Fracture characterization
Understanding fracture orientation and their intensity are important for the development of unconventional reservoirs. The vertically aligned parallel fractures in the subsurface cause variations in some physical attributes of seismic waves, namely, amplitude, travel-time and velocity with azimuth that is evident on 5D-interpolated prestack time migrated seismic gathers, when sorted by common-offset and common-azimuth (COCA) as shown below.
The NMO corrected gathers for six different azimuths shown to the left. Though, travel-time differences corresponding to individual seismic reflection events exist on the azimuthal-sectored gathers, it is difficult to visualize them when the gathers are sorted in this way. The equivalent COCA display is shown on the right. The azimuthal travel time variations are evident at each offset bin of individual seismic reflection events as seen clearly on the zoomed portion displayed in the foreground. (Adapted from Sharma & Chopra, 2019)
Grechka and Tsvankin (1998) showed that azimuthal variation of NMO velocities can be expressed in the form of sinusoids or ellipses (in polar coordinates) whose ellipticity is proportional to fracture density and their major and minor axes delineate the orientation of the fractures. Besides, Ruger and Tsvankin (1997) demonstrated an approach of estimating fracture orientation and intensity by making use of azimuthal variation of amplitude. Thus, the analysis of variation of velocity with azimuth (VVAz) and amplitude variation with azimuth (AVAz) using wide-azimuth prestack seismic data can provide a promising way to estimate fracture properties, and are widely accepted techniques in the geophysical domain. However, it is worth mentioning that VVAz is a layer-based approach, and AVAz is interface-based. Consequently, both these approaches exhibit different results for the same properties. Additionally, the poor data resolution offered by VVAz technique, and limitation of AVAz technique in terms of 90-degree ambiguity associated with the extracted fracture orientation make it very challenging to extract reliable estimation of fracture intensity and their orientation.
The importance of fracture toughness in the estimation of seismic anisotropy and stress orientation in shale formations
It is well known that hydraulic fractures open in the direction of minimum horizontal stress which means the resistance offered by a formation in this direction is minimum. Consequently, fracture toughness must be minimum in the direction of minimum horizontal stress and maximum in the direction of maximum horizontal stress. Therefore, the azimuthal variation of fracture toughness should allow us to extract the maximum stress direction. Furthermore, the difference between minimum and maximum fracture toughness should provide the magnitude of anisotropy as per workflow shown below.
Workflow for estimating maximum horizon stress direction as well as magnitude of anisotropy using fracture toughness.
An arbitrary line section from the maximum stress orientation volume extracted using AVAz (upper) and proposed FT approach (lower). The estimated maximum stress orientation with AVAz approach is seen to exhibit excessive variation within the same formation, it looks more stable and reasonable when FT approach is followed. (Adapted from Sharma & Chopra, 2020)
Notice, while the maximum stress orientation extracted from the AVAz approach do not shown any stable pattern, the general trend seen on the display of the orientation extracted from the azimuthal variation of FT is consistent and appears to be NE-SW that matches with the regional trend noticed in WCSB. (Adapted from Sharma & Chopra, 2020)
Importance of fracture toughness in estimating fracture network pattern
A hypothetical situation when the formation offers (a) close to isotropic resistance to the fracture propagation i.e. the difference between minimum and maximum FT is low, and fractures can propagate in all directions; (b) Resistance is pronounced in specific direction i.e. the difference between minimum and maximum FT is high, and fractures can propagate in a preferred direction.
From the above figure, it is intuitive that complex fracture network is preferable if fracture toughness is same in all directions. Therefore, azimuthal variation of FT should allow to the extraction of such information. For this purpose, a new attribute named differential horizontal FT ratio (DHFTR) is introduced as
This attribute can be used along with HFC to identify the pattern of induced fractures as shown below
(Adapted from Sharma & Chopra, 2020)
(Adapted from Sharma & Chopra, 2020)
(Adapted from Sharma & Chopra, 2020)
References
Grechka, V., I. Tsvankin and J. K. Cohen, 1999, Generalized Dix equation and analytic treatment of normal-moveout velocity for anisotropic media, Geoph. Prosp., 47, 117-148.
Rüger, A., and I. Tsvankin, 1997, Using AVO for fracture detection: Analytic basis and practical solutions: The Leading Edge, 10, 1429–1434.
Sharma, R. K. and S. Chopra, 2019, Conditioning prestack seismic data in the offset-azimuth domain, published in the AAPG Explorer, October’19 issue, 18-19.
Sharma, R. K, S. Chopra and L. Lines, 2019, Adequate QC steps and their impact on reservoir characterization analysis, presented at 2019 Geoconvention, held at Calgary, in May. (O)
Sharma, R. K. and S. Chopra, 2020, Importance of fracture toughness and its azimuthal variation for fracability analysis, published in the AAPG Explorer, April’20 issue, 16-17.
Sharma, R. K. and S. Chopra, 2020, Role of fracture toughness in estimation of seismic anisotropy and maximum stress orientation accepted for 2020 SEG Convention. (withdrawal later on)