Anyone nostalgic for the natural gas infrastructure boom of the latter half of the last decade need only wake up to the natural gas liquids (NGL) infrastructure boom of today — and look forward to what’s to come in response to growing crude oil production — according to an analysis to be finished in about three weeks.
Bentek Energy LLC and Turner, Mason & Co. (TMC) are partnering on a study of the infrastructure available and planned to handle growing NGL production over the next five years.
“Today it’s about natural gas liquids,” Bentek Vice President Director Rusty Braziel told NGI. “We’re in the middle of a natural gas liquids investment cycle. For example, just natural gas liquids pipelines — not counting gas plants, fractionators and chemical companies — we’re spending $5.7 billion on new NGL pipelines, doing many of the same things that we did a few years ago in natural gas.
“Natural gas pipeline, fractionation and processing investment [for NGLs] is adequate if it all gets built. Pretty much everything that’s been announced has got to be built, and in that case we make it.”
And plenty of projects have been announced. Bentek and TMC have tallied about 8.3 Bcf/d of gas processing additions planned by 2014. The Texas Gulf Coast leads, followed by the Marcellus Shale and then the Anadarko Basin. Spending on those plants will be on top of the $5.7 billion for new/expanded NGL pipelines.
On the market side, the petrochemical industry has planned numerous projects to take advantage of cheap U.S. ethane and the other gifts of the liquids-rich shale boom. “The petrochemical industry should be able to absorb most of the incremental ethane, but that construction has to happen,” Braziel said. “The propane will move offshore, and there are some very interesting things happening between condensates and natural gasoline.” (For instance, condensate from the Eagle Ford could one day make its way to Canada for use as a diluent in oilsands production, Braziel said.)
During the dry gas construction boom, the goal was to get product from the middle of the country to high-dollar eastern markets, busting through the existing west-east capacity constraints. With NGLs, the production action is up and down a liquids-rich fairway running from the top of the Dakotas to the bottom of Texas.
Production from basins in this region has liquids content as high as 5.6 gallons per Mcf (GPM) in the Williston, 5.3 GPM in the Granite Wash, and 5.2 GPM in the Eagle Ford down to 0.7 GPM in the Powder River, according to Bentek. It’s gotta go to the Gulf Coast. [A small amount (45,000 b/d) of production could travel from North Dakota to Canada on one proposed pipeline. Over in the Marcellus Shale, it looks as if about 65,000 b/d will be heading to Sarnia, ON.]
Just like the west-east basis differential for gas before it, the north-south differential for NGLs and crude will be crushed, Braziel said. Liquids players haven’t seen anything like this before, he said, at least not since before the 1980s when he was in the business.
Underlying it all is gas production that just won’t quit growing, particularly in liquids-rich plays where internal rates of return (IRR) are the sweetest of all. A dry gas producer in the Marcellus enjoys an average 37% IRR, according to Bentek. But a producer pulling up gas and liquids from the Anadarko Basin can get a 107% IRR and a 98% IRR in the Eagle Ford. Oil producers in the Bakken and Niobrara can get 78% and 59%, respectively.
NGLs are today’s story, but tomorrow the infrastructure obsession will be crude oil. Bentek is projecting a nearly 3 million b/d increase in crude oil production from the U.S. and Canada in five years. “In other words, we’re going back to a new peak in crude oil production in the U.S. and Canada combined,” Braziel said. “Who would have thunk it, but we’re back to the ’70s in crude oil production, a 3 million bbl increase.
“So crude oil is the new NGLs. It’s growing like crazy. One of the most interesting things in the Eagle Ford and the Anadarko is that it is very very light crude from 50-65 API [American Petroleum Institute] gravity, which means it looks very much like natural gasoline. And there are at least three projects that are being touted to keep that product clean and move it into the diluent market to take it up to Canada to stir it with the bitumen crude or to run in the petrochemical plants instead of natural gasoline. If that happens, it will be a very, very big deal.
“The bottom line on all of this is the shale stuff that has made such a big difference in natural gas is making an equally big difference in natural gas liquids, and it looks like it could make an even bigger difference in crude oil once we start rolling all of that technology through the crude oil marketplace, just like we’ve done for natural gas.”
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