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. 

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. 

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. 

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. 

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. 

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? 

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.  

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.

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. 

Commodities

Industry-standard products. Common liquid scavengers:

Examples: MEA Triazine Caustic Soda Glyoxal

Alternatives

Specialized Solid Bed Catalysts: Metal-based catalyst that reacts with H2S and adsorbs mercaptans and oxygenates. Example: Pro3 Nano

Specialized Liquid Scavengers: Non-Triazine direct substitute to Triazine. Example: Pro3 GT

Alternative Liquid Scavengers: Expensive / Patented or protected products / Highly regulated products Examples: 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 

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. 

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.

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.

 

Sources:

https://prism.ucalgary.ca/bitstream/handle/1880/112374/ucalgary_2020_du_steven.pdf?sequence=2&isAllowed=y

http://static1.squarespace.com/static/53556018e4b0fe1121e112e6/54b683d0e4b09b2abd348a7b/54b683e4e4b09b2abd348e9a/1421247460293/GATEKEEPER-H2S-Scavenging-Triazine.pdf?format=original