DE-AC26-00NT40690

Goal:
The goal of this project is to develop a next-generation fracture detection and characterization technology for producing natural gas from low permeability formations.

Background:
The research proposed here combines a new seismic shear wave (s-wave) imaging concept for 3-1 acquisition geometries with a new microfracture based analysis technique of oriented sidewall cores. This is the next-generation technology for detecting and characterizing subsurface fractures. The seismic component of this research is an approach that abandons the conventional industry practice of using Alford rotation to create fracture-sensitive s-wave images in 3-D geometries. Our investigation of existing industry practice leads us to conclude that data processing techniques, that separate s- waves into fast and slow modes in 3-D geometries, are fundamentally flawed. We propose that a new data- processing model, based on SH and SV mode concepts, be used in 3-D imaging of s-waves. This model is leading us to a new data-processing technology for detecting fractures when s-waves are recorded by 3-1 seismic templates. The seismic calibration portion of the research relies on collecting sidewall cores and then observing and classifying micro-fractures to calibrate fracture-sensitive seismic attributes.

Amplitude Contours

Performer: University of Texas at Austin Bureau of Economic Geology

Location:
Austin, Texas 78713

Project Impact:
This research used a new seismic shear-wave (s-wave) imaging concept for 3-D acquisition geometries for detecting and characterizing subsurface fractures. An unexpected change in an industry partner resulted in no core being available for microfracture studies. A new data-processing model based on SH and SV mode concepts were used for 3-D imaging of shear waves. Seismic data acquired across a fractured carbonate reservoir system illustrate how 3 component 3-D seismic data can provide useful information about fracture systems. Fast-S and slow-S data are used to illustrate how these effects can be analyzed in the prestack domain to recognize fracture azimuth, and then demonstrate how fast-S and slow-S data volumes can be analyzed in the post-stack domain to estimate fracture intensity.

Accomplishments:
The key observations from the study were:

• When a seismic propagation medium has a reasonable amount of anisotropy, converted-SV wavefields bifurcate into fast-S (S1) and slow-S (S2) modes.
• S1 and S2 azimuths can be estimated in the prestack domain by creating common-azimuth trace gathers of radial and transverse components of the reflected P-SV wavefield.
• Azimuth-dependent variations in propagation velocity and/or reflectivity are greater for P-SV reflected data than for P-P reflection data.
• Fracture orientation coincides with the azimuth in which there is the maximum reflectivity of the radial component of the P-SV wavefield. This concept was verified by well control.
• Using prestack determinations of S1 and S2 azimuths, 3C3D data can be processed to generate independent S1 and S2 data volumes.
• Attributes extracted from S1 and S2 data volumes can be used to infer key fracture properties, such as fracture orientation and relative fracture intensity.
• The ratio of S1-to-S2 reflection amplitudes indicated where fracture intensity for one targeted reservoir interval increased and decreased in a relative sense. This concept was supported by anecdotal information provided by the field operator.

Project Start: June 6, 2000
Project End: December 31, 2003

DOE Contribution: $599,367
Performer Contribution: $170,800

Contact Information:
NETL – Gary Sames (412-386-5067 or gary.sames@netl.doe.gov)
UTA – Robert Hardage (512-471-1534 or bob.hardage@beg.utexas.edu)

Additional Information:
Final Report - [PDF-6050KB]