Triazine vs. Pro3® GT & GT+: Is it time to Make the Switch for H2S Removal?

Triazine vs. Pro3 GT & GT+: Is it time to Make the Switch for H2S Removal? 

The natural gas industry faces a constant challenge: removing harmful hydrogen sulfide (H2S) from its product for safe and efficient transportation. Traditionally, triazine has been the go-to solution, but recent innovations have sparked a question – are there better options available? 

Our team at Q2 Technologies made a laboratory investigation to compare the performance of triazine, Pro3 GT, and GT+. This wasn’t just about finding alternatives, it was about discovering solutions that could streamline operations and overcome the limitations of existing methods. 

The Experiment Unfolds 

We first pitted 40% active MEA triazine against Pro3 GT, its chemically similar counterpart designed as a direct substitute. Both performed neck and neck in H2S removal efficiency until the point of breakthrough. As expected, Pro GT+, as a concentrated form of Pro3 GT, was able to last longer in this controlled application. 

triazine vs pro3 gt removal efficiency

Beyond Efficiency: The Challenge of Solids 

But our investigation didn’t stop there. We delved into the byproducts formed during H2S removal. Triazine, under excessive dosing, readily formed solid compounds – dithiazine and trithiane – which can wreak havoc on equipment, causing blockages and operational headaches. Pro3 GT and GT+, on the other hand, remained liquid even under overdosing, showcasing their resistance to solid formation. 

Triazine byproducts

When the Temperature Drops: 

We then turned our focus towards extreme cold, mimicking harsh winter conditions. Unfortunately, triazine faltered again, solidifying – exactly mimicking what we see in cold conditions -icing up hinders the ability to operate. In contrast, Pro3 GT and GT+ maintained their liquid state, proving their ability to withstand harsher environments. 

Triazine temperature trial

The Verdict: A Promising New Chapter 

While this study offers a glimpse into the potential advantages of Pro3 GT and GT+, it’s crucial to remember that the real world presents a complex landscape. Field conditions and economic factors like cost and treatment longevity also play a vital role in the decision-making process. 

However, the impressive performance of Pro3 GT and GT+ in H2S removal efficiency, resistance to solid formation, and cold temperature resilience suggests they can be strong contenders in the H2S removal arena. We encourage you to explore further, consult with professionals, and consider all factors before embarking on your own journey towards a streamlined and efficient H2S removal solution. 

Addressing H2S/Mercaptans in Crude Oil: Treatment Options at the Wellhead, Terminal, or Port. – FAQs from Various Midstream Companies. 

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

– FAQs from Various Midstream Companies. 

Midstream continuum h2s and mercaptans

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 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.  


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. 

h2s and mercaptan treatment process

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.

Not passing copper strip tests at truck offload stations?

Not passing copper strip tests at truck offload stations? 

Copper strip test image

When delivering NGLs, field stabilized liquid products, or even plant processed purity products, H2S and mercaptans can still cause problems for on spec deliveries. Copper strip testing in the oil and gas industry, a measurement of the corrosion potential found in different liquids, has been a testing staple for decades. Metallurgical analysis and failure procedures has been an area of study since the beginning of modern chemistry.  

A requirement that jet fuel must pass the copper strip corrosion test ensures that organic sulfur compounds are not present in the product that could corrode or impede copper-based alloys that may be present in certain jet engines or components that make up jet turbine systems. As an approved ASTM method, test D130/IP 154 states that a polished copper strip coupon be immersed in a sample for 2 hours at 100C/212F and then removed and washed. It is then visually inspected and compared to an agreed upon standard chart (an example chart depicted above). If sulfur compounds are present, the coupon will tarnish going from a shiny copper penny sheen to a bluish/purple distortion, often in wavy or swirl type stains, to increasingly black/dark and pitted conditions on the sample.  

Truck LACT setup

With Q2 Technologies’ Pro3 NGL, a non-amine/non-triazine based and highly engineered dry catalyst, the afflicted product is routed through a set of fixed reactor units allowing for the truck LACT location to accept and treat on-demand. Treatment can occur prior to or after the LACT intact, the fixed reactors do not use moving elements and the system is not contingent on continuous flow. This system is designed with flexibility in mind and will ensure that product meets copper strip testing and other UOP or ASTM methods also approved for merchantability.  

Want to learn even more? Feel free to reach out to us.  

Interested in a liquid chemical solution to treat H2S or mercaptans in crude oil? Check out our solution here! 

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.

Testing and Treating H2S and Mercaptans in Crude Oil

Testing and Treating H2S and Mercaptans in Crude Oil 

H2S monitor

We recently attended a conference in Salt Lake City, where we discussed various testing methods for H2S and mercaptans. Given the significant interest in this topic, we want to provide an overview for those who could not attend. Crude oil, a crucial resource in the energy industry, often contains unwanted contaminants such as Hydrogen Sulfide (H2S) and Mercaptans. These compounds not only impact the oil’s quality but also pose substantial health and safety risks. In this blog, we will delve into the testing and treatment methods typically used for these compounds. 

A Brief Overview of H2S & Mercaptans 

Hydrogen Sulfide (H2S): 

H2S is a toxic and pungent gas found in both the formation and post-production phases of crude oil. It is present in crude oil, natural gas, and water, earning it the nickname “sour gas.” H2S is soluble in water and behaves like a weak acid, making it corrosive. 

Mercaptans (RSH): 

Mercaptans are organic molecules with a structure resembling alcohol but with a sulfur atom chained to hydrocarbons, known as thiols. There are many mercaptan species, and they are notorious for their unpleasant odor. The human nose can detect mercaptans at concentrations as low as 10 parts per billion (ppb). 

Testing Procedures 

Testing for H2S and Mercaptans is a crucial step in ensuring the quality and safety of crude oil. However, not all testing methods are created equal, and the choice of method often depends on the commercial contract. Some common testing methods include: 

Vapor Testing 

  • ASTM 5705 modified: A test that yields results in H2S concentration (ppm/v). It has been modified to test crude oil since it was originally designed for fuel oil testing. 

Liquid Testing: 

  • ASTM D7621: A standard method for determining H2S in fuel oils by rapid liquid phase extraction. 
  • UOP 163: A titration that measures H2S (ppm/w) and mercaptan (ppm/w) concentrations. 
  • ASTM D5623: A GC method that provides H2S (ppm/w) and mercaptan speciation (ppm/w) data. 
  • ASTM D130-9/D1838-16: A subjective copper strip test for specific sulfur contaminants. 

Results obtained through these tests are vital for H2S scavenging, ensuring safety, and adhering to contract specifications. Historically, there has been a lack of correlation between different test methods, emphasizing the importance of using a consistent method throughout the process. In the United States, UOP 163 and ASTM 5705 are commonly used for crude oil quality contracts. 

Challenges with Testing Methods 

  • ASTM 5705 modifications may be necessary to adapt to crude oil testing conditions, and there is no standardized temperature for testing in practice. 
  • Reading stain tubes can be challenging. Moisture in the air and other contaminants in the raw crude oil may negate the accuracy of the tube. 
  • UOP 163 may suffer from interference by chemical contaminants and variations in technicians’ interpretations of titration curves. 

Scavengers for H2S and Mercaptans 

To address the presence of H2S and Mercaptans in crude oil, various scavenging methods are employed. These include: 

  1. Typical Amines:
  • Monoethanolamine (MEA) 
  • Diethanolamine (DEA) 
  • N-methyldiethanolamine (MDEA) 
  • Diglycolamine (DGA) 
  1. Non-Regenerative H2S Scavengers:
  • Solid, basic metallic compounds 
  • Oxidizing chemicals 
  • Aldehydes, including Formaldehydes 
  • Reaction products (may include triazines) 
  • Metal carboxylates/chelates 
  • Other amine-based solutions 

Each of these chemical solutions has its advantages and disadvantages, making it necessary to evaluate them on a case-by-case basis. 

Alternatives to Treat H2S 

In addition to scavenging methods, nitrogen stripping is an alternative approach to treat H2S. This method involves bubbling nitrogen through a column, which attracts H2S, allowing lighter-end volumes to escape and be transported to a flare. However, this process comes with its own set of considerations, including the need for a compressor, a nitrogen membrane generation unit, stripping tower kit, and a tie-in to the flare line. Moreover, the loss of hydrocarbons at the flare may raise environmental, social, and governance (ESG) concerns. 

Why It Matters 

Understanding and effectively addressing H2S and Mercaptans in crude oil is essential for various reasons: 

  • Prolonging Asset Life: Proper treatment ensures that your assets last longer, maximizing their value. 
  • Expanding Markets: High-quality crude with low H2S and Mercaptan content opens doors to more markets. 
  • Building Optionality: The ability to adapt to different market conditions leads to better netback prices. 
  • Ensuring Personnel Safety: Protecting the health and safety of workers is of utmost importance. 
  • Asset Integrity: Treating H2S and Mercaptans preserves the integrity of equipment and facilities. 

 Managing H2S and Mercaptans in crude oil is a critical aspect of the industry. By understanding the characteristics of these compounds, employing appropriate testing methods, choosing effective scavengers, and considering alternative treatments, companies can ensure safer operations and better financial outcomes. Ultimately, the equation for success in the industry is the combination of the highest quality and merchantability, resulting in the highest netback prices. 

Final Thoughts  

Understanding and complying to the commercial contract is paramount. These commercial contracts will stipulate which method is required to meet specifications, so when in doubt, have the operations team speak to the crude quality or commercial teams to understand the exact parameters to ensure the quality of the crude is being met for final delivery. 

Sulfur and Carbon: A Plight in the Oil & Gas Industry

Sulfur and Carbon: A Plight in the Oil & Gas Industry 

Sulfur and Carbon

According to a report by Grand View Research, fluctuations in crude oil prices and the growing number of mature oil fields in the U.S. are expected to result in a substantial surge in the adoption of enhanced oil recovery methods, aimed at improving the efficiency and effectiveness of oil production from wells. Additionally, the report highlights that the U.S. carbon dioxide market was valued at USD 3.19 billion in 2021 and is projected to grow at a compound annual growth rate (CAGR) of 8.4% from 2022 to 2030. These findings emphasize the significance of these factors in shaping the oil and gas industry landscape. 

Given the relevance of this forthcoming growth, we think addressing the challenges associated with sulfur and carbon in the oil and gas industry is important, this blog focuses on these two powerful elements. Extracted from crude oil and natural gas, sulfur, and carbon bring forth unique challenges, including handling difficulties, corrosion risks, health concerns, and environmental impacts. Understanding and effectively managing these challenges is crucial. In this blog, we will explore the showdown between sulfur and carbon and delve into the innovative solutions offered by Q2 Technologies to overcome these challenges. 


Sulfur: Unleashing the Corrosive Fury 

In the duel between sulfur and carbon, sulfur emerges as a corrosive antagonist in the oil and gas industry. Sulfur compounds, found in crude oil and natural gas, pose a relentless threat to equipment, pipelines, and infrastructure. Their corrosive nature can cause degradation, leaks, and expensive maintenance issues, putting the operational efficiency and safety of oil and gas facilities at risk. Additionally, the health hazards of sulfur include respiratory problems and eye irritation for industry workers. 

Sulfur compounds released into the atmosphere during oil and gas extraction can contribute to air pollution and the destructive phenomenon of acid rain. This not only harms ecosystems and vegetation but also corrodes infrastructure. Furthermore, sulfur dioxide emissions can have detrimental effects on human and animal health, leading to respiratory issues and other health problems. In response to these concerns, countries have implemented stringent regulations mandating the use of emission control technologies to reduce sulfur content in fuels. 

Sulfur release


Carbon: Confronting the Challenges of a Powerful Element 

As if it wasn’t enough, now carbon takes center stage as a significant risky element. As a vital component in energy production and industrial processes, carbon presents unique challenges that directly impact the industry’s infrastructure and operations. From the accumulation of carbon deposits causing blockages in pipelines to the potential corrosion risks associated with certain carbon compounds, the oil and gas sector faces the need to address these challenges head-on. To maintain their competitive edge and uphold environmental responsibilities, companies seek innovative solutions that excel in performance. 

Carbon: Confronting the Challenges of a Powerful Element  



Molecule Combinations: Unveiling the Risks 

The fight between sulfur and carbon gives rise to various molecule combinations, each with its own set of risks and consequences. Sulfur dioxide (SO2), a byproduct of sulfur combustion, poses significant health hazards and contributes to air pollution and acid rain. The corrosive nature of SO2 presents a tangible challenge for equipment and infrastructure, adding complexity to the operations of the industry. The detrimental effects of SO2 emissions must be carefully managed to ensure the longevity and integrity of critical assets. 

On the other hand, carbon dioxide (CO2), the primary molecule combination resulting from carbon combustion, presents a critical challenge in the ongoing fight against climate change. The rapid increase in CO2 emissions is a concern for the industry, as it contributes to global warming and climate instability.  

Furthermore, the combination of CO2 with water forms carbonic acid (H2CO3), which leads to ocean acidification. This process poses a threat to marine ecosystems, including delicate coral reefs. As greenhouse gases, carbon compounds such as carbon dioxide (CO2) and methane (CH4) play a significant role in exacerbating global warming and climate change. To address these challenges, it is crucial to focus on the capture and storage of carbon emissions. 


Sulfur and Carbon Disposal 

Sulfur and Carbon Disposal

Carbon Capture and Storage (CCS) and transporting sulfur and carbon require specialized infrastructure and handling procedures. Sulfur is commonly stored and transported in solid form, while CCS involves capturing and compressing CO2 for transport to storage sites. These processes come with significant costs and require careful planning. The disposal of sulfur and carbon byproducts must adhere to environmental regulations and sustainability practices, adding to the economic challenge. 


Q2 Technologies enters with solutions 

As the oil and gas industry grapples with the challenge of the Sulfur & Carbon issues, Q2 Technologies is taking on the mantle with the Pro3 series especially formulated to combat Hydrogen Sulfide, a toxic gas and common offshoot of Sulfur found in crude oil and natural gas. With its advanced chemistry and proven effectiveness, Pro3 series products extend the operational lifespan of equipment and infrastructure, reducing maintenance costs and enhancing safety within the oil and gas industry and most importantly, they remove H2S to avoid health risks and increase the value of the barrels. Further, in combination with assisting carbon sequestration in treating H2S in CO2 streams, the Pro3 Nano catalytic absorbent and engineered reactor units allow CO2 and other Carbon molecules to pass through unabated, thus allowing the Producer or Transporter of the CO2 stream to move the entirety of the stream to carbon sequestration wells. 



In the dual effort to clean or remove both sulfur and carbon from oil and gas, Q2 Technologies emerges as a formidable competitor with our Pro3 series, offering advanced solutions to combat components of Sulfur and aid in carbon sequestration efforts. With our proven effectiveness, these products extend equipment lifespan, reduce maintenance costs, and enhance safety, while removing harmful substances and increasing the value of oil and gas production. By adopting responsible practices and innovative technologies like the Pro3 series, the industry can overcome the challenges posed by sulfur and carbon, paving the way for a cleaner, more efficient, and sustainable future in the oil and gas sector. 

Common Questions About H2S Removal from Natural Gas Answered

Common Questions About H2S Removal from Natural Gas Answered

Hydrogen Sulfide (H2S), commonly found in natural gas reservoirs, is a colorless gas that poses serious health and safety threats to people, including asset corrosion and degradation. Therefore, H2S removal from natural gas production processes must be an integral component of production operations; so, in this blog post, we address some frequently asked questions regarding H2S and its removal from natural gas. 

What is H2S removal from natural gas? 

H2S removal from natural gas refers to the practice of eliminating H2S from natural gas streams in order to prevent corrosion and meet pipeline quality standards. But first, one must confirm via appropriate test methods the levels of H2S present, see our article on test methods here. Knowing the starting point and what levels need to be achieved for safety and commercial aspects is a critical first step when considering a treatment approach for H2S.  

Why is H2S removal important?  

H2S is a harmful gas that can lead to respiratory illnesses, eye irritations, and other health concerns, and at high enough concentrations, it can be fatal. Furthermore, its corrosion can damage pipelines and equipment – thus making its removal from natural gas essential in protecting personnel, equipment, and the environment from damage. 


How much H2S to remove? 

As mentioned earlier, H2S can be fatal and lethal levels can be low as 100 ppm; therefore, many natural gas pipeline systems require thresholds of <10 ppm or sometimes <4 ppm. This is often cited in the pipeline tariffs or commercial contract and is commonly referred to as pipeline specifications or pipeline spec for short. If the tariff or commercial contract is not available, seek the lowest possible treatment threshold. 


What are the methods of H2S removal? 

The methods of H2S removal can be broadly categorized into two groups: commodity scavengers, and alternative scavengers. Commodity scavengers include widely used products such as MEA Triazine, Caustic Soda, and Glyoxal. These liquid scavengers, react with the H2S to form less harmful compounds through absorption or oxidation processes.  

Alternative scavengers, on the other hand, may encompass products like zinc-based scavengers and MMA Triazine. While these alternatives offer effective H2S removal, they tend to be expensive or highly regulated due to their specific composition and handling requirements. This is why, within the alternative category, we can also find specialized products such as Solid Bed Catalysts and Specialized Liquid Scavengers.

For example, there is an alternative method for H2S removal that involves the use of specially formulated metal-based catalytic absorbents called Pro3 Nano. Pro3 Nano utilizes a porous, granulated media that reacts with H2S and adsorbs mercaptans and oxygenates, providing efficient purification. This catalyst is particularly suited for gas and light liquid hydrocarbon treatment applications. 

Furthermore, specialized scavengers like Pro3 GT offer a non-triazine direct substitute to traditional triazine-based products. These specialized solutions provide effective H2S removal while addressing concerns associated with triazine usage. Oftentimes, triazine needs to be closely monitored for effectiveness. For example, if over-treating of triazine occurs, scale can begin to build up and that results in blocked pipe and infrastructure, which builds up pressure creating strain on throughput. Fortunately, there are products that eliminate those concerns and still eliminate H2S. 

Industry-standard products. Common liquid scavengers:

  • MEA Triazine
  • Caustic Soda
  • Glyoxal
Specialized Solid Bed Catalysts:
Metal-based catalyst that reacts with H2S and adsorbs mercaptans and oxygenates.

  • Pro3 Nano
Specialized Liquid Scavengers:
Non-Triazine direct substitute to Triazine.

  • Pro3 GT
Alternative Liquid Scavengers:
Expensive / Patented or protected products / Highly regulated products

  • Zinc-based
  • MMA Triazine

Q2 Technologies Product examples: 

Pro3 Nano  

Pro3 Nano is primarily used in gas treatment applications. The combination of the catalyst and the specialized filtration in the Pro3 Nano reactor system selectively allows the passage of gas molecules while blocking the passage of larger particles and contaminants. The metal-based catalyst then allows for a reaction to take place for H2S or adsorbs mercaptans and oxygenates until the active ingredients are spent, resulting in purified gas output. The rate of consumption is calculated based on flow and inlet containment levels and is cleaned out and refilled once fully utilized. Pro3 Nano is commonly used in industries such as oil and gas, petrochemicals, and air purification, where the removal of impurities from gas streams is essential. 

Pro3 GT 

The main advantage of Pro3 GT, as compared to MEA triazine, is it does not create solids or buildup in scrubbing units; further, it offers faster reaction kinetics and increased capacity. And a hallmark benefit of Pro3 GT is its non-reversible and non-oxidizing properties when reacting with H2S. 


Triazine-based treatment has long been the commodity solution for many Producers, Midstreamers, and Refiners for many years. But now, due to advancements in technology, as mentioned above, there are a variety of alternatives that are very effective. 

What is the most effective method of H2S removal? 

The most effective method of hydrogen sulfide (H2S) removal from natural gas depends on several factors, including H2S concentration, desired gas purity levels, operational conditions, and economic considerations. Here are the commonly used methods and their suitability in different scenarios: 

When to use commodities? 

Determining when to use commodities depends on various factors. Commodity solutions are particularly valuable in situations where a facility lacks the necessary technical support or industry infrastructure to implement changes effectively. It is crucial to have personnel who are capable of consistently measuring and monitoring the progress of the commodity solution on an ongoing basis. This ensures that the desired outcomes are achieved and that the chosen commodity solution is effectively integrated within the existing framework. 


When to use Metal-Based Catalysts? 

Determining the appropriate circumstances to utilize metal catalysts involves considering specific factors. The iron catalyst is particularly suitable when dealing with inconsistent volume and fluctuating H2S levels. In such cases, it becomes the preferred medium due to its effectiveness in addressing these challenges. Additionally, if the operational process cannot accommodate solids and particulates as by-products, the catalyst proves advantageous. It serves as a reliable option for situations where complete filtration of H2S and its impurities is required. By employing catalysts, organizations can effectively manage these unique requirements and achieve the desired outcomes. 


When to use Specialized Scavengers? 

Specialized scavengers, such as Pro3 GT, come into play in specific situations when triazine has not been an effective H2S removal solution. Pro3 GT and its suite of products act as alternatives to conventional triazine-based products, addressing concerns such as no solids or particulate buildup, which unfortunately is common when overtreated or misappropriated dosing is done by triazine. By taking factors like improved performance, specific applications, and regulatory compliance into account, end-users can make informed decisions on when to opt for specialized scavengers as the most appropriate choice for their H2S removal requirements. 


How is H2S removal measured? 

Measuring H2S removal in natural gas involves assessing the concentration of H2S before and after the removal process. This measurement is typically expressed in parts per million (ppm*), which indicates the number of H2S molecules per million molecules of natural gas. The objective of H2S removal is to achieve a concentration that complies with pipeline quality standards and ensures the safety of personnel and equipment. 


*In some instances, one may see ppm expressed as ppm/v or ppm/w. The added “/v” and “/w” indicate “by vapor” or “by weight”, respectively. The vapor reading simply indicates the ppm level in the headspace of a specific volume, and the by weight (also known “by liquid”) is measuring the ppm in the liquid portion of the volume. Therefore, when measuring H2S in natural gas, measuring the vapor phase of ppm is most common. 


To determine the effectiveness of H2S removal, various industry-approved test methods are employed. These methods help quantify the H2S concentration accurately: 

  • Gas Chromatography (GC): It separates and quantifies H2S from gas mixtures by analyzing its retention time or peak area. 
  • Electrochemical Sensors: These devices detect H2S concentration based on its electrochemical reactions, measuring current or potential. 
  • Titration Methods: They determine H2S concentration by reacting it with a known reagent that generates a measurable signal or color change. 
  • Spectroscopic Techniques: These techniques use light interaction to detect H2S concentration through its absorption or emission at specific wavelengths. 

What are the safety considerations when removing H2S from natural gas? 

H2S removal from natural gas is a hazardous process that requires proper safety measures to be in place. Safety considerations include: 

  • Always review safety protocols when on location before starting any work around natural gas.  
  • Personal protective equipment (PPE): Personnel should wear appropriate PPE, such as respiratory protection, chemical-resistant clothing, and eye protection to prevent exposure to H2S and other chemicals. 
  • Ventilation: Adequate ventilation should be provided to prevent the buildup of H2S and other gases in the work area. 
  • Monitoring: Gas detectors and monitoring equipment should be used to continuously monitor the work area for H2S and other hazardous gases. 
  • Emergency response: Emergency response procedures should be in place in case of accidental exposure or release of H2S. 

What are the environmental considerations when removing H2S from natural gas? 

When removing H2S from natural gas, several environmental considerations need to be considered. One crucial aspect is the proper handling of waste and emissions generated during the process. 

To handle emissions, it is crucial to implement appropriate control measures. These include regular inspections, well-maintained equipment, and leak detection systems. By promptly identifying and addressing any potential leaks or releases, the emission of H2S or other hazardous gases, such as SO2, can be minimized. 

Once the H2S removal process is successfully completed using a scavenger such as triazine or Pro3 GT, the next important step is to address the management of the spent product. For these types of products, the commonly employed method is sending it to a Saltwater Disposal well (SWD). SWDs involve treating the spent triazine solutions to eliminate impurities before responsibly disposing of them. This approach aims to minimize any potential environmental impact and adhere to waste management regulations. 

However, when dry media scavengers like Pro3 Nano are used, waste handling techniques vary slightly. These scavengers typically produce solid waste in the form of spent catalyst. Proper waste management involves careful collection, packaging, and transportation of the spent media to a designated landfill facility equipped to handle and contain hazardous materials. By following this procedure, the waste can be appropriately disposed of in landfills as the spent material is non-hazardous passing TCLP tests, responsibly sending it to landfills reduce the risk of environmental contamination. 

What are the benefits of H2S removal from natural gas? 

The benefits of H2S removal from natural gas include: 

  • Improved safety: H2S removal prevents health and safety hazards associated with exposure to H2S and corrosion of equipment and pipelines. 
  • Meeting pipeline quality standards: H2S removal ensures that natural gas meets pipeline quality standards and can be transported safely and efficiently. 
  • Environmental protection: H2S removal minimizes the environmental impacts associated with natural gas production and transportation. 

Who provides H2S removal services? 

At Q2 Technologies, we specialize in providing natural gas treatment solutions, including H2S removal services. With years of experience in the industry, we have the expertise and advanced equipment necessary to design, implement, and optimize H2S removal systems for various natural gas streams. If you are in need of H2S removal services for your natural gas operations, trust Q2 Technologies as your reliable and experienced partner. We have a proven track record of delivering effective solutions tailored to your specific needs. With our expertise, commitment to innovation, and focus on customer satisfaction, we stand out as a leading provider in the field of H2S removal services. 

The Science of H2S Removal: Our Oilfield Chemical Solutions

The Science of H2S Removal: Our Oilfield Chemical Solutions










As one of the leading H2S scavenger manufacturers and oilfield chemical suppliers in the industry, Q2 Technologies is committed to delivering high-quality H2S removal solutions to its clients. We understand the importance of removing H2S from natural gas and crude oil, as it is a toxic and corrosive gas that can cause serious damage to pipelines, equipment, and the environment. In this blog post, we will discuss the science of H2S removal and how our oilfield chemical solutions can help. 

H2S Scavengers: How they work 

H2S scavenger technologies are used to remove hydrogen sulfide (H2S) from natural gas and crude oil streams. There are various chemistries used for H2S scavenging, including nitrite-based, triazine-based, iron sponge, and caustic-based methods. 

Nitrite-based scavengers work by oxidizing H2S to elemental sulfur in the presence of oxygen. These scavengers can also provide corrosion inhibition, making them a popular choice in certain applications. 

Triazine-based scavengers react with H2S to form stable, non-toxic compounds that can be easily separated from the treated gas or liquid. They are often used in natural gas processing and refining. 

Iron sponge is another common H2S scavenger. It works by using iron oxide to react with and remove H2S from gas streams. 

Caustic-based scavengers (such as sodium hydroxide) react with H2S to form sodium sulfide, which can then be further treated or disposed of. They are commonly used in refineries and other industrial processes. 

Each H2S scavenger has its advantages and disadvantages, and the choice of scavenger depends on several factors such as the composition of the production stream, operating conditions, and environmental regulations. However, with careful selection and application, H2S scavengers can effectively reduce the risks associated with H2S gas in the oil and gas industry. 

H2S Removal Solutions from Q2 Technologies 

At Q2 Technologies, we offer a range of H2S removal solutions to meet the needs of our clients from liquid non-triazine products, iron-based scavengers, to more traditional triazine based scavengers, all designed at removing H2S from crude oil and natural gas. Specifically for crude oil and liquid hydrocarbons, Pro3® is a non-triazine scavenger that offers several advantages over other H2S scavengers, including: 

  1. High H2S removal efficiency: Pro3® is highly effective at removing H2S from crude oil streams, even at low concentrations. This is due to its unique chemical composition, which enables it to react with H2S and convert it into sulfate byproducts which drop out into the BS&W. 
  2. Long-lasting protection: Pro3® provides long-lasting protection against H2S, which reduces the need for frequent scavenger injections. This can help to reduce costs and increase operational efficiency. 
  3. Environmentally friendly: Pro3® is a non-triazine-based H2S scavenger, which means it does not contain triazine or amine compounds that can be harmful to the environment. 
  4. Compatible with other chemicals: Pro3® is compatible with other chemicals commonly used in oil and gas operations, including corrosion inhibitors and demulsifiers. This makes it easier to integrate into existing operations. 

Overall, Pro3® offers a high-quality, effective, and environmentally friendly solution for H2S removal in the oil and gas industry. Its unique chemical properties and benefits make it a preferred choice for many Producers and Midstream companies looking to improve their H2S removal processes. 

In addition to Pro3®suite of products, Q2 Technologies offers several other products from this chemical line including  ProM®  and Pro3®HT , all H2S scavengers for the removal of hydrogen sulfide from  crude oil and liquid hydrocarbon streams. ProM® is an oil dispersible  option that is ideal for combating against certain species of mercaptans (a similar sulfur-based compound). Pro3®HT is a specialized product designed for high-temperature applications, with stability and effectiveness up to 150°C (302°F).  

For sour natural gas applications, we offer a range from traditional triazine-based products to non-triazine products in both liquid and dry media applications.  

  1. Triazine based scavengers, if properly managed, can be a standard approach to treating H2S. We also provide a vast range of field strength concentrations as well as several additives that can be used for greater effectiveness or for compatibility concerns. 
  2. We also have a non-triazine/non-amine alternative to MEA triazine: Pro3®GT & Pro3®GT+ are specially formulated to have the same outcome as triazine. However, GT & GT+’s reactions are not subject to the same side effects one experiences when overtreatment occurs with triazine, such as scale or buildup of particulates. Further, Pro3®GT & Pro3®GT+ has more kinetic prowess than triazine, typically using 20% less overall product when compared to triazine. 
  3. Lastly, Pro3®Nano is our innovative dry media that can effectively target H2S in sour natural gas streams that tend to have significant production swings or experience massive ranges in H2S. This product can handle any environment and will provide a sweetened gas stream consistently. With a regenerative aspect, this system is a great change to traditional liquid systems, where the product can be re-energized in system. 


The importance of removing H2S from natural gas and crude oil cannot be overemphasized, as it is a toxic and corrosive gas that can cause serious damage to pipelines, equipment, and the environment. Q2 TechnologiesPro3® H2S scavenger, along with its other products, offers a unique and effective solution for H2S removal, with advantages such as high H2S removal efficiency, reduced iron sulfide formation, long-lasting protection, and environmental sustainability. With a range of options available, Q2 Technologies offers tailored H2S removal solutions that meet the specific needs of its clients, making it an ideal partner for any oil and gas operation. 

If you are interested in learning more about our H2S removal solutions, please contact us. Our team of experts is always ready to answer any of your questions. 

Odor Management in Refinery Operations

Odor Management in Refinery Operations –Where odor occurs and how it is managed. 


What are Mercaptans and where are they found? 

Methyl mercaptan, or methanethiol, is a colorless, flammable gas that smells like rotten eggs and is present in many different ways in our environment. For example, onions, asparagus, oranges, and radishes are some foods that naturally contain mercaptans. Certain marine bacteria can also generate mercaptans, they are partly responsible for the marshy or stagnant smell in water. Due to its distinct smell, mercaptans can be helpful odorants to aid people in detecting the presence of other gases or chemicals since they can be noticed by humans in lower quantities. This is why mercaptans are added in low concentrations to natural gas.  

Although commercially added mercaptans are helpful, naturally occurring mercaptans form in much higher concentrations and their presence may cause corrosion to production sites, health issues to personnel, and noxious discomfort to workers and communities that live close to where these afflicted hydrocarbons are processed, which includes crude oil and refined products. Because of these issues, there are oilfield chemical companies that provide odor control chemicals that not only eliminate the rotten -egg smell but also help with all mercaptans’ inconveniences.

In this blog, we will dive into how to deal with naturally occurring mercaptans and mercaptan odor control. 


Why we need to treat Mercaptans. 

Mercaptan odor control is one of the many aspects addressed when dealing with mercaptans. Aside from odor issues, mercaptans increase corrosivity, contribute to instability, and make it exceedingly difficult to meet product specifications. The presence of mercaptans along the oil production chain can create problems both from steel and alloys corrosion during storage and transportation, to odor complaints from neighbors.

This is why mercaptan removal is necessary in feedstocks and refined products.  

While mercaptans are closely related to hydrogen sulfide (H2S) and may be efficiently handled with comparable methods, there are certain unique issues to be aware of: 

  1. Detection levels for mercaptans are much lower than hydrogen sulfide, so it is way easier for mercaptans to cause complaints. 
  2. Mercaptans are not as soluble in water as H2S. Water solubility is an important property of chemicals because it impacts how easily they will break down. 
  3. Mercaptan molecule structures have a higher level of complexity than H2S molecules. Since mercaptans undergo additional steps in their biological breakdown, treating them may take longer. 
  4. Although noxious at moderate levels, even high mercaptan levels are not fatal as compared to relatively low levels of hydrogen sulfide (H2S). 
  5. Mercaptan molecules are more complex than H2S and are harder to break down. The simplest mercaptan is methyl mercaptan but chained/complex mercaptans are also common. 
Standard Test Method for Sulfur Compounds in Light Petroleum Liquids by Gas Chromatography and Sulfur Selective Detection
Standard Test Method for Sulfur Compounds in Light Petroleum Liquids by Gas Chromatography and Sulfur Selective Detection.


How to manage Mercaptans 

Our mercaptan scavenger, ProM®, is currently being used in multiple applications to reduce the presence of mercaptans. ProM® has consistently outperformed alternative chemistries for lower chain mercaptan removal. 

How ProM® works at a glance: 

  1. First, a specialized lab analysis is made to determine the mercaptan levels and variety of mercaptan species present. 
  2. Based on lab results, we determine the appropriate dosing of ProM® chemical. 
  3. Introducing the product to the afflicted crude oil or liquids at a point in the pipeline or vessel that has the most effective turbulence and contact time is critical.  
  4. Lastly, a repeat test confirms that quality spec has been reached and the volume may continue to sales. 

Remember, unlike H2S, mercaptans are overly complex branched sulfur-based hydrocarbon chains that require lab analysis to determine treatment approach. ProM® has been specifically engineered to use non-triazine/non-amine based chemicals, which makes it safe to be used in refineries. 




When mercaptans are treated, crude oil commercial specs are achieved, and the crude may be sent to a refiner. Additionally, odor is controlled and neighborhoods downwind from the facilities will not be affected. And finally, the health and safety of the workers on locations is improved. 

Whether you need mercaptan removal from natural gas, wastewater odor control, mercaptan removal from LPG, or from any other hydrocarbon, contact us to find solutions to mercaptan contamination. We have the mercaptan scavengers to satisfy your needs and we offer many more oilfield services for H2S and mercaptan treatment.



MEA-triazine – A Hydrogen Sulfide Scavenger for Natural Gas Operations

MEA-triazine - A Hydrogen Sulfide Scavenger for Natural Gas Operations

Hydrogen sulfide (H2S) is a hazardous, corrosive, and toxic gas that can be found in oil and gas production. Its rotten egg smell is a distinctive marker and it is flammable. The smell can be detected at very low concentrations (about 1ppm), which serves as a warning as H2S is extremely toxic: at levels of 100ppm, inhalation of it can be fatal. In addition to being extremely toxic, H2S can cause severe corrosion issues to equipment. To avoid these operational risks and to meet commercial specifications, H2S must be removed from natural gas. According to general industry standards, gas is considered sour if it contains more than 4ppm of H2S.


MEA Triazine


There are many chemicals being used in the gas sweetening process, an MEA Triazine based H2S scavenger is one of the most common.


MEA Triazine (also known as Monoethanolamine Triazine, or simply just triazine) is a clear to light yellow liquid with a mild amine odor, which has a fishy smell. Triazine cannot be used in its pure form and so various concentrations of the product are manufactured, common field strength levels range from 20 to 80%.  Its primary application is to remove hydrogen sulfide from gas and oil. Custom formulations based on this product can be blended with various polymers and additives to enhance or decrease certain attributes found in the natural gas stream. 


Application methods


Direct Injection

In many applications, triazine is injected directly into the gas stream. When there is good injection flow and enough time to respond, this approach works for H2S removal. Due to the H2S dissolving into the product, typical efficiencies are lower, although a removal efficiency of around 40% is to be expected. The location of the injection and the product choice must be carefully considered for direct injection to be successful. Atomizers, fog nozzles and static mixers tend to be used when applying MEA Triazine via direct injection.


Contactor Tower

Another common approach is routing sour natural gas through a triazine-filled contactor tower. The tower layout can take on a variety of designs, but essentially H2S is eliminated when the gas passes through the liquid and dissolves into the triazine. The H2S removal efficiency of contactor towers can reach up to 80%. As a result, much less chemical is used, and OPEX may be significantly decreased. The contactor tower and chemical storage tanks, however, are less useful for offshore use since they take up a lot of room and weight.


Benefits of Q2 Technologies’ MEA Triazine

  • Simple treatment with a low investment.
  • When buying directly from the manufacturer you may reduce H2S scavenger costs.
  • Up to 80% active triazine with other dilutions available.
  • Over 20 years’ experience as Triazine manufacturers along plus applied engineering support.
  • Turn-key automated skids for lease or purchase.
  • Specialty blends with a variety of inhibitors.


Natural Gas Treatment Case Study


A major gas producer in Southeast Texas was using a mixture of 10 drums of fresh water with Sodium Nitrate for the removal of H2S in their contact tower. The run time equated to two months before change-outs were necessary. After each run, the tower trays were removed and the system steam cleaned in order to remove the precipitated sulfur and other deposits that had accumulated on the interior wall of the sparger. This process included a labor crew and steam-cleaning unit. The clean-out time ran from one to two days depending on the severity of disposition.


Due to ongoing sulfur deposition and labor intensive change-outs, Q2 Technologies was invited to test our triazine process utilizing the same tower. Calculations indicated that a 50% reduction in total product would achieve the same results as the Sodium Nitrite. Five drums of triazine and five drums of fresh water were added to the contractor.


It was determined after the two-month test period, that our triazine achieved the same performance as Sulfa-Check with half as much product. In addition, the vessel was found to be free of solids upon inspection. There was no clean out involved and the reacted product was easily drained and the tower recharged.


Download this case study here.

Case Study 305

Other Chemistries


MEA-Triazine is an effective solution for H2S removal. However, each application is different and may require different scavenger alternatives. At Q2 Technologies, we also offer a non-triazine/non-amine H2S scavenger solution: Pro3® Nano. This alternative is a low CAPEX modular solution designed to lower LOE compared to conventional triazine scavengers. The Pro3® Nano chemical process is specifically designed to treat sour gas volumes using a unique combination of nano particles in a contact tower with a regenerative cycle.


What’s the best solution?


The best solution is whatever works best for your application. The main goal will always be H2S removal, but there are financial, operational, and commercial considerations that must be weighted.? 

  • Have all KPIs (Key Performance Indicators) been identified and quantified?
  • In doing so, are OPEX and CAPEX being optimized? 
  • Are the assets suffering from corrosion or over/under utilization? 
  • Is the hydrocarbon stream meeting commercial  ppm requirements or thresholds? 


These are some ideas to consider when choosing suitable treatment solutions, it not only depends on reaching H2S level requirements, but also on seeing how the scavenger affects your project as a whole. At Q2 Technologies we can help provide recommendations based on your specific needs, contact us and we’ll help you find exactly what you need to treat your sour gas.



Quality Chemicals Matter

Quality control is the basis for our business. Delivering high-quality products is fundamental to our clients. Providing consistent, high-quality products time and time again leads to long-term and trusted partnerships.


Therefore, keeping a close watch and testing our batches ensures our manufacturing processes are not deviating and we deliver the highest quality possible.


In much the same way, when out in the field, we are often asked to check unknown products. This arises at the request of the client if their existing product is not effective or worse, causing production hindrance.  This is performed as a troubleshooting effort for our clients and is the starting point in discovering a workable solution.


So how do we ensure in the lab that our manufactured products are meeting our exacting standards or how we determine what an unknown field substance may contain? One of the many advanced ways we detect the presence of different ratios of chemistries is by utilizing a Fourier-transform infrared spectroscopy (FTIR) unit. 

Quality Chemicals Matter

Maintaining the highest quality of our chemical products is fundamental to how Q2 Technologies ensures we maintain our trusted partnership status for leading Oil & Gas producers, midstreamers, refiners, biogas, and wastewater operators. We rely on proven technologies not only for our chemical products, but how we implement them in our growing range of industries. 


Not Just in the Name

For over 20 years, Q2 Technologies has been at the forefront of chemical development and implementation in Oil & Gas, and as such, ‘technologies’ is a core concept we embrace from early stage chemical development, to the logistics of manufacturing, to final implementation for the end-user. Our clients know that we scrutinize all aspects of our process and it shows in the results of having consistent products at or near the clients’ locations every day of the year. Check out our latest inventory initiative announcement here [insert link to recent mid-season hurricane and inventory PR announcement]. 

One of the more advanced techniques we utilize to ensure our unique products are manufactured to our tight specifications and standards is the use of infrared (IR) spectroscopy. IR spectroscopy, specifically Fourier transform infrared (FTIR) spectroscopy, is a widely popular analysis technique used today. FTIR is used across many industries as the process is quite adaptable to suit many scenarios. Considering that it has use cases for all types of matter: solid, liquid, and gaseous analytes. 


FTIR machine


How it works

The study of infrared light dates back to the astronomer William Herschel in the early 19th century. Herschel used a prism to refract light from the sun and noticed the temperature increase when focused beyond the red portion of the spectrum. Although the term infrared was not used until the late 19th century, beyond the visible red light was surely a curiosity to him. Since then, the study of the interaction of IR light with matter has expanded greatly. In the ongoing studies with a FTIR device, a light source shines on a substance and the resulting wavenumber or unique IR signature is observed on a detection plate. The study of chemical bonds has proven that molecules are not held together in static fashion, rather they vibrate at the molecular level leading to concepts of symmetrical and asymmetrical stretching, wagging, scissoring, rocking, just to name a few, and when IR light attempts to pass through certain molecules that are vibrating at different frequencies, we can determine with high confidence that a particular molecule is present. The process yields a detection graph that will have a series of unique identifiers that would confidently point to different chemicals present. FTIR Comparison of G2

The FTIR test would be akin to a baker identifying all of the ingredients of a cake, to replicate the recipe, one would need the measurements of each ingredient. That is where we pause in our evaluation of unknown substances, chiefly we do not need to recreate a substance and secondarily, this is where the science and artform deviate, beyond the FTIR test, one is making gross assumptions. However for our purposes, the resulting identification of the presence of certain elements is quite sufficient, with this information we are able to make inferred rational judgements on the nature of a product. Again this works well for our quality control best practices, for example if a significant presence of an out of place molecule shows, we may with statistical evaluation conclude that the sample has been contaminated and would need to be reconfigured. To be fair, significant deviations are taken into account, as well as a deep understanding of how our product would chemically react to the rogue molecules.


Putting it into Practice

As part of our professional service offerings of supplying chemical products to our clients’ different facilities, we take a concerted effort to ensure that the products are delivered on time to location and are administered appropriately. Word can travel fast in the oil patch and this can lead to potential clients requesting us to troubleshoot why their chemical products are not as effective or at worse causing production curtailment, in short, they are seeking to know what is causing the issue. We start by reviewing the SDS and comparing that to what the FTIR analysis provides. In some cases, products are diluted or manufactured with other chemicals, rendering them less effective. Oftentimes, a solution for H2S or mercaptan treatment from our ProSeries® suite of products is a good fit and we are able to quickly scope out a workable application. 


If you would like to learn more about how we use FTIR analysis in the lab or how it may apply to your asset in the field for hydrocarbons afflicted with H2S or mercaptans, we would be happy to discuss with you your situation to find solutions. Contact us today!



FTIR Image Source: