Harken back to the 1990s, and one would have been convinced that prestack depth migration was the solution to imaging below complex salt structures in areas like the Gulf of Mexico (GoM). In the early 2000s the answer was wide-azimuth (WAZ) seismic acquisition and then broadband acquisition and processing.
But none of these techniques provided the full answer. “We’ve beaten our heads against this problem for 15 years,” said Joe Dellinger of BP America. He added that the salt in the GoM has caused the industry to leap from shallow water to ultradeep water because the prospective areas in between are too challenging to image properly. “One-third of the U.S. Gulf lies in this area,” he said, speaking at a recent Geophysical Society of Houston luncheon.
Model studies have indicated that the limiting factor is the ability to make good velocity models, which are required to process the WAZ seismic data into a clear subsurface image. Full waveform inversion (FWI) demonstrated that it can deliver good velocity models in sedimentary basins, but it has not been successful for salt. However, Dellinger said model studies indicate FWI could fi x salt velocity models but only with seismic data that contain measurements below 2 Hz.
“The problem then becomes how do we get the required data at a reasonable cost?” he said. “How do we design an entirely new acquisition strategy around velocity model building using FWI?”
BP was faced with some daunting questions: Did it tell the interpreters to keep trying to come up with better velocity models without the low frequencies, which are hard to obtain with airgun sources? Did it support academic research to develop cleverer inversion algorithms that might not require low frequencies? Did it move toward automated interpretation?
The answer was Wolfspar, a low-frequency source project that BP undertook after realizing there was no commercial product available. Studies indicated the solution to the velocity model issue required wide offsets and low frequencies at an adequate signal-to-noise (S/N) ratio. It also had to be available at a reasonable cost. Making sound at such low frequencies and offsets is challenging at the level of basic physics and engineering understanding, requiring a source that can displace a large volume of water but be engineerable and not consume excessive power.
The project started in 2006, and by 2013 BP had a prototype ready to test in Seneca Lake, N.Y. By 2014 the company was able to run a systems integration test in the GoM. The system provided a 45-dB signal above airguns at 1.8 Hz, producing a very good S/N ratio at these low frequencies. The investigators felt confi dent this source could fi x the problems limiting velocity model derivation using FWI without being wildly expensive or operationally impractical.
Originally hoping to gain industry support for the project, BP was forced to self-fund it after the market crashed. “The current oil price environment played a role, with both operators and suppliers cutting back R&D budgets and focusing on more incremental developments,” Dellinger said. “We also see a reluctance to develop new technologies without clear demand coming from oil and gas operators. But that demand won’t come until someone fi rst proves that the concept works. That’s why we have needed, so far, to develop this technology under the BP proprietary umbrella.”
Rhonda Duey’s Exploration Technologies column originally appeared in the July 2017 issue of E&P.
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