Exxon tests successful tech in quest to tap oil shale
ExxonMobil, the world’s largest energy company, wants to jolt kerogen from the oil shale trapped deep in the Piceance Basin.
The company has run successful tests with the “Electrofrac” technology in its Colony Mine near the east end of the 150-mile stretch and now wants to try it on a larger plot of land leased from the federal government for research and development of oil shale.
The Interior Department is planning a second round of those leases. ExxonMobil sought, but was denied one in the first round in 2005. The company, however, is ready to try again for a research and development lease, having learned it’s possible to create a fracture in oil shale, fill it with a conductive material and run a charge through it powerful enough to heat surrounding hydrocarbon-bearing rock.
“What we’re doing is making a giant underground toaster,” ExxonMobil spokesman Patrick J. McGinn said.
The company ran tests for the first time in September on land it owns, proving it could use electricity to heat surrounding rock, setting the stage for further tests of the Electrofrac process.
The resistive heating element far beneath the surface will heat up just as the coils in a toaster do, but the ExxonMobil technique heats rock. By heating the surrounding rock to 300 degrees Centrigrade, ExxonMobil hopes to free oil shale’s petroleum-like treasure and allow it to migrate, much like gas or oil, to collection wells that would draw out the kerogen for refining.
That heat would be contained within the rock and couldn’t be detected from several thousand feet above on the surface, McGinn said.
The process the company envisions calls for the use of horizontal drilling instead of vertical drilling to limit the amount of surface disturbance, McGinn said.
Assuming that the process works on a large scale, ExxonMobil sees tantalizing prospects for shale: up to 162,000 barrels of oil per surface acre at a 50 percent recovery rate.
The results suggest a 3-to-1 ratio of energy recovered over energy expended to obtain it, McGinn said.
The Green River Formation in western Colorado, eastern Utah and Wyoming is believed to contain the equivalent of as many as 2 trillion barrels of oil.
Even under the most optimistic of scenarios, ExxonMobil sees no production coming from oil shale for 10 to 24 years, McGinn said.
That leaves plenty of time for the company to plan what would be a extensive network needed to generate the electricity necessary to heat the shale, collect the kerogen and begin moving it to refineries and then to markets.
Exxon can use some of the natural gas it’s drilling on the Piceance Basin to supply the electricity needed to collect the kerogen, McGinn said.
It appears ExxonMobil can make its process work using about 1.5 barrels of water for each barrel of oil produced, he said.
To place that in some perspective, production of 500,000 barrels a day, “and that would be huge,” would require about 3,500 acre-feet per year of water, McGinn said.
About 14 million acre-feet of water on average run through the Upper Colorado River basin.
ExxonMobil has yet to study the economic and social implications of development, McGinn said.
“We’re talking about research and development,” he said. “We’re not in the project-planning mode.”