pipeline external leak detection

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August 18, 2014

“There are simply very few places in

the world where you can dump oil in

the ground and test this kind of thing

and not get in trouble.”

Pipeline firms turn to new technologies

as public scrutiny intensifiesCould external sensing technologies restore confidence in pipeline safety?

BY JESSE SNYDER | follow Jesse Snyder on Twitter

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In February 2013, ExxonMobil Corp. sent a smart-pig leak detection device squealing down

its Pegasus pipeline, a decades-old stretch of steel that funnels Canadian heavy oil from a

terminal station in Patoka, Illinois, to refineries in Texas. One month later, as the company was

analyzing the pig’s preliminary data, a 17-foot fracture occurred along the seam of the pipe,

releasing between 5,000 and 7,000 barrels of diluted bitumen.

By the time the company had shut down the pumps, the damage had been done: Canadian

heavy crude had oozed to the surface and flowed into a suburban cul-de-sac near the town of

Mayflower, Arkansas. In a filing to the U.S. State Department months later, ExxonMobil

concluded that small hairline fractures along the lengthwise seam caused the rupture. The

company later said the smart-pig technology, largely still the linchpin of liquid pipeline leak

detection, was unable to detect those fractures. Even nine months after the spill, when the final

data was analyzed, the pipe showed no indication of a structural fault.

These types of leaks are rare. According to the

Canadian Energy Pipeline Association, 492

cubic meters of liquid were spilled in Canada in

2012. Many of those leaks occurred in lines

that were buried before the Arab Oil Embargo

in the ’70s. But criticism of the Pegasus leak

was nonetheless used to raise doubt about the

safety of pipelines in general – including TransCanada Corp.’s proposed Keystone XL. The

incident punctured a hole in the widely held assumption that operators could indeed detect very

small leaks before they led to serious ecological damage. And given the severity of the Arkansas

spill, the criticism was certainly justified.

In a cluttered warehouse on the southern edge of Edmonton, among large spools of plastic

tubing and coils of yellow cable, a competition is underway. It’s a kind of low-key game show whose results could someday alter Canada’s ongoing pipeline debate. The contestants are not

people, but rather companies promoting monitoring technology; in various locations around

the warehouse, 12 different monitoring stations have been set up, each listening for precisely

the same leap in activity. Black curtains are drawn across each station to conceal the equipment

behind.

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Hosted by C-FER Technologies, an Edmonton-based subsidiary of government-funded Alberta

Innovates – Technology Futures, the competition uses a simulator called the external leak

detection experimental research (ELDER) device. The contest has a straightforward purpose.

Near the 12 stations, a seven-meter-long pipeline is placed in a two-meter-tall steel box and

buried with soil or clay, simulating real-life pipeline conditions. Various external leak detectiontechnologies, including fiber optic cables or plastic tubing, are buried near the pipeline, and

diluted bitumen from a nearby 2,000-liter tank is pressurized, heated and circulated through

the line.

At one or two points in a five-day testing period, a pinhole-sized leak deliberately releases dilbit

into the soil. Each company attempts to identify when the leak occurred and reports its findings

one week later, a process that allows vendors to test their technologies in a safe environment.

“There are simply very few places in the world where you can dump oil in the ground and test

this kind of thing and not get in trouble,” says Brian Wagg, director of business development

and planning at C-FER.

Enbridge Inc. approached C-FER in 2012 after being bombarded with pitches from companies

all offering slightly different versions of the same technology: real-time external leak detection.

Should there be a clear winner from the ongoing tests, Enbridge and TransCanada could reap

new technologies while the winning vendors could land a major contract.

But money is only part of the issue. The National Energy Board approved the Northern Gateway

project with 209 conditions on June 15, obligating Enbridge to invest in so-called“complementary” detection systems. Conditions 110 and 111 stipulate that Enbridge must file a

report to the NEB 90 days before construction, detailing its search for new pipeline leak

detection technologies, including “a timetable for installing and implementing the chosen

complementary leak detection systems.”

To that end, Enbridge invested $1.6 million to get the ELDER simulator constructed, and begin

preliminary tests. Shortly before the first tests were run at the end of 2013, midstream rival

TransCanada also joined with a $1.6 million investment. It expects to invest up to $3 million as

the scope of the testing widens. The Alberta government invested another $1.1 million, and

Western Economic Diversification Canada gave over $2 million to test some specific

technologies. The results of the tests are expected to be provided to Enbridge and TransCanada

around the beginning of 2015.




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“Most technologies out there today

have yet to be fully evaluated and

commercially proven.”

There are four main technologies being tested at the ELDER facility: Fiber optic cables can use

distributed temperature sensing, which detects fluctuations in soil temperature; distributed

acoustic sensing works as a microphone to listen for sound disruptions; hydrocarbon sensing

cables send electric currents when in contact with bitumen, triggering an alarm; vapor sensing

tubing, because it is permeable only to hydrocarbons, allows analysts to identify leaks by

pressurizing the tubing with air.

Infrastructure companies are far

from sold on external leak detectiontechnologies. In June 2013, TransCanada

announced it wouldn’t be installing f iber

optic cables along its proposed Keystone

XL pipeline. A report from Bloomberg

News some time later found that an

additional $705,000 would be required to

install the cables along the most

ecologically sensitive regions of the route.

“Most technologies out there today have

yet to be fully evaluated and commercially

proven,” says Vern Meier, vice-president of

pipeline safety and compliance for TransCanada. “There is an expense associated with

implementing these kinds of things.” He couldn’t confirm the accuracy of the Bloomberg figure.

Other external technologies, like aerial surveying, do not always provide dependable results,

particularly on liquids pipelines that give off little heat during leaks compared to gas pipelines.

Internal pipeline monitoring allows TransCanada to monitor a drop in pressure anywhere

above 1.5 per cent of its full capacity within a two-hour period. That may not catch pinhole-

sized ruptures.

The U.S. Environmental Protection Agency has criticised operators’ dependence on aerial

surveying, saying additional external monitoring is needed. A report by the U.S. State

Department assessing safety concerns of Keystone XL called into question the shutdown times

of the pipeline. It cited the 2011 Ludden spill on the existing Keystone line, which the report

said took 12 minutes to shut down.

Meier says the company has kept a close eye on

the results of the ELDER test. “We’re bullish on

the potential applications for these

technologies,” he says. Yet it is expected to be

years before they are ever implemented, if at

all. There is uncertainty over the precise

applications of the technologies. Companies at the ELDER facility are still determining what

distance the cables should be buried from the pipeline to get the most accurate reading. The

range of the different technologies vary widely, so the number of so-called repeater stations

along any given route is still uncertain. For instance, an 80-kilometer range would cost

considerably less than a 50-kilometer range.

But perhaps the weakest link, Wagg says, is not the technologies themselves but how accurately

the data is read. In the most catastrophic leaks it can be the operators who misread the data and

cause a delay in solving the problem. “It all comes down to their interpretation of the data,” he

says. Acoustic sensing devices, for example, have such highly acute detecting capabilities that

operators often misinterpret sounds picked up from harmless sources. “They can hear people

walking across the floor, they can tell when you open the door, that’s how sensitive these things

are.”

Wagg says the competing companies at CFER are working to better their technologies. Whether

those internal leak detection technologies ever make their way into the field remains to be seen.

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