New US pipeline safety report finds more problems with Enbridge, problems also found in other big pipeline companies

Leak detection report coverA new draft report for the U.S. Congress from the United States Pipeline and Hazardous Materials Safety Administration takes new aim at Enbridge for failures in its pipeline leak detection and response system.

Not that the PHMSA is singling out Enbridge, the report is highly critical of leak detection systems on all petroleum and natural gas pipeline companies, saying as far as the United States is concerned, the current pipeline standards are inadequate.

The release of the “Leak Detection Report” written by Kiefner & Associates, Inc (KAI) a consulting firm based in Worthington, Ohio, comes at a critical time, just as Enbridge was defending how it detects pipeline leaks before the Joint Review Panel questioning hearings in Prince George, where today Enbridge executives were under cross-examination by lawyers for the province of British Columbia on how the leak detection system works.

In testimony on Wednesday, October 12, Enbridge engineers told the Joint Review Panel that the company’s pipelines are world-class and have a many prevention and detection systems.

Northern Gateway president John Carruthers testifed there is no way to eliminate all the risks but the company was looking for the best way of balancing benefits against the risk.

However, the KAI report points out that so far, all pipeline company cost-benefit analysis is limited by a short term, one to five year point of view, rather than looking at the entire lifecycle of a pipeline.

Two Enbridge spills, one the well-known case in Marshall Michigan which saw bitumen go into the Kalamazoo River and a second in North Dakota, both in 2010, are at the top of the list in the study for PHMSA by the consulting firm.

On the Marshall, Michigan spill the KAI report goes over and adds to many of the criticisms of Enbridge in the National Transportation Safety Report in July which termed the company’s response like the “Keystone Kops.”

The second spill, in Neche, North Dakota, which, unlike the Marshall spill, has had little attention from the media, is perhaps equally damning, because while Enbridge’s detection systems worked in that case–the KAI report calls it a “text book shutdown”– there was still a spill of 158,928 gallons (601,607 litres) of crude oil, the sixth largest hazardous liquid release reported in the United States [between 2010 and 2012] because Enbridge “did not plan adequately for containment.”

(The KAI report also examines problems with natural gas pipelines, including one by TransCanada Northern Border line at Campbell, Wyoming in February 2011. Northwest Coast Energy News will report on the natural gas aspects of the report in a future posting.)

The highly technical, 270-page draft report was released on September 28, as Enbridge was still under heavy criticism from the US National Transportation Safety Board report on the Marshall, Michigan spill and was facing penalties from the PHMSA for both the Marshall spill and a second in Ohio.

Looking at overall pipeline problem detection, KAI says the two standard industry pipeline Leak Detection Systems or LDS didn’t work very well. Between 2010 and 2012, the report found that Computational Pipeline Monitoring or CPMs caught just 20 per cent of leaks. Another system, Supervisory Control and Data Acquisition or SCADAs caught 28 per cent.
Even within those acronym systems, the KAI report says major problem is a lack of industry standards. Different companies use different detector and computer systems, control room procedures and pipeline management.

The report also concludes that the pipeline industry as a whole depends far too much on internal detectors, both for economic reasons and because that’s what the industry has always done. External detectors, the report says, have a better track record in alerting companies to spills.

A significant number of spills are also first reported by the public or first responders, rather than through the pipeline company system and as KAI says of Enbridge, “Operators should not rely on the public to tell them a pipeline has ruptured.”

The consultants also say there are far too many false alarms in spill detection systems.

Although the KAI report concentrates on the United States, its report on Enbridge does raise serious questions about how the company could detect a pipeline breach or spill in the rugged northern British Columbia wilderness where the Northern Gateway Pipeline would be built, if approved by the federal government.

The report comes after the United States Congress passed The Pipeline Safety, Regulatory Certainty, and Job Creation Act, which was signed into law by President Barack Obama on January 3, 2012. The law called on a new leak detection study to be submitted to Congress that examines the technical limitations of current leak detection systems, including the ability of the systems to detect ruptures and small leaks that are ongoing or intermittent. The act also calls on the US Department of Transportation to find out what can be done to foster development of better technologies and economically feasible ways of detecting pipeline leaks. The final report must be submitted to Congress by January 3, 2013.

(The draft report does note in some ways, Canadian standards for detecting pipeline leaks are better than those in the United States. For example, Canada requires some pipeline testing every year, the United States every five years. It also finds European pipeline monitoring regulations also surpass those in the United States).

The spills studied in the report all found weaknesses in one or more of those three areas: people, company procedures and the technology. It appears that the industry agrees, at least in principle, with executives telling the consultants:

The main identified technology gaps – including those identified by operators – include: reduction or management of false alarms; applicable technical standards and certifications; and value / performance indicators that can be applied across technologies and pipelines.

The report echoes many of the findings of the US National Transportation Safety Board in its examination of the Enbridge Marshall, Michigan spill but it applies to all pipeline companies, noting:

Integration using procedures is optimal when it is recognized that alarms from the technology are rarely black-and-white or on/off situations. Rather, at a minimum, there is a sequence: leak occurrence; followed by first detection; followed by validation or confirmation of a leak; followed by the initiation of a shutdown sequence. The length of time that this sequence should take depends on the reliability of the first detection and the severity of the consequences of the release. Procedures are critical to define this sequence carefully – with regard to the technology used, the personnel involved and the consequences – and carefully trained Personnel are needed who understand the overall system, including technologies and procedures.

We note that there is perhaps an over-emphasis of technology in LDS. A recurring theme is that of false alarms. The implication is that an LDS is expected to perform as an elementary industrial automation alarm, with an on/off state and six-sigma reliability. Any alarm that does not correspond to an actual leak is, with this thinking, an indicator of a failure of the LDS system.

Instead, multiple technical studies confirm that far more thought is required in dealing with leak alarms. Most technologies infer the potential presence of a leak via a secondary physical effect, for example an abnormal pressure or a material imbalance. These can often be due to multiple other causes apart from a leak.

The report takes a critical look at the culture of all pipeline companies which divides problems into leaks, ruptures and small seeps. Under both pipeline practice and the the way problems are reported to the PHMSA in the US a “rupture is a situation where the pipeline becomes inoperable.” While a rupture means that a greater volume of petroleum liquid or natural gas is released, and is a higher priority than a leak or seep, the use of language may mean that there is a lower priority given to those leaks and seeps than the crisis created by a rupture.

(Environmental groups in British Columbia have voiced concerns about the cumulative affect of small seeps from the Enbridge Northern Gateway that would be undetectable under heavy snow pack either by an internal system or by external observation)

Overall, the report finds serious flaws to the way pipeline companies are conducting leak detection systems at the moment, including:

  • Precisely the same technology, applied to two different pipelines, can have very different results.
  • Leak Detection Systems do not have performance measures that can be used universally across all pipelines. Compounding the problem are different computer systems where software, program configuration and parameter selection all contribute, in unpredictable ways, to overall performance.
  • Many performance measures present conflicting objectives. For example, leak detection systems that are highly sensitive to small amounts of lost hydrocarbons are also prone to generating more false alarms.
  • The performance of a leak detection system depends critically on the quality of the engineering design, care with installation, continuing maintenance and periodic testing.
  • Even though an internal technology may rely upon simple, basic principles, it is in fact, complex system that requires robust metering, robust SCADA and telecommunications, and a robust computer to perform the calculations. Each of these subsystems is individually complex.
  • Near the inlet and the outlet of the pipeline a leak leads to little or no change in pressure. Flow rates and pressures near any form of pumping or compression will generally be insensitive to a downstream leak
  • Differences in any one of these factors can have a dramatic impact on the ultimate value of a leak detection system.

The report goes on to  say:

There is no technical reason why several different leak detection methods can not be implemented at the same time. In fact, a basic engineering robustness principle calls for at least two methods that rely on entirely separate physical principles.

The report strongly recommends that pipeline companies take a closer look at external leak detection systems. Even though the US Environmental Protection Agency began recommending the use of external detection as far back as 1988, the companies have resisted due to the cost of retrofitting the legacy pipeline network. (Of course if the pipeline companies had started retrofitting with external detectors in 1988 they would be now 24 years into the process).

KAI says:

  • External leak detection is both very simple – relying upon routinely installed external sensors that rely upon at most seven physical principles – and also confusing, since there is a wide range of packaging, installation options, and operational choices to be considered.
  • External leak detection sensors depend critically on the engineering design of their deployment and their installation.
  • External sensors have the potential to deliver sensitivity and time to detection far ahead of any internal system.
  • Most technologies can be retrofitted to existing pipelines. In general, the resistance to adopting external technologies is, nevertheless, that fieldwork on a legacy pipeline is relatively expensive.
  • The report goes on to identify major bureaucratic roadblocks within pipeline companies. Like many other big corporations, walls exist that prevent the system from working well
  • A particular organizational difficulty with leak detection is identifying who “owns” the leak detection system on a pipeline. A technical manager or engineer in charge is typically appointed, but is rarely empowered with global budgetary, manpower or strategic responsibilities. Actual ownership of this business area falls variously to metering, instrumentation and control, or IT.

The report calls for better internal standards at pipeline companies since with leak detection “one size does not necessarily fit all”.

It also notes that “flow metering is usually a central part of most internal leak detection systems,” but adds “flow meter calibration is by far the most laborious part of an internal system’s maintenance.

Also, the central computer and software technology usually has maintenance requirements far greater than most industrial automation and need special attention.”

While a company may do a cost benefit analysis of its leak detection system and risk reduction system it will generally emphasize the costs of the performance and engineering design of the leak detection system, the companies usually place less emphasis on the benefits of a robust system, especially the long term benefits.

At present the pipeline companies look at the benefit of leak detection as a reduction in risk exposure, or asset liability, “a hard, economic definition… understood by investors.” But the report adds that leak detection systems have a very long lifetime and over that life cycle, the cost-benefit approaches the reduction in asset liability caused by the system, when divided by annual operational costs. However, since pipeline companies budget on a one to five year system the long term benefit of robust, and possibly expensive spill detection is not immediately apparent.


The consultants studied 11 US oil spills, the top two with the greatest volume were from Enbridge pipelines. The others were from TE Products Pipeline, Dixie Pipeline, Sunoco, ExxonMobil, Shell, Amoco, Enterprise Products, Chevron and Magellan Pipeline. Not all US spills were used in the KAI report, the 11 were chosen for availability of data and documentation.

The largest spill in the KAI study was the pipeline rupture in Michigan at 843,444 gallon (3,158,714 litres) which has been the subject of continuing media, investigative and regulatory scrutiny. The second spill in North Dakota, has up to now received very little attention from the media. That will likely change once the US Congress gets the final report. Even though the Neche, North Dakota spill, has been described as “text book case” of a pipeline shutdown, there was still a large volume of oil released.

Marshall, Michigan spill

On the Marshall, Michigan spill that sent bitumen into the Kalamazoo River the report first goes over the facts of the 843,444 gallon spill and the subsequent release of a highly critical report from the US National Transportation Safety Board. It then looks at the failures of Enbridge’s detection system from the point of view mandated for the report to Congress:

The pipeline was shutting down when the ruptured occurred. Documentation indicates that a SCADA alarm did sound coincident with the most likely time of the rupture. It was dismissed. The line was shut down for around 10 hrs and crude oil would have drained from the line during this time.

On pipeline start up, alarms in the control room for the ruptured pipeline sounded. They were dismissed. This was repeated two more times. The pipeline was shut down when the control room was notified of the discharge of the crude oil by a member of the public. The time to shut down the pipeline is not relevant here because of the 17 hours that elapsed after the rupture occurred.

The review identified issues at Enbridge relevant to this Leak Detection Study:

1. Instrumentation on a pipeline that informs a controller what is happening to the pipeline must be definitive in all situations.
2. However, the instrumentation did provide warnings which went unheeded by controllers.
3. Instrumentation could be used to prevent a pump start up.
4. Operators should not rely on the public to tell them when a pipeline has ruptured.
5. Pipeline controllers need to be fully conversant with instrumentation response to different operations performed on the pipeline.
6. If alarms can be cancelled there is something wrong with the instrumentation feedback loop to the controller. This is akin to the low fuel warning on a car being turned off and ignored. The pipeline controller is part of an LDS and failure by a controller means the LDS has failed even if the instrumentation is providing correct alarms.
7. If the first SCADA alarm had been investigated, up to 10 hours of pipeline drainage to the environment might have been avoided. If the second alarm had been investigated, up to 7 hours of pumping oil at almost full capacity into the environment might have been avoided.
8. CPM systems are often either ignored or run at much higher tolerances during pipeline start ups and shutdowns, so it is probable that the CPM was inoperative or unreliable. SCADA alarms, on the other hand, should apply under most operating conditions.

Neche, North Dakota spill

At approximately 11:37 pm. local time, on January 8, 2010, a rupture occurred on Enbridge’s Line 2, resulting in the release of approximately 3000 barrels or 158,928 gallons of crude oil approximately 1.5 miles northeast of the town of Neche, North Dakota, creating the sixth largest spill in the US during the study period.

As the report notes, in this case, Enbridge’s detection system worked:

At 11:38 pm., a low-suction alarm initiated an emergency station cascade shutdown. At 11:40 pm., the Gretna station valve began closing. At 11:44 pm., the Gretna station was isolated. At 11:49 pm., Line 2 was fully isolated from the Gretna to Donaldson pump stations.

Documentation indicates a rapid shut down on a low suction alarm by the pipeline controller. From rupture to shut down is recorded as taking 4 minutes. The length of pipeline isolated by upstream and downstream remotely controlled valves was 220,862 feet. The inventory for this length of line of 26-inch diameter is 799,497 gallons. The release amount was around 20 per cent of the isolated inventory when the pipeline was shut down.

The orientation of the 50-inch long rupture in the pipe seam is not known. The terrain and elevation of the pipeline is not known. The operator took around 2 hours and 40 minutes to arrive on site. It is surmised that the rupture orientation and local terrain along with the very quick reactions by the pipeline controller may have contributed to the loss of around 20 per cent of the isolated inventory.

The controller was alerted by the SCADA. Although a CPM system was functional the time of the incident it did not play a part in detecting the release event. It did provide confirmation.

But the KAI review identified a number of issues, including the fact in item (7) Enbridge did not plan for for containment and that containment systems were “under-designed.”

1. This release is documented as a text book shut down of a pipeline based on a SCADA alarm.
2. The LDS did not play a part in alerting the pipeline controller according to
documentation. However, leak detection using Flow/Pressure Monitoring via SCADA
worked well.
3. Although a textbook shut down in 4 minutes is recorded, a large release volume still occurred.
4. The release volume of 158,928 gallons of crude oil is the sixth largest hazardous liquid release reported between January 1, 2010 and July 7, 2012.
5. The length of pipeline between upstream and downstream isolation valves is long at 41.8 miles.
6. If not already performed, the operator should review potential release volumes based on ruptures taking place at different locations on the isolated section.
7. The success of a leak detection system includes planning for the entire process: detection through shutdown through containment. In this case, the operator did not plan adequately for containment so that although the SCADA leak detection technology, the controller and the procedures worked well, the containment systems (isolation valves) were under-designed and placed to allow a very large spill.”



 KAI Draft report on Leak Detection Systems at the Pipeline and Hazardous Materials Safety Administration website


From Pro Publica: North Dakota’s Oil Boom Brings Damage Along With Prosperity

Northwest Coast Energy News is republishing this story  on spills and other waste from the North Dakota shale oil and gas boom from the U.S. investigative site Pro Publica. Of most interest to readers here in northwest BC is ProPublica’s map of the spills in North Dakota, which is linked to in the story but not part of the republication package. You can find the map at this link or in the body of the story. That spill map, of course, could be a model for anyone tracking similar events in British Columbia.

North Dakota’s Oil Boom Brings Damage Along With Prosperity
by Nicholas Kusnetz, Special to ProPublica June 7, 2012

Oil drilling has sparked a frenzied prosperity in Jeff Keller’s formerly quiet corner of western North Dakota in recent years, bringing an infusion of jobs and reviving moribund local businesses.

But Keller, a natural resource manager for the Army Corps of Engineers, has seen a more ominous effect of the boom, too: Oil companies are spilling and dumping drilling waste onto the region’s land and into its waterways with increasing regularity.

Hydraulic fracturing 2014 the controversial process behind the spread of natural gas drilling 2014 is enabling oil companies to reach previously inaccessible reserves in North Dakota, triggering a turnaround not only in the state’s fortunes, but also in domestic energy production. North Dakota now ranks second behind only Texas in oil output nationwide.

The downside is waste 2014 lots of it. Companies produce millions of gallons of salty, chemical-infused wastewater, known as brine, as part of drilling and fracking each well. Drillers are supposed to inject this material thousands of feet underground into disposal wells, but some of it isn’t making it that far.

According to data obtained by ProPublica, oil companies in North Dakota reported more than 1,000 accidental releases of oil, drilling wastewater or other fluids in 2011, about as many as in the previous two years combined. Many more illicit releases went unreported, state regulators acknowledge, when companies dumped truckloads of toxic fluid along the road or drained waste pits illegally.

State officials say most of the releases are small. But in several cases, spills turned out to be far larger than initially thought, totaling millions of gallons. Releases of brine, which is often laced with carcinogenic chemicals and heavy metals, have wiped out aquatic life in streams and wetlands and sterilized farmland. The effects on land can last for years, or even decades.

Compounding such problems, state regulators have often been unable 2014 or unwilling 2014 to compel energy companies to clean up their mess, our reporting showed.

Under North Dakota regulations, the agencies that oversee drilling and water safety can sanction companies that dump or spill waste, but they seldom do: They have issued fewer than 50 disciplinary actions for all types of drilling violations, including spills, over the past three years.

Keller has filed several complaints with the state during this time span after observing trucks dumping wastewater and spotting evidence of a spill in a field near his home. He was rebuffed or ignored every time, he said.

“There’s no enforcement,” said Keller, 50, an avid outdoorsman who has spent his career managing Lake Sakakawea, a reservoir created by damming the Missouri River. “None.”

State officials say they rely on companies to clean up spills voluntarily, and that in most cases, they do. Mark Bohrer, who oversees spill reports for the Department of Mineral Resources, the agency that regulates drilling, said the number of spills is acceptable given the pace of drilling and that he sees little risk of long-term damage.

Kris Roberts, who responds to spills for the Health Department, which protects state waters, agreed, but acknowledged that the state does not have the manpower to prevent or respond to illegal dumping.

“It’s happening often enough that we see it as a significant problem,” he said. “What’s the solution? Catching them. What’s the problem? Catching them.”

Ron Ness, president of the North Dakota Petroleum Council, a lobbying group, said the industry is doing what it can to minimize spills and their impacts.

“You’re going to have spills when you have more activity,” he said. “I would think North Dakotans would say the industry is doing a good job.”

In response to rising environmental concerns related to drilling waste, North Dakota’s legislature passed a handful of new regulations this year, including a rule that bars storing wastewater in open pits.

Still, advocates for landowners say they have seen little will, at either the state or federal level, to impose limits that could slow the pace of drilling.

The Obama administration is facilitating drilling projects on federal land in western North Dakota by expediting environmental reviews. North Dakota’s Gov. Jack Dalrymple has urged energy companies to see his administration as a “faithful and long-term partner.”

“North Dakota’s political leadership is still in the mold where a lot of our oil and gas policy reflects a strong desire to have another oil boom,” said Mark Trechock, who headed the Dakota Resource Council, a landowner group that has pushed for stronger oversight, until his retirement this year. “Well, we got it now.”

Reaching ‘the Crazy Point’

Keller’s office in Williston is as good a spot as any to see the impacts of the oil boom.

The tiny prefab shack 2014 cluttered with mounted fish, piles of antlers and a wolf pelt Keller bought in Alaska 2014 is wedged between a levee that holds back Missouri River floodwaters and a new oil well, topped by a blazing gas flare. Just beyond the oil well sits an intersection where Keller estimates he saw an accident a week during one stretch last year due to increased traffic from drilling.

Keller describes the changes to his hometown in a voice just short of a yell, as if he’s competing with nearby engine noise. Local grocery stores can barely keep shelves stocked and the town movie theater is so crowded it seats people in the aisle, he said. The cost of housing has skyrocketed, with some apartments fetching rents similar to those in New York City.

“With the way it is now,” Keller said, “you’re getting to the crazy point.”

Oil companies are drilling upwards of 200 wells each month in northwestern North Dakota, an area roughly twice the size of New Jersey.

North Dakota is pumping more than 575,000 barrels of oil a day now, more than double what the state produced two years ago. Expanded drilling in the state has helped overall U.S. oil production grow for the first time in a quarter century, stoking hopes for greater energy independence.

It has also reinvigorated North Dakota’s once-stagnant economy. Unemployment sits at 3 percent. The activity has reversed a population decline that began in the mid-1980s, when the last oil boom went bust.

The growth has come at a cost, however. At a conference on oil field infrastructure in October, one executive noted that McKenzie County, which sits in the heart of the oil patch and had a population of 6,360 people in 2010, required nearly $200 million in road repairs.

The number of spill reports, which generally come from the oil companies themselves, nearly doubled from 2010 to 2011. Energy companies report their spills to the Department of Mineral Resources, which shares them with the Health Department. The two agencies work together to investigate incidents.

In December, a stack of reports a quarter-inch thick piled up on Kris Roberts’ desk. He received 34 new cases in the first week of that month alone.

“Is it a big issue?” he said. “Yes, it is.”

The Health Department has added three staffers to handle the influx and the Department of Mineral Resources is increasing its workforce by 30 percent, but Roberts acknowledges they can’t investigate every report.

Even with the new hires, the Department of Mineral Resources still has fewer field inspectors than agencies in other drilling states. Oklahoma, for example, which has comparable drilling activity, has 58 inspectors to North Dakota’s 19.

Of the 1,073 releases reported last year, about 60 percent involved oil and one-third spread brine. In about two-thirds of the cases, material was not contained to the accident site and leaked into the ground or waterways.

But the official data gives only a partial picture, Roberts said, missing an unknown number of unreported incidents.

“One, five, 10, 100? If it didn’t get reported, how do you count them?” he said.

He said truckers often dump their wastewater rather than wait in line at injection wells. The Department of Mineral Resources asks companies how much brine their wells produce and how much they dispose of as waste, but its inspectors don’t audit those numbers. Short of catching someone in the act, there’s no way to stop illegal dumping.

The state also has no real estimate for how much fluid spills out accidentally from tanks, pipes, trucks and other equipment. Companies are supposed to report spill volumes, but officials acknowledge the numbers are often inexact or flat-out wrong. In 40 cases last year, the company responsible didn’t know how much had spilled so it simply listed the volume of fluid as zero.

In one case last July, workers for Petro Harvester, a small, Texas-based oil company, noticed a swath of dead vegetation in a field near one of the company’s saltwater disposal lines. The company reported the spill the next day, estimating that 12,600 gallons of brine had leaked.

When state and county officials came to assess the damage, however, they found evidence of a much larger accident. The leak, which had gone undetected for days or weeks, had sterilized about 24 acres of land. Officials later estimated the spill to be at least 2 million gallons of brine, Roberts said, which would make it the largest ever in the state.

Yet state records still put the volume at 12,600 gallons and Roberts sees no reason to change it.

“It’s almost like rubbing salt in a raw wound,” Roberts said, criticizing efforts to tabulate a number as “bean counting.” Changing a report would not change reality, nor would it help anyone, he added. “If we try to go back and revisit the past over and over and over again, what’s it going to do? Nothing good.”

In a written statement, Petro Harvester said tests showed the spill had not contaminated groundwater and that it would continue monitoring the site for signs of damage. State records show the company hired a contractor to cover the land with 40 truckloads of a chemical that leaches salt from the soil.

Nearly a year later, however, even weeds won’t grow in the area, said Darwin Peterson, who farms the land. While Petro Harvester has promised to compensate him for lost crops, Peterson said he hasn’t heard from the company in months and he doesn’t expect the land to be usable for years. “It’s pretty devastating,” he said.

Little Enforcement

The Department of Mineral Resources and the Health Department have the authority to sanction companies that spill or dump fluids, but they rarely do.

The Department of Mineral Resources has issued just 45 enforcement actions over the last three years. Spokeswoman Alison Ritter could not say how many of those were for spills or releases, as opposed to other drilling violations, or how many resulted in fines.

The Health Department has taken just one action against an oil company in the past three years, citing Continental Resources for oil and brine spills that turned two streams into temporary toxic dumps. The department initially fined Continental $328,500, plus about $14,000 for agency costs. Ultimately, however, the state settled and Continental paid just $35,000 in fines.

The agency has not yet penalized Petro Harvester for the July spill, thought it has issued a notice of violation and could impose a fine in the future, Roberts said, one of several spill-related enforcement actions the agency is considering.

Derrick Braaten, a Bismarck lawyer whose firm represents dozens of farmers and landowner groups, said his clients often get little support from regulators when oil companies damage their property.

State officials step in in the largest cases, he said, but let smaller ones slide. Landowners can sue, but most prefer to take whatever drillers offer rather than taking their chances in court.

“The oil company will say, that’s worth $400 an acre, so here’s $400 for ruining that acre,” Braaten said.

Daryl Peterson, a client of Braaten’s who is not related to Darwin Peterson, said a series of drilling waste releases stretching back 15 years have rendered several acres unusable of the 2,000 or so he farms. The state has not compelled the companies that caused the damage to repair it, he said. Peterson hasn’t wanted to spend the hundreds of thousands of dollars it would take to haul out the dirt and replace it, so the land lies fallow.

“I pay taxes on that land,” he said.

At least 15 North Dakota residents, frustrated with state officials’ inaction, have taken drilling-related complaints to the U.S. Environmental Protection Agency in the last two years, records show.

Last September, for example, a rancher near Williston told the EPA that Brigham Oil and Gas had plowed through the side of a waste pit, sending fluid into the pond his cattle drink from and a nearby creek. When the rancher called Brigham to complain, he said, an employee told him this was “the way they do business.”

A spokeswoman for Statoil, which acquired Brigham, said the company stores only fresh water in open pits, not wastewater, and that “we can’t remember ever having responded in such a manner” to a report about a spill.

Federal officials can offer little relief.

Congress has largely delegated oversight of oil field spills to the states. EPA spokesman Richard Mylott said the agency investigates complaints about releases on federal lands, but refers complaints involving private property to state regulators.

The EPA handed the complaint about Brigham to an official with North Dakota’s Health Department, who said he had already spoken to the company.

“They said this was an isolated occurrence, this is not how they handle frac water and it would not happen again,” the official wrote to the EPA. “As far as we are concerned, this complaint is closed.”

Salting the Earth

Six years ago, a four-inch saltwater pipeline ruptured just outside Linda Monson’s property line, leaking about a million gallons of salty wastewater.

As it cascaded down a hill and into Charbonneau Creek, which cuts through Monson’s pasture, the spill deposited metals and carcinogenic hydrocarbons in the soil. The toxic brew wiped out the creek’s fish, turtles and other life, reaching 15 miles downstream.

After suing Zenergy Inc., the oil company that owns the line, Monson reached a settlement that restricts what she can say about the incident.

“When this first happened, it pretty much consumed my life,” Monson said. “Now I don’t even want to think about it.”

The company has paid a $70,000 fine and committed to cleaning the site, but the case shows how difficult the cleanup can be. When brine leaks into the ground, the sodium binds to the soil, displacing other minerals and inhibiting plants’ ability to absorb nutrients and water. Short of replacing the soil, the best option is to try to speed the natural flushing of the system, which can take decades.

Zenergy has tried both. According to a Department of Mineral Resources report, the company has spent more than $3 million hauling away dirt and pumping out contaminated groundwater 2014 nearly 31 million gallons as of December 2010, the most recent data available.

But more than a dozen acres of Monson’s pasture remain fenced off and out of use. The cattle no longer drink from the creek, which was their main water source. Zenergy dug a well to replace it.

Shallow groundwater in the area remains thousands of times saltier than it should be and continues to leak into the stream and through the ground, contaminating new areas.

There’s little understanding of what long-term impacts hundreds of such releases could be having on western North Dakota’s land and water, said Micah Reuber.

Until last year, Reuber was the environmental contaminant specialist in North Dakota for the federal Fish and Wildlife Service, which oversees wetlands and waterways.

Reuber quit after growing increasingly frustrated with the inadequate resources devoted to the position. Responding to oil field spills was supposed to be a small part of his job, but it came to consume all of his time.

“It didn’t seem like we were keeping pace with it at all,” he said. “It got to be demoralizing.”

Reuber said no agency, federal or state, has the money or staff to study the effects of drilling waste releases in North Dakota. The closest thing is a small ongoing federal study across the border in Montana, where scientists are investigating how decades of oil production have affected the underground water supply for the city of Poplar.

Joanna Thamke, a groundwater specialist with the U.S. Geological Survey in Montana, started mapping contamination from drilling 20 years ago. She estimated it had spread through about 12 square miles of the aquifer, which is the only source of drinking water in the area. Over the years, brine had leaked through old well bores, buried waste pits and aging tanks and pipes.

In the Poplar study and others, Thamke has found that plumes of contaminated groundwater can take decades to dissipate and sometimes move to new areas.

“What we found is the plumes, after two decades, have not gone away,” she said. “They’ve spread out.”

Poplar’s water supply is currently safe to drink, but the EPA has said it will become too salty as the contamination spreads. In March, the agency ordered three oil companies to treat the water or to find another source.

North Dakota officials are quick to point out that oversight and regulations are stronger today than they were when drilling began in the area in the 1950s. One significant difference is that waste pits, where oil companies store and dispose of the rock and debris produced during drilling, are now lined with plastic to prevent leaching into the ground.

New rules, effective April 1, require drillers in North Dakota to divert liquid waste to tanks instead of pits. Until now, drillers could store the liquid in pits for up to a year before pumping it out in order to bury the solids on site. The rule would prevent a repeat of the spring of 2011, when record snowmelt and flooding caused dozens of pits to overflow their banks.

But Reuber worries that the industry and regulators are repeating past mistakes. Not long before he left the Fish and Wildlife Service, he found a set of old slides showing waste pits and spills from decades ago.

“They looked almost exactly like photos I had taken,” he said. “There’s a spill into a creek bottom in the Badlands and it was sitting there with no one cleaning it up and containing it. And yeah, I got a photo like that, too.”

Keller has grown so dispirited by the changes brought by the boom that he is considering retiring after 30 years with the Army Corps and moving away from Williston. He runs a side business in scrap metal that would supplement his pension.

Still, determined to protect the area, he keeps alerting regulators whenever he spots evidence that oil companies have dumped or spilled waste.

Last July, when he saw signs of a spill near his home, Keller notified the Health Department and sent pictures showing a trail of dead grass to an acquaintance at the EPA regional office in Denver. The brown swath led from a well site into a creek.

If the spills continued, he warned the EPA in an email, they could “kill off the entire watershed.”

EPA officials said they spoke with Keller, but did not follow up on the incident beyond that. The state never responded, Keller said. The site remained untested and was never cleaned up.

“There was no restoration work whatsoever,” Keller said.


TransCanada restarting Keystone oil pipeline: Reuters


TransCanada Corp (TRP.TO) was restoring operations on Sunday along the Keystone crude oil pipeline, one week after it was shut by a leak at a Kansas pumping station, a company spokesman said.

“We are in the process of restarting Keystone but I can’t give you a firm time line (on shipments) – likely imminent,” said TransCanada spokesman James Millar in statement.

The 591,000 barrel-per-day pipeline brings oil from Hardisty, Alberta to the Cushing, Oklahoma, oil hub.

TransCanada News Release

CALGARY, Alberta – May 13, 2011 – TransCanada Corporation (TSX, NYSE: TRP) (TransCanada) today announced it has re-started its Keystone Pipeline system. The line has been closed since May 7 following an above-ground incident at a pump station in Sargent County, North Dakota. 

More than 30 workers and their equipment have been on site at the Ludden Pump Station. Three hundred and ninety three barrels of oil have been recovered out of an estimated 500 barrels. Three hundred cubic yards of contaminated soil will be removed to an approved location and replaced with clean soil and gravel. The majority of the clean-up should be finished by the weekend.

 “TransCanada has taken this incident very seriously. We have fully communicated details regarding the incident and our corrective actions to our U.S. regulator PHMSA in ensuring the steps we have taken will enable us to safely re-start the pipeline,” said Russ Girling, TransCanada president and chief executive officer. “We reacted quickly, shutting down the line within a few minutes of detecting a drop in pressure, demonstrating our safety systems work effectively.”