A four-way well tie using synthetic, a VSP corridor stack, 3-D VSP and 3-D SS images. Right: The fault interpretation results done in Petrel using 3-D VSP, which allows indentification of possible reservoir faults. Graphic courtesy of Schlumberger.
If three-dimensional vertical seismic profiling sounds complex to geologists, well, that’s because it is – but don’t be deterred.
The process has proven its value for several decades and continues to deliver in the right conditions.
But the key to success lies in planning – and perhaps even in deciding whether or not to perform a VSP survey – according to Les Nutt, borehole seismic marketing manager for WesternGeco GeoSolutions in Houston.
“Many (proposed surveys) are not done,” the victims of simple logistics or economics, Nutt said.
The recent introduction of very long array tools – often more than 100 levels – plus better sources and source control and advances in imaging techniques have helped make 3-D VSP a valuable asset in complex geological environments, such super-deep wells like those in the Gulf of Mexico, Nutt said.
On the other hand, in the Middle East the emphasis is more on refining the resolution and getting clearer images of targets identified in old surveys, he said.
Repeating a survey adds a fourth dimension – time – making VSP a useful method in reservoir monitoring, particularly helpful in fields such as carbon sequestration, he said.
Routine applications for 3-D VSP have included imaging and characterizing clastic reservoirs under various complex overburdens, including shallow gas clouds, salt, carbonates and for reservoirs of generally low acoustic impedance contrast.
In deep, sub-salt wells in the Gulf of Mexico, “any sort of image is an improvement,” Nutt said.
In Middle Eastern fields, the technique is applied to enhance the resolution of subsurface images for continuing exploitation and horizontal attacks, he said.
Downhole geophones are used to hone interpretations from old surface seismic, helping companies direct new drilling closer to the best targets, Nutt said.
In the 1990s, a tool might have only five levels, and would be moved during the survey to provide perspective from additional levels, he said.
Today’s arrays let companies complete complex surveys in one pass, greatly reducing lost drilling time.
With downtime costs ranging up to $1 million per day, the quicker the survey the better, he said.
The new, longer arrays “were built to address that issue,” he said.
Challenges to Tackle
Three-D VSP acquisition remains, however, a logistical challenge.
It is, Nutt says in his Mid-Continent abstract, a tool that requires creative thinking for choice of source and source deployment and is bound by the operational constraints of drilling the well and the placement of a suitable receiver array.
Three-D ray trace modeling of the often complex subsurface is necessary to understand the subsurface coverage for any given acquisition geometry – and the subsurface coverage can often be adversely affected, particularly on land by surface conditions. It is usually not enough to simply perform ray trace modeling.
To understand and illustrate the challenges for 3-D VSP imaging in complex geological settings, Nutt and his team used the SEG Advanced Modeling (SEAM) Phase I velocity model for 3-D VSP finite difference synthetic data generation and imaging.
The SEAM model simulates a complex geological environment; the model includes complex salt, grottoes, salt welds, sub-seismic resolution stratigraphic details and even an overturned set of sediments.
“For optimum survey design we recommend an iterative flow of ray trace modeling, 3-D finite difference synthetic data generation and imaging,” Nutt said.
With recent advances in tool and source technology the acquisition time for 3-D VSPs has been significantly reduced.
“In complex geological environments,” Nutt said, “better model building and calibration methods and more accurate imaging algorithms such as RTM will lead to successful 3-D VSP surveys.”
Time for 4-D
Carbon sequestration is another area where VSP – especially in 4-D – can be useful, Nutt said.
Here, the goal is not enhancing data. Goals may include showing seismic changes over time or monitoring fluid fronts, he said.
Coal-fired power plants that inject carbon underground to sequester it need to track such information, he said.
Smaller targets, land ownership and other issues can make surface surveys less attractive, he said.
VSP leaves a much smaller surface footprint, he said.
Recent projects in this area have been undertaken in cooperation with national energy departments in the United States and Australia, Nutt said.
For an effective 4-D survey, “You have to try and repeat the same shot,” perhaps a year later, Nutt said.
In some cases, a geophone array may be left downhole from the earlier survey.
The most crucial steps are the earliest – identifying a need, modeling, then designing a project, Nutt said.
New or additional data expected from the coverage may not justify the survey’s cost. Logistics may make other projects unfeasible. Uncemented casing, for example, prevent effective coupling between the geophones and the formation, Nutt said.
Because VSP usually is performed in the most complex areas, processing results can take weeks.
“Processing time is shrinking ... it takes a lot of computing power,” he said.
“VSP is not a generic solution to all seismic problems, but the industry is moving this way,” he said. “There is a lot of investment by the service industry.”