Amine Plant 101 – How to optimize your existing infrastructure

Have you ever wondered if you’re getting the most out of your natural gas processing? Natural gas often contains impurities such as carbon dioxide (CO2) and hydrogen sulfide (H2S) that need to be removed before it can be used. An amine plant is a key part of this process which primarily involves the use of aqueous solutions of various alkanolamines, hence the name “amine plant.” At Q2 Technologies, we understand the fundamental need to treat large quantities of acid gases at scale, and we recognize that these amine plants can be challenged in getting full utilization rates on a consistent basis. That’s where our experts can assist in ensuring that H2S, mercaptans, and total Sulfur content is further optimized.

Where are amine units found?

Amine units are typically found at downstream locations such as Natural Gas Processing Plants, Fractionators, or at LNG facilities. However, amine headers can also be found further upstream at compressor stations.

The Amine Plant 101

Now that we have established what an amine plant is and where we can find it, let’s dive into how they work. We will go step by step using a gas processing plant as our main example:

1. Gas Inlet

Raw or untreated natural gas, which contains acid gases like CO2 and H2S, enters a facility via a pipeline. In its unprocessed state, the acid gas may contain other impurities, so oftentimes the amine plant is at the front end of these types of facilities. Again, being in a raw state, this gas stream is typically saturated with water vapor.

2. Chemical Reaction

In the absorption tower, the gas comes into contact with a solution of amine-based absorbent, commonly monoethanolamine (MEA), diethanolamine (DEA), and methyldiethanolamine (MDEA). These amines selectively react with acidic gases, forming stable compounds and removing them from the gas stream. The acidic gases react with the amine solution to form soluble compounds, and because of this relation, choosing the right amine concentration is important. Due to the stoichiometric balancing during these reactions, the CO2 reaction, as it is the stronger acid of the two, the amine process is not 100% effective in stripping out all of the H2S, remaining CO2, and light mercaptans can pass unabated. In sum, amine units are moderately effective for H2S streams that have low CO2, but for weaker acids such as mercaptans, they are not a catchall and so a polisher system should be considered for final mercaptan adsorption.

3. Sweet Gas Outlet

The treated gas, now largely free of acidic gases, exits the top of the absorption tower as “sweet” or purified natural gas, ready for further processing or distribution.

4. Regeneration:

The amine solution, now rich in absorbed acidic gases, flows to a regeneration unit. Here, heat is applied to release the absorbed gases. The regenerated amine solution, now depleted of acidic gases, is recycled back to the absorption tower for reuse.

5. Recovery and Disposal:

The released acidic gases, along with any excess water vapor, are separated from the amine solution in the regeneration unit. These gases can be further processed or treated to meet environmental standards before disposal.

amine plant process

Source: https://www.sciencedirect.com/topics/engineering/amine-system

Here are the basic components of the Amine unit. Start with the Sour Gas and follow the arrows to Sweet Gas. The Regenerator aspect of the unit is in a constant sequence of turning Rich Amine to Lean Amine.

Additional considerations…

Heat Integration: Many modern amine plants incorporate heat integration techniques to optimize energy efficiency. This involves exchanging heat between the hot regenerated amine solution and the incoming rich amine solution or between the hot gas stream and the reboiler.

Monitoring and Control: Throughout the process, various parameters such as temperature, pressure, flow rates, and concentrations are continuously monitored and controlled to ensure efficient operation and adherence to safety and environmental regulations.

Amine plants play a vital role in natural gas processing by removing the bulk of acid gases through the amine gas sweetening process, also known as natural gas sweetening process or sour gas sweetening, to meet product specifications, environmental regulations, and pipeline transmission requirements, but even with these steps, the resulting “sweet” streams may not be enough to meet commercial specifications. Remember that resulting mercaptan component after the stream had been treated? Unfortunately, mercaptans are challenging molecules to render, fortunately there are solutions.

Q2 Technologies has developed a process that takes the resulting “sweet” stream and purifies it a step further. Our Pro3® Nano and our suite of mixed metal catalysts act as a next level polisher to ensure specs are met consistently. These robust units can take swings of H2S, mercaptans, and remaining Sulfur compounds in a combined reaction and absorption process. If your amine unit is at capacity, these polishers are excellent ways to scrub out any remaining Sulfur contaminants.

With a better working framework of how an amine plant operates, we hope this helps explain how an amine unit works. If you have any questions or would like to learn how our advanced solutions can effectively remove H2S, mercaptans, and total Sulfur, please contact us.

H2S in Oil & Gas Reservoirs: Biogenic Vs. Abiogenic Formation and Age

H2S IN OIL & GAS RESERVOIRS: BIOGENIC VS. ABIOGENIC FORMATION AND AGE

Not all Hydrogen Sulfide (H2S) is created equal! But it results in the same damaging, toxic, and deadly gas. Knowing the source can ultimately assist in finding the appropriate treatment for a permanent solution. In today’s blog we’ll discuss the two major ways H2S in the oil and gas industry can come about, the differences between the two formations, and maybe some uncommon ways to approach finding a solution to these problems.

Hydrogen sulfide in crude oil and gas (H2S) is commonly present in reservoirs, posing both challenges and opportunities for the industry. Understanding its formation mechanisms and age is crucial for safe and efficient exploration and production in high H2S oil fields. H2S removal is an essential process to mitigate these challenges and ensure safety during operations. H2S scavengers are specific compounds or materials employed to capture and remove H2S from these reservoirs.

The Two Faces of H2S Formation

Biological Formation

This process involves the breakdown of organic matter (think buried plant and animal remains) by sulfate-reducing bacteria (SRB) in oxygen-depleted environments. These bacteria utilize sulfate (SO4²⁻) as an electron acceptor during organic matter degradation, releasing H2S as a byproduct. This mechanism is prevalent in formations with past or present sulfate-rich brines and organic material.

A few great examples of biological formation of H2S can be found in swampy bayous, peat bogs, stale pond water, or uncirculated retention ponds at oil and gas or wastewater treatment facilities.

Geological Formation

Here, H2S generation doesn’t involve living organisms. It can occur through:

Thermal Decomposition: High temperatures can break down sulfur-containing minerals like gypsum (CaSO4·2H2O) into H2S, calcium oxide (CaO), and water vapor.
Thermochemical Sulfate Reduction (TSR): Under high temperatures and pressures, reactions between hydrocarbons and sulfate minerals can yield H2S, carbon dioxide (CO2), and metal sulfides.

Geological creation of H2S in oil reservoirs is happening at major fault lines all around the world, especially where uplifts are grinding against active oil formations. A well-known example is the eastern slope of the Delaware as it is slowly being lifted by the Central Basin Platform, a granite uplift that bifurcates the two major lobes of the Permian. This movement allows for the geological process to occur deep underground in the slightest alcoves of rock fissures and micro pore spaces.

How to determine where H2S is coming from?

There’s a technique called EA-IRMS that helps us determine where sulfur comes from. Here’s how it works:

Like a Fingerprint:

Sulfur has a unique “fingerprint” depending on where it originated, either from deep underground (geological) or from living organisms (biological). EA-IRMS analyzes these tiny variations in the sulfur atoms to differentiate between the two sources with the δ34S scale (colloquially pronounced delta 34 S). The δ34S scale is a way for scientists to measure the relative abundance (“fingerprints”) of two types of sulfur atoms: sulfur-32 (³²S) and sulfur-34 (³⁴S). By measuring the δ34S value of a sample (compared to the CDT reference), scientists can gain insights into whether the sulfur originated from geological processes or was influenced by biological activity.

Interpreting the δ34S Values:

A δ34S value greater than 0 on the scale (positive) suggests that bacteria have been using up δ32S, leaving behind a higher proportion of δ34S. This indicates a likely biological influence.

More negative δ34S values suggest that there has been little to no biological activity using up δ32S. This might point towards a more geological origin of the sulfur.

Let’s take a look at this example:

H2S in reservoirs

Source: Seal II RR (2006). “Sulfur Isotope Geochemistry of Sulfide Minerals”

High δ34S values (positive side): Reservoirs like modern seawater sulfate and ancient marine evaporites often show higher δ34S values. This suggests a possible biological influence from sulfate-reducing bacteria.
Intermediate δ34S values: Meteorites, igneous rocks, petroleum, and coal might have some biological influence due to their position on the positive side of the scale. However, their values might not be as extreme as seawater sulfate, indicating a potential mix of geological and biological processes.
Low δ34S values (negative side): Modern and ancient sedimentary pyrite tend to have lower δ34S values, suggesting a more dominant geological origin with less biological influence.

The Takeaway

Getting to know the formation mechanism and age of H2S in your reservoir provides significant advantages in several areas. From a safety standpoint, understanding its origin allows you to predict H2S concentration and implement appropriate safeguards for drilling, production, and transportation. Furthermore, knowing the formation mechanism guides the selection of the most efficient H2S removal techniques for your produced oil and gas streams. Finally, the presence and type of H2S offer valuable clues into the geological history and properties of the reservoir, aiding in accurate reservoir characterization.

Explore our H2S scavengers.

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?

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!

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:

Typical Amines:

Monoethanolamine (MEA)
Diethanolamine (DEA)
N-methyldiethanolamine (MDEA)
Diglycolamine (DGA)

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.

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.

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:

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.
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.
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.
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.

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.
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.
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.

Conclusion

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 Technologies‘ Pro3® 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:

Detection levels for mercaptans are much lower than hydrogen sulfide, so it is way easier for mercaptans to cause complaints.
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.
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.
Although noxious at moderate levels, even high mercaptan levels are not fatal as compared to relatively low levels of hydrogen sulfide (H2S).
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.*

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:

First, a specialized lab analysis is made to determine the mercaptan levels and variety of mercaptan species present.
Based on lab results, we determine the appropriate dosing of ProM® chemical.
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.
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.

Conclusion

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.

Sources:

https://www.chemicalsafetyfacts.org/chemicals/methyl-mercaptan/#:~:text=Methyl%20mercaptan%2C%20or%20methanethiol%2C%20is,from%20paper%20and%20pulp%20mills.

https://chem.libretexts.org/Courses/Northeastern_University/12%3A_Chromatographic_and_Electrophoretic_Methods/12.4%3A_Gas_Chromatography

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.

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