SJE is a leading maker of “dry media” for the oilfield, and we are leaders in eradicating H₂S gas from natural gas streams. When I describe our system to people unfamiliar with the chemistry, I often say there are two broad approaches to eliminating H₂S: the dry way (ours) and the wet way.
Because dithiazine and its polymerized forms have very low solubility, they precipitate out — inside pipes, vessels, heat exchangers, separators, you name it.
So what exactly is the “wet way,” and why do some operators go that route? The wet way typically means using a liquid triazine derivative injected into a vessel, scrubber, or contactor. That way, the H₂S is converted to something else rather than reacted out of existence, as in a solid bed media tower.
To understand how the wet way works (and why it has pros and cons), you need a short chemistry lesson about triazines.
Triazine is a nitrogen-containing heterocycle with the parent formula C₃H₃N₃ (or substituted variants), and there are several kinds. In oil & gas, “triazine” has become shorthand for a specific class of H₂S scavenger molecules. The version most used in H₂S mitigation is MEA-triazine, which stands for monoethanolamine-substituted triazine. Geek out on these terms as you see fit!
At a well pad, triazine is fed into a contact zone (pipe, vessel, scrubber) where the sour gas passes or bubbles through. The reaction is a kind of nucleophilic substitution: the triazine effectively donates electrons to bind sulfur from the H₂S. One mole of MEA-triazine reacts with two moles of H₂S, forming a new molecule called dithiazine.
And so, the H₂S is no longer free to do harm, but the new problem comes with the dithiazine. The monomeric formula for what we call MEA-dithiazine is C₅H₁₁NOS₂. Over time, the dithiazine tends to polymerize, forming insoluble deposits. This spells trouble.
Because dithiazine and its polymerized forms have very low solubility, they precipitate out — inside pipes, vessels, heat exchangers, separators, you name it. As that material builds up, the pipe diameter shrinks. Pressure drop increases. Flow may get choked or restricted in spots. The deposits are chemically sticky, and sometimes they bind to other chemical species present, making them hard to remove.
Because deposits are so persistent, equipment often must be taken offline for mechanical or chemical cleaning (chipping, acid washes, high-pressure jetting). Some chemical dissolvers (for example, hydrogen peroxide) offer partial relief, but they have drawbacks: risk of corrosion, poor penetration into dense deposits, limited effectiveness.
There’s another operational pain:
As the deposits grow, some of your active scavenger chemistry is diverted into forming more solids rather than doing the clean H₂S removal you paid for. If you try to compensate by overdosing, your chemical costs balloon. Also, the deposits themselves can act as sinks or “adsorbers” for corrosion inhibitors, surfactants, or other downstream additives — reducing their effectiveness.
So yes:
When everything goes well, triazine works, and you remove H₂S. But the catch is that your byproduct (dithiazine/polymer) often starts causing deposits downstream.
Given all these potential drawbacks, why does triazine still maintain a niche in the H₂S world? Because it is cheap (relatively), easy to handle in many settings, and simple to inject or dose in a tower or line. In cases with moderate H₂S load and modest flow, its capital simplicity and low up-front costs make it attractive — provided the operator is willing to accept or manage the downstream risks.
The dry method has none of these downstream effects. The H₂S is reacted away in the tower. It’s gone. Dead. Bye-bye. At SJE, we can compare our solution to triazine and provide insight into the costs and concerns of both methods. Reach out for a short consultation.
