H2S and Mercaptan Treatment in Crude Oil: Key FAQs from Midstream Companies

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Q2 Technologies Team

Experts in H2S Scavenging Solutions

With decades of combined experience, the Q2 Technologies team specializes in innovative hydrogen sulfide (H2S) scavenging solutions for the oil and gas, wastewater treatment, and industrial sectors.

Addressing H2S/Mercaptans in Crude Oil: Treatment Options at the Wellhead, Terminal, or Port.

– FAQs from Various Midstream Companies.

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.

What challenges do H2S and mercaptans pose for midstreamers?

Commercial Challenges
  • Pipeline and terminal shut-ins.
  • Quality deducts (lower product value).
  • Demurrage charges due to delays in handling contaminated crude.
Operational & Safety Concerns
  • Health risks: H₂S is toxic and poses serious safety hazards for workers.
  • Corrosion issues: Sulfide compounds can damage pipelines, tanks, and infrastructure.
  • Operational disruptions: Requires treatment, monitoring, and sometimes halts in flow.
Causes of H₂S/Mercaptans Formation
  • Souring of shale plays: Longer production periods increase sulfide compound presence.
  • Brine/water seepage: Water sources enter production horizon, activating microbial activity.
  • Microbial activity: Revitalized or introduced microbes generate H₂S.
  • Post-production contamination: Tanks and pipes can act as incubators, accelerating H₂S production.

Can blending solve sour crude problems?

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.

Why treat H2S after separation, not downhole?

Treating downhole is not optimized for the Pro3 Series technology due to its pre-separation nature where crude, water, and gas are all commingled (three-phase). 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.

Where along the midstream chain should treatment happen?

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.

How can ports provide a final opportunity for 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.

Q2 Technologies, is a leading provider of chemical treatment solutions. Unlike traditional oilfield chemical companies and oilfield chemical suppliers, Q2 Technologies offers innovative products such as the Pro3 NGL catalyst. Contact Q2 Technologies today to learn more about this revolutionary approach to oilfield chemical treatment.

Addressing H2S/Mercaptans in Crude Oil: Treatment Options at the Wellhead, Terminal, or Port.

– FAQs from Various Midstream Companies.

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.

What challenges do H2S and mercaptans pose for midstreamers?

Commercial Challenges
  • Pipeline and terminal shut-ins.
  • Quality deducts (lower product value).
  • Demurrage charges due to delays in handling contaminated crude.
Operational & Safety Concerns
  • Health risks: H₂S is toxic and poses serious safety hazards for workers.
  • Corrosion issues: Sulfide compounds can damage pipelines, tanks, and infrastructure.
  • Operational disruptions: Requires treatment, monitoring, and sometimes halts in flow.
Causes of H₂S/Mercaptans Formation
  • Souring of shale plays: Longer production periods increase sulfide compound presence.
  • Brine/water seepage: Water sources enter production horizon, activating microbial activity.
  • Microbial activity: Revitalized or introduced microbes generate H₂S.
  • Post-production contamination: Tanks and pipes can act as incubators, accelerating H₂S production.

Can blending solve sour crude problems?

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.

Why treat H2S after separation, not downhole?

Treating downhole is not optimized for the Pro3 Series technology due to its pre-separation nature where crude, water, and gas are all commingled (three-phase). 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.

Where along the midstream chain should treatment happen?

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.

How can ports provide a final opportunity for 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.

Q2 Technologies, is a leading provider of chemical treatment solutions. Unlike traditional oilfield chemical companies and oilfield chemical suppliers, Q2 Technologies offers innovative products such as the Pro3 NGL catalyst. Contact Q2 Technologies today to learn more about this revolutionary approach to oilfield chemical treatment.

When introduced into a stream afflicted with H2S, the hemiformal decomposes to release formaldehyde, which then reacts with hydrogen sulfide to form stable, non-volatile byproducts such as thiomethylene glycol.  The reaction is typically fast and efficient, particularly in aqueous or mixed-phase environments. Unlike some traditional scavengers, hemiformal can maintain activity across a broad pH range and is less likely to generate problematic solids. When considering if hemiformal is the right product, certain operating conditions are reviewed, such as pH and temperature.

Heading 1

When introduced into a stream afflicted with H2S, the hemiformal decomposes to release formaldehyde, which then reacts with hydrogen sulfide to form stable, non-volatile byproducts such as thiomethylene glycol.  The reaction is typically fast and efficient, particularly in aqueous or mixed-phase environments. Unlike some traditional scavengers, hemiformal can maintain activity across a broad pH range and is less likely to generate problematic solids. When considering if hemiformal is the right product, certain operating conditions are reviewed, such as pH and temperature.

Heading 2

When introduced into a stream afflicted with H2S, the hemiformal decomposes to release formaldehyde, which then reacts with hydrogen sulfide to form stable, non-volatile byproducts such as thiomethylene glycol.  The reaction is typically fast and efficient, particularly in aqueous or mixed-phase environments. Unlike some traditional scavengers, hemiformal can maintain activity across a broad pH range and is less likely to generate problematic solids. When considering if hemiformal is the right product, certain operating conditions are reviewed, such as pH and temperature.

Heading 3

Heading 4

When introduced into a stream afflicted with H2S, the hemiformal decomposes to release formaldehyde, which then reacts with hydrogen sulfide to form stable, non-volatile byproducts such as thiomethylene glycol.  The reaction is typically fast and efficient, particularly in aqueous or mixed-phase environments. Unlike some traditional scavengers, hemiformal can maintain activity across a broad pH range and is less likely to generate problematic solids. When considering if hemiformal is the right product, certain operating conditions are reviewed, such as pH and temperature. 

Key Benefits:

  • Controlled formaldehyde release 
  • Lower vapor pressure and improved safety profile 
  • Broad applicability across liquid and gas-phase systems 
  • Reduced scaling in sour water stripping and other high-temp operations 
  • Hemiformal can make the scavenger safe for transport as it is a very stable compound 

Heading 5

Hemiformal is used in a variety of upstream and midstream applications, including: 

  • Gas sweetening systems 
  • Produced water treatment 
  • Crude oil storage and transport 
  • Sour water stripper overheads 
  • Temporary H2S mitigation during maintenance or turnaround

Its adaptability makes it especially useful in operations where system conditions fluctuate or where traditional triazine-based products may underperform. 

Heading 6

While hemiformal offers many advantages, it is not a one-size-fits-all solution. The rate of formaldehyde release can vary depending on formulation and environmental conditions. Additionally, while safer than raw formaldehyde, hemiformal must still be handled with care and appropriate PPE. 

For optimal results, formulation expertise and application-specific customization are key—something we at Q2 Technologies excel at delivering. 

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