Three-D compressional (P-P) reflection seismic is the standard tool of choice to determine structural setting, depth to target, drilling path, and faulting. Three-D P-P full-azimuth reflection seismic gives the added information about the in situ horizontal stress field – the azimuth of the local maximum horizontal stress and the inequality of the horizontal stresses as well as the vertically aligned fractures open in the subsurface – to determine fracture azimuth and relative fracture density for one set of vertically aligned fractures. Full-azimuth 3-D typically denotes the use of a square receiver patch as opposed to a long, skinny receiver patch of geophones so that offsets equaling target depth are recorded over 360° of source-receiver azimuth.

Measuring the stress field

These azimuthal changes in P-P travel times are first quantified as azimuthal normal moveout velocity and then quantified as azimuthal interval velocity (VINTaz). VINTaz is the proper quantity to evaluate for reservoir characterization. The far offset, where offset is defined as the distance from source to receiver, must be approximately equal to target depth to best use this technique. These far offsets, traveling at angles of incidence of 30° to 45° off vertical, are sensitive to the effective horizontal stress in the direction of source to receiver. The fastest travel time is parallel to the maximum horizontal stress; the slowest travel time is parallel to the minimum horizontal stress.

Laboratory measurements have demonstrated that as stress increases, the P-wave velocity in the direction of the increased stress also increases. For shear waves, as the stress is increased, the S-wave with either wave direction or particle motion in that direction has an increased velocity. Thus, in situ stress affects both travel time and amplitudes, the latter of which are governed by the contrast of impedance (density times velocity) at the boundary.

The interval velocity is best calculated over an interval of fairly uniform lithology, bounded by reflections at the top and base of the interval. About 40 milliseconds to 50 milliseconds two-way time is a large enough thickness for the interval velocity to be fairly stable. As the interval thickness decreases, the interval velocity becomes unstable. Equal horizontal stresses in such an interval will result in no azimuthal variation in interval velocity; unequal horizontal stresses will cause azimuthal variation in the interval velocity. A decrease in the minimum horizontal stress associated with a low breakdown pressure for a uniform mineralogy and porosity rock is associated with a decrease in the minimum (slow) interval velocity. Therefore, if one desires a low breakdown pressure and the frac job to create a complex fracture network, low minimum horizontal stress and equal horizontal stresses would be desired.

Finding fractures

Rich and Ammerman (2010) described a case history where the microseismic measured during the frac job indicated a wide complex fracture network when those stages were situated in zones of small azimuthal variation in interval velocity. Moreover, it was precisely those stages that had the pressure treatment curves associated with better production.

Interval velocity is affected by several factors: depth of burial, mineralogy (lithology), porosity, and pore fill, as well as by in situ stress. The effects of each of these variables on the targets in the 3-D survey must be investigated.

If there is one set of open vertically aligned fractures, then both the P-wave and S-wave velocities are affected azimuthally. The best place to look for the evidence of natural fractures is in the amplitudes, specifically the amplitude variation with offset and azimuth. Azimuthal anisotropy in seismic data is caused by unequal horizontal stresses and/or vertically aligned fractures. Distinguishing between unequal horizontal stresses vs. vertically aligned fractures by means of acquiring proper calibration data as well as azimuthal seismic is one of the seismic industry's forefront objectives.

The co-rendering of curvature (most positive curvature, most negative curvature, etc.) with the azimuthal interval velocity can give insight as to whether the rocks appear held in extension or in compression as well as the location of the neutral plane, wherein the rock is held neither in compression nor extension.

The inversion attributes, Lambda-Rho and Mu-Rho, are typically used to evaluate the brittleness of the unit under study. Joel Starr (2011) showed how Poisson's ratio, derived from both of those inversion attributes, can be used to estimate the stress gradient attribute. This attribute is associated with the closure stress, commonly assumed to be equivalent to the minimum horizontal stress. The technique can be expanded to the azimuthal P-P seismic world, where the amplitudes in the slow VINT direction are taken through inversion and the calculation of Poisson's ratio.

image- 3-D P-P full-azimuth reflection seismic map

Three-D P-P full-azimuth reflection seismic gives additional information about stresses in the reservoir, aiding in fracture detection. (Image courtesy of Lynn, Jefferson, and Ammerman, from 12th International Workshop on Seismic Anisotropy, 2006)

Necessary data

Different basins have different geologic histories, lithologies, etc., so the above assertions must be tested against a company's own database. This database would include, at a minimum:

  1. Every multi-arm caliper log in the area of interest. These are routinely run by engineers to evaluate the shape of the borehole to ensure the proper volume of cement is used. These logs, when showing borehole ovality, reveal the local in situ horizontal stress field, with the in-gauge direction being the maximum horizontal stress direction. Areas of interest are above target, at target, and below target (where possible). What is of interest is the change in the stress field both vertically and laterally throughout the 3-D survey and the area of interest;
  2. Three-D azimuthal P-P seismic and/or 3-D 3-C azimuthal seismic (P-P and P-S processed for azimuthal variations in interval velocity and amplitude). In a case history from the Marcellus shale (Bell et al., 2012), 3-D 3-C data were acquired, processed, and evaluated for azimuthal anisotropy. The findings were interpreted to be sensitive to the populations of in situ, natural vertically aligned fractures, and the authors did find evidence of the two dominant fracture sets, the J1 and the J2;
  3. Microseismic and frac job parameters (pumping rate, pumped volume, breakdown pressure, etc.) and production data (stage by stage);
  4. Wireline logs, cores, and laboratory measurements on cores, as time and budget permit; and
  5. Any interference data showing communication between wells.

In five to 10 years the industry will be routinely evaluating azimuthal variations of travel time and amplitude on prestack depth-migrated data. Prestack depth migration is the industry's most powerful and sensitive imaging technique, and azimuthal prestack depth migration has the added benefit of displaying the faults in the same place, regardless of source-receiver azimuth, when the velocity model is correct.