz gas from commercial gas. However, the commercial-gas reservoir in figure 3 creates a modest amplitude anomaly in the P-SV image. This P-SV reflectivity behavior is predicted by the large lateral variation in bulk density ∆ρ listed for a commercial-gas target in figure 1.
The difference between this P-SV reflectivity across a commercial-gas reservoir and the P-SV reflectivity across a fizz-gas reservoir shown in figure 2 allows fizz-gas reservoirs to be distinguished from commercial-gas reservoirs with rather good success.
A major challenge to overcome when using multicomponent seismic data is that an interpreter has to decide how to accurately depth register the P-P and P-SV images that are compared.
Note in the examples in figures 2 and 3, the target in P-SV image space is positioned at time coordinates that are approximately (but not exactly!) a factor of two greater than the time coordinates of the target position in P-P image space. The time-warping factor that should be used to adjust P-P and P-SV images to a depth-equivalent interpretation space varies laterally and vertically throughout seismic image space and will rarely be the same function at any two reservoir targets.
Some of the techniques used to define these dynamic and spatially varying time-warping factors were discussed in last month’s “Geophysical Corner.”
Acknowledgements: Devon and Seitel Data provided the 4C OBC data used in this research. The U.S. Department of Energy provided the research funding.
(Editor’s note: The authors are all with the Bureau of Economic Geology in Austin, Texas.)