LONDON, May 29 (Reuters) - The discovery of perilous concentrations of hydrogen sulphide gas in a crude oil storage tank earlier this month has sparked a furious row between pipeline operator Enbridge and Bakken crude shippers including Plains Marketing and Murex.
On May 8, Enbridge Energy Partners made an emergency application to the Federal Energy Regulatory Commission (FERC) to amend its conditions of carriage to give it the right to reject crude containing more than 5 parts per million of hydrogen sulphide (H2S) (Docket IS13-273-000).
The pipeline operator made the application just three days after the vapours in one crude tank at Berthold terminal in North Dakota were sampled and found to contain H2S at an extremely high concentration of 1200 parts per million, more than enough to be fatal.
But the speed with which the company has sought to introduce new H2S limits, and its decision to impose more stringent ones than some other operators, have drawn a furious challenge from crude shippers who could be forced to shut in oil and gas wells as a result.
Hydrogen sulphide is a colourless, flammable and extremely hazardous gas formed by the breakdown of organic matter in the absence of oxygen, and is the most commonly occurring impurity in oil and especially gas fields.
Exposure to hydrogen sulphide causes severe irritation and respiratory problems. It is immediately dangerous to life and health at concentrations above 100 parts per million (ppm), according to the federal government’s Occupational Safety and Health Administration (OSHA).
Hydrogen sulphide is explosive when mixed with air, and can cause severe corrosion to oil field equipment including pipelines.
The characteristic rotten egg smell is detectable at concentrations well under 1 ppm, and becomes sickly sweet over 30 ppm, but is dangerously odourless when the concentration rises over 100 ppm because the olfactory nerves in the nose are paralysed.
Concentrations of as little as 50-200 ppm can cause shock, convulsions and coma. Inhaling H2S in excess of 1,000 ppm will cause immediate respiratory paralysis followed by death according to the Environmental Protection Agency (EPA) (“Report to Congress on Hydrogen Sulfide Air Emissions Associated with the Extraction of Oil and Gas” 1993).
Under OSHA regulations, workers must not be exposed to an average concentration more than 20 ppm over the course of an eight hour shift. Exposures of 20-50 ppm are permitted for no more than 10 minutes at a time. Workers must never be exposed to concentrations over 50 ppm.
In the circumstances, there is no surprise Enbridge took immediate action “to ensure the health and safety of Enbridge North Dakota employees” in the words of its filing with FERC.
Enbridge warned of the risk to employees and contractors involved in testing and maintenance activities, as well as loading crude from the pipeline system into railway tank cars. “Enbridge North Dakota ... will not expose employees to such a serious health risk that would contravene OSHA regulations,” the company told FERC.
Other operators have already introduced strict limits. Tesoro High Plains Pipeline has enforced a binding 5 ppm limit on its system since January 1. Belle Fourche and Bridger Pipeline companies have enforced 10 ppm limits on their own pipelines since April 1.
Enbridge warned shippers at a meeting on March 20 that it would likely follow suit, though it did not apparently stipulate a level or a date.
“At that time ... Enbridge had not seen any noticeable increase of hydrogen sulfide on its system and did not anticipate an immediate need to make that change,” according to the company’s submissions to FERC.
“In the next shipping cycle after the April 1 restrictions on competitor pipelines went into effect, there was a dramatic increase to the proportion of crude tendered to Enbridge North Dakota with high levels of hydrogen sulfide.”
The company felt compelled to act “given the spike in hydrogen sulphide levels on its system and the emergency need to protect workers.”
Plains Marketing and Murex Petroleum have asked FERC to reject the application.
Both complain Enbridge has not given them enough time to comply. The abrupt attempt to implement it “has left Plains in the extremely difficult position of potentially having to shut in up to 4,000 barrels per day of crude petroleum that might exceed the proposed standard,” the company wrote to FERC.
“Typically crude oil marketers purchase and resell crude oils of differing qualities and they are obviously not capable of instantaneously changing their purchase and sale arrangements to meet newly imposed quality standards,” Plains explained.
“Nor can they bring crude oil that has already been purchased and stored, and that is fully compliant with existing quality standards, into instantaneous compliance with newly imposed requirements.”
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Both shippers also question why Enbridge is trying to impose a 5 ppm limit (with discretion to accept crudes with more H2S given advanced notice) when some other operators have settled for a 10 ppm one.
Murex suggested the problem stems from Enbridge’s decision to stop operating the pipeline in batch mode (with each shipper’s crude handled separately) and to combine it with a rail terminal.
“Enbridge ND’s employees operated the same pipeline facilities and managed the same risk for decades of batched transportation service. The risk of workers becoming exposed to H2S gas appears to have been triggered by Enbridge’s agreement to allow its affiliate to connect a rail terminal on the North Dakota system,” Murex argued.
Plains too wondered why Enbridge tried to hurry in restrictions with just 24 hours notice.
“No hydrogen sulfide standard has been in existence on the Enbridge North Dakota system for approximately the last twenty years.” It complained the “Draconian” 10 ppm standard had been rushed in “based on a single test”.
The dispute points to the potential for a bigger problem with Bakken crude.
Most oil and gas fields produce some hydrogen sulphide but the proportion varies widely. Oil fields tend to produce relatively little, while in a gas field the proportion can rise to 40 percent or even 90 percent.
Twenty “vulnerability zones” have been identified in the United States which are especially prone to hydrogen sulphide in underground formations linked with oil and gas.
The potential in western North Dakota, where the Bakken is being drilled, has been known for decades and the state was the first to establish a comprehensive monitoring programme back in the early 1980s. But H2S concentrations are very field and pool/layer specific.
In North Dakota’s Little Knife oil field, the concentration of H2S in gas produced from the Madison Pool is approximately 10 percent, and the Red River formation almost 8 percent, but there has been negligible hydrogen sulphide in gas produced from the Bakken and Duperow layers, EPA told Congress in 1993.
Well operators with sour oil or gas must install expensive separation equipment to remove the H2S or send it to a treatment plant on dedicated sour gas/oil pipelines.
Bakken is primarily oil-bearing, containing low levels of sulphur, which is why the oil is prized as a sweet crude, so the risk of encountering high concentrations of H2S has been seen as low.
But the Bakken is big; some wells will yield more sulphur and H2S than others. H2S levels are not necessarily constant either. The process by which an oil field can sour, yielding more H2S over time as the oil is produced, is well known within the industry.
“The souring of oil ... from reservoirs in the Bakken Formation has been observed in the field,” according to one paper presented to the Society of Petroleum Engineers in 2011. Fracturing, underground mineral migration and bacterial action can all cause an oil or gas field to become more sour.
The spike in H2S on Enbridge’s system suggests there could be a problem with at least some wells. Pipeline operators as well as the rest of the industry will be watching carefully.
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