Operators have the tools today to tap into unconventional natural gas and oil reservoirs at a more efficient and more productive pace but the technologic advances have only scratched the rock’s surface, a Schlumberger Ltd. executive said earlier this month.
“Technology is the enabler…but further technological advancements are required,” Schlumberger’s Jeff Spath told an audience at the recent GasMart 2011 conference in Chicago. The vice president of industry affairs said “maximizing reservoir contact is the key to success,” but modeling and forecasting techniques still have a way to go.
The Houston-based oilfield services giant has some of the best and the brightest researchers and developers in the business. They continually test new equipment around the world to better the service offerings for the onshore and offshore. For the unconventional gas and oil fields, it’s been rewarding, but also especially trying, Spath said.
“I can’t emphasize how difficult some of the reservoirs are to produce. One shale is not like another…” and within each shale play, the same techniques used successfully in one well won’t work for another. Trying to find the sweetest of the sweet spots has resulted in a lot of misses and some hits, and unconventional drilling when it began in earnest about a decade ago was an inefficient and costly undertaking.
But that was long ago. The digital devices that have changed people’s everyday lives haven’t been lost on the energy industry geeks.
Intelligent wells today are equipped with computerized monitoring equipment and completion components; operators may adjust the numbers to optimize production, either automatically or manually. It’s quality-over-quantity drilling.
Shale gas offers “minimal geologic risk,” Spath said. “If you know where the basin is, you can go in and drill in the shale gas reservoir. It may not be economic, but it will be a shale gas reservoir with some kind of gas saturation…” but “sometimes high depletion rates.”
The Barnett Shale is an example of how technology has evolved. Barnett operators in the early days of the shale revolution — the late 1990s and the early 2000s — tapped into some of what were then gas gushers in the North Texas field. However, once they “stepped out of the core area, they were constantly having to drill new wells,” which sapped financial resources and burdened equipment, the Schlumberger executive said.
More frack stimulations didn’t lead to more output. One Barnett well was completed with 24 frack stages “quite unscientifically.” Still, operators knew there was gas in the shale. As the technology evolved, producers were able to more accurately drill a well and find the fractures that would stimulate production.
Today it’s “state-of-the-art well placement,” said Spath, “with technologies around drilling and completing massive horizontal wells.”
Seismic, which has become a go-to component, isn’t the be-all, end-all as an exploration tool, he explained. Using only seismic, “where we know shale gas basins exist, the hit rate of productive wells versus nonproductive wells is very high.” However, by correlating the core data and the log data, operators have a “very rough overview of the reservoir.”
As the technology continues to evolve, operators are “discovering” more productive reservoirs — some that produced decades ago and today have become born again. That means “the potential is high” for shale gas to be unearthed not only in the United States, but around the world, said Spath. “It’s definitely a worldwide phenomenon.”
One of the newer innovations is microseismic hydrofrack monitoring, which allows an operator to pressure a formation, which causes the rock to “slip,” which in turn generates a microseismic event, an acoustic signal that can be detected in another well. The process allows operators to digitally track the growth and the operation of hydrofrack treatments, and in turn, help to determine the best possible places to frack, said Spath.
Another innovation is acoustic emission analysis, which can see which direction the rock’s fracture is moving so that stimulation can be optimized. This type of analysis “uses as little water as possible while maintaining the maximum production rate,” he said.
“The ability to pinpoint sweet spots can reduce fractures as much as 50% while not reducing the productivity of the well.”
Today the time to drill a “standard” well in the Fayetteville Shale has fallen from 18 to 12 days, Spath said. In the Eagle Ford, “they are drilling wells in less than 10 days…”
And that leads to returns on the bottom line. “The bulk of the investment on the operator side is in completion rather than drilling and fracturing,” he said. For instance, the average lateral length of wells has gone from 2,500 feet to more than 4,000 feet. An “average” horizontal well in the Eagle Ford is 4,100 feet.
The innovations continue. “From our standpoint, there’s a lot of work to do to scale down water use,” and not only in North America,” said the Schlumberger executive. Finding a way to use less water would “be required if we’re ever successful in producing shale gas in places like Western Europe and even eastern Australia.
“All of this technology was not available 10 years ago,” said Spath. “It’s made a huge difference in productivity and efficiency…The wells drilled per rig are much higher and the economics are more and more positive for the operator as we learn…
“And we’re still learning, by the way.” The industry “by no means is where we need to be.”
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