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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