Multicomponent seismic technology can improve the economic success of tight gas exploration and production.

S-wave propagation through azimuthal and anisotropic medium of parallel vertical fractures. A S-wave entering this medium oblique to the fracture planes splits into two waves with the polarization of the faster (S1) wave parallel to the fractures. (Modified from Martin, M.A. and Davis, T. L. [1987] “Shear-wave birefringence: A new tool for evaluating fractured reservoirs.” The Leading Edge, 10, 22-28. Figures courtesy of RCP)

The Colorado School of Mines Reservoir Characterization Project (RCP) is currently researching multicomponent seismic applications to tight gas sand exploration and production at Rulison field, Colo. Rulison field is located in the Piceance Basin of Colorado. It produces from tight gas sandstones of the Late Cretaceous Williams Fork Formation. The best production is associated with a “sweet spot” in the middle of the field involving a naturally fractured zone where the minor fracture system is open. High expected ultimate recovery (EUR) wells are associated with this fairway. Stacked, amalgamated, fractured sandstone bodies, connected by hydraulic fracturing, provide the drainage volume and enhanced permeability that leads to wells with high EUR.

Fractured sandstone bodies at Rulison cannot be detected with conventional compressional (P)-wave seismic data. Shear (S) waves offer the potential to detect these fractured geobodies because of the elastic impedance contrast that occurs between the fractured sandstone bodies and the surrounding shales.

Naturally fractured sandstone geobodies connected to the well bore constitute the main target for drilling and completions at Rulison. As a result, fractured geobody detection could change the strategy of well placement from grid drilling to precise target drilling, thus improving the economics of tight gas sandstone exploration and development. Reserve growth can be achieved and recovery efficiency improved if depleted zones can be avoided and bypassed reserves can be added through precise target drilling.

 S-wave seismic anisotropy

Aligned vertical fractures cause anisotropy which can be detected seismic. Seismic anisotropy is best exhibited in this tight gas environment by measuring S-wave splitting. An initial S-wave will split into two waves when it encounters anisotropy caused by vertically aligned fractures (Figure 1). The resulting two S-waves are recorded and separated as a fast (S1) and slow (S2) wave that can be used to calculate the amount and direction of anisotropy. Cross-dipole sonic logs run in a few of the newly drilled wells measured anisotropy ranging from a few percent up to 25% in the highly fractured intervals. The log anisotropy range for the fractured intervals is typically between 3% and 10% and lower for unfractured sandstones. These ranges in log anisotropy values are the same ranges that we would expect to see in S-wave seismic anisotropy for fractured and unfractured zones.

S-wave seismic anisotropy analysis is normally done as a horizon-based analysis by comparing travel time and amplitude differences between the S1 and S2 split S-wave seismic. Since this type of thin-bed anisotropy determination is only applicable for short time windows around the horizons of interest, the thick reservoir interval and the lack of continuous reflectors of the seismic at Rulison Field challenge the accuracy of this horizon-based approach. To better estimate the horizontal and vertical changes in anisotropy throughout the thick heterogeneous reservoir, a new volumetric approach to anisotropy determination was developed to make anisotropy detection more applicable and robust. This approach starts with the use of the warping algorithm in Transform Software to remove the time-shift between S1 and S2 volumes by moving the S2 volume into the S1 time domain. This type of algorithm is normally used to move converted-wave data into the P-wave time domain for registration. The time shifts applied to each S2 reflector match it to the corresponding S1 reflector varied horizontally and vertically and provide a low-resolution travel-time difference anisotropy estimate.

These aligned volumes were then used to create a high-resolution anisotropy volume by differencing and normalizing elastic impedance inversion volumes of the S1 and S2 data sets. Figure 2 shows a seismic line of this volume with a smoothed anisotropy log from an intersecting well overlain. There are large variations in anisotropy values in the seismic line and the well log that indicate that some sandstones are fractured and others are not. At many depths where the log is overlain on the seismic, the magnitude of the log anisotropy and the seismic anisotropy are nearly the same. This is not a perfect correlation, but for a well-to-seismic tie in a reservoir like Rulison, it is quite good. Correlation between the high-anisotropy zone and the other cross-dipole logs in the RCP area is good except in the low-fold areas on the edge of the study area.

All of the high-EUR wells intersect zones of high-impedance anisotropy. The best producing well in the field, in the middle of the survey area, is drilled through an area of high-impedance anisotropy near the Cameo Coal interval, which indicates increased natural fracturing in the rock near the coals. A fracture connection to the coals could explain the well’s anomalously high and steady production. Well ties and time-lapse seismic data verify that the anisotropy volume is detecting the fractured geobodies producing in this well.

Similarity

Similarity, a coherency-based seismic attribute, was explored to enhance the detection of anisotropy in the subsurface. A similarity difference volume was calculated by taking the difference in similarity between the S1 and S2 impedance volumes after time registration alignment. The values in this volume represent the percent difference between the S1 and S2 similarity volumes with a positive and negative scale that illustrates which trace ensemble is changing. If the S2 changes more than the S1, it is shown in red or positive; if the greater change is in S1, then it is shown in blue or negative. In this manner, a dominant fracture orientation is implied though the color scheme. S2 is sensitive to the dominant open fracture set oriented to the northwest at Rulison.

The largest number of anisotropic anomalies occurs in the Middle Williams Fork Formation. This interval has a higher percentage of sandstone and is capable of sustaining open fractures. Figure 3 shows the position of fractured sandstone bodies on a horizontal slice through the Middle Williams Fork interval. This depiction shows a remarkable image of fractured fluvial sandstone bodies in plan view. All high-EUR wells encounter these fractured geobodies, primarily the fractured geobodies detected by the S2. Notice how many of these fractured geobodies have not been encountered by any of the wells, and these wells are already drilled at nearly 10-acre spacing. Remember that this is only a single slice and that a volume rendering is essential to visualize these features in three dimensions. Armed with this volume and impedance anisotropy volume, wells can be precisely drilled to target these fractured geobodies and improve the economic success of drilling tight gas sandstones at Rulison Field.

Conclusions

High-EUR wells are those that connect naturally fractured geobodies to the well bore through hydraulic fracture stimulation. Natural fractures increase permeability, the most important reservoir parameter in tight gas sand development. Connecting natural fracture permeability to the well bore is critical to economic production. Locating permeable geobodies is critical to tight gas exploration and production because of the marginal economic thresholds associated with development. Increasing these margins through technology is critical to economic success. Volumetric anisotropy and similarity analysis of multicomponent seismic is a technology that can improve the economic success of tight gas exploration and production as demonstrated at Rulison field.

Acknowledgements

The authors wish to acknowledge Williams RMT Company, operator of Rulison field, for permission to conduct this work, and we would like to thank all of the sponsors of the Reservoir Characterization Project.