A Tomographic Fracture Image™ in the Eagle Ford, showing an oblique view of the wellbore with microseism hypocenters (blue dots) and one-voxel-thick slice of the image at the wellbore.
For the most part, the proverbial “man on the street” tends to think of hi-tech as being synonymous with the latest pop culture electronic gizmos.
The fact that the oil and gas industry overall is essentially the epitome of hi-tech just isn’t on the radar screen of the general populace.
But it should be: One of the latest esoteric developments in the seismic sector of the industry is Tomographic Fracture Imaging (TFI).
The newly available, patented TFI technology originated at STRM LLC, which was acquired by Global Microseismic Services (GMS), a subsidiary of Global Geophysical Services.
“We have been validating this technology for many years, including analysis over unconventional resource plays,” noted STRM founder and AAPG member Peter Geiser, chief technologist for tomography-based natural fracture imaging at GMS.
Simply speaking, the technology is a passive-microseismic surface-based array method for imaging both natural and induced fractures on a reservoir scale. TFI delivers detailed images of the fracture networks in reservoirs via tomographic analysis of energy emitted from subsurface activity such as hydraulic fracturing, hydrocarbon production or the natural background seismicity of the earth.
TFI directly images the fracture flow paths in the reservoir as complex surfaces, which is orders of magnitude beyond the current, familiar industry standard of dots-in-a-box display during fracture monitoring.
The new technology utilizes a novel approach to Seismic Emission Tomography (SET) in combo with empirical data on fracture geometry. SET is a technique for imaging sources of seismic energy contained within the volume being imaged.
The seismic energy is recorded by a surface or near-surface receiver array. The collected data are processed to provide a 3-D grid of voxels, or 3-D pixels, with node points at the body center of each voxel cube.
The TFI method looks at cumulative signals from each voxel over time rather than attempting to single out individual microseismic events.
In addition to direct mapping of fracture/fault networks, the technology provides a more confident representation of reservoir connectivity than traditional microseismic techniques.
Another advantage is the ability to I.D. fracture propagation rates.
When tomographic images are time sequenced, they can illustrate the rate of energy propagation away from the wellbore.
In other words, data gathering in time enables the interpreters to see movement of acoustic energy in the reservoir. Independent data show these pathways to be permeability corridors.
The reservoir permeability field can be mapped via the summary of natural and induced responses to changes in reservoir pressures presented by the TFI data.
The time-sequenced images of TFI have the capability to show:
- Rate of hydraulic fracture propagation.
- Dynamic features of the fracture interaction with the rock.
- Movement of pressure responses away from the hydraulic fracture.
- Reservoir rock response to these pressure changes (such responses show the likely optimal production horizons).
Nailing reservoir boundaries is of prime importance to geoscientists and others, and TFI can be used to image the lateral and vertical connection – or isolation – of the hydraulic fracture energy. Acquiring information that this energy impacted only the reservoir rock and nothing else of significance, such as, an overlying aquifer, is undeniably a good thing.
Advanced information about geological events that can affect drilling decisions is invaluable to help ensure a smooth running drilling operation. Geiser says TFI has the capacity to:
- Recognize the in situ stress regime.
- Predict the presence of active fault/fracture networks ahead of the drill bit.
- Identify a reservoir’s most productive areas.