An Integrated Frac Geometry Control Approach To Prevent H2S Production
Authors: Do Tien 
Published: January 2024

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Hydrogen sulfide (H2S) production has in recent years become a mounting issue facing operators and midstream companies in major US basins.

At present, H2S production appears to be random and poorly understood. As such, H2S is considered by many to be an unpreventable nuisance and one that is largely addressed by treating the dangerous gas at surface before putting it to a sales line.

This article highlights impacts of H2S, possible sources, and a successful case study of a completions operation designed specifically to prevent H2S production in North Dakota’s Williston Basin.

H2S and Its Impacts

H2S is a colorless gas known for its pungent “rotten egg” odor at low concentrations. It is extremely flammable, highly toxic, poisonous, and corrosive. H2S is commonly encountered during the drilling and production of crude oil and natural gas, as well as in wastewater treatment, utility facilities, and sewers.

H2S is well-known for its significant health and safety risks, along with substantial financial implications in the event of an accidental release. The substance ranks as the second leading cause of workplace gas inhalation deaths in the US. This is according to the US Bureau of Labor Statistics, which concluded that H2S caused 46 worker deaths between 2011 and 2017.

Due to its corrosiveness, wells that produce even small volumes of H2S may compromise wellbore integrity and lead to premature failure of production equipment. Sour oil and gas is considered to have about 10% lower profit margin than traditional sweet Bakken crude (SPE 141434).

An electrical submersible pump replacement can cost an operator up to $250,000, plus production downtime. Additionally, according to one leading chemical company, it costs $2,250 per day to treat 200 ppm H2S at a typical gas production rate of 2,000 Mcf/D.

H2S Sources

A recent study, URTeC 3852794, published by the Energy and Environmental Research Center (EERC) at the University of North Dakota suggests three possible causes of H2S: geo-mechanical, thermochemical, and biogenic.

Geo-mechanical: Mission Canyon organic-rich intervals could be a source of H2S for a limited number of the Bakken producing wells via communication between reservoirs caused by out-of-zone stimulation work. This conclusion was evidenced by matching the δ34S isotope between 30 H2S producing wells and formation cores.

Thermochemical sulfate reduction (TSR): Another possible mechanism of H2S generation involves the presence of anhydrites and hydrocarbons at a higher reservoir temperature of 110° to 150°C. This mechanism is plausible for wells with the δ34S in the range from +10 to +19‰. The EERC research team is currently investigating the TSR existence in the Williston Basin.

Biogenic: This third mechanism of reservoir souring is questionable in the Bakken because of the high reservoir temperatures (110° to 150°C) and elevated salinity of the formation water (TDS 200,000 mg/L) making microbial growth unlikely, especially in the context of the predominance of heavier 34S isotope (δ34S of +2 to +19‰) in produced H2S.