|
BP wants to be serious player in GTL New vice president leads global effort that includes continuing work at Nikiski testing facility, as high oil prices boost prospects Allen Baker Petroleum News Contributing Writer
High crude prices and low-cost supplies of natural gas around the world have put plans for turning gas into an easily transported liquid back on the front burner.
BP Exploration & Production made its move last December, picking David Robertson as the new vice president charged with commercializing the company’s GTL technology.
“Natural gas continues to offer value compared to crude oil,” says Robertson, whose title is vice president, gas to products. “My responsibility is to develop a portfolio of technology that will allow monetization of natural gas through syngas.”
Syngas in the product of the initial step in GTL technology. That step “reforms” methane into a mix rich in hydrogen and carbon monoxide — the building blocks for more complex hydrocarbons. Many products Among the products that can come from that mix are diesel fuel, naphtha, lube stocks, methanol and acetic acid. BP is already a partner in the largest methanol plant in the world, a Trinidad facility that turns natural gas into 5,000 tons of methanol a day. It’s also a leader in producing acetic acid from gas.
“If people believe the value of crude oil will remain elevated compared to historical numbers, then products that didn’t look attractive before look a lot more attractive. There’s a broad range of opportunities there,” he said.
Robertson was in Alaska Sept. 29 for a meeting of his global team, inviting “internal customers” from BP business units to hear what his engineers can offer. Nikiski was a natural site for the meeting, since BP has been testing aspects of the process at its GTL pilot plant there since 2002.
That testing was expected to last a year to 18 months, but engineers are continuing to tinker with aspects of the design. Nikiski plant plugs on “Nikiski continues to be a demonstration plant. We haven’t finished the program yet,” Robertson told Petroleum News. “We’re considering some further modifications to it.”
The GTL plant ran most of second quarter, but it’s been shut down for further modifications. Once it’s started up again, Robertson anticipates it will run for the rest of the year. About 15 people work at the facility.
The plant was originally expected to cost $86 million and turn about 3 million cubic feet of gas daily into a token 300 barrels of synthetic crude. It was sited in Alaska, instead of closer to BP’s UK research facilities, as part of the antitrust deal when ARCO was swallowed up and BP was looking to mollify state authorities.
BP has spent $120-$130 million at Nikiski, Robertson estimates, with total company spending on gas-to-products research in excess of $300 million.
“We want to be considered a serious player,” he said. “(Nikiski) is a fantastic facility.”
One of BP’s big hopes for the Nikiski test was its compact design for the reformer that produces the syngas. Unlike much of the rest of the plant, the reformer was built to commercial scale.
“We’ve had very good success with the reformer. We definitely see opportunities to improve reliability.” Still, “it’s not proven. Until we’re comfortable with something we’ve demonstrated at scale, we won’t go ahead with it. At the moment we’re not considering a commercial project using a compact reformer.” Colombian GTL project The company does have its eye on a field in Colombia for development using a more traditional reformer along with BP technology for turning the syngas into liquid fuels using a modern version of the Fischer-Tropsch technology developed by German scientists in the 1930s.
Colombia, with a startup date of 2011, “is going to be the first big project we’ll be developing using this technology,” Robertson said. “We’re looking at early studies for a GTL project in Colombia, to monetize the gas that’s being reinjected.”
As for Alaska’s huge North Slope gas reserves, BP remains focused on sending that gas to the Lower 48 through a dedicated pipeline.
Various studies over the years have speculated that producing GTL liquids on the North Slope and sending them down the oil pipeline could be a viable option if crude prices are high enough, and there’s likely enough gas to feed both a major gas pipeline and a giant GTL plant. But it’s an expensive gamble, with costs that run into the billions of dollars.
“The big risk element is that we don’t know what the price of oil is going to be in five years when these plants come on line,” he notes. Sasol a leader While major oil companies including ExxonMobil and ConocoPhillips have plans for big GTL facilities in Qatar, Robertson figures South Africa’s Sasol and Shell have the lead in the technology.
Sasol makes 160,000 bpd of liquids from synthetic gas derived from coal, and is set to begin operation of its 34,000 bpd Oryx operation in Qatar next year. The company got its start on GTL when South Africa was under an economic blockade during the apartheid era.
Shell has been producing liquid fuels at its Bintulu plant in Malaysia for a decade. It has awarded a $6 billion-plus contract to Japan’s JGC Corp. and Halliburton’s KBR for a Qatar plant that will produce 140,000 bpd at full capacity in 2010.
“ExxonMobil has a fantastic number of patents. They’re smart people. They have a plan and they’ve worked it through,” Robertson said. “But Shell and Sasol have a proven track record.
“It’s all very well designing the chemistry. But running it is the big challenge. You have to be in this for a long time. You have to be persistent and learn your lessons.” Costs rising While the economics of a GTL plant will benefit if the price of oil remains high, costs for steel and other construction materials are also rising.
“People have talked about $27,000 per installed barrel (daily),” Robertson said. “I think everybody is going to struggle to hit that one.” High capital costs are a big reason GTL plants haven’t been proliferating.
Engineers also are hoping for a breakthrough on overall efficiency, the main motivator for developing the compact reformer. Most operations lose about a third of the energy in the gas in the conversion, though some of it can be recycled to produce steam and electricity.
| 