Unlike like some hydrogen sulfide treatment processes that create pollution or toxic wastes, the Streamline VALKYRIE™ solution destroys H2S, creating water vapor and elemental sulfur.
Streamline’s Simple Elemental Sulfur™ is now Listed with the Organic Material Review Institute (OMRI), which lists substances that can be used for Organic Production.
David Sisk, CEO and Co-Founder, said, “We are proud that Streamline Simple Elemental Sulfur is included on the OMRI Products List. This strengthens our promise to eliminate pollution with our environmentally forward technology, and helps facilitate progress towards to a circular economy.”
This powdered, amorphous form of sulfur can be beneficial as a soil amendment, increasing the pH of soil and improving the uptake of nitrogen. Using sulfur as a soil amendment is natural and consistent with organic cultivation practices as defined by the US Department of Agriculture’s National Organic Program regulations.
Simple Elemental Sulfur is now approved by OMRI for Organic Production(Photo Copyright Streamline Innovations 2021)
More information is available on the OMRI website at OMRI.ORG.
About Streamline Innovations
Streamline is realizing our vision of A Green Future by Eliminating Emissions Through Technology. We have developed and deployed a suite of environmentally forward technologies and chemistries that are revolutionary in their efficiency and effectiveness at treating the toughest problems related to H2S, CO2 and associated contaminants.
Our technology can be applied across industries, delivering sustainable solutions that eliminate the base contaminate, that if left untreated result in emissions causing acid rain, greenhouse gases, and dangerous work and living environments.
If you’re evaluating H2S treatment options for a multi-well pad or a growing Permian asset, you already know the pain points: rising chemical costs, scavenger units scattered across every location, and the recurring expense of buying back sweet gas to run your own gas lift compressors. You’re not alone. Across the Permian Basin, operators are re-evaluating how, and where, they treat sour gas, and a growing number are moving away from decentralized, site-by-site treating toward centralized H2S removal facilities serving multiple well sites or pads.
The shift is driven by two converging trends: as Permian zones mature, H2S concentrations tend to rise, squeezing margins; and development is pushing outside core Tier 1 acreage into assets that are inherently sour. Both trends mean that sour gas production from the Permian Basin is increasing, and traditional H2S removal strategies are driving lease operating expenses higher every year. If you’re actively sourcing a H2S treatment solution, here’s what you need to know before your next capital decision.
What are The Hidden Costs of Decentralized H2S Removal?
Most operators start with decentralized treating almost by default: installing a scavenger unit or media bed at each wellhead or pad, sized to that location’s volume and H2S concentration. It’s simple to deploy and doesn’t require gathering infrastructure changes. But as your well count grows, the cumulative cost of that “simple” approach compounds fast:
Redundant capital. Every site needs its own vessel, skid, and footprint – potentially even sites that don’t produce enough sour gas to justify a full-sized unit on their own.
Inefficient chemical consumption. Scavenger chemistry (triazine, iron sponge, etc.) has a unit cost (per Mcf or pound of H2S removed) that gets worse at small scale. Trucking chemicals to five locations instead of one adds logistics cost and emissions on top of the chemical spend itself.
Labor and safety overhead multiplied. Every additional treating point means another location requiring H2S-qualified personnel, monitoring equipment, calibration schedules, and safety protocols.
Disposal inefficiency. Spent media and one-time use chemicals generated at scattered sites are harder and more expensive to aggregate for trucking and disposal than volume consolidated at a single hub.
Individually, these costs might look manageable. Add them up across a multi-pad development, and decentralized treating starts looking like the more expensive option – not the simpler one.
What are the Benefits of a Centralized H2S Treatment Model?
Centralizing H2S removal means routing sour gas from multiple wells or pads to one larger treatment facility (or a small number of regional hubs) instead of installing standalone units at every well site or pad. The economics shift in your favor in several concrete ways:
Lower cost per unit of treating capacity. A single larger treatment unit costs less per Mscf of design capacity than several small units combined – the same economies of scale you’d expect from any process equipment or commingled tank battery.
Chemical and consumable savings at scale. Consolidating sour gas production can make regenerative H2S removal systems economically viable in scenarios where they would never meet the internal IRR hurdle rate for a single wellhead. Regenerative systems typically carry a much lower per-unit treating cost than one-time use scavenger media once you have the volume to support them.
Simplified operations. One monitoring point. One inspection and maintenance schedule. One location where your H2S-trained personnel need to be, instead of five. Spares inventory and turnaround planning get dramatically simpler when you’re managing one or two systems instead of a dozen.
Fewer failure points, less downtime exposure. Fewer discrete treating units in the field means fewer things that can go wrong – and centralized systems are typically easier to keep instrumented, monitored, and maintained to a high standard.
The Overlooked Line Item: Sweet Gas Buyback
Here’s the piece that often gets missed in a straight capex comparison, and it’s frequently the difference-maker in the total cost picture.
Sour gas produced on site from the wellhead in a decentralized model usually can’t be used to run field equipment. H2S is corrosive to compressors, engines, and pneumatic instrumentation, and it creates a direct personnel safety hazard anywhere it’s combusted or vented on location. So gas lift compression, instrument gas systems, and other on-site equipment often run on purchased sweet gas bought back from the midstream gatherer – even though the well is simultaneously producing raw gas a few hundred feet away.
That’s a double cost: you’re selling your own production at a sour-gas discount (net of the H2S treatment processing fee) and then buying sweet gas at a higher price to power your own operation.
Centralized H2S removal can eliminate sweet gas buyback. When sour gas is treated at a central facility, the sweetened gas stream can be routed directly to gas lift compression and other equipme
no external purchase required. For operators running gas lift across multiple wells, eliminating that recurring buyback expense functions like a direct, ongoing fuel-cost offset stacked on top of the capital, chemical, and labor savings already discussed. It’s often the factor that pushes a centralized system’s ROI timeline from “marginal” to “obvious.”
Where Centralized H2S Removal Makes the Most Sense
Centralized treatment isn’t the right strategy for every asset – the model shift is driven by specific conditions that are increasingly common across the Permian:
Well density/contiguous acreage. Multiple wells or pads within a tight enough geographic footprint that gathering line capex doesn’t exceed the treatment savings.
Rising H2S concentrations. Many maturing Permian zones are seeing higher sour gas loading over time, making per-site scavenger costs climb. In contrast, centralized systems get more attractive at scale, potentially extending the economic life of legacy assets.
Active gas lift operations. If you’re already buying back sweet gas to run lift compression, centralized treating turns that expense into a savings line instead.
Growth trajectory. Operators planning to add wells or pads to an area benefit from sizing a central facility for future volume rather than repeating the standalone-unit cycle with every new location.
What to Weigh Before You Commit to a Centralized H2S Removal Strategy
A responsible evaluation should also account for the trade-offs:
Gathering infrastructure. Centralizing requires piping sour gas from multiple sites to a hub, which means added gathering capex and possibly compression to manage pressure losses.
Corrosion exposure in gathering lines. Untreated sour gas traveling further before treatment increases corrosion exposure, which may call for upgraded metallurgy or corrosion inhibition.
Consolidated risk. A central unit going down affects every connected site at once, so redundancy and reliability need to be factored in from the start.
VALKYRIE® H2S Removal – The Regenerative H2S Treatment Solution for Centralized Facilities
For operators considering a centralized H2S removal strategy, next-generation liquid redox technology offers a compelling alternative to one-time, throwaway scavengers.
Valkyrie Next-Generation Liquid Redox
Valkyrie has emerged as a proven, field-tested H2S removal solution built specifically for the demands of sour gas treating:
50+ Valkyrie units deployed across producing operations
9% uptime track record in the field
<1.0 ppm H2S outlet achieved, well below typical pipeline spec
5 LT/day H2S treating capacity per unit
60 MMCFD max gas throughput
Benefits of Valkyrie H2S Treatment
Regenerative chemical process — the treating chemistry is continuously regenerated on-site, eliminating the cleanouts and disposal cycles associated with scavenger-based systems, and keeping operating costs low because the chemistry is used, regenerated, and used again
Sidestep sour takeaway constraints — produce and sell gas without waiting on sour gathering or centralized treating capacity
Eliminate routine flaring of sour gas — treat gas to spec rather than flaring it while waiting on infrastructure
Minimize or eliminate sweet gas buyback for gas lift — treated gas can be used on-site, reducing dependence on purchased sweet gas
9% reliability for continuous production — minimizes the downtime risk inherent to shared, third-party treating capacity
Turnkey solution — designed for minimal impact on daily field operations and existing workflows
Features and Capabilities
Widest operating envelope of any H2S treating method — performs across the full range of pressures, flows, and H2S concentrations operators encounter in the field
TALON® chemistry is non-toxic, biodegradable, and continuously regenerated, avoiding the hazardous waste streams associated with traditional treating chemicals
OMRI-certified elemental sulfur byproduct, suitable for use in organic food production — turning a waste stream into a marketable output
VALKYRIE INTELLIGENCE PLATFORM® (VIP) delivers advanced automation, real-time monitoring, and remote control, giving operators visibility and command over treating performance from anywhere
The math is simple: once an area of operation has enough sour gas production volume and well density, the savings on chemicals, capital, labor, and sweet gas buyback outweigh the cost of a centralized H2S removal facility and the associated gathering infrastructure – often by a wide margin. Meeting that threshold keeps getting easier to hit across the Permian, as pad density rises and H2S loading increases across maturing acreage.
If you’re currently running decentralized treating across multiple wells or pads – particularly if you’re also buying back sweet gas for lift operations – it’s worth running the numbers on a centralized alternative for your specific volumes, H2S concentrations, and well spacing. The economic analysis increasingly leans in favor of centralization, and the operators making the switch now are locking in the operating cost advantage before the rest of the basin catches up.
Ready to evaluate what centralized H2S treatment could save on your acreage? Contact a Streamline Innovations engineer who can model your specific well volumes, H2S loading, and gas lift fuel requirements against a centralized system design.
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.
Much of the water production in the Midland and Delaware Basin regions is coming from sour assets and contains high concentrations of hydrogen sulfide (H₂S), one of the oil and gas industry’s most persistent operational headaches.
Hydrogen sulfide is corrosive, malodorous, and acutely toxic, dissolved H₂S in produced water creates real risks for personnel, infrastructure, and the environment. Treating it has historically meant accepting a set of uncomfortable tradeoffs – hazardous chemicals, disposable reagents, hazardous byproducts, and mounting costs. But that tradeoff is no longer necessary.
Streamline Innovations’ ThunderOx™ Sulfide Elimination System is changing how operators think about H₂S treatment — delivering a green solution that is safer for people, easier on the environment, and more cost-effective than conventional approaches.
The Problem with Traditional H₂S Treatment
Produced water containing high concentrations of dissolved H₂S must be reduced before transfer, reuse, or disposal. Conventional treatment typically relies on one-time-use chemical scavengers — broad-spectrum oxidizers applied in high volumes to push sulfide levels below acceptable limits.
The problems with this approach are both operational and environmental:
Hazardous chemical exposure. Personnel handling traditional scavengers face meaningful risks from the chemicals themselves, which can be corrosive or toxic.
Hazardous byproducts. Many conventional treatments generate byproducts that require disposal at specialized facilities, adding logistics complexity and cost.
High chemical consumption. Because oxidizers are broadly reactive rather than selectively targeting H₂S, they are consumed quickly and must be replenished continuously — at significant cost, especially when high-H₂S concentrations are high.
Slow reaction kinetics. Some scavengers require extended contact time to achieve meaningful sulfide reduction, which is impractical in fast-moving produced water systems where water may reach transfer points within minutes of treatment.
In short, traditional methods were built around what was available, not what was ideal.
ThunderOx: A Fundamentally Different Approach to Produced Water Treatment
ThunderOx treatment takes a different path entirely, using a selective liquid redox reaction that targets H₂S specifically rather than broadly oxidizing everything in the water.
The mechanism is elegantly simple: ThunderOx catalyst, combined with hydrogen peroxide as the oxidant source, reacts selectively with dissolved sulfide species, converting H₂S directly into elemental sulfur. That’s where the green story begins.
A Truly Non-Hazardous Byproduct. Unlike the byproducts of many conventional treatments, elemental sulfur is:
Non-toxic and non-hazardous under standard regulatory classifications
Easily handled without specialized personal protective equipment
Transportable without hazmat requirements
Disposable through conventional channels, no specialized disposal facility required
This means that from start to finish, ThunderOx treatment doesn’t introduce new hazards into the operation. Workers aren’t exposed to dangerous reagents. There’s no secondary waste stream requiring special handling. The environmental risk is significantly less than conventional alternatives.
Regenerative Chemistry Means Less Chemical, Not More. Because ThunderOx is a regenerative system, the catalyst is not consumed in the treatment reaction. It acts as a facilitator — enabling the oxidation reaction — and remains active, reducing the amount of chemical required to treat a given volume of water compared to traditional single-use scavengers.
This selectivity has a powerful practical consequence: operators don’t have to overdose to achieve results. The chemistry goes exactly where it’s needed — to treating H₂S — and not into unnecessary side reactions that consume reagent without benefit.
Rapid Reaction Kinetics. In field testing at a central tank battery in Lea County, New Mexico, ThunderOx reduced dissolved H₂S concentrations from nearly 200 ppm to below 1 ppm within five minutes of mixing — well within the time constraints of typical produced water handling systems. At full scale, treating approximately 6,500 barrels per day, the system consistently delivered custody transfer quality water with dissolved H₂S below 1 ppm, starting from an average untreated concentration of approximately 122 ppm.
That kind of rapid, reliable performance is what operators need when water is moving fast and custody transfer limits are non-negotiable.
Sustainability in oil and gas operations is no longer a secondary consideration. Regulatory expectations are tightening and environmental performance commitments are shaping capital decisions, and the practical costs of managing hazardous waste streams are real and growing.
ThunderOx addresses all these issues simultaneously:
No hazardous byproducts means no hazardous disposal costs, no waste manifests, and no regulatory complexity around secondary waste streams.
Reduced chemical volume means fewer truck deliveries, smaller storage requirements, and a smaller logistics footprint overall.
Non-hazardous reagents mean lower safety risk for field personnel and reduced liability exposure for operators.
Selective chemistry means less total chemical entering the water and the environment.
It’s worth noting that Streamline Innovations has earned recognition for this approach. TIME Magazine ranked Streamline 6th among 250 companies on its inaugural list of America’s Top GreenTech Companies 2024 — a recognition of the company’s broader commitment to eliminating H₂S emissions through technology that is genuinely environmentally responsible.
Cost-per-Barrel Economics Reinforce the Environmental Case
Green solutions sometimes carry a price premium. ThunderOx does not. In the Lea County case study, ThunderOx delivered more than $1 million per month in chemical savings compared to the conventional scavenger program it replaced — while meeting or exceeding treatment performance targets.
The economic advantage comes from the same source as the environmental advantage: selective, regenerative chemistry that does more with less. When evaluating treatment programs, engineers are often advised to look beyond the cost per gallon of chemical and focus instead on the cost per barrel treated — a metric that captures how efficiently the chemistry is working. On that measure, ThunderOx consistently outperforms conventional alternatives in high-H₂S environments.
If you’re evaluating H₂S treatment strategies for high volumes of produced water having elevated sulfide levels, don’t rely on theory, review the field data.
Download the full ThunderOx case study to see:
Detailed before-and-after water quality data
Chemical loading ratios and dosing methodology
Optional SCADA automation configuration
Economic analysis of treatment cost reductions
Operational results at 6,500 BBL/day in a high-sulfide gathering system
ThunderOx is Field-Proven, Scalable, and Operationally Simple
ThunderOx is designed for real oilfield conditions:
Low to no capex — the system can be deployed into existing infrastructure without major capital investment
Automated dosing — ThunderOx dosing equipment adjusts in real time based on flow rate, preventing over- or under-treatment
Scalable — the system has been deployed across a range of volumes and H₂S concentrations, from moderate to extreme
Broad applicability — while produced water is a key application, ThunderOx is also effective for municipal and industrial wastewater, sour groundwater, and storage pits
Streamline’s team provides on-site technical support through field demand studies, baseline characterization (pH, ORP, sulfide loading), and ongoing operational integration — becoming an extension of your staff.
The Bottom Line
Operators have long accepted that treating H₂S is a necessary recurring cost and risk. ThunderOx challenges both assumptions. By leveraging selective next-generation redox chemistry, it eliminates dissolved sulfides rapidly and completely, generates only non-hazardous elemental sulfur as a byproduct, and does so at a fraction of the chemical cost of conventional approaches.
For operators facing stringent water midstream pipeline specifications, growing sustainability expectations, and the practical pressures of managing sour produced water at scale, ThunderOx represents something rare: a solution that is simultaneously better for the environment, safer for personnel, and more economical to operate.
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.
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
As operators move development programs outside the defined fairways of unconventional plays in the Permian Basin, the produced water from new oil and gas wells is increasingly characterized by high hydrogen sulfide (H₂S) concentrations. For SWD facility and midstream water operators, this creates a persistent challenge: how to consistently meet disposal and custody transfer specifications without driving up chemical costs, operational risk, or downtime.
In one Lea County, New Mexico operation, produced water contained approximately 200 ppm dissolved H₂S, with headspace concentrations exceeding 20,000 ppm, well into the hazardous exposure range. At these levels, the operator was spending approximately $1 million per month on chemical scavengers and still failing to consistently meet midstream limits of <10 ppm dissolved H₂S, exposing the system to surcharges and potential shut-in events.
The root issue is not just H₂S concentration; it’s inefficiency of the treatment method.
Conventional non-selective oxidizers and scavengers often react with a wide range of water constituents, meaning more chemistry is required just to maintain partial control of sulfides. Meaning, you’re just throwing more product at the problem and driving up costs as a result. Eventually, that inefficiency becomes economically unsustainable.
At full scale and treating approximately 5,500 BBL/day, the average dissolved H₂S concentration dropped from ~122 ppm untreated, with consistent custody transfer levels of <1 ppm.
Why Chemistry Matters in H₂S Treatment
ThunderOx works through a selective liquid redox reaction that targets H₂S. This reduces chemical demand while improving treatment efficiency. The system is also regenerative, using hydrogen peroxide as the oxidant source and converting H₂S into stable, non-hazardous elemental sulfur.
For the operator, the practical impact is significant:
Elimination of midstream H₂S surcharges
Decreased HSE concerns from H2S exposure
Rapid <5-minute reaction time with real-time dosing control
Reduced manpower to approximately one operator hour per day via SCADA-enabled automation
No major infrastructure modifications required
Transforming Produced Water Treatment
Produced water management is becoming one of the defining operational challenges of modern oil and gas production. As operators encounter increasingly sour resources, sulfide treatment solutions must deliver three critical capabilities:
ThunderOx demonstrates how combining selective chemistry with rapid kinetics can meet all three.
For produced water systems where speed, safety, and cost control are essential, rapid sulfide elimination is not just beneficial, it is operationally necessary.
If you’re evaluating sulfide treatment strategies for high-H₂S produced water, don’t rely on theory, review the field data.
The case study reveals:
Detailed before-and-after water quality data
Chemical loading ratios and dosing methodology
Optional SCADA automation configuration
Economic analysis of treatment cost reductions
Operational results at 5,500 BBL/day in a high-sulfide SWD system
See how ThunderOx reduced dissolved H₂S from nearly 200 ppm to below 1 ppm in minutes, transforming both the safety and economics of produced water treatment.
When Encountering High Concentrations of H₂S: Speed Matters
Unlocking the value of sour oil & gas assets is increasingly facing the challenge of treating produced water containing high levels of hydrogen sulfide (H₂S). In regions like the Delaware Basin region of the Permian Basin as well as South Texas, dissolved sulfide concentrations approaching or exceeding 200 ppm are becoming more common. These levels create serious safety hazards, corrosion risks, and operational bottlenecks at saltwater disposal (SWD) facilities and midstream transfer points.
While many treatment programs focus on chemistry itself, speed of treatment is often just as critical as chemical effectiveness. Produced water systems move continuously, and treatment solutions must react quickly enough to prevent H₂S from reaching downstream infrastructure or custody transfer points.
Field results from Streamline Innovations’ ThunderOx™ Sulfide Elimination System demonstrate that rapid reaction kinetics can fundamentally change the economics and operational reliability of produced water treatment.
Reaction Speed Is Critical in Produced Water Treatment
Produced water treatment systems typically operate in fast-moving environments. Water leaving tank batteries or central facilities may reach midstream transfer points within minutes. If chemical treatment cannot neutralize sulfides quickly enough, operators face several risks:
Custody transfer non-compliance if dissolved H₂S exceeds contractual limits (often <10 ppm).
Vapor-phase H₂S hazards, with storage tank headspace concentrations reaching lethal levels.
Corrosion damage to pipelines, tanks, and transfer infrastructure.
Operational delays or shut-ins while treatment levels are adjusted.
Traditional sulfide scavengers frequently require longer reaction times or higher chemical loading to achieve meaningful reductions in sulfide levels. This can lead to overtreatment, inconsistent results, and excessively high operating costs.
For high-volume produced water systems, slow treatment is simply not operationally viable.
Rapid Sulfide Elimination with ThunderOx
The ThunderOx H₂S Removal System from Streamline Innovations approaches sulfide treatment differently. Instead of relying on broad-spectrum oxidizers or high-dose scavengers, ThunderOx uses a selective liquid redox reaction that specifically targets sulfide species while in solution.
This selectivity allows the chemistry to react extremely quickly with dissolved H₂S.
Field testing demonstrated that ThunderOx can reduce sulfide concentrations within five minutes of mixing.
ThunderOx Field Test Results
During initial testing During initial testing at a SWD facility in Lea County, New Mexico:
Untreated Produced Water
Sample Point
pH
ORP
Dissolved H₂S
Tank 1 Bottom
5.7
-316
187 ppm
Tank 2 Bottom
5.4
-277
196 ppm
After 5 Minutes of ThunderOx Treatment
Sample Point
pH
Dissolved H₂S
Tank 1 Bottom
6.3
0.55 ppm
Tank 2 Bottom
6.5
0.26 ppm
Within minutes, sulfide concentrations dropped from nearly 200 ppm to well below 1 ppm.
This rapid reaction allows operators to treat water directly within existing tank systems or transfer infrastructure without requiring long residence times or complex treatment trains.
Real-Time Performance in Active Operations
After implementation, the ThunderOx system was deployed to treat produced water at an SWD facility handling approximately 5,500 barrels per day.
Operational results included:
Untreated H₂S (average): 122 ppm
Treated H₂S (average): 1.7 ppm
Custody transfer concentration: consistently below 1 ppm
Because treatment occurs rapidly, the system can eliminate sulfides before the water reaches downstream pipelines or transfer points, ensuring continuous compliance with midstream specifications.
For operators, this means reliable treatment without the need for excessive chemical dosing or extended holding times.
Rapid Treatment Enables Automation
The fast reaction time of ThunderOx also allows treatment to be integrated into automated facility operations.
At the Lea County site, the system was installed using:
Peristaltic chemical injection pumps
Chemical storage tanks
SCADA-based monitoring and control
The SCADA system provides:
Bi-directional pump control
Remote tank level monitoring
Real-time dosing adjustments
Because ThunderOx chemistry works quickly and predictably, dosing can be optimized automatically. A Streamline field operator now spends approximately one hour per day on site performing sampling and inspection.
This level of automation significantly reduces manpower requirements while maintaining consistent treatment performance.
Faster H2S Treatment for Produced Water = Lower Operating Costs
Rapid sulfide elimination does more than improve safety and compliance, it also lowers total treatment costs.
After deployment at the Lea County site, ThunderOx delivered:
The speed of the reaction plays a major role in this economic improvement. Because ThunderOx reacts quickly and selectively, less product is required to treat each barrel of water, reducing overall consumption.
Safety Benefits of Rapid Sulfide Removal
Another critical advantage of fast sulfide elimination is improved worker safety.
Before treatment, headspace measurements at the facility exceeded 20,000 ppm H₂S, a concentration that can be immediately lethal.
By rapidly converting dissolved sulfides into elemental sulfur, ThunderOx reduces the formation of vapor-phase H₂S in tanks and equipment.
This significantly lowers:
Worker exposure risk
Odor emissions
Corrosion caused by sulfide gas
The result is a safer operating environment with fewer HSE hazards.
Transforming Produced Water Treatment for Sour Resources
Produced water management is becoming one of the defining operational challenges of modern oil and gas production. As operators encounter increasingly sour resources, sulfide treatment solutions must deliver three critical capabilities:
Rapid reaction time
Reliable sulfide elimination
Cost-effective chemical usage
ThunderOx demonstrates how combining selective chemistry with rapid kinetics can meet all three.
For produced water systems where speed, safety, and cost control are essential, rapid sulfide elimination is not just beneficial, it is operationally necessary.
If you’re evaluating sulfide treatment strategies for high-H₂S produced water, don’t rely on theory, review the field data.
Download the full ThunderOx™ case study to see:
Detailed before-and-after water quality data
Chemical loading ratios and dosing methodology
SCADA automation configuration
Economic analysis of treatment cost reductions
Operational results at 5,500 BBL/day in a high-sulfide SWD system
See how ThunderOx reduced dissolved H₂S from nearly 200 ppm to below 1 ppm in minutes, transforming both the safety and economics of produced water treatment.
In our recently released case study, we examined how Streamline’s ThunderOx™ sulfide elimination system dramatically reduced treatment costs at a high-H₂S produced water facility in Lea County, New Mexico—delivering more than $1 million per month in chemical savings while consistently reducing dissolved sulfides to below custody transfer limits.
In this blog post, we take a deeper look at the economics behind that result, exploring why conventional sulfide treatment programs often become prohibitively expensive and how selective redox chemistry can significantly lower the cost per barrel of produced water treated while improving reliability and safety.
As operators push their asset development into areas prone to sour oil and gas resources in the Permian Basin, South Texas and elsewhere, they and the water midstream companies serving them, are faced with a growing challenge – produced water contaminated with elevated hydrogen sulfide (H₂S) and dissolved sulfides. In many areas, concentrations exceed 200 ppm, levels that create safety risks, corrosion, and costly non-compliance at saltwater disposal (SWD) and midstream transfer points.
For SWD facility engineers, the central question is: what is the most cost-effective way to consistently reduce dissolved H₂S to below 10 ppm?
The High Cost of “Conventional” Chemistry for H2S Removal
Traditional chemical treatment programs, often hemiformal based, are frequently applied in high volumes to combat elevated sulfide loads. In one Lea County, New Mexico case, an operator treating approximately 5,500 barrels per day of produced water containing ~200 ppm H₂S was spending approximately $1MM per month on chemical treatment alone.
Despite that high operating expense, the operator still struggled to:
Maintain dissolved H₂S below 10 ppm
Avoid midstream custody transfer surcharges
Prevent corrosion and vapor-phase H₂S exposure (>20,000 ppm headspace measured)
The result was escalating operating expense with inconsistent performance and an unsustainable scenario.
Selective Chemistry for H2S Removal = Lower Chemical Demand
Streamline’s ThunderOx™ sulfide elimination system changes the cost equation by selectively targeting sulfides via a liquid redox reaction rather than applying broad-spectrum oxidizers or non-selective scavengers.
Field performance data demonstrated:
Untreated H₂S (avg): 122–200 ppm
Treated H₂S (avg): 1.7 ppm
Custody transfer point: consistently <1 ppm
Reaction time: <5 minutes
Because ThunderOx selectively reacts with dissolved sulfide species, the required chemical loading is significantly lower than conventional scavengers. Less chemistry per barrel directly translates into lower cost per barrel treated.
Quantifiable Economic Impact of Streamline’s ThunderOx™ Sulfide Elimination System
Automation through SCADA-enabled dosing and remote tank monitoring further reduced labor costs and minimized overtreatment. For SWD facilities operating on thin margins, reducing both chemical costs and operator hours significantly reduces the total cost of ownership.
Beyond Chemistry Costs
The cost effectiveness of ThunderOx extends beyond reagent pricing:
Eliminates midstream surcharges and shut-in risk
Reduces corrosion-related maintenance and capital replacement
Improves HSE by eliminating lethal headspace H₂S levels
Converts H₂S to elemental sulfur with no special disposal requirements
We recommend when evaluating sulfide treatment programs, engineers should look beyond cost per gallon of chemical and focus on cost per barrel treated. In high-H₂S produced water systems, ThunderOx has demonstrated that selective chemistry, rapid kinetics, and automation can eliminate sulfide contamination at a fraction of traditional scavenger costs, while improving safety and operational reliability.
A leading oil and gas producer with operations in Lea County, New Mexico, faced a serious challenge – treating produced water with ~200 ppm hydrogen sulfide (H2S). High H2S levels posed significant safety risks, caused costly chemical treatments, and threatened midstream compliance, putting both operations and revenue at risk.
The solution? Streamline’s ThunderOx Sulfide Elimination System, a highly selective, regenerative technology that targets dissolved H2S efficiently without forming harmful byproducts.
Reduced H2S from ~200 ppm to <1 ppm at the custody transfer point
Cut chemical treatment costs by over 80%
Automated, less than 5-minute reaction time
Integrated seamlessly with existing infrastructure
ThunderOx not only delivered safe, reliable, and real-time treatment, but it also transformed operational efficiency while protecting workers and the environment.
Download our Case Study “Eliminating H2S in Produced Water” to see how ThunderOx can help your operations achieve the same results – safe, cost-effective, and hassle-free.
SAN ANTONIO, TEXAS, NOVEMBER 18, 2025 – Ernst & Young LLP (EY US) announced that David Sisk, CEO and Co-Founder of Streamline Innovations was named an Entrepreneur Of The Year® 2025 National Finalist. Sisk was named a Gulf South regional award winner back in June, and the National Finalists were selected from the group of 221 regional winners representing 191 companies across the United States.
For 40 years, Entrepreneur Of The Year has been the premiere competitive business award for ambitious entrepreneurs who are transforming industries, impacting communities and creating long-term value.
“It is such an honor to be selected as a National Finalist for the 2025 Entrepreneur Of The Year,” said David Sisk. “At EY’s national forum, you interact with so many incredible entrepreneurs and business leaders, so being recognized at the national level is humbling. I was there to represent the tireless dedication of the entire Streamline team, to share the challenges we’ve overcome, the victories we’ve earned, and the journey that’s taken us from a neighborhood coffee shop to deploying more than 70 VALKYRIE® units and treating more than a billion gallons of water every day. The journey truly has been remarkable, but I still feel like we are just getting started.”
David Sisk was selected by a panel of independent judges comprised of entrepreneurs and other respected business leaders from across the US. The candidates were evaluated based on their proven records of building long-term value through entrepreneurial spirit, purpose, growth and impact, among other core contributions and attributes.
Streamline Innovations’ vision is Reducing Emissions Through Technology. Streamline applies technology and innovative solutions in an environmentally forward manner to address poisonous emissions from various industrial processes. The Company uses its patented chemistry and VALKYRIE® processing units to eliminate toxic and corrosive hydrogen sulfide (H2S) emissions from oil and gas, produced water, renewable natural gas, carbon dioxide, municipal and industrial wastewater and other industrial processes.
Entrepreneur Of The Year honors many different types of business leaders, including original founders who grew their business from inception, visionary CEOs who transformed companies with innovation, and family business leaders who modernized legacy models for future success, for their ingenuity, courage and entrepreneurial spirit.
Founded and produced by Ernst & Young LLP, the Entrepreneur Of The Year Awards include presenting sponsors PNC Bank, SAP, Cresa LLC, Marsh USA, and the Ewing Marion Kauffman Foundation.
About Entrepreneur Of The Year
Founded in 1986, Entrepreneur Of The Year® has celebrated more than 11,000 ambitious visionaries who are leading successful, dynamic businesses in the US, and it has since expanded to nearly 80 countries and territories globally.
The US program consists of 17 regional programs whose panels of independent judges select the regional award winners every June. Those winners compete for national recognition in November at the Strategic Growth Forum®, where National finalists and award winners are announced. The overall National winner represents the US at the World Entrepreneur Of The Year® competition. Visit ey.com/us/eoy.
Contact
Randy Rohlfs Chief Commercial Officer Streamline Innovations, Inc. randy.rohlfs@streamlineinnovations.com
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.
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.
