Refinery positions itself to handle more U.S. shale crude

Motiva Enterprises’ plan to run its Norco and Convent refineries as a single operation by linking them via a major pipeline may signal that the company, like a number of other refiners, is positioning itself to handle more of the “super light” crude gushing from U.S. shale formations.

“One of the challenges with North American refinery operations … is that most aren’t configured right now to handle a lot of this lighter stuff because they were all configured to handle imports,” said David Dismukes, executive director of the LSU Center for Energy Studies. “Now all of a sudden, you’ve got tons of production here.”

Gulf Coast refiners spent billions of dollars in the 1980s on modifications that enabled them to process the heavy, high-sulfur crudes imported from Mexico, Venezuela and other countries. But in the last few years, U.S. oil production, driven by the super light oil from shale formations, has swamped Gulf Coast refiners.

Until recently, refiners have mainly handled the flood of crude through “no- and low-cost options,” according to the U.S. Energy Information Administration. Those steps include cutting out light and medium imports, refining more oil into exportable products — diesel to Europe and Latin America, which is also importing U.S.-made gasoline — and making incremental efficiency improvements.

But the American Fuel & Petrochemical Manufacturers, which represents refiners, says that is changing.

Those refiners account for 61 percent of U.S. capacity.

Joanne Shore, chief industry analyst for AFPM, said refiners’ biggest investments remain infrastructure improvements, such as pipelines and rail terminals needed to move the oil.

But spending on crude distillation jumped from the No. 5 spot in 2013-14 to No. 2 for 2015-16, Shore said.

“Now we’re starting to see the investments that need to be made … inside these refineries to be able to use more of this crude,” Shore said.

Refiners have proposed 11 splitter projects — nine of them in Texas — with an estimated cost of $2.4 billion, according to an EIA report released earlier this month. Splitters offer a less-expensive way for refiners to expand light crude oil distillation capacity. The proposed projects would add 570,000 barrels of daily capacity through 2018. Total/BASF added 75,000 barrels of capacity at their Port Arthur, Texas, facility in 2000.

“The number could be more or less. Proposed projects might not go forward, and there are projects … that haven’t been announced or proposed that could go forward,” said Mike Ford, principal contributor on the report.

The improvements refiners are making now involve far less investment and risk than those to handle heavy crude. For example, a coking unit to process heavy crude costs about $1 billion. In order to produce more diesel at its St. Charles plant, Valero spent $1.6 billion to add a hydrocracker.

A lot of the light-crude investments can be made for $10 million or $100 million, Shore said.

Motiva did not provide specifics of its investment.

The work involves a multimillion-dollar investment and could create up to 700 jobs at peak construction, Shell spokesman Ray Fisher said.

The construction jobs suggest Motiva’s investment will be on the larger side.

Dismukes said it would be good news if that’s what Motiva is doing.

One of the big questions facing refiners has been why, if they are confident in shale-reserve forecasts, haven’t companies made the investments needed to take advantage of the super light crude?

Meanwhile, SemGroup, a publicly traded pipeline company, will spend $500 million to build the Maurepas pipeline system, three lines that will connect Motiva’s Norco and Convent refineries and link the existing LOCAP terminal in St. James to Norco. That work will create up to 500 construction jobs.

The amount of oil pouring from Texas shale formations prompted Shell to reverse the flow of its Houma-to-Houston pipeline system in 2013. The system now flows west to east and includes a pipeline from Houma to St. James that can move 260,000 barrels of oil per day.

Norco’s October turnaround improved the refinery’s light crude capabilities, Fisher said, and the facility is strongly positioned to take advantage of light crude once connected to St. James.

The refineries in Convent and Port Arthur, Texas, are positioned to process light crudes when it makes economic sense to do so, he said.

Motiva also plans to shut down the fluid catalytic cracker at Convent once the two refineries are connected by pipeline.

Altogether, those moves may mean the Convent refinery will handle more light crude, while Norco may be handling more of the heavy stuff, said Richard Metcalf, director of environmental affairs for the Louisiana Mid-Continent Oil and Gas Association.

He said the new crude mix has a low yield for middle distillates, such as diesel.

“My guess is that Convent, which was historically a Texaco refinery, a Louisiana sweet crude refinery, that they’re better optimized to handle the lighter sweet crude that’s coming out of the shale plays,” Metcalf said.

Norco, equipped with one of the largest fluid catalytic crackers in the country, may be a better place to run the heavy, offshore crudes, Metcalf said.