For Midstreamers, perhaps the ultimate daily objective is ‘throughput’ – keeping the barrel moving through the system – and thus making delivery at desired commercial markets. Throughput is crucial for operational success, facilitating the flow of hydrocarbons to their destination. However, numerous factors can disrupt this rhythm, and H2S/mercaptans may be high on that list.  

In today’s discussion, we will explore common scenarios Midstreamers face when dealing with H2S/mercaptans in their pipelines, terminals, or other facilities. While it’s widely recognized that H2S and mercaptans present commercial challenges like shut-ins, deducts, and demurrage charges, they also bring about significant operational and health concerns. 

So, what can be done to avoid these issues? First, understanding the nature of H2S and mercaptans can certainly help in preparing for their presence in your assets. Studies indicate that shale plays tend to sour or experience an increase in the presence of sulfide compounds the longer they stay on production. This is partly due to the formation of brine or other water sources seeping into the production horizon, revitalizing or introducing microbes present in crude to increase or initiate H2S production. Other post-production activities can contribute or act as accelerated incubators for H2S generation, namely through above ground contamination in tanks and pipes that all lead to H2S production. 

One frequently asked question is whether blending can resolve sour crude problems. While adding sweet crude to get into pipeline spec can partially address the issue, depending on the concentration of H2S or mercaptan levels, there might not be enough local volume to acquire for blending to reach a commercially acceptable threshold. And more importantly, it may not be economic to purchase that much blend stock. Chemical treatment is by far a more economic avenue. 

Regardless of how sulfur compounds started showing up, if blending is not the first step in solving the issue, treating it chemically is the next logical step. Addressing the issue at the earliest known location is critical to mitigate long-term exposure risks to personnel and assets. By limiting exposure, you can extend the lifespan of your assets without being exposed to the side effects of sulfur corrosion.  

Treating downhole is not suitable for the Pro3 Series technology due to pH levels and contaminants in water and gas phases. Other unknown factors that could affect performance include potential surfactants and other frac chemicals that have varying pH levels. These elements could counteract with the scavengers in a negative way. Hence, our process focuses on treating after the Heater Treater, which is after separation, to ensure that we are treating in the oil phase only. Our team would work with your engineers and operators to identify ways to optimize the treatment at locations such as this – affecting change on the afflicted crude oil molecules.  

In cases where isolated well sites are too remote or operationally burdensome to treat, identifying a comingled point along the trunk lines or at the terminal would be a more strategic treatment point. Since continuous flow is paramount, we would focus on finding places along the system that have the most flow or turbulence to assist in mixing terminals typically experience the highest shear along the midstream continuum, facilitating effective mixing of chemical products with crude oil during treatment. 

Lastly, treating before or directly onto a crude oil vessel at the port presents an opportunity for a final polishing treatment. Movements at the port are the final points along the midstream sphere of influence and provide an opportunity to offer the shipper a bit of insurance before proceeding to other markets that may have extremely tight parameters for meeting H2S, mercaptan, and sulfur concentration levels. 

Okay, but back to blending: when can it be implemented correctly? When the desired outcome is to reach as close to zero as possible, chemical treatment may have done the “heavy lifting” up to this point. In such cases, it may be worthwhile to consider blending feed stock as a final option. It may be a better use of allocations to introduce blending after chemical treatment has successfully removed a substantial portion of the issue. Incorporating a blending component into the overall mix may open opportunities for increased throughput.  

What has been a big issue affecting your system? Feel free to reach out to us to share. 

H2S removal from crude oil is a critical process to ensure compliance with quality specifications and safety standards. Mercaptans in crude oil contribute to corrosion and foul odors, posing challenges throughout the transportation and refining stages. Implementing effective H2S removal solutions not only mitigates operational disruptions but also safeguards assets and personnel against health hazards. By investing in robust removal technologies and strategic treatment points, midstream companies can optimize throughput while maintaining product integrity and meeting market demands.