* Plans to boost rig count to 10 from 7 on new Permian acreage
* Shell's Odum says "makes sense" to look at LNG exports
* Believes Brent/WTI spread eventually will narrow
NEW YORK, Nov 29 (Reuters) - Royal Dutch Shell expects "years and years" of production from oil and natural gas acreage it recently bought from Chesapeake Energy Corp and plans to add more drilling rigs, the head of Shell's Americas operations said on Thursday.
Shell paid $1.94 billion last September for 618,000 acres in the Permian Basin, a vast oil and natural gas source in western Texas.
Shell and other global energy companies, including Exxon Mobil Corp and Chevron Corp, are buying more oil and gas assets in North America to boost production in a sector where most resources are located and tightly controlled by countries like Brazil and Russia.
Much of the Permian Basin land bought by Shell, which Chesapeake desperately needed to sell, is considered prospective at best and only has seven drill rigs in operation. The properties are currently producing 26,000 barrels of oil equivalent per day, low by industry standards.
Shell believes the land could produce much more, and expects the rig count to rise to 10 "over a period of time," Marvin Odum, president of the Dutch oil major's U.S. arm, Shell Oil Co, and director of Shell's Upstream Americas division, said in an interview with Reuters on Thursday.
"We made a very good acquisition here," Odum said. "This is a relatively small payment for a lot of resources that are reasonably well-proven, but yet to be developed, and a very nice suite of acreage that's more in the appraisal/exploration phase."
Shell had little comment about the deal when it was first announced and has been quiet about production plans.
The company was attracted to the land because it already is producing, meaning production has been proved viable, Odum said. At the same time, Shell was intrigued about exploration possibilities elsewhere on the acreage, he said.
Odum said Shell, which is counting on cheap U.S. natural gas feedstock for a chemical plant it plans to build in Pennsylvania, also would be interested in participating in LNG export projects from the United States.
Companies have been lining up to export the surplus gas that has flooded the U.S. market because of the shale drilling boom.
U.S. natural gas futures have been trading in a range between $2 to $4 per million British thermal units (mmBtu) this year, while natural gas imports in Asia cost as much as $15 per mmBtu, a strong incentive for building U.S. export terminals.
It is more than a year since the U.S. Energy Department issued its first and so far only approval for gas exports to Cheniere's Sabine Pass terminal, which is not expected to be online until 2014 or 2015.
The DOE has said it will not make any decisions on allowing more exports until a comprehensive macroeconomic study is completed by the end of the year.
Natural gas exports to all but a handful of countries with free trade agreements require approval from the Energy Department.
"We think it would make sense to look into export projects at some point," Odum said, without addressing specific plans. "Everything from a producer's side says there is enough gas for exports."
Odum said existing U.S. LNG export projects by other companies, in planning or permitting stage, are "probably pretty viable prospects."
The Obama administration is likely to take a "stepwise approach" to allowing new LNG export projects, Odum said, noting that U.S. manufacturers have been pushing for access to cheap and abundant gas feedstocks.
Odum declined to forecast oil prices.
London-traded Brent crude, trading above $110 a barrel, is on track for an annual record price this year, but U.S. crude futures have been trading at a discount of around $22.50 a barrel to Brent, in part due to a glut of crude in their Midwestern delivery hub at Cushing, Oklahoma.
That transatlantic price spread could be eliminated over the next two to three years, Odum predicted, as firms race to build new pipelines and other infrastructure to ship crude out of Canada and the U.S. Midwest down to the Gulf Coast, where crude can fetch premium prices closer to Brent.
"It's simply a matter of math and infrastructure," Odum said. "The arbitrage will be solved."