WASHINGTON — Energy companies currently leave about 95 percent of the crude in the ground at today’s unconventional oil wells, but they face major technological challenges in boosting recovery rates, a Schlumberger scientist said Tuesday.
Robert Kleinberg, a fellow with the oilfield services firm, bemoaned the current 5 percent recovery factor at tight oil wells, where crude is pulled from the pores of extremely dense rock formations.
Geologists and engineers are actively looking for ways to boost the figure, but traditional methods applied at more conventional oil wells — such as pumping steam underground and flooding the formations with water — don’t really apply to tight plays, Kleinberg said.
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“Our entire spectrum of secondary recovery methods don’t work,” Kleinberg said, in a sobering talk at the Energy Information Administration’s annual summit in the nation’s capital.
Water flooding — where water can be swept from separate injection and producer wells — isn’t an option because the tight oil formations are too dense to permit those water flows.
And while carbon dioxide can be used to pressure up a conventional oil well, there’s currently a limit on the amount of that gas that is available to pump underground. “The oil industry would like to have more CO2, which is a great way to get more oil out of the ground, but there are limits on affordable, accessible supplies of CO2,” Kleinberg said, quipping: “The oil industry lives in a CO2 constrained world; it is only the oil industry that thinks there is not enough carbon dioxide.”
New projects for capturing carbon dioxide and using it to enhance oil recovery, including a just-launched project near Houston, generally are focused on conventional reservoirs. The sharp constraints on the amount of CO2 available for enhanced oil recovery mean that it will be a long time before it flows to unconventional plays, Kleinberg predicted.
Steam has the potential to boost recovery at tight oil wells, but it is unlikely to be economic, Kleinberg said. Companies would essentially be heating up 97 percent of the formation to heat up the 3 percent of total rock volume that is oil, he noted.
One option that has gotten industry talking is refracking — an approach that involves returning to previously drilled, completed and fractured wells to hydraulically fracture the site again. A number of technical papers have been published highlighting promising results.
But the approach is expensive, costing potentially several million dollars even at a previously drilled and fractured well, since companies must remobilize water trucks, sand deliveries and the entire infrastructure to support a new round of activity at an old site.
Kleinberg said refracturing’s best potential may be in returning to wells that were drilled early in the life of a field, with mistakes made, before the geology of the play was well known.
Given the costs and limitations, “the current strategy generally is to go and drill a new well somewhere else,” Kleinberg said. “That’s where we are today. But refrack could work.”
Oil industry technologists are actively working to solve one of the biggest challenges: the limited reach of the sand used to prop open underground fissures so oil and gas can keep flowing. While hydraulically fractured wells today may have pressure interference effects that extend 1,000 feet, the proppant isn’t deposited beyond 300 feet.
“We’re just not putting proppant deep into the formation,” Kleinberg said. That’s “a big waste of water, sand, chemicals and, most importantly, time.”
“People are working very hard at trying to push that proppant deeper into the formation,” Kleinberg said. If the research is successful, he said, it could be “a cheap alternative to in-fill drilling,” where companies bore new wells amid existing wells in a field.