The E&P industry has wrung enormous value from 3-D seismic, yet the demands made on this technology continue to increase.
For instance, seismic data are needed to support a whole new level of imaging quality necessary to better explore and exploit the many complex, often unconventional reservoirs, e.g., tight sands and fractured shales, commonly targeted by industry today. Conventional 3-D seismic technology, however, falls short of providing the needed information.
It's time to kick it up a notch.
Enter full-wave seismic, which is positioned to become the next new thing in seismic imaging technology, according to a number of industry experts.
Full-wave seismic acquisition and processing provide adequate sampling of the full seismic wavefield, which is essential for producing the best possible subsurface image, according to Joe Jacquot, director of product marketing at Input/Output (I/O).
Full-wave technology records the complete ground motion from both pressure (P) and shear (S) waves in three dimensions using MEMS (micro-electro-mechanical system)-based accelerometers.
In contrast, the standard analog geophone arrays measure only the vertical component of the seismic waves reflected from the subsurface. Eliminating the conventional phone array has the added benefit of lighter, less bulky equipment and greater operational efficiency.
Seeking Subsurface Resolution
The technology required for land full-wave imaging consists of high vector fidelity, three-component, single point receivers and high capacity land acquisition systems capable of supporting the high receiver densities and large channel count operations required by wide azimuth and long offset recording, according to Jacquot.
The purpose-built, multi-component VectorSeis and DSU systems of I/O and Sercel, respectively, currently serve the full-wave market.
Digital sensors deployed as point receivers measure any energy impinging on them whether it's seismic or source-generated noise, which can be removed in processing. They can be deployed at any angle because they are insensitive to orientation.
While geophones act as a filter on the highest seismic frequencies, the point receivers record a wider bandwidth of signal, including both higher and lower frequencies. This results in better resolution of subsurface layers, which can be particularly beneficial when planning placement of horizontal wells, according to Jacquot.
"Because these receivers use accelerometers, they measure acceleration rather than velocity, so they can measure lower frequencies down to 1-2 Hz," Jacquot said.
"The point with recording lower frequencies is you can do a better job with seismic inversion, whereas the preservation of higher frequencies lets you see thinner beds in the subsurface.
"Another thing, because you can measure ground roll characteristics, there's the potential to do a better job of modeling near surface velocity variations," Jacquot said. "If you can model velocity and thickness properties of these layers, then you can do a better job of removing their influence during processing and end up with a clearer seismic image."
An added benefit of full-wave technology is the concept of a wide azimuth survey. Point receivers deployed in wide azimuth surveys give a much better idea of anisotropy -- or azmuthmal variations in velocity -- and that gives a better indication of the fracture regime at the reservoir level.
This is particularly meaningful when working in carbonates or a formation such as the Barnett shale.
Because geoscientists in general are still struggling to get their collective arms around the still-challenging shear wave data, particularly when it comes to processing, these data sometimes might be considered extraneous information gleaned from full-wave seismic. The advantage is they will be in-house when the technology to best process and interpret them matures.
Colorado Case Study
Even though full-wave is essentially in its infancy, a number of field implementations are in place.
In fact, a group of 23 companies representing a variety of oil and gas industry sectors are jointly sponsoring a full-wave 4-D seismic project at Rulison Field in the Piceance Basin, Colorado. The program kicked off in July 2003 under the auspices of the Reservoir Characterization Project (RCP) at the Colorado School of Mines.
The field is operated by Williams Company and produces from Mesaverde tight gas fluvial sandstones of the Cretaceous. The reservoir is made up of multiple stacked channel sand lenses having permeabilities between 5 and 80 microdarcys. Conventional P wave data are not sufficient to locate the channel sands or to resolve the subtle fracture networks that control gas migration.
The time-lapse, or 4-D, multi-component analysis of the field was undertaken to:
- Integrate reservoir characterization and improved imaging to increase gas production from tight gas formations with minimal environmental impact.
- Understand the fracture networks that determine gas migration and accumulation.
- Use time lapse shear waves to monitor the stress changes associated with reservoir depletion of the gas sands.
Thus far, two surveys have been implemented: a base line survey in the fall of 2003 and a monitoring survey last fall, according to Tom Davis, professor of geophysics and director of the RCP. Because wells are being drilled in the field each year, changes in production response should be observable.
The team replants the sensors rather than incur the expense of buying the sensors and then having to drill to place them relatively deep in the subsurface because of the considerable drilling activity in the field. Davis noted they replanted 1,500 stations in only 1-1/2 days.
"We have a lot of data rolling in," Davis said, "and now we're trying to tie it all together. It started out to be mainly multi-component seismology, and now it's a truly integrated research project with geologists, geophysicists and petroleum engineers.
"It's the first survey of this kind related to tight gas and related to depletion only," he added, "and we're looking at primary depletion."
Given the methodology being used, Davis anticipates they may be able to find the better areas to drill first to get the most production up front. Because the reservoir is 2,000 feet thick, there is also an issue of how best to drill the wells, which historically have been vertical.
"If we can identify the sweet spots, maybe fewer wells could be located off these pads if they angle out into the sweet spots," Davis said. "So maybe drilling costs can be reduced through better location."
The project area is sensitive, environmentally speaking. There are multiple landowners to answer to, and the land borders onto federal BLM land. Numerous permits were required for the program to move forward.
Employing a recording system using point receivers requires a smaller footprint and no dynamite, which helped considerably to appease outside parties.