In the rush to get more gathering and processing infrastructure in place to handle currently flared Bakken Shale associated gas, some hurdles are being met by wells with heavy concentrations of sour gas, or high hydrogen sulfide (H2S) levels, according to North Dakota energy officials.
It turns out that some of the new gas processing plants being built lack sulfur removal capabilities, said Lynn Helms, director of the state Department of Mineral Resources (DMR). “They are strictly designed for low-sulfur Bakken gas, so they can only handle a few parts-per-million of H2S,” he said.
Traditional gas streams run from 1% to up to 8%, according to Helms, who got in a discussion of the issue at a recent mid-month oil/gas production news media event. Older plants in the area can handle H2S content as high as 10% and processing the gas, but the newest plants cannot, Helms said.
He said the (Oneok Partners) Stateline and Garden Creek gas processing plants don’t have that capability, and it can be an issue depending on where the supplies come from.
“As a result, they are looking to put equipment somewhere out in the gathering system with the ability to remove sulfur from the gas so it never reaches the plant,” said Helms, noting that there would be a system to redirect the gas with heavy sulfur content to plants where it could be handled. “That would help if some plants go down due to the sulfur,” he said.
“It is a big issue, and its an issue the we [the state DMR] need to investigate in terms of what’s causing the higher sulfur content. At this point, we don’t know what is causing the hydrogen sulfide. It is just in some wells and some areas.”
Helms said it is found predominantly in older wells but has been also found in a newer Bakken well. In this case, “it really matters whether it is single wells or a wide area,” he said. Sour production from a single well can usually be dealt with at the well site before it enters the gas system, he said.
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