The Business Case for Regenerative Hydrogen Sulfide Treatment

For producers operating sour assets, the commercial argument for investing in hydrogen sulfide treating is straightforward — but the magnitude of the opportunity depends on the specific asset profile. Here are the primary value drivers:

Converting Flared Gas into Sales Revenue. Every Mcf of sour gas that is flared rather than treated and sold represents destroyed revenue. For an unconventional multi-well pad flaring meaningful volumes because of hydrogen sulfide, on-site treating can convert that flared gas directly into sales gas — converting a waste stream into revenue while simultaneously reducing emissions.

Eliminating Sour Takeaway Dependency. Many sour gas producers in the Permian Basin and elsewhere depend on midstream partners to transport and treat their sour gas. This creates a structural vulnerability: when sour takeaway capacity is constrained — a recurring challenge in the Permian Basin as production growth repeatedly outpaces midstream infrastructure — operators face production curtailments or are forced to flare. On-site hydrogen sulfide treating removes this bottleneck, allowing operators to sweeten their own gas at the wellhead and inject it directly into sweet gas gathering infrastructure.

Enabling Gas Lift Without Sweet Gas Buyback. Gas lift is one of the most common artificial lift methods used in unconventional oil production in the Permian Basin. It requires a supply of compressed gas injected into the wellbore to reduce hydrostatic pressure and increase oil flow. When the produced gas at a well site is sour, operators traditionally must purchase sweet gas from a third party for gas lift injection — an expense called sweet gas buyback. On-site hydrogen sulfide treating eliminates this cost by enabling operators to sweeten their own produced gas and use it directly for gas lift.

Strengthening Environmental Performance. Reducing routine flaring and eliminating the use and disposal of hazardous chemicals are increasingly material to oil and gas operators’ environmental performance. Hydrogen sulfide treating technology that converts H₂S into non-hazardous elemental sulfur — rather than destroying it through flaring or disposing of spent chemical waste — addresses multiple environmental performance metrics simultaneously.

Common Hydrogen Sulfide Challenges and Their Consequences

The Challenge	The Consequence
Hydrogen sulfide exceeds pipeline specification	Gas cannot enter the sales pipeline; revenue is lost or gas is flared
Limited sour gas takeaway capacity	Production is curtailed; sour assets remain stranded
Flaring restrictions tighten	Operators face regulatory exposure and reputational risk
Triazine scavengers overwhelmed at high hydrogen sulfide concentrations	Treatment costs escalate; performance degrades
No sweetened gas available for gas lift	Operators must purchase expensive sweet gas buyback

Why Legacy Hydrogen Sulfide Treatment Methods Fall Short

Traditional approaches to treating hydrogen sulfide in natural gas streams — including triazine chemical scavengers and amine sweetening systems — were developed for a different era of oil and gas production and carry limitations that make them a poor fit for many of the sour gas challenges operators face today.

Triazine Scavengers. Triazine is the most widely used non-regenerative H₂S scavenger in the U.S. oil and gas industry. It captures hydrogen sulfide through a one-time, irreversible chemical reaction that produces Dithiazine — a liquid hazardous waste requiring disposal at a saltwater disposal well or licensed hazardous materials facility. Because triazine is consumed in the reaction, spent chemical must be continuously repurchased and the Dithiazine byproduct continuously disposed of. At the hydrogen sulfide concentrations common in the Permian Basin and Eagle Ford, triazine scavengers can quickly become economically unsustainable: the chemical becomes overwhelmed, efficiency degrades, and costs escalate rapidly with H₂S load.

Amine Sweetening. Amine scrubbing systems are effective at high volumes and can achieve deep hydrogen sulfide removal, but they require significant capital investment, skilled operations, and a stable, predictable gas feed. They are designed for gas plant and refinery-scale operations, not for the variable-volume, distributed-production environments typical of upstream oil and gas operations in unconventional plays.

Flaring. As previously noted, flaring converts hydrogen sulfide to SO₂, wastes a saleable commodity, and is increasingly restricted by state and federal regulation. It is a disposal method, not a value-creation strategy, and it creates environmental and regulatory risk rather than eliminating it.

Regenerative Liquid Redox: A Purpose-Built Solution for Unlocking the Value of Sour Gas Assets

Next-generation liquid redox hydrogen sulfide treating addresses the limitations of legacy methods by combining a regenerative chemical process with advanced automation — making it practical, economical, and operationally manageable across the distributed, variable-volume conditions typically found in the production of unconventional assets.

How Liquid Redox Works

In a liquid redox process, sour gas contaminated with hydrogen sulfide is directed into a treatment vessel containing specialized chemistry. Hydrogen sulfide in the gas stream donates electrons to the chemistry — oxidizing the H₂S into elemental sulfur, which precipitates out as a solid. The chemistry, now reduced, is routed to a regeneration vessel where exposure to air re-oxidizes it back to its active state, ready to treat more gas. The treated gas exits the system sweet, at non-detect hydrogen sulfide levels, and can be directed immediately to a sales pipeline, gas lift header, or fuel gas system.

Streamline Innovations’ VALKYRIE® system executes this cycle using TALON® chemistry — a non-toxic, biodegradable, patented reagent — combined with advanced process control and automation that manages the treating and regeneration cycle continuously with minimal field labor.

Technical note: Liquid redox is not a catalytic process. The TALON® chemistry actively participates in the reaction — accepting and donating electrons — and is then regenerated for reuse. It is a regenerative chemical oxidation process, distinct from both non-regenerative scavengers and true thermal-catalytic methods such as the Claus process, so less product is required to treat the same volume as an equivalent method.

The Byproduct Advantage of Liquid Redox

Instead of Dithiazine waste, the VALKYRIE® process produces Simple Elemental Sulfur — a non-hazardous solid listed by the Organic Materials Review Institute (OMRI) for use in organic food production. The byproduct can be sold or disposed of as non-hazardous material, eliminating the hazardous waste disposal costs that burden triazine-based programs.

Valkyrie Operating Envelope

The VALKYRIE® H2S removal system is engineered to treat across the full spectrum of conditions found in upstream and midstream oil and gas operations:

Hydrogen sulfide concentrations from trace levels up to high-concentration sour gas streams that overwhelm triazine scavengers
Gas flow rates from single-well pads to multi-well production facilities
The full range of operating pressures encountered from wellhead to refinery
Near 100% turndown capability without loss of efficiency as production volumes vary

This operating flexibility — the widest of any field hydrogen sulfide treating method — is what makes next-generation liquid redox suitable for the variable-volume, distributed-production environments of unconventional oil and gas plays.

VALKYRIE® Hydrogen Sulfide Treatment Applications in Oil & Gas

Application	What It Does	Key Benefit
Wellhead sweetening	Treat sour gas at the point of production before it enters gathering lines	Eliminates flaring; enables gas sales
Gas lift sweetening	Sweeten sour produced gas on-site for use as gas lift injection gas	Eliminates sweet gas buyback expense
Fuel gas conditioning	Sweeten gas for use as on-site fuel for generators or compressors	Eliminates hydrogen sulfide exposure risk from fuel combustion
Field-wide deployment	Multiple VALKYRIE units deployed across a production area	Eliminates sour takeaway dependency at scale

Real-World Results: Unlocking Sour Gas Value in the Permian Basin

VALKYRIE® hydrogen sulfide treating systems have been deployed across the Permian Basin and other U.S. sour gas producing regions, with operators including Chevron and others among those putting the technology to work.

In a representative deployment, a Permian Basin operator used VALKYRIE hydrogen sulfide treating technology to unlock the value of its sour oil and gas assets. With on-site VALKYRIE treating installed at the production pad, the operator was able to:

Sweeten produced gas to pipeline specification and sell it directly into sweet gas gathering infrastructure
Use a portion of the treated gas for gas lift operations, eliminating sweet gas buyback
Eliminate routine flaring of sour gas at the site, reducing SO₂ and methane emissions
Expand the deployment field-wide as additional wells came online

The result was a sour asset that had previously required flaring or remained constrained by takeaway capacity being converted into a commercially productive, low-emission operation.

Is On-Site Hydrogen Sulfide Treating Right for Your Operation?

On-site liquid redox hydrogen sulfide treating is best suited to operations where one or more of the following conditions apply:

Sour gas cannot be commercialized due to hydrogen sulfide concentrations that exceed pipeline specification
Sour gas takeaway capacity is limited or unreliable, constraining production
Flaring restrictions are tightening and routine flaring of sour gas creates regulatory or reputational exposure
Gas lift operations require sweetened gas but sweet gas buyback costs are significant
Triazine scavenger costs are escalating as hydrogen sulfide loads increase
ESG commitments require measurable reductions in flaring and hazardous chemical use

For operators in the Permian Basin, Eagle Ford, or other sour-prone producing regions, the economics of on-site hydrogen sulfide treating improve substantially as hydrogen sulfide concentrations rise and gas volumes grow — precisely the conditions where legacy scavenger methods become least viable.

Ready to Unlock Your Sour Gas Assets? We engineer hydrogen sulfide treatment solutions for upstream and midstream oil and gas operators across the United States. Whether you are evaluating on-site treatment for the first time or looking to replace a legacy scavenger program that is no longer working efficiently, our team can assess your specific asset conditions and recommend the right configuration.

Ready to find the right hydrogen sulfide treatment solution for your operation? Contact Streamline Innovations to speak with an engineer about hydrogen sulfide treatment solutions for your operations.

Liquid Redox, Oil & Gas, Valkyrie

June 18, 2026Oil & Gas

Which Hydrogen Sulfide Treatment Method is Right for Your Oil & Gas Operation? Triazine Scavenger vs. Liquid Redox

Treating natural gas streams for hydrogen sulfide (H₂S) is a non-negotiable operational requirement for Oil & Gas producers in the United States. Hydrogen sulfide is highly corrosive to steel pipelines and compression equipment, and at elevated concentrations it presents a life-safety hazard to field personnel. Most natural gas transmission pipelines impose strict limits on hydrogen sulfide concentration, requiring producers to remove hydrogen sulfide before gas can enter the sales pipeline. Operators frequently compare Triazine vs. liquid redox treatment methods.

In producing regions where sour gas is common, such as the Permian Basin in West Texas and southeast New Mexico, as well as the Eagle Ford trend in southern Texas, the ability to treat hydrogen sulfide efficiently and economically impacts whether a sour gas asset can be commercialized.

This article compares two hydrogen sulfide treatment strategies for natural gas in the field: the triazine chemical scavenger (the traditional industry default) and next-generation liquid redox used in Streamline Innovations’ VALKYRIE® system. In the Triazine vs. liquid redox comparison, understanding the differences in mechanism, cost, byproduct handling, and operational complexity is essential for producers evaluating which approach best fits their assets and production profile.

Key Term: “Sour gas” refers to natural gas containing hydrogen sulfide, typically with concentration exceeding pipeline specification. Removing hydrogen sulfide to bring gas within spec is called “sweetening.”

What Is a Triazine H2S Scavenger?

Triazine is arguably the most widely used non-generative liquid scavenger for hydrogen sulfide treatment in the U.S. oil and gas industry. Chemically, it is a hexahydrotriazine compound, a clear to pale yellow liquid with a fishy smell. Triazine is usually mixed with other substances to bring concentration down to field strengths ranging from 20-80%, depending on the application.

There are two primary deployment methods:

Contact tower (scavenger tower): Sour gas is fed into a tower vessel where it bubbles up through the triazine liquid. As the hydrogen sulfide contacts the triazine in the treatment tower, a chemical reaction captures it and renders it harmless. Contact towers can achieve up to 80% efficiency in hydrogen sulfide removal.
Direct injection: Triazine is injected directly into the gas stream. This method is simpler to install but significantly less effective, achieving only 40% efficiency.

How the Triazine Reaction Works

Triazine removes hydrogen sulfide through a non-reversible chemical reaction: one mole of triazine reacts with two moles of hydrogen sulfide to produce Dithiazine and monoethanolamine (MEA). Because this is a one-time, non-reversible chemical reaction, the triazine is consumed in the process and cannot be regenerated. Once spent, the triazine must be replaced periodically and the spent liquid must be disposed of.

Dithiazine: The Disposal Problem

Dithiazine is the unavoidable byproduct of triazine-based hydrogen sulfide treatment. It has no commercial secondary use and is classified as a liquid hazardous waste. Disposal options are limited:

Injection into saltwater disposal (SWD) wells alongside produced water, if the SWD operator permits it
Disposal at a licensed hazardous materials facility

As hydrogen sulfide concentrations increase or treatment volumes grow, Dithiazine generation scales proportionally, meaning disposal costs can become a significant operational burden on oil and gas assets with high concentration of hydrogen sulfide.If you’re evaluating sulfide treatment strategies for high-H₂S produced water, don’t rely on theory, review the field data.

Chemical Handling and Safety of Triazine

Liquid triazine is typically transported in plastic totes to the well site or production pad. Field personnel encounter direct exposure risk when moving totes, maintaining contact towers, and servicing injection equipment. The U.S. Environmental Protection Agency classifies types of triazines as possible human carcinogens, and exposure can cause skin rashes and eye irritation. Chemical handling training and PPE requirements add to the operational overhead of triazine-based hydrogen sulfide treatment programs.

Triazine: Pros and Cons Summary

The benefits of using triazine for treating H₂S in gas streams include:

Low upfront capital cost.
Zero air emissions.
Widely available in most oil and gas producing regions.
Skid-based units can be mobilized from one location to another quickly and easily.

Downsides include:

Efficiency degrades under high hydrogen sulfide loads.
Dithiazine byproducts require hazardous waste disposal.
Contact towers are typically only 80% efficient, direct injection only ~40% efficient.
Non-regenerative process, meaning frequent media changes.
Often requires use of other chemicals to mitigate negative downstream effects.
Contact towers (bubble towers) can be operationally complex and require frequent attention.
Can be costly when treating gas with high concentrations of hydrogen sulfide and/or high gas flow rates.
Worker exposure to chemicals at the worksite, potential health and safety concerns.

What is Next-Generation Liquid Redox for Hydrogen Sulfide Treatment?

Early generations of liquid redox hydrogen sulfide treatment suffered from operational complexity and inconsistent performance. Next-generation liquid redox systems, such as the VALKYRIE® platform from Streamline Innovations, address those limitations through upgraded chemistry and advanced automation, making regenerative hydrogen sulfide treatment practical across a wide range of field conditions.

The VALKYRIE H₂S treating solution from Streamline Innovations utilizes relatively recent technological advances in automation control to create the “Next Generation Redox” system. The VALKYRIE system utilizes patented TALON®, our non-toxic, biodegradable Redox chemistry. Unlike triazine, TALON chemistry participates in a reduction-oxidation (redox) cycle that converts hydrogen sulfide into elemental sulfur and water, and then regenerates itself through exposure to air, allowing the chemistry to be recycled and reused.

How the Liquid Redox Process Works

The mechanism has two stages that operate in a continuous loop:

Reduction: Sour gas contacts TALON chemistry in a treating vessel. Hydrogen sulfide (H₂S) is oxidized into elemental sulfur – a solid that precipitates out of the liquid.

Oxidation (regeneration): The chemistry is then regenerated with exposure to oxygen back to its active state, ready to treat more hydrogen sulfide.

The treated gas exits the system free of hydrogen sulfide (at non-detect levels), and the elemental sulfur is filtered, collected, and periodically removed. The VALKRYIE system uses advanced process control and automation to manage this cycle with minimal field labor.

Simple Elemental Sulfur™: A Byproduct with Value

Unlike Dithiazine, the elemental sulfur produced by Streamline’s VALKYRIE system is non-toxic and produces Simple Elemental Sulfur™, which has been approved by the Organic Materials Review Institute (OMRI) for use in organic food production. This means the byproduct can potentially be sold rather than disposed of — a meaningful difference in the total lifecycle cost calculation.

VALKYRIE Operating Range and Applications

A significant advantage of next-generation liquid redox over triazine for hydrogen sulfide treatment is its operating envelope. The VALKYRIE system is designed to treat across the full spectrum of:

Pressure ranges encountered across upstream and midstream applications
Gas flow rates from smaller single-well pads to multi-well production facilities
Hydrogen sulfide concentrations from low ppm levels up to high-concentration sour gas streams that would overwhelm triazine scavengers

This flexibility makes liquid redox suitable for a range of oil and gas hydrogen sulfide treatment configurations, including wellhead sweetening, field gas conditioning for gas lift operations, and fuel gas conditioning. Several leading operators, including Chevron and others, have deployed VALKYRIE units in the Permian Basin.

Next Generation Liquid Redox: Pros and Cons Summary

The benefits of using Next Generation Redox for treating hydrogen sulfide in gas streams include:

Treats hydrogen sulfide to non-detect levels
Regenerative chemistry — dramatically reduced ongoing chemical cost
Non-toxic, biodegradable TALON chemistry; improved field safety
Elemental sulfur byproduct is non-hazardous and potentially marketable
Widest operating envelope of any field hydrogen sulfide treatment method
Advanced automation reduces field labor and oversight requirements

Downsides include:

Higher initial capital investment than triazine scavenger equipment
Requires a power source for automation and controls

Triazine vs. Liquid Redox: Side-by-Side Comparison

The table below summarizes the key differences between triazine scavenger and next-generation liquid redox for hydrogen sulfide treatment in natural gas:

Factor	Triazine Scavenger	Next-Gen Liquid Redox (VALKYRIE®)
Treatment Mechanism	Non-regenerative chemical reaction (one-time)	Regenerative redox cycle (reused continuously)
Byproduct	Dithiazine — liquid hazardous waste	Elemental sulfur — reusable, non-hazardous
Efficiency	Up to 80% (contact tower); ~40% (direct injection)	Treats to non-detect levels
High H2S Loads	Becomes overwhelmed; cost escalates rapidly	Widest operating envelope across all concentrations
Chemical Handling	Requires PPE and training for safe handling and disposal	Non-toxic, biodegradable chemistry
Disposal Cost	Ongoing — SWD wells or hazardous waste facility	Minimal — elemental sulfur has market value or can be incinerated
Operational Overhead	Frequent media changes; high field labor	Advanced automation; minimal field intervention
Mobility	Skid-mounted; easily relocated	Skid-mounted; easily relocated
Upfront Cost	Low	Higher initial capital
Best For	Low-volume, low H₂S, short-duration applications	High H₂S concentrations; sustained production operations

Which Hydrogen Sulfide Treatment Method Is Right for Your Operation?

The right choice depends on the specific characteristics of the sour gas asset and the operational context:

Triazine scavengers may be the better fit when:

Hydrogen sulfide concentrations are low and/or volumes are small
The treatment needs are short-term — for example, during workover operations or temporary production testing
Minimizing upfront capital cost is the primary constraint
Midstream sour gas takeaway capacity makes wellhead treating optional

Liquid redox is typically the better fit when:

Hydrogen sulfide concentrations are high enough to push triazine costs to unacceptable levels
The asset is a sustained producing operation where accumulated chemical and disposal costs favor a regenerative system
Pipeline hydrogen sulfide specifications are stringent and require non-detect outlet levels
On-site treating is needed to enable gas lift, fuel gas conditioning, or other operations requiring sweetened gas
Reducing risks of field chemical handling risk and improving ESG performance are operational priorities

For most sour gas producers in the Permian Basin and Eagle Ford trend operating sustained production assets with meaningful hydrogen sulfide concentrations, next-generation liquid redox typically offers a lower total cost of ownership and better performance profile than triazine scavenger — even when accounting for the higher initial capital investment.

About Streamline Innovations’ VALKYRIE® Hydrogen Sulfide Treatment System

Streamline Innovations develops and deploys next-generation liquid redox hydrogen sulfide treatment systems for oil and gas producers, midstream operators, and other industrial applications. The VALKYRIE® platform uses patented TALON® chemistry and advanced automation to remove hydrogen sulfide from natural gas streams reliably, safely, and economically across the full range of operating conditions found in U.S. oil and gas production.

VALKYRIE® units are deployed across upstream, midstream, and downstream configurations, including direct treating at the wellhead, tail gas treating, and gas lift sweetening. Contact Streamline Innovations to learn how liquid redox hydrogen sulfide treatment can unlock the value of your sour gas assets.

Ready to find the right hydrogen sulfide treatment solution for your operation? Contact Streamline today to speak with an Engineer

Oil & Gas, Valkyrie

October 16, 2025Elemental Sulfur

Sour Gas Treating: Introducing the New VALKYRIE® 1.5 Ton H₂S Treatment Unit

Removing Sour Gas Takeaway Constraints

For too long, oil and gas operators have been forced to leave valuable resources in the ground – or flare and choke back production – because sour gas takeaway capacity simply wasn’t available. Midstream bottlenecks, limited processing capacity, and the inefficiencies of legacy scavenger treatments have slowed operations and stifled profitability.

Streamline Innovations has changed the game. With the introduction of the VALKYRIE™ 1.5 LTPD Sour Gas Treating Unit, operators can eliminate the sour gas takeaway constraint and unlock the full value of their sour hydrocarbon resources. Built on the proven foundation of the VALKYRIE fleet’s 99.9%+ mechanical availability, this larger system delivers unmatched capacity and efficiency – while setting the standard in environmental responsibility. VALKYRIE 1.5 LTPD units are in the field today working reliably for leading operators.

Bigger Capacity for Sour Gas Treating. Smarter Investment

The VALKYRIE 1.5 LTPD unit is engineered to process more gas and extract more sulfur than our standard 1.0 LTPD unit. That means operators can replace multiple scavenger systems or run just two VALKYRIE units instead of three—reducing capital outlays while simplifying operations.

The Lowest-Cost Path to Sweet Gas

Streamline Innovations has led the way in reliable, cost-effective, and environmentally friendly sour gas treatment, and the 1.5 LTPD continues that tradition. By delivering the lowest onsite treating costs for large volumes and high concentrations of H₂S, operators can expand production while keeping OPEX under control.

Removing Bottlenecks, Unlocking Production

Sour takeaway constraints no longer have to limit your production rates. By sweetening gas directly at the wellsite, the VALKYRIE system eliminates reliance on limited midstream capacity. With VALKYRIE you gain flexibility, reliability, and control – removing the bottlenecks that restrict revenue growth.

A True Sustainable and Safe Technology

The future of on-site gas treating isn’t just about efficiency – it’s about responsibility. VALKYRIE technology uses a non-toxic, eco-friendly TALON® chemistry that safeguards workers and the environment alike. Unlike traditional methods, the process produces no harmful byproducts. Instead, the primary output is Simple Elemental Sulfur™, a recyclable and OMRI-certified material approved for use in organic food production.

A True Turnkey Solution

With Streamline, you don’t just get hardware – you get a partner. The VALKYRIE 1.5 LTPD comes with a full-service operating model, including chemical management, maintenance, sulfur removal, and operations support. Backed by 99.9+% uptime, Streamline takes the burden off field personnel and ensures sour gas treatment never stands in the way of production.

Smarter. Cleaner. More Profitable.

The VALKYRIE 1.5 Ton H₂S treatment unit isn’t just a bigger system – it’s a smarter way to unlock sour hydrocarbon resources for operators who demand efficiency, safety, and sustainability. By reducing capital costs, lowering OPEX, eliminating operational constraints, and delivering a proven eco-friendly process, Streamline Innovations is once again redefining what’s possible in sour gas treatment.

Turn sour constraints into sweet profits with Streamline Innovations. Contact us today to learn how you can put the VALKYRIE 1.5 LTPD to work and unlock the value of your sour oil and gas resources.

Elemental Sulfur, Oil & Gas, Valkyrie

June 3, 2025Events

Initial Deployment of 1.5 Ton VALKYRIE® Units: Enhancing Environmental H2S Treatment for Oil & Gas Applications

Streamline Innovations has launched its first VALKYRIE® units capable of treating up to 1.5 long tons per day of hydrogen sulfide (H₂S) and handling up to 60 MMCFD of gas. These units offer a 50% increase in sulfur extraction compared to the standard system and the lowest cost onsite gas treating option for large volumes and concentrations of sour gas.

Importantly, VALKYRIE technology is known for its reliable and environmentally friendly liquid redox chemistry.

More Options for Maximizing Operational Efficiency

The new 1.5 LTPD system expands the standard product offering, offering oil and gas operators more options for using VALKYRIE H₂S treating technology across a broader range of production volumes and H₂S concentrations. The 1.5-ton unit, developed with trusted partners, employs the same proven and eco-friendly liquid redox chemistry as all VALKYRIE units.

Successful Initial Deployments

The first VALKYRIE 1.5 LTPD unit was installed and commissioned on a production facility operated by Devon Energy during the first quarter of 2025. The 1.5-ton system successfully allowed for economic and environmentally friendly treating at a centralized tank battery (CTB), reducing total H₂S treating costs, simplifying operations and improving overall operational efficiency.

Valkyrie 1.5 Ton H2S Treating Technology

Three additional 1.5 LTPD units have been delivered, installed and successfully commissioned with other operators in both the Midland and Delaware Basins.

Additionally, Streamline will deploy a 5^th 1.5 LTPD unit in the Midland Basin in Q4 of 2025 and we are adding additional inventory and taking orders for 2026 delivery.

Benefits of VALKYRIE Gas Treating Technology

Reduced Capital Outlays. The VALKYRIE 1.5 LTPD unit can process more gas and extract more sulfur than any previous standard units, allowing it to replace multiple H₂S scavengers using legacy treatments or permitting the use of only two VALKYRIE systems instead of three.
Lower Operating Costs. The 1.5 LTPD unit continues the Streamline advantage of being the lowest onsite gas treating option for large volumes and concentrations of sour gas.
Remove Operational Constraints. Onsite gas sweetening also removes bottlenecks in areas where sour takeaway is constrained and unreliable or limited by lack of midstream processing capacity.
Non-Toxic and Eco-Friendly Chemicals: VALKYRIE technology employs non-toxic and environmentally friendly chemicals, minimizing harm to the environment and ensuring worker safety.
Turnkey Solution: Streamline handles all chemicals, maintenance, operations, and sulfur removal, taking away what is traditionally an operations headache for our customers. We do this with 99+% operational uptime.
No Harmful Byproducts: The VALKYRIE treatment process produces no harmful byproducts, further contributing to environmental sustainability. The primary byproduct is Simple Elemental Sulfur™, approved by the Organic Materials Review Institute (OMRI) for use in organic food production.
Recyclability or Reusability: Many VALKYRIE systems allow for the recycling or reuse of chemicals, reducing waste and enhancing cost-effectiveness.

Contact

Randy Rohlfs
Chief Commercial Officer
Streamline Innovations, Inc.
randy.rohlfs@streamlineinnovations.com

About Streamline Innovations

Streamline Innovation’s vision is Reducing Emissions Through Technology. We help heavy industry around the world achieve environmental performance objectives, improve sustainability, and transition to a sustainable, low-carbon economy.

TIME Magazine ranked Streamline in 6th place out of 250 companies included in TIME’s inaugural list of America’s Top GreenTech Companies 2024. This prestigious recognition is presented by TIME and Statista, Inc., a leading statistics portal and industry ranking provider.

H₂S is present in almost every industrial process in the world. Our technology can be applied across industries, delivering a sustainable solution that eliminates H2S, the leading cause of acid rain, a deadly greenhouse gas dangerous for work and living environments.

Streamline believes that achieving the E (“Environmental”) in ESG requires data. Creating intelligent systems that operate effectively and efficiently without human intervention is critical to reducing emissions that harm the environment. We integrate advanced data collection, process control, and analytics in our technologies to provide a total solution for customers.

We serve organizations in multiple sectors, including Energy/Oil & Gas, Biogas, Landfill Gas & Renewable Fuels, Municipal Wastewater and Industrial Air & Water.

Events, Oil & Gas, Permian Basin, Valkyrie

February 26, 2025Educational

VALKRYIE® H2S Treating System Environmental Sustainability Scorecard 2024

Streamline Innovation’s vision is Reducing Emissions Through Technology. We help global industries meet environmental goals, enhance sustainability, and transition to a lower-carbon future.

Streamline Innovations’ VALKYRIE® H₂S Treating System supports environmental and sustainability goals by destroying H₂S and producing elemental sulfur, which can be used in agriculture, unlike some processes that produce pollution or toxic waste.

Streamline’s VALKYRIE uses TALON®, a non-toxic, biodegradable Redox process to remove H₂S from gas streams. This is done by converting H₂S to elemental sulfur and regenerating the chemistry with air, allowing the process to repeat continuously. The elemental sulfur is then filtered out of solution and stored in a container for transport.

The VALKYRIE® H₂S Treating System doesn’t just capture H₂S, it destroys it, eliminating the need to flare sour gas, which is critical for reducing routine flaring and SO₂ emissions.

The infographic below summarizes the environmental sustainability benefits provided to our customers by VALKYRIE units operating during 2024.

“Leading oil and gas operators are utilizing Streamline technology to unlock the value of their sour gas assets in an efficient and environmentally friendly way. The VALKYRIE Environmental Sustainability Scorecard highlights the measurable environmental advantages of our technology.”

– David Sisk, CEO

Streamline’s sulfur produced from the VALKYRIE solution is listed as Simple Elemental Sulfur™ with the Organic Material Review Institute (“OMRI”) for use as an organic fertilizer. OMRI certification complies with USDA National Organic Program (“NOP”) regulations. Simple Elemental Sulfur™ is a powdered, amorphous sulfur that acts as a soil amendment, raising soil pH and enhancing nitrogen uptake.

About Streamline Innovations

We serve organizations in multiple sectors, including Energy/Oil & Gas, Biogas, Landfill Gas & Renewable Fuels, Municipal Wastewater and Industrial Air & Water.

Educational, Elemental Sulfur, Press Release, Talon Sulfide Elimination System, Valkyrie

January 6, 2025Educational

NEWSWEEK: Streamline Innovations Revolutionizes Disposal of Toxic Industrial Wastes

Streamline Innovations was recently featured in the Newsweek magazine Industry Innovators report.

Excerpt: True to its corporate name, Streamline Innovations uses patented technologies to help heavy industries run more sustainably, efficiently and profitably. One such innovation is used in treating hydrogen sulfide (H2S), a major contaminant in the oil and gas, wastewater, renewable gas and industrial markets. Instead of traditionally flaring H2S-contaminated gas, which releases many toxic substances, Streamline Innovations has developed the VALKYRIE® plant that uses the company’s non-toxic biodegradable TALON® chemistry. This process converts H2S into water and OMRI (Organic Materials Review Institute) certified elemental sulfur that can be used in organic food production.

We’re making a difference by making our clients’ operations greener, easier to implement and more profitable. Our VALKYRIE® plant uses our biodegradable TALON® chemistry to convert hydrogen sulfide into water and sulfur for fertilizer, helping advance the circular economy. Besides helping our clients generate huge savings from more uptime and leaner operations, we’re eliminating about 300,000 pounds monthly of hazardous chemicals they don’t have to handle and transport.“
-David Sisk, Co-Founder and CEO, Streamline Innovations

Download Newsweek’s Interview with David Sisk

About Streamline Innovations

H₂S is present in almost every industrial process in the world. Our technology can be applied across industries, delivering a sustainable solution that eliminates H₂S, the leading cause of acid rain, a deadly greenhouse gas dangerous for work and living environments.

We serve organizations in multiple sectors, including Energy/Oil & Gas, Biogas, Landfill Gas & Renewable Fuels, Municipal Wastewater and Industrial Air & Water.

Educational, Odor Control, Oil & Gas, Press Release, RNG, Talon Sulfide Elimination System, Valkyrie, Wastewater Treatment

August 22, 2024Educational

VALKYRIE® H2S Treating for Reducing Emissions in Oil and Gas Production – Debottlenecking Sour Crude Assets

As operators extend their development beyond the established “fairways” of unconventional shale plays, they are increasingly encountering oil and gas resources containing high levels of hydrogen sulfide (H₂S), otherwise known as “sour” assets. Sour oil and gas resources are especially prevalent in the Delaware Basin portion of the Permian Basin, located in New Mexico and West Texas.

Because it is poisonous and highly corrosive, sour gas presents a threat to both human health and infrastructure. When produced with crude oil, sour gas must be treated and transported off the production facility or flared for safety purposes. However, operators are increasingly encountering barriers to developing sour oil and gas resources in the forms of sour takeaway capacity and initiatives to eliminate routine flaring.

In this article, we cover the challenges operators face when developing their sour crude and natural gas assets and offer a solution to help them alleviate the constraints in an environmentally friendly way.

The Constraint of Sour Takeaway

Sour gas requires treatment before it can be distributed to residential, commercial, and industrial customers. Traditionally, sour gas has been flared or combusted to convert the contaminated gas into less harmful substances. However, flaring sour gas produces other pollutants such as sulfur dioxide (SO₂), which contributes to acid rain; volatile organic compounds (VOCs); and nitrogen oxides (NOx), which can react with particulates and sunlight to form ozone. Additionally, incomplete combustion may release raw H₂S where it can accumulate at the production facility and present a threat to worker safety.

Instead of flaring sour gas, it can be treated and sold as pipeline quality gas. Traditionally, sour gas treating occurs downstream at a gas processing plant operated by the midstream partner. The contaminated gas must be transported using equipment that has been treated and coated to withstand the corrosive effects of sour gas, also known as sour takeaway. Sour takeaway, however, is expensive to install and even if it is available, downstream H₂S treating capacity in many regions has not kept pace with the development. Both lack of sour takeaway capacity and downstream H₂S treating bottlenecks create significant hurdles for operators.

Without a treating solution in places where flaring is not an option because of regulatory restrictions or voluntary emissions reduction practices, developing sour gas resources must come to a halt.

Debottlenecking – Removing Sour Gas Takeaway Constraints

Operators can debottleneck sour production by installing H₂S treating capacity at the well site or production pad for “sweetening” sour gas, effectively removing midstream capacity constraints.

In our article, Gas Sweetening, Sour Gas Treatment Strategies by Volume, we identified the three primary categories of traditional gas treating methods for removing H₂S from produced gas, including (a) scavengers and adsorbents, (b) catalytic reactions, and (c) mechanical destruction or injection. These methods, however, have numerous downsides, including:

Create negative downstream processing effects.
Require the use of chemicals that can be expensive and present a safety risk.
Require the disposal of contaminated media, creating environmental and safety risks.
Operational complexity, requiring frequent oversight on location and problem solving.

VALKYRIE® H₂S Technology for Debottlenecking Sour Gas Production

VALKYRIE H₂S treatment technology helps oil and gas operators overcome the constraint of limited sour takeaway capacity, unlocking the value of their sour oil and gas assets. Because VALKYRIE technology safely and effectively treats H₂S without flaring or injecting acid gas, it facilitates the achievement of voluntary emissions reduction initiatives and regulatory compliance.

The Liquid Redox (Reduction-Oxidation) process converts H₂S into elemental sulfur and water vapor byproducts using chemistry (Reduction) that can be regenerated and used again with exposure to air (Oxidation).

Using a Next Generation Liquid Redox process, sour gas is directed into a treating vessel containing specialized chemistry and then exits the system sweet (without H₂S) into a gas sales line. The elemental sulfur byproduct is filtered out of the liquid, and the chemistry is then regenerated with exposure to oxygen. The regenerated chemistry is then recirculated back into the treating vessel to perform the reaction again. The regenerative nature of the chemistry reduces media changes, disposal costs and reduces chemical handling requirements on the well site.

The VALKYRIE® H₂S treating solution from Streamline Innovations utilizes relatively recent technological advances in automation control to create the “Next Generation Redox” system. The VALKYRIE system utilizes TALON® chemistry, our non-toxic, biodegradable Redox chemistry.

VALKYRIE technology is a true green solution, by reducing the flaring of sour gas and related emissions at oil and gas production sites by converting H₂S into harmless byproducts, including elemental sulfur certified for use in food production.

The Streamline VALKYRIE H₂S removal system is the next generation of Liquid Redox (Reduction-Oxidation) to cost-efficiently help oil and gas operators unlock the value of sour gas resources and reduce emissions from oil and gas operations.

VALKYRIE Technology Applications

In addition to debottlenecking sour crude and natural gas production, VALKYRIE H₂S treating units for sour gas sweetening and reducing emissions from oil and gas operations are suitable for a variety of oil and gas applications, including:

Field gas conditioning for Gas Lift.
Tail Gas treating.

Benefits of the VALKRYIE gas treating system:

A green solution that converts H₂S into benign substances including water and elemental sulfur.

Universal application for biogas, landfill gas and oil and gas production.

Widest operating envelope of any H₂S gas treating method extending across the full spectrum of pressures, flow rates and H₂S concentrations.

Treating to established specifications for sales pipelines, gas lift and fuel gas.

Flexibility of placement along the production stream whether at the anaerobic digester, at a landfill, wellhead, refinery, in a direct or tail gas treating configuration.

Meets the most stringent outlet specifications.

In our 2023 Sustainability Scorecard, the VALKYRIE fleet helped operators avoid 39.7 million pounds of SO₂ emissions by eliminating flaring of sour gas, among other benefits.

Contact us today to learn how VALKYRIE H₂S treating technology can help you reduce emissions from your oil and gas production operations and debottleneck your operations.

About Streamline Innovations

We serve organizations in multiple sectors, including Energy/Oil & Gas, Biogas, Landfill Gas & Renewable Fuels, Municipal Wastewater and Industrial Air & Water.

Educational, Liquid Redox, Oil & Gas, Valkyrie

August 8, 2024Educational

VALKYRIE® H2S Treating for Reducing Emissions in Oil and Gas Production – Gas Lift Application

As oil and gas wells age, natural reservoir pressure diminishes resulting in a natural decline in production rates. Eventually, the well reaches its economic limit when lower production and net revenue no longer cover ongoing operating expenses. It is literally a race against time. Artificial lift methods, however, can extend the life of the well by boosting production and one of the most effective artificial lift techniques is gas lift.

Gas lift systems inject natural gas into the well casing to assist in lifting liquids to the surface through the production tubing. Operators use gas lift when reservoir pressure declines, water cuts increase and gas-to-oil ratios (GORs) change over time.

The primary barriers to using gas lift, however, include the availability of natural gas produced at the well site and/or if the produced gas is “sour” and contains high levels of hydrogen sulfide (H₂S). Sour gas presents serious threats to both human health and infrastructure, rendering it unsuitable for gas lift operations.

Fuel Gas Conditioning – Eliminating H2S and Reducing Emissions

In situations where sufficient gas is produced at the well site for gas lift, but it is sour gas, operators typically have resorted to purchasing sweet gas (not containing H₂S) from their midstream partner in a practice known as sweet gas buyback. The downside to this approach is that it tends to be expensive.

Operators with sour gas operations can avoid the expense of buying back sweet gas by treating H₂S on-site. This approach not only ensures a reliable source of gas for gas lift operations but can also lead to cost savings and environmental benefits.

In areas with sour takeaway constraints, on site field gas conditioning can also significantly mitigate or eliminate the flaring by sweetening sour gas and using it for gas lift and/or selling it to the pipeline. Avoiding the flaring of sour gas also reduces potentially harmful emissions, like sulfur dioxide (SO₂).

In fact, leading operators including Taprock Resources and Franklin Mountain Energy are using VALKYRIE technology to reduce emissions by sweetening sour gas on site and using it for gas lift operations.

VALKYRIE Next Generation Liquid Redox for Emissions Reduction

VALKYRIE Technology Applications

In addition to fuel gas conditioning for Gas Lift applications, VALKYRIE H₂S treating units for sour gas sweetening and reducing emissions from oil and gas operations are suitable for a variety of oil and gas applications, including:

De-bottlenecking sour gas takeaway constraints with onsite H₂S treating.

Tail Gas treating.

Benefits of the VALKRYIE gas treating system:

A green solution that converts H₂S into benign substances including water and elemental sulfur.

Universal application for biogas, landfill gas and oil and gas production.

Widest operating envelope of any H₂S gas treating method extending across the full spectrum of pressures, flow rates and H₂S concentrations.

Treating to established specifications for sales pipelines, gas lift and fuel gas.

Flexibility of placement along the production stream whether at the anaerobic digester, at a landfill, wellhead, refinery, in a direct or tail gas treating configuration.

Meets the most stringent outlet specifications.

In our 2023 Sustainability Scorecard, the VALKYRIE fleet helped operators avoid 39.7 million pounds of SO₂ emissions by eliminating flaring of sour gas, among other benefits.

Contact us today to learn how VALKYRIE H₂S treating technology can help you reduce emissions from your oil and gas production operations.

About Streamline Innovations

We serve organizations in multiple sectors, including Energy/Oil & Gas, Biogas, Landfill Gas & Renewable Fuels, Municipal Wastewater and Industrial Air & Water.

Educational, Liquid Redox, Oil & Gas, Valkyrie

July 25, 2024Biogas

VALKYRIE® H2S Treating for Reducing Emissions in Oil and Gas Production

Hydrogen sulfide (H2S) is produced from the decomposition of plant and animal matter, with around 90 percent of H2S emissions being naturally sourced. Hot springs and volcanoes also release substantial amounts of H2S. Natural gas containing significant levels of sulfur is termed “sour” and requires treatment before it can be distributed to residential, commercial, and industrial customers. Untreated H₂S is typically flared for safety reasons and to convert it into less dangerous pollutants, but the practice still generates emissions.

How Sour is Sour?

Natural gas produced from oil and gas wells is approximately 70-90 percent methane and contains up to 20 percent of heavier hydrocarbons, including ethane, butane, and propane. Gas produced from an oil or gas well typically contains other contaminants, too, including water vapor, sand, oxygen, carbon dioxide, nitrogen, and in many cases, hydrogen sulfide.

There is no one set definition of what constitutes “sour” gas, because concentration levels can vary widely from area to area. The Texas Railroad Commission, however, defines sour gas as having an H2S concentration of 100 ppm or more as noted in Statewide Rule 36, which provides provides sour gas operating requirements to safeguard worker and community safety (source: Statewide Rule 36).

How Does Sour Gas Cause Emissions?

Sour gas presents a threat to both human health and infrastructure. Sour gas production must be produced and transported using equipment specialized for “sour service,” treated and coated to withstand the corrosive effects of sour gas and is subject to stringent maintenance regimes. In some cases, very high levels of H2S contamination (10,000 ppm or greater) may require onsite gas treatment to reduce H2S to lower levels suitable for sour service handling. Otherwise, these assets cannot be produced.

Traditionally, sour gas has been flared or combusted to transform the contaminated gas into less harmful substances. However, flaring sour gas produces other pollutants such as sulfur dioxide (SO₂), which contributes to acid rain; volatile organic compounds (VOCs); and nitrogen oxides (NOx), which can react with particulates and sunlight to form ozone. Additionally, incomplete combustion may release raw H2S into the atmosphere.

Restrictions on flaring are increasingly stringent due to both regulatory mandates and voluntary industry efforts. For instance, the North Dakota Industrial Commission, which regulates the Oil and Gas industry in that state, requires operators to capture 90% of produced gas and reduce flaring. In New Mexico, the Oil Conservation Commission requires upstream and midstream operators to reduce routine natural gas flaring and venting by 98% by 2026.

The U.S. Environmental Protection Agency has also recently revised its emissions regulations in NSPS OOOOb and EG OOOOc, aiming to phase out all non-emergency flaring in the future.

Many operators have committed to voluntary emissions reduction programs. The Oil and Gas Methane Partnership 2.0 (OGMP 2.0) has emerged as an influential industry group who members include many large operators with producing assets in the United States and worldwide. OGMP 2.0 has developed a framework for estimating and reporting emissions from oil and gas operations, including emissions from tank venting, purging, and flaring.

Gas Sweetening

The process of treating sour natural gas to remove H2S so it can be sold instead of flared, generating emissions, is called “sweetening.”

Create negative downstream processing effects.
Require the use of chemicals that can be expensive and present a safety risk.
Require the disposal of contaminated media, creating environmental and safety risks.
Operational complexity, requiring frequent oversight on location and problem solving.

Valkyries Reduce Oil & Gas Emissions Using Next Generation Liquid Redox for H2S Treating

The VALKYRIE® H₂S treating solution from Streamline Innovations utilizes relatively recent technological advances in automation control to create the “Next Generation Liquid Redox” system. The VALKYRIE system utilizes TALON® chemistry, our non-toxic, biodegradable Redox chemistry.

VALKYRIE technology is a true green solution, by reducing the flaring of sour gas and related emissions at oil and gas production sites by converting H₂S into harmless byproducts, including elemental sulfur certified for use in food production.

VALKYRIE Technology Applications

VALKYRIE H₂S treating units for sour gas sweetening and reducing emissions from oil and gas operations are suitable for a variety of oil and gas applications, including:

De-bottlenecking sour gas takeaway constraints with onsite H₂S treating.
Fuel gas conditioning for Gas Lift to minimize sweet gas buyback.
Tail Gas treating.

VALKYRIE gas treating units have been operating reliably for oil and gas producers in the Permian Basin and elsewhere, including Chevron Corporation, Franklin Mountain Energy, and Taprock Energy, among others.

Benefits of the VALKRYIE gas treating system:

A green solution that converts H₂S into benign substances including water and elemental sulfur.
Universal application for biogas, landfill gas and oil and gas production.
Widest operating envelope of any H₂S gas treating method extending across the full spectrum of pressures, flow rates and H₂S concentrations.
Treating to established specifications for sales pipelines, gas lift and fuel gas.
Flexibility of placement along the production stream whether at the anaerobic digester, at a landfill, wellhead, refinery, in a direct or tail gas treating configuration.
Meets the most stringent outlet specifications.

In our 2023 Sustainability Scorecard, the VALKYRIE fleet helped operators avoid 39.7 million pounds of SO₂ emissions, among other benefits.

Contact us today to learn how VALKYRIE H₂S treating technology can help you reduce emissions from your oil and gas production operations.

About Streamline Innovations

We serve organizations in multiple sectors, including Energy/Oil & Gas, Biogas, Landfill Gas & Renewable Fuels, Municipal Wastewater and Industrial Air & Water.

Biogas, Chemicals & Refining, Educational, Liquid Redox, Permian Basin, Valkyrie

June 27, 2024Biogas

Dairy Digesters to RNG: Converting H2S Into OMRI Certified Organic Sulfur

H2S Treatment Technology That Keeps Your Dairy Digester to RNG Operation Green

Agricultural biogas streams are important feedstocks for upgrading to Renewable Natural Gas (RNG). Before biogas from a dairy digester or similar facility can be sold to a commercial pipeline as RNG, it must be treated for hydrogen sulfide (H2S) contamination. For a dairy digester biogas-to-RNG project to live up to its green value proposition, however, project designers have to consider not just the efficient aggregation of manure and capturing methane from the digester, but also the byproducts of the upgrading process itself.

Green H2S Treating Methods

There are several methods for treating H₂S in dairy digester biogas-to-RNG applications, but only two are truly “green” from the standpoint of not creating negative byproducts: Biologic solutions and Next Generation Liquid Redox.

Biologic H2S Treating Systems

Biological processes are green because they utilize natural microorganisms to convert H₂S into non-harmful compounds. However, this strength is also the primary weakness of biologic treating solutions. Living organisms are not as predictable or consistent as known chemical processes.

Downsides of biologic H₂S treating options:

Because the bacteria colony in a biologic treater acclimates to the amount of H₂S it consumes, biologics are highly sensitive to variations in gas flow rates, temperatures, and H₂S concentrations, making the entire system more prone to unplanned downtime and lengthy restarts.
Usually require a complex and costly installation.
Typically require long initial start-up times to allow a critical mass of microorganisms to grow.
Often require additional equipment to maintain a steady state, increasing the cost of these systems and adding operational complexity.

Next Generation Liquid Redox (VALKYRIE®)

The next generation of liquid redox solutions, such as VALKYRIE Biogas-to-RNG technology, provide operators of dairy digester plants with a H₂S purification solution that is not only green, but operationally robust. Like biological H₂S treating options, VALKYRIE technology is a green solution, but unlike biologics delivers high reliability and fast startups.

Upsides to VALKYRIE technology:

Reacts quickly to changes in gas flow, temperatures, and H₂S concentrations for high reliability, process stability, and uptime.
Simple, cost effective “plug and play” installation
One-button, fast startup.

Additionally, VALKYRIE technology extracts elemental sulfur from the gas stream that can be sold as Simple Elemental Sulfur™ for use in organic food production, advancing the circular economy concept.

LEARN MORE: VALKYRIE® Biogas-to-RNG Upgrading Technology

In summary, Streamline Innovation’s VALKYRIE H₂S treating technology offers dairy digester biogas-to-RNG operators the most reliable, green option for removing H₂S from gas streams in the biogas-to-RNG upgrading process.

Contact us today to learn more about how VALKYRIE ECO and ECO FLEX solutions can help you achieve your agricultural biogas-to-RNG upgrading needs.

About Streamline Innovations

We serve organizations in multiple sectors, including Energy/Oil & Gas, Biogas, Landfill Gas & Renewable Fuels, Municipal Wastewater and Industrial Air & Water.

Biogas, Elemental Sulfur, Projects & Missions, RNG, Valkyrie

Common Hydrogen Sulfide Challenges and Their Consequences

Why Legacy Hydrogen Sulfide Treatment Methods Fall Short

Regenerative Liquid Redox: A Purpose-Built Solution for Unlocking the Value of Sour Gas Assets

How Liquid Redox Works

The Byproduct Advantage of Liquid Redox

Valkyrie Operating Envelope

VALKYRIE® Hydrogen Sulfide Treatment Applications in Oil & Gas

Real-World Results: Unlocking Sour Gas Value in the Permian Basin

Is On-Site Hydrogen Sulfide Treating Right for Your Operation?

What Is a Triazine H2S Scavenger?

How the Triazine Reaction Works

Dithiazine: The Disposal Problem

Chemical Handling and Safety of Triazine

Triazine: Pros and Cons Summary

What is Next-Generation Liquid Redox for Hydrogen Sulfide Treatment?

How the Liquid Redox Process Works

Simple Elemental Sulfur™: A Byproduct with Value

VALKYRIE Operating Range and Applications

Next Generation Liquid Redox: Pros and Cons Summary

Triazine vs. Liquid Redox: Side-by-Side Comparison

Which Hydrogen Sulfide Treatment Method Is Right for Your Operation?

About Streamline Innovations’ VALKYRIE® Hydrogen Sulfide Treatment System

Removing Sour Gas Takeaway Constraints

Bigger Capacity for Sour Gas Treating. Smarter Investment

The Lowest-Cost Path to Sweet Gas

Removing Bottlenecks, Unlocking Production

A True Sustainable and Safe Technology

A True Turnkey Solution

Smarter. Cleaner. More Profitable.

More Options for Maximizing Operational Efficiency

Successful Initial Deployments

Benefits of VALKYRIE Gas Treating Technology

Contact

About Streamline Innovations

About Streamline Innovations

About Streamline Innovations

The Constraint of Sour Takeaway

Debottlenecking – Removing Sour Gas Takeaway Constraints

VALKYRIE® H2S Technology for Debottlenecking Sour Gas Production

VALKYRIE Technology Applications

About Streamline Innovations

Fuel Gas Conditioning – Eliminating H2S and Reducing Emissions

VALKYRIE Next Generation Liquid Redox for Emissions Reduction

VALKYRIE Technology Applications

About Streamline Innovations

How Sour is Sour?

How Does Sour Gas Cause Emissions?

Gas Sweetening

Valkyries Reduce Oil & Gas Emissions Using Next Generation Liquid Redox for H2S Treating

About Streamline Innovations

H2S Treatment Technology That Keeps Your Dairy Digester to RNG Operation Green

Green H2S Treating Methods

Biologic H2S Treating Systems

Next Generation Liquid Redox (VALKYRIE®)

About Streamline Innovations

VALKYRIE® H₂S Technology for Debottlenecking Sour Gas Production