Blog Category: The ABCs of H2S and mercaptans

Triazine Vs. Non-Triazine for H2S Treatment

Why Choose Between Triazine and Non-Triazine?

When selecting an H2S scavenger whether a traditional triazine-based product, an alternative triazine formula, or a non-triazine solution—it’s important to carefully evaluate all available options. Different scavengers perform better under specific process conditions and applications, such as oil treatment, acid gas sweetening, or mercaptan odor removal. As our analysis will show, one may be better than the other depending on the specific conditions of what needs to be treated. Over the years, triazine-based treatment has been the go-to solution for many Producers, Midstreamers, and Refiners, and to a large extent it is still the go-to choice. But for some, implementing new technology such as non-triazine products has positively impacted their operations and has lowered their costs. Is one better than the other? That all depends on your use case and process conditions. Here you’ll find a brief description of both triazine and non-triazine alternatives to help inform you of the effective solutions on the market for your application.

Aspect Triazine Treatment Non-Triazine Treatment
Industry Usage Longtime go-to solution for Producers, Midstreamers, and Refiners Gaining adoption as new technology
Reliability Proven and still widely used Effective alternative depending on conditions
Impact on Operations Trusted but may have operational challenges (e.g., fouling, amine salts) Can positively impact operations, often lowering costs
Best Use Case Suited for many traditional applications Better fit in certain cases where triazine limitations matter
Key Consideration Still the default choice for many May be preferred when cost savings or refinery safety is a concern

What is Triazine Treatment?

Triazine for H2S scavenging is an established and reliable chemical reaction that is employed in the Oil & Gas industry to remove H2S from gas streams. The H2S scavenging can be done via direct injection in pipelines with fog nozzles, wet scrubbers, or bubble towers at either wells, central batteries or midstream systems. The triazine H2S scavenger technique is a cost-effective solution for gaseous streams with sulfur loading of less than 1000 lbs. per day. However, consider alternative catalyst systems for extended long-term use and savings. It typically reduces H2S concentrations to <4 ppm and partially removes several light mercaptans (methyl, ethyl, and propyl). Triazine’s ability to remove H2S is affected by various parameters, including temperature, pH, contact duration, and natural gas composition. The final product is water soluble and is usually discharged in the produced water tanks and commercial saltwater disposal facilities.


It is important to note that using triazine as an H2S scavenger may cause fouling from the polymerization of dithiazine in contact towers, scrubbers and/or pipelines. Careful use and monitoring of the triazine solution is needed to ensure smooth operation. Q2 Technologies has been manufacturing traditional triazine blends for decades and also offers expertise in developing unique formulas for special cases.

Check out this case study:

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What is Non-Triazine Treatment?

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Even though triazine is a well-trusted solution, many companies have chosen non-triazine-based scavengers as alternatives for use in crude oil applications. One of the main characteristics of our non-triazine product, Pro3®, is a non-amine and non-glyoxal technology, making it safe for refineries and pipelines. If left unchecked, Amine salts that form from spent triazine can ultimately cause damage to the top stacks of a refinery when heated to >500 °F. Many refiners in the US Gulf Coast and overseas monitor amine content and require traders and midstream companies to use vetted non-triazine chemistries.

Advantages of Non-Triazine H2S Scavengers

Producers and Midstream companies alike have found success with our non-triazine products:

  • The quality of the oil is upgraded when H2S content is reduced.
  • Safer environment for all personnel on-site.
  • Infrastructure and equipment will last longer now that corrosion caused by H2S has been neutralized.
  • Our non-triazine scavengers are not based on commodity-priced products, so our prices are protected and are less impacted by external factors such as freezes and industrial raw material shortages.

Field Results and Performance

Our non-triazine H2S removal technology has proven to reduce chemical use up to 50-75% as compared to triazine. This definitely does not mean that triazine should always be replaced by non-triazine, rather, Q2 Technologies can assist you from a technical, engineering, and commercial viewpoint. Each application is different and needs to be carefully analyzed to determine the treatment product.

Triazine vs. Non-Triazine: Key Considerations

In conclusion, both triazine based H2S scavenger and-non triazine H2S scavenger options have their benefits and are the go-to alternatives for oil and gas treatment. However, one may be better than the other depending on the specific characteristics of the product that needs to be treated. For more information on triazine-based scavengers for natural gas operations, check out our detailed overview here. If you’re looking for the right H2S scavenger solution for your company, feel free to contact us! You can also read more about how switching to Pro3® can be the game-changer for your operations in our detailed comparison of triazine versus non-triazine treatments here


Sources:


https://www.sciencedirect.com/science/article/abs/pii/S1875510017304559

Complete H2S guide for Health and Safety

What Is Hydrogen Sulfide (H2S)?

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.

Why is H2S so dangerous?

Health Hazards of H2S Exposure

  • The health consequences of hydrogen sulfide depend on how much and how long the worker breathes it in. Exposures to concentrations of 100 ppm or more are harmful to human health. However, even at low doses, significant impacts are observed. The effects range from moderate, such as headaches or eye discomfort, to extremely dangerous, such as permanent loss of smell and taste to unconsciousness and death.


Equipment Damage and Corrosion

 

  • In oil and gas applications, sour gas and sour crude (which contains H2S) can react with air and moisture to produce sulfuric acid, which can corrode metals. The durability and impact strength of facility equipment, particularly the inside surfaces of different components, are diminished, eventually resulting in premature failure.

Essential H2S Safety Equipment

H2S Gas Monitors

Refinery,Technician,Checking,Gas,With,His,Pocket,Type,H2s,Gas
  • Always make sure to carry an electronic meter that detects hydrogen sulfide gas. And clip the monitor near your face, on the lapel of your shirt for example. Always “bump test” by clicking the test button on the monitor prior to entering any job site to ensure the alarm on the monitor is loud – there may be large decibel producing equipment creating loud noises, your monitor should be louder so you can hear it.
  • Do not rely on your sense of smell to detect the presence of hydrogen sulfide or to alert you of dangerous amounts. At low quantities in air, hydrogen sulfide has a “rotten egg” smell. However, after a while, you lose your capacity to detect the gas even if it is still present (olfactory fatigue). In large quantities, this loss of smell can occur extremely quickly, and the ability to detect the gas can be gone instantly (olfactory paralysis).
Protective personal equipment
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Personal Protective Equipment (PPE)

  • Wear respiratory and other personal protective equipment.
  • Make sure you have been properly mask fitted to make sure you will be protected from hazardous vapors.
  • If measures fail to lower H2S levels below the allowed exposure limit, respiratory protection must be used as well as additional personal protective equipment (PPE) such as eye protection and perhaps fire-resistant clothing.

What To Do If Your H2S Monitor Goes Off

Imagine your hydrogen sulfide sensor has gone off, indicating the presence of H2S in your work environment. Now, what do you do?

1. Put On Your Gear:

Put on your gas mask if you have one handy and aren’t already wearing one. Pull your straps down firmly and breathe. While you evacuate the area, your mask will keep you safe.

The requirements for carrying a mask differ based on the setting, so if you don’t have one, don’t worry, just go on to the next stage.

2. Get Upwind: 

Orange,Windsock,On,Sunset,Sky,And,Industrial,Estate,Background
  • If you’re working in an area with the possibility of H2S release, there should be flags or windsocks on the work site to show you which direction the wind is blowing. Head in the opposite direction immediately. If you can’t see the windsock, toss some dirt or leaves into the air, or look at the trees.
  • The wind can blow and concentrate the H2S into valleys or stands of trees, so the direction you go is essential. If you see a designated gathering area, or “muster site” downwind, go there.
  • This is the easiest and most effective way to avoid H2S inhalation or poisoning.
  • Lastly, if your work plan makes it difficult to evacuate an area, consider revising your work plan with your team before starting work in the first place.

H2S Removal & Long-Term Safety Measures

H2S Scavengers should be employed by crude oil companies to benefit from less fouling, corrosion, and property damage, significant reduction of health risks, and a potential increase in the value of production barrels. Learn more about the versatility of H2S solutions across various sectors by reading about its role in the pulp and paper industry here

In conclusion, anyone who has the possibility of being exposed to H2S must be ready with the recommended safety equipment and the know-how for whenever the H2S monitor goes off.

Always carry:

  • H2S monitor
  • Properly fitting PPE

If the monitor goes off, remember to:

  • Put on your gear
  • Get upwind

Q2 Technologies manufactures specialty H2S Scavenger Chemistry products that remove H2S from millions of barrels of oil every month. For more information, contact us!



Sources:


https://www.osha.gov/hydrogen-sulfide


https://www.draeger.com/library/content/h2s-ebook-enus.pdf


https://www.fldata.com/hydrogen-sulfide-oil-gas-industry


https://www.gdscorp.com/blog/hydrogen-sulfide/the-four-steps-to-take-in-a-hydrogen-sulfide-h2s-emergency/#:~:text=Get%20Upwind&text=The%20wind%20can%20blow%20and,avoid%20H2S%20inhalation%20or%20poisoning.

Cracking the Code on Treating H2S: Q2 Technologies’ Non-Triazine Scavengers Reducing Chemical Use Up to 75%

Why Triazine-Based Scavengers Are Problematic

When it comes to treating Hydrogen Sulfide (H2S) in Crude Oil and liquid hydrocarbons, there are several types of triazine-based compounds that have historically been used. Unfortunately, if not closely monitored, the by-products of many of these chemistries can actually be more operationally detrimental and thus vastly more expensive, because overuse may cause corrosion and fouling in downstream systems.

Pro3®: A Safer, More Efficient Alternative

Fortunately, new technology has emerged! Q2 Technologies boasts a revolutionary new product that is in a class all by itself: Pro3® is an innovative non-triazine and non-amine H2S scavenger for Crude Oil and liquid hydrocarbon applications that is able to reduce chemical use up to 50-75% as compared to Glyoxal and MEA Triazine.

Less chemical

Pro3®’s active ingredient is chemically more effective and efficient at rendering H2S into non-reversible components than triazine could be, chemically speaking Pro3® is superior to triazine.


In a recent study, Pro3®, a non-triazine scavenger, was recommended to substitute a 40% MEA-triazine scavenger, resulting in an 80% cut on chemical consumption compared to triazine. This resulted in a reduction in deliveries and lowered the overall chemical spend. Read more about this case study here.

Chemical usage Pro3 vs. Triazine

No Fouling or Corrosion Risk with Pro3®

Q2 Technologies’ non-triazine product does not contain any amines or nitrogen compounds, making it 100% safe for refineries and pipelines. Amine salts from triazines can end up doing more damage to the top stacks of a refinery when heated to +500 °F as compared to the pinhole corrosion that H2S would cause if routed through the refinery untreated. 

The distillation column is the backbone of any refinery and keeping the internals free of corrosion is critical. Refineries that manage asset integrity are constantly evaluating the inlet volume for amines and monitoring the physical nature of the columns.

How Pro3® Bypassed Supply Chain Disruption

In the Spring of 2021 there was a significant winter storm event in Texas which had far reaching implications for the triazine market for much of the United States, and consequently Canada and parts of South America. The week-long deep freeze shuttered many chemical plants, and by the company’s estimates, nearly 90% of plants along the Gulf Coast that create the raw materials for triazine were shut down for months. This caused the near-commodity price of triazine to skyrocket: a classic under supply situation resulted in higher demand and the Oil & Gas producers and consumers were hindered by this for over a year. Q2 Technologies monitored this phenomenon closely.  Since our Pro3® is a non-triazine based product, there were no supply chain issues and prices were not affected. Unfortunately, for those that depend heavily on triazine as a main scavenger, the threat of a shutdown could easily happen again, as some plants simply did not come back online in the summer of 2021, and those that were were repaired carry the additional operational burden to produce more and more triazine.

Why It’s Time to Switch to Pro3®

If scavenger costs and operational concerns are a priority, learn more about Pro3® and see how Q2 Technologies can lower your net chemical usage, protect infrastructure, and increase overall hydrocarbon production by rending H2S out. If you think your project can benefit from using Pro3® contact us today. 

The ABCs of H2S and Mercaptans

Mercaptans have become a hot topic over the last few months as pipeline tariffs have become stricter in regard to both H2S and mercaptans. We have been getting an increasing number of inquiries about mercaptans in crude oil – what they are, how they are measured and how they can be removed to meet pipeline specs. In this post we will address these questions and how our chemistries at Q2 Technologies® can effectively manage H2S and mercaptans.

What is a mercaptan?

A mercaptan also known as a thiol is a sulfur compound that is naturally occurring in both crude oil and natural gas. It is the sulfur equivalent of an alcohol and comes in the form an R-SH, where R represents an alkyl or other organic group. What is interesting about mercaptans is that unlike its cousin (H2S/hydrogen sulfide) it can come in many different forms – methyl mercaptan, ethyl mercaptan, propyl mercaptan, butyl mercaptan and other branched and more complicated variations. Interestingly, we have all been exposed to mercaptans as its used as an odorant additive in commercially sold natural gas so that people can easily detect a leak through smell. Figure 1 shows the Methyl Mercaptan molecule and Figure 2 shows the Ethyl Mercaptan molecule.

Figure 1. Methyl Mercaptan molecule  Figure 2. Ethyl Mercaptan molecule

How are mercaptans measured in crude oil?

The most common way to measure mercaptans in crude oil is through two standardized test methods- ASTM D3227 and UOP 163. Both methods can be run at oilfield or inspection laboratories. Both test methods are titration based and require lab equipment. We have seen costs for these tests to range between $250-$500. The results obtained are in parts per million by weight (ppmw) and reported as mg/kg. It is important to note that chemical contaminants in crude oil may affect the results obtained through these test methods. Unlike H2S that can be measured in both the vapor phase (parts per million by volume) and ppmw, both test of these methods only yield a ppmw result.

More detailed analysis on mercaptans can be done through sulfur speciation studies as shown on Figure 3.

How do you remove mercaptans from crude?

At Q2 Technologies we regularly remove mercaptans from crude oil and condensate using both our Pro3® and ProM®chemistries. By removing mercaptans we help producers meet pipeline requirements and help traders meet contract specifications for crude sold to refiners. We typically see mercaptan requirements in pipeline tariffs to be less than 50 ppm. In early 2020 we successfully treated a 750,000 barrel export cargo with high mercaptans.

Treating mercaptans is more complicated than H2S. Mercaptans are heavier and more complex molecules that require more time and contact for the chemical reaction to happen. We recommend to performing lab testing prior to chemical treatment to ensure specifications will be met. Figure 3 below shows a sulfur speciation done before ProM® and post ProM® treatment. To find out about the materials and methodology we followed to obtain the data and to learn how we can help you remove mercaptans from your crude, visit our detailed guide on removing mercaptans while keeping costs in line or contact us today.

Sulfur Speciation Pre and Post ProM® Treatment

Figure 3. Sulfur Speciation Pre and Post ProM® Treatment

H2S Mitigation Technologies for Gas

3 Questions about H2S: Why, When and Where

Approximately 90 percent of the sources that emit hydrogen sulfide into the air are natural such as the decomposition of dead plant and animal material. Hot springs and volcanos also emit H2S.

Sources of H2S in Natural Gas

Hydrogen sulfide is a naturally occurring component of natural gas since it is a product of thermal conversion of decayed organic matter. Natural gas is about 70 to 90 percent methane and up to 20 percent of other hydrocarbons like butane, propane and ethane. There are contaminants naturally present in natural gas too such as water vapor, sand, oxygen, carbon dioxide, nitrogen, helium, neon and hydrogen sulfide. In fact, hydrogen sulfide is the predominant impurity in natural gas. Natural gas is classified as sour when H2S is present in amounts greater than 4 ppm.

Figure 1.- H2S and Treatment Spots along Gas Processing Line

 

Anthropogenic Releases of H2S in Gas Operations

Anthropogenic releases of H2S into the air result from industrial processes such as in natural gas operations including its extraction, transportation, storing and processing. Figure 1 shows the stages of gas production where H2S might be released and/or treated. Hydrogen sulfide may be released into the atmosphere at wellheads, pumps, piping, separation devices, oil storage tanks, water storage vessels, and during flaring operations. Flares burn gases that are not to be sold as shown on Figure 2, or where operating problems may occur. Sulfur dioxide (SO2) is the product of combusting hydrogen sulfide, but in the event of incomplete combustion, H2S may also be emitted into the atmosphere.

Figure 2.- H2S and Treatment Spots along Gas Processing Line

H2S Concentration and Prone Regions

Between 15 to 25 percent of natural gas in the US may contain hydrogen sulfide, while worldwide, the figure could be as high as 30 percent. Figure 3 shows the major H2S prone regions within the continental US. The regions with the largest percentage of proven reserves with at least 4ppm hydrogen sulfide are Eastern Gulf of Mexico (89 percent), Overthrust (77 percent), and the Permian Basin (46 percent).

Common H2S Mitigation Techniques

Sour gas is routinely ‘sweetened’ through different H2S mitigation techniques. Ninety five percent of the gas sweetening process involves removing the H2S by absorption in an amine solution, while other methods include carbonate processes, solid bed absorbents, and physical absorption.

Figure 3.- H2S Prone Regions within Continental US

 

There are some environmental regulations for controlling emissions from major sources of H2S and it is also regulated as an occupational hazard. Additionally, H2S is corrosive and it needs to be removed. Gas is routinely tested to determine H2S concentration. Once H2S testing has been performed, it is necessary to mitigate its impacts and bring the gas to the desired specifications. There are mechanical/operational (physical), biological and chemical mitigation techniques from which engineers choose according to gas characteristics, H2S concentration, economic considerations, and other variables. Hydrogen sulfide is not found in isolation but together with methane, hydrogen and higher hydrocarbons, and traces of nitrogen-, oxygen- and metal- containing species which complicate the selection of the most suitable H2S mitigation technique.

 

Managing H2S is a challenge at every stage of gas operations. H2S mitigation techniques are implemented in order to preserve the environment, take care of workers, avoid corrosion and bad smells, and protect the value of products. In selecting a gas sweetening process, responsible engineers need to consider many variables such as gas stream pressure, impurities present in the feed gas, composition of the acid gas and quantity of sulphur to be removed.

Mechanical/operational H2S mitigation techniques

When natural gas is produced as a byproduct of oil extraction, operators will often vent or flare the gas. Flaring is the practice of burning gas that is deemed uneconomical to collect. Flaring is also used to burn gases that would otherwise present a safety problem. It is common to flare natural gas that contains hydrogen sulfide, in order to convert the highly toxic hydrogen sulfide gas into less toxic compounds. Venting is the direct release of methane gas to the atmosphere. During oil development, gas may vent to the atmosphere. The solids and fluids from the well go to the pits, while the gases are allowed to escape to the atmosphere, or they are flared.

Physically, stripping is a very common alternative to remove H2S. The oil industry often uses a nitrogen stripping system to remove the H2S. Nitrogen is an inert gas that prevents the flammable gases from igniting and thus eliminates the risk of explosion. Once the H2S has been separated from the gas, it can be converted to a waste product that can safely be disposed of or it can be used in the manufacturing of sulphur. However, it is difficult and costly to transport the liquid nitrogen that stripping systems need.

Membrane technology could offer a solution for the nitrogen transportation hassle that some sour crude treatment facilities require. In this case, compressed air is pushed through a set of polymer fibers or the membrane. As the compressed air moves through the membrane, the nitrogen molecules are separated from the other molecules.

Biological H2S mitigation techniques

These are used to remove H2S from water in wastewater treatment plants but not for gas at the moment.

Chemical H2S mitigation techniques

Additives to treat H2S in gas are very diverse and work in different forms. The caustic soda wash is one of the oldest chemical absorption processes for removing small quantities of CO2 and H2S from natural gas and refinery gases. The Iron Sponge process is another old scavenger used to remove H2S and mercaptans from natural gas though it is difficult to dispose of spent Iron Sponge. SulfaTreat is a dry, free-flowing iron oxide based media that selectively removes H2S and some light mercaptans from vapor and liquid streams but is limited to wet gas streams. The reduction in concentration of hydrogen sulfide might follow the absorption route, such as alkanolamine, ammonia solution and alkaline salt solutions; and oxidation of H2S using iron oxide, activated carbon or a Claus process.

 

H2S mitigation technologies are not mutually exclusive and a combination of techniques might be used.
On Table 1, we show the different chemical additives that are commonly used for H2S removal from gas including our dry media Pro3® Nano and our custom formulated MEA triazines.

Table 1.- Chemical H2S Scavengers for Gas

Q2 Technologies’ Solutions for H2S Mitigation

Whether you need to mitigate H2S at the wellhead, during storage, transportation, or processing, we at Q2 Technologies can help you treat your gas and get more bang for your money. We offer our Pro3® Nano and are reliable manufacturers of triazine-based scavengers, which will bring your gas to specs and are custom formulated according to your needs. For more details on H2S removal technologies, check out our H2S removal solutions for crude oil. Contact us today to discuss how we can serve you.

H2S Removal Technologies in Crude Oil

Hydrogen sulfide (H2S) is typically a minor gaseous constituent found in crude, gas, and water, produced when sulfate-reducing bacteria (SRBs) break down organic sulfur compounds. Some fracking fluids can also react with rock formations under high pressure to generate H2S.

After performing H2S testing, it is crucial to mitigate its impact and bring crude oil to the desired specifications. Various mitigation techniques, such as mechanical/operational, biological, and chemical methods, are chosen based on factors like crude characteristics, H2S concentration, and economic considerations. To learn more about how we can help mitigate H2S in oil and gas reservoirs, check out this article. Hydrogen sulfide is not found in isolation but together with methane, hydrogen and higher hydrocarbons, and traces of nitrogen-, oxygen-, calcium-, and metal- containing species which complicate the selection of the most suitable H2S mitigation technique.

Importance of H2S Testing and Treatment

Managing H2S is a challenge at every stage of hydrocarbon production. Whether it is downstream, midstream or upstream, H2S mitigation techniques are implemented in order to preserve the environment, take care of workers, avoid corrosion and bad smells, and protect the value of refined products and physical assets. Even crude that has already been treated, might produce more H2S, as SRBs continue to digest the oil. Testing and treatment needs to be performed across the different stages of the production line. Learn more about effective solutions for handling toxic crude oil here.

Mechanical/operational H2S mitigation techniques

When natural gas is produced as a byproduct of oil extraction, operators will often vent or flare the gas. Flaring is the practice of burning gas that is deemed uneconomical to collect. Flaring is also used to burn gases that would otherwise present a safety problem. It is common to flare natural gas that contains hydrogen sulfide, in order to convert the highly toxic hydrogen sulfide gas into less toxic compounds. Venting is the direct release of methane gas to the atmosphere. During oil development, gas may vent to the atmosphere. The solids and fluids from the well go to the pits, while the gases are allowed to escape to the atmosphere, or they are flared.

 

Physically, stripping is less common alternative to remove H2S. The oil industry may use a nitrogen stripping system to remove the H2S. Nitrogen is an inert gas that prevents the flammable gases from igniting and thus eliminates the risk of explosion. Once the H2S has been stripped from the crude oil, it is usually flared. This process tends to create 5-10% barrel losses as other light compounds are stripped from the crude. This process is energy intensive and time consuming as it occurs in batches.

 

Membrane technology could offer a solution for the nitrogen transportation hassle that some sour crude treatment facilities require. In this case, compressed air is pushed through a set of polymer fibers or the membrane. As the compressed air moves through the membrane, the nitrogen molecules are separated from the other molecules.

Biological H2S mitigation techniques

These are used for water in wastewater treatment plants but not for crude oil at the moment.

Chemical H2S mitigation techniques

Additives to treat H2S in crude oil are very diverse and work in different forms. The reduction in concentration of hydrogen sulfide might follow the absorption route, such as alkanolamine, ammonia solution and alkaline salt solutions; and oxidation of H2S using iron oxide, activated carbon or a Claus process.

H2S mitigation technologies are not mutually exclusive and a combination of techniques might be used. On Table 1, we show the different chemical additives that are commonly used for H2S removal in crude oil.

Table 1.- Chemical Additives for H2S Removal in Crude Oil

H2S Scavenger Use in Oil & Gas Operations

Upstream Applications

H2S is present along the hydrocarbon production line. Figure 1 shows where in the upstream operations H2S scavengers are used as well as the places where H2S is found.

Figure 1.- Points where H2S scavengers are used in oil/condensate production operations.

 

Midstream Applications

Midstream operations link the upstream and downstream entities, and mostly include resource transportation and storage services for resources, such as pipelines and gathering systems. H2S scavengers are used for cargo treatment, before introducing the oil in pipelines and when it is being removed from storage units. It is key to meet H2S specs in order to transport crude oil and gas via pipeline.

 

Downstream Applications

Downstream operations are oil and gas processes that occur after the production phase such as refineries, petrochemical plants and retail outlets. Figure 2 shows the points in the downstream operations where H2S scavengers are used.

Figure 2.- Points where H2S scavengers are used in refinery operations.

 

Whether your needs to mitigate H2S are upstream, midstream, or downstream, we at Q2 Technologies can help you treat your crude oil and get more bang for your money. We are reliable suppliers of triazine-based scavengers that will bring your oil to specs. Similarly, we offer our high-performance non-triazine Pro3® scavenger and mercaptan scavenger ProM® to provide you with the best solutions for your H2S challenges. For more information, check out our common questions about H2S removal. Contact us today to discuss how we can serve you.

H2S Test Methods

Why H2S in Crude Oil Is Dangerous

Hydrogen sulfide (H2S) is a very dangerous, toxic, explosive and flammable, colorless and transparent gas which can be found in crude oil and can be formed during the manufacture of the fuel at the refinery and can be released during handling, storage, and distribution. At very low concentrations, the gas has the characteristic smell of rotten eggs. However, at higher concentrations, it causes a loss of smell, headaches, and dizziness, and at very high concentrations, it causes instantaneous death. It is strongly recommended that personnel involved in the testing for hydrogen sulfide are aware of the hazards of vapor-phase H2S and have in place appropriate processes and procedures to manage the risk of exposure.

Impact of H2S on Operations and Compliance

The presence of H2S in oil impacts not only the oil price but handling requirements. H2S in oil causes corrosion of pipelines and equipment. It is also necessary to meet specs from environmental, health and safety authorities, for compliance purposes and to avoid acid rain, illnesses and even fatalities. However, there is no standardized H2S test method specific to crude oil. Although H2S is a single molecule, it is hard to determine its exact levels in crude and many testing methods are available.

 

Importance of Sample Integrity

Regardless of the test method to be used, sample integrity is a key factor where one must consistently consider:

 

Garbage in = Garbage out

 

All variables need to be controlled and all samples need to follow identical protocol. Ideally, testing is to measure what is actually occurring in the sampling point. However, many sulfur compounds, for example, hydrogen sulfide and mercaptans, are reactive and their concentration in samples may change during sampling and analysis. Even the equilibrium of the vapor phase is disrupted the moment a vent or access point is opened to collect a sample. Because of the reactivity, absorptivity, and volatility of H2S, any measurement method only provides an H2S concentration at a given moment in time. Proper sampling techniques are essential to avoid costly mistakes and ensure accurate results. Since there is a time lapse between taking the sample and testing, it is important not to alter sample conditions in order to get valid test results.

Key Variables to Consider During Sampling

Key Variables as shown on Figure 1:

  • Stable temperature of the sample is important in order to be able to compare data from different samples as fair representations of their source. Protocols and procedures stated in the method need to be consistently followed to maintain the sample temperature.
  • Container as specified in protocol for selected method since different materials have different implications.
  • Age of sample. Older samples have a higher risk of altered results. Storage in ideal conditions can help maintain sample stability but lab results might be different and not comparable.

Figure 1 H2S Testing Methods and Key Considerations

Overview of H2S Testing Methods

Test methods were designed for light petroleum liquids and fuel oils. Different products require different testing methods since variables behave differently and measurements vary accordingly.

When presenting test results, it is of critical importance to state what test method was used and the measuring units in those results along with any modifications that were made by the inspection lab.
The measurement of H2S in the liquid phase is appropriate for product quality control, while the measurement of H2S in the vapor phase is appropriate for health and safety purposes. Test results are critical for H2S scavenging, safety and contract specs. with traders. Q2 Technologies can help mitigate H2S in crude with our Pro3® H2S non amine scavenger and our triazine for scavenging natural gas and some liquid hydrocarbons. Contact us to further discuss how we can help you.

 

The most common test methods are also shown on Figure 1 including liquid phase methods and vapor phase methods along with the units in which test results are stated.

Comparing H2S Test Methods

Figure 2 shows a comparison of the different test methods though it is important to clarify that no correlation between Methods is to be assumed.

Figure 2 Comparative of Alternative H2S Testing Methods

Q2 Technologies’ Expertise in H2S Mitigation

Q2 Technologies participated in the H2S Mitigation Panel at COQA New Orleans Spring 2019 discussing these H2S testing methods. We will be happy to further discuss this and any other topic to help you get more for your barrel.

Avoiding Costly Mistakes – The Importance of Sampling in H2S Testing

Why Accurate Sampling Matters in H2S Testing

Getting an accurate sample of Hydrogen Sulphide (H2S) whether in gas or in crude oil is crucial for safety, environmental and marketing purposes. Measuring H2S in natural gas is straight forward since the H2S is only in the gaseous phase.

Challenges in Measuring H2S in Crude Oil

Measuring H2S in crude oil brings a challenge. H2S can be measured in the liquid phase of the crude as parts per million by weight (ppmw) or it can be measured in the headspace in the gaseous phase as parts per million by volume (ppmv). Correlation between gas and liquid measurements brings a challenge because H2S can migrate from the liquid to vapor phase depending on temperature, pressure and type carbon chains within the hydrocarbon.

So What Does This Mean?

The lack of correlation causes discrepancies between test methods designed to measure H2S in the liquid phase and test methods designed to measure H2S in the vapor phase. The most common test method for vapor phase measurement is ASTM- D5705 which involves the use of a pump and glass tubes that stain when H2S is detected. The most common test method for liquid phase measurement is UOP-163 which involves a titration.

Field Sampling Best Practices for H2S

H2S in the field is usually measured with stain tubes and a pump. Using proper on-site testing for H2S during this stage helps minimize data variability and improves decision-making at the wellsite.

 

  • The crude oil H2S is measured at ambient or well temperature which can cause high variability between readings.
  • H2S can escape depending on the sampling procedure and how long crude oil is held within a sample bottle.
  • H2S can vary significantly (>1000 ppm) from day to day at the wellsite.

Laboratory Sampling Guidelines for Reliable H2S Results

Getting an accurate measurement begins with sampling.

 

  1. Get a fresh crude sample from a heater treater sample valve. The crude oil is still hot and it will be as fresh as it gets.
  2. Use a glass quart bottle and fill to 50% capacity.
  3. Close immediately.
  4. Shake vigorously for 30-60 seconds and take your measurement.
  5. Repeat if possible.

Best Laboratory Practices

The number one source for an inaccurate measurement will come when the crude oil is sampled at the well and transported to the lab.

  1. It is crucial that the samples are fresh and ideally coming from a heater treater sample valve.
  2. Use a glass quart bottle and fill to 100% capacity. Filling to 100% capacity will make H2S stay in the liquid phase and reduces chances for it to escape.
  3. Use thread sealing tape on the glass quart threads to ensure the best seal possible.
  4. Immediately store the bottles upside down in an ice chest.
  5. Test in a lab setting using a standardized test method within 6-12 hours.
  6. Obtain several samples to ensure repeatability.

H2S Treatment Solutions After Sampling

Q2 Technologies> has brought to market an innovative technology for H2S and Mercaptans removal. By removing sulfur compounds at the wellhead, a producer or an oil trader can sell the crude at a higher price. Its non-amine properties are favored by refineries and allows crude oil marketers to have more outlets for their crude. The use of the Pro3® essentially increases the value of a barrel and can remove over 100,000 ppmv of H2S.