Reflection P- and S-wave data were used in an investigation to determine the relative merits and strengths of these two data sets to characterize a naturally fractured gas reservoir in the Tertiary Upper Green River formation. The objective is to evaluate the viability of P-wave seismic to detect the presence of gas‐filled fractures, estimate fracture density and orientation, and compare the results with estimates obtained from the S-wave data. The P-wave response to vertical fractures must be evaluated at different source‐receiver azimuths (travelpaths) relative to fracture strike. Two perpendicular lines of multicomponent reflection data were acquired approximately parallel and normal to the dominant strike of Upper Green River fractures as obtained from outcrop, core analysis, and borehole image logs. The P-wave amplitude response is extracted from prestack amplitude variation with offset (AVO) analysis, which is compared to isotropic‐model AVO responses of gas sand versus brine sand in the Upper Green River. A nine‐component vertical seismic profile (VSP) was also obtained for calibration of S-wave reflections with P-wave reflections, and support of reflection S-wave results. The direction of the fast (S1) shear‐wave component from the reflection data and the VSP coincides with the northwest orientation of Upper Green River fractures, and the direction of maximum horizontal in‐situ stress as determined from borehole ellipticity logs. Significant differences were observed in the P-wave AVO gradient measured parallel and perpendicular to the orientation of Upper Green River fractures. Positive AVO gradients were associated with gas‐producing fractured intervals for propagation normal to fractures. AVO gradients measured normal to fractures at known waterwet zones were near zero or negative. A proportional relationship was observed between the azimuthal variation of the P-wave AVO gradient as measured at the tops of fractured intervals, and the fractional difference between the vertical traveltimes of split S-waves (the “S-wave anisotropy”) of the intervals.
This case history is one of three field projects funded by the US Department of Energy as part of its ongoing research effort aimed to expand current levels of drilling and production efficiency in naturally‐fractured tight‐gas reservoirs. The original stated goal for the 3-D P-wave seismic survey was to evaluate and map fracture azimuth and relative fracture density throughout a naturally‐fractured gas reservoir interval. At Rulison field, this interval is the Cretaceous Mesaverde, approximately 2500 ft (760 m) of lenticular sands, silts, and shales. Three‐dimensional full‐azimuth P-wave data were acquired for the evaluation of azimuthal anisotropy and the relationship of the anisotropy to commercial pay in the target interval. The methodology is based on the evaluation of two restricted‐azimuth orthogonal (source‐receiver azimuth) 3-D P-wave volumes aligned with the natural principal axes of the azimuthal anisotropy, as estimated from velocity analysis of multiazimuth prestack gathers. The Dix interval velocity, as well as the interval amplitude variation with offset (AVO) gradient, was calculated for both azimuths for the gas‐saturated Mesaverde interval. The two seismic attributes best correlated with commercial gas pay (at a 21-well control set) were (1) values greater than 4% azimuthal variation in the interval velocity ratio (source‐receiver azimuth N60E/N30W) of the target interval (the gas‐saturated Mesaverde), and (2) the sum of the interval AVO gradients (N60E + N30W). The sum of the interval AVO gradients is an attribute sensitive to the presence of gas, but not diagnostic of an azimuthal variation in the amplitude. The two‐azimuth interval velocity anisotropy mapped over the survey area suggests spatial variations in the orientation of the maximum horizontal stress field and the open (to flow) fracture system.
A multicomponent vertical seismic profile (VSP), cross‐dipole shear‐wave log, formation micro imaging (FMI) log, and oriented core were obtained in the Brady Ranch 1–5 well, Carter County, Oklahoma in November 1992. The intent was to study the properties of fractured intervals and the response of the seismic data with respect to fracture orientation. The primary zones of interest were the Sycamore and Hunton carbonates. A full nine‐component VSP was obtained from 152 to 3010 m. Data from a cross‐dipole shear‐wave log were obtained primarily in the deep carbonates at 2600–2900 m. The VSP and cross‐dipole data gave estimates of the orientation of azimuthal anisotropy in the section, and indicate three changes in the orientation of azimuthal anisotropy with depth. An east‐northeast orientation was obtained in the deepest zone, which includes the carbonate interval. The cross‐dipole data indicate anisotropy having east‐northeast, east‐south‐east, and approximately north‐south orientations in this zone. The cross‐dipole tool may be responding to small scale microcracks, which may have more random orientations than the larger scale macrofractures. FMI log data and oriented core, also obtained in the deep carbonate section, indicate macrofractures oriented in east‐northeast and east‐southeast directions.
Multiazimuth binning of 3-D P-wave reflection data is a relatively simple but robust way of characterizing the spatial distribution of gas-producing natural fractures. In our survey, data were divided into two volumes by ray azimuth (approximately perpendicular and parallel (±45 • ) to the dominant fracture strike) and separately processed. Azimuthal differences or ratios of attributes provided a rough measure of anisotropy. Improved imaging was also attained in the more coherent fractureparallel volume. A neural network using azimuthally dependent velocity, reflectivity, and frequency attributes identified commercial gas wells with greater than 85% success. Furthermore, we were able to interpret the physical mechanisms of most of these correlations and so better generalize the approach. The apparent velocity anisotropy was compared to that derived from other Pand S-wave methods in an inset three-component survey. Prestack determination of the azimuthal moveout ellipse will best quantify velocity anisotropy, but simple two-or four-azimuth poststack analysis can adequately identify regions of high fracture density and gas yield.
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