Natural Fracture Recovery from Seismic Data
Tight oil reservoirs have accelerated the development of seismic imaging and reservoir characterization methods that greatly enhance geoscientists’ understanding of the geomechanical properties of the subsurface. Today, seismic imaging procedures can use surface recorded seismic data to recover images of fracture intensity, fracture density, fracture orientations, stresses, brittleness, facies, and even estimates of total organic carbon. These images can help geoscientists and engineers define permeability and low stress zones, identify preferred drilling directions, and optimize well spacing.
To recover and model fracture orientations and intensities, geophysicists must be able to observe and detect amplitude or velocity differences as a function of in-situ azimuth. Fractured reservoirs or reservoirs under stress exhibit anisotropic amplitude or velocity behavior described by variations along the principle axes of stress symmetry. Two types of fracture related anisotropy that are routinely modeled in tight oil formations include HTI anisotropy and orthorhombic anisotropy. The former describes vertical fractures in homogeneous media while the later describes vertical fractures in layered or compacted media. Accurately measuring and describing these conditions requires the best from the seismic method in velocity determination, imaging and inversion.
While all of this sounds routine, outcomes from traditional seismic imaging and inversion methods are frequently determined to be unsatisfactory or unreliable. Traditional approaches for fracture determination using the seismic method often rely on azimuthal sectoring approaches, where the azimuths are measured at the acquisition surface. Unfortunately, this process both under-samples and averages the data, masking and compromising the seismic signatures that are required to accurately measure fracture and stress orientation and intensity. Additionally, accurate determination of fracture properties from seismic data requires that we localize the seismic operator in-situ, like the way a cross dipole sonic tool scans a formation. This is not a trivial process. To do so requires localization of the seismic operator in depth so that the recorded seismic data can be reconstructed with the highest levels of directional (azimuthal), temporal and amplitude resolution.
To improve on these traditional processes, a new procedure for the seismic imaging and characterization of fractures has been developed. This procedure performs a five-dimensional (5D) decomposition and imaging of surface recorded seismic data, in-situ, in depth, and over all azimuths and angles. This remarkable “full azimuth” imaging and characterization procedure generates prestack gathers described by 360 degrees of full azimuth reflectivities (amplitudes) so that inversion methods can recover fracture orientations and intensities at the highest directional resolution as possible. This breakthrough and patented method has been demonstrated to measure fracture anisotropies of less than 1% at depths of 12,000 feet. It provides geoscientists with new deliverables to prospects for natural fracture swarms and sweet spots, while providing drilling engineers with new deliverables for safe and economic well planning.