Permian H2S Removal Solutions: Centralized vs Decentralized Sour Gas Treatment

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

Summary

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.

Educational, Oil & Gas, Permian Basin, Produced Water

August 4, 2026Elemental Sulfur

Produced Water Treatment – ThunderOx is the Green Solution for Stubborn H2S Problems

For every barrel of oil produced in the Permian Basin, operators must also manage four to six barrels of water, according to the Wall Street Journal.

The U.S. EIA reported that Permian Basin oil production reached 6.6 million barrels per day in 2025, or 48% of total U.S. crude oil production. According to B3 Insight, Permian Basin oil wells produced roughly 20.7 million barrels per day of produced water in 2024, and by 2030 that figure is projected to exceed 26 million barrels per day.

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.

CASE STUDY DOWNLOAD | Eliminating Hydrogen Sulfide in Produced Water

Why “Green” Matters in Produced Water Treatment

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.

That’s not a tradeoff. That’s progress.

Talk to an H2S Treatment Expert today.

Elemental Sulfur, Liquid Redox, Oil & Gas, Permian Basin, Produced Water, ThunderOx

April 8, 2026Case Study

Liquid Redox for Rapid H2S Treatment for Produced Water

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:

Volume treated: 5,500 BBL/D
Monthly chemical savings: Over $1 million
Manpower requirement: ~1 operator hour per day
Infrastructure additions: Minimal (peristaltic pumps + storage tank + SCADA integration)

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.

– DOWNLOAD THE THUNDEROX CASE STUDY –

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.

Case Study, Liquid Redox, Oil & Gas, Permian Basin, Produced Water, ThunderOx

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

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.”

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.

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

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 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.

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

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

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.

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

November 7, 2023Educational

Streamline Innovations at the HART Energy Executive Oil Conference 2023

Streamline Innovations will be attending the HART Energy Executive Oil Conference 2023 on November 15-16 at the Midland County Horseshoe Arena in Midland, Texas.

David Sisk, CEO, and Kade Horton, Director of Business Development, will both be attending the event. Interested parties are invited to contact Kade Horton to schedule an appointment to learn more about Streamline’s environmentally friendly solutions for removing H2S from oil and gas production streams.

Streamline offers the world’s most efficient H₂S gas treating solution. This Redox process allows complete removal of H₂S in natural gas with a resulting by-product of organic elemental sulfur and water. This technology is deployed at any stage of the natural gas life cycle: upstream production, midstream gathering and processing, and downstream refining.

Our VALKYRIE® H₂S treating solutions use TALON® chemistry, a non-toxic and biodegradable Redox substance to remove H₂S in an environmentally responsible way. The Simple Elemental Sulfur™ byproduct is approved by Organic Materials Review Institute (OMRI) for use in organic food production.

Contact

Kade Horton
Vice President of Business Development
Streamline Innovations, Inc.
kade.horton@streamlineinnovations.com

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 gases 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, Events, Permian Basin

October 26, 2023Liquid Redox

Sweetening Sour Gas for Gas Lift Operations

Maintaining consistent production output can be a challenge as oil and gas reservoirs age. Over time, natural reservoir pressure diminishes, causing a decrease in production rates which impacts the economic viability of older wells and the value of proved reserves. When the natural drive of a well is no longer sufficient to bring liquids to the surface, artificial lift methods become indispensable. Among these methods, gas lift stands out as a cost-effective and efficient solution.

Gas lift is an artificial lift system where natural gas is injected into the well casing to assist in lifting liquids to the surface through the production tubing. Gas lift is employed when reservoir pressure declines, water cuts increase and gas-to-oil ratios (GORs) change over time. Gas lift systems provide operators with an effective and economical means of optimizing production in a wide range of well configurations, whether they are shallow or deep, vertical or horizontal.

Benefits of Gas Lift

Gas lift has several advantages that make it a preferred choice for artificial lift operations:

Low Operating Costs: Gas lift systems often use the natural gas produced from the well as fuel for compressors used to inject gas back into the reservoir, commonly referred to as “lease use” gas. This usually results in lower operating costs compared to other artificial lift methods.
Minimal Downhole Equipment: Unlike some other artificial lift systems, gas lift does not require the installation and maintenance of additional downhole equipment such as submersible pumps or rods. A downhole gas lift valve and compressor are typically all that is required. This simplicity translates to reduced capital outlays for equipment and maintenance expenses.
Easier Maintenance: Gas lift systems have fewer moving parts than other artificial lift methods, leading to less wear and tear. There is no risk of a broken rod downhole, eliminating the need for a workover rig to fix it. This simplicity keeps repair costs relatively low.
Ease of Replacement: When flow conditions change, the gas lift valve can be replaced cost-effectively without the need for a workover rig, minimizing downtime.

Sweet Gas Buyback

One challenge in gas lift operations arises when there isn’t enough natural gas produced at the well site for use in the system, or if the produced gas is contaminated with impurities like hydrogen sulfide (H₂S). Gas contaminated with H₂S, commonly referred to as sour gas, poses significant challenges to system integrity and human health, making it unsuitable for gas lift operations.

In these scenarios, operators often resort to purchasing “sweet gas,” usually from their midstream partner, to fulfill their gas lift requirements, a practice known as “sweet gas buyback.” Depending on the prevailing price of natural gas, however, sweet gas buyback may be prohibitively expensive.

Fuel Gas Conditioning – Dealing with H2S

As a highly corrosive and toxic gas, H2S must be effectively removed before it can be safely used in gas lift operations. 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 where midstream H₂S treating capacity and sour takeaway is limited, on-site sour gas treatment can remove this constraint, providing the additional advantage of using the treated gas for gas lift. Even if adequate sour gas takeaway capacity exists, on-site H₂S treatment reduces or can even eliminate the expense of sour gas takeaway.

Traditionally, sour gas has been treated using various methods, such as amine gas sweetening or scavengers. These methods, while somewhat effective, have drawbacks in terms of cost, environmental impact, and operational complexity.

Next Generation Liquid Redox (VALKYRIE®)

A promising solution for treating H₂S in gas lift operations is the use of Next Generation Liquid Redox, which is the basis for our VALKYRIE H₂S treating technology. This innovative approach offers several benefits over traditional methods:

Reduced Expense of Sweet Gas Buyback: VALKYRIE technology enables on-site treatment of sour gas, reducing or eliminating the need for expensive sweet gas buyback.

Reduced Expenses Associated with Sour Gas Takeaway: Operators can reduce expenses related to sour gas takeaway paid to midstream partners, leading to significant cost savings.

Non-Toxic and Eco-Friendly Chemicals: VALKYRIE technology employs non-toxic and environmentally friendly chemicals, minimizing harm to the environment and ensuring the safety of workers.

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 its environmental sustainability.

Recyclability or Reusability: Many VALKYRIE systems allow for the recycling or reuse of chemicals, reducing waste and enhancing cost-effectiveness.

Leading operators like Chevron and Franklin Mountain Energy have been using VALKYRIE technology for years for effective H₂S removal.

LEARN MORE: VALKYRIE Technology for Gas Sweetening and H₂S Removal

Summary

Gas lift is a valuable artificial lift method for optimizing production in oil and gas wells. It offers numerous benefits, including low operating costs, minimal downhole equipment requirements, ease of maintenance and versatility. However, in cases where sour gas is present the expense of buying back sweet gas can pose challenges.

The use of advanced sour gas treatment technologies like VALKYRIE units offer operators a green solution for sour gas sweetening that not only ensures a reliable source of gas for gas lift but also reduces costs, minimizes environmental impact and enhances safety. Embracing these innovative technologies can lead to more efficient and sustainable gas lift operations in the oil and gas industry.

Contact us today to learn more about Next Generation Liquid Redox H2S treating technology and determine if the VALKYRIE system is right for your operation.

Contact

Jacob Pratt
SVP – Sales
Streamline Innovations, Inc.
jacob.pratt@streamlineinnovations.com

About Streamline Innovations

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

Liquid Redox, Permian Basin, Petroleum Engineering, Valkyrie

September 28, 2022New Commissioning

Streamline Innovations VALKYRIE® H2S Treatment Technology Successfully Deployed for Chevron in the Permian Basin

Streamline’s VALKYRIE technology is a green solution for treating sour gas, helping oil and gas producers unlock the value of sour gas assets in an environmentally friendly way
VALKYRIE units have been deployed to a Chevron production pad in the Permian Basin and have been operating reliably for four consecutive months

SAN ANTONIO, TEXAS (September 28, 2022)

Streamline Innovations, Inc. (“Streamline”) announced it is providing Chevron a solution for treating hydrogen sulfide (H₂S) in the Permian Basin.

Valkyrie™ 1-Ton Skid in the Permian Basin — *Streamline Innovations VALKYRIE™ 1-Ton Skid located in the Permian Basin.*

VALKYRIE H₂S treatment technology helps oil and gas producers overcome the constraint of limited sour take-away capacity, allowing the operator to produce and sell more oil and gas. Streamline’s technology safely and effectively treats H₂S without flaring or injecting acid gas.

We recently deployed Streamline VALKYRIE 1.0 LTPD Skid Units to a Chevron location in Lea County, New Mexico. The units have been operating successfully for four months, helping Chevron develop and produce its sour gas assets in the area.

“Our VALKYRIE technology represents a green revolution for treating sour gas and is a true game-changer,” said Randy Rohlfs, Chief Commercial Officer with Streamline Innovations. “The VALKYRIE solution is a cost-effective, green technology that permanently dismantles the hydrogen sulfide molecule into harmless substances, eliminates flaring and allows operators to unlock the value of their sour gas assets in an environmentally friendly way.”
Randy Rohlfs, Chief Commercial Officer

Streamline is managing, servicing, and maintaining the fleet of VALKYRIE units under a Service Agreement, providing a turnkey solution to Chevron.

About Streamline Innovations

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

Streamline’s environmentally forward H₂S treating solutions help our customers achieve environmental performance by significantly reducing emissions with our green H₂S solutions. H₂S is present in many industrial processes throughout the world, and our technology can be applied across industries, delivering a sustainable solution that eliminates H₂S, a leading cause of human inhalation accidents, corrosion and SO₂ emissions, a primary cause of acid rain.

We also believe that achieving climate-improving directives requires data. Creating intelligent systems that operate effectively and efficiently without human intervention is critical to measuring and reducing emissions that harm the environment. We integrate advanced process control, data collection 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.

Visit streamlineinnovations.com for more information.

Contact

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

New Commissioning, Permian Basin, Valkyrie

September 23, 2022Educational

Gas Sweetening | A Comparison Guide

In our blog article Gas Sweetening | Sour Gas Treatment Strategies by Volume, we covered how natural gas, biogas, and water that contain sulfur compounds is considered “sour.” In low concentrations, these contaminants can cause maleficent odors, and in higher concentrations they can create serious hazards to both infrastructure and human health.

When methane gas is contaminated with hydrogen sulfide (H2S) or other sulfur compounds it is sour, whether it is produced from an oil and gas well or generated in an anaerobic digester as part of a Renewable Natural Gas (RNG) project. Considering methane gas, whether produced from a well producing from an underground oil and gas reservoir or generated on the surface in an anaerobic digester or landfill, being sour usually refers to the presence of hydrogen sulfide (H2S). Whether in the context of natural gas or biogas, gas sweetening is synonymous with hydrogen sulfide removal, also known as desulfurization.

The comparison guide below summarizes the major differences between gas sweetening methods, including their pros and cons.

Method	Operational Factors	Environmental Factors
Liquid Redox	• Chemistry is reused, resulting in lower total cost • No hazardous disposal requirements	Green technology with harmless byproducts, including elemental sulfur, which can be put to beneficial use
Scavengers and Adsorbents	• Frequent media changes • Personnel can be exposed to chemicals and potential spontaneous combustion • Can generate negative downstream effects	• H2S is not permanently destroyed, could eventually come out • In most cases, must be disposed of in hazardous waste facility
Claus Process	• Established, proven process • Requires large and expensive facilities staffed by skilled personnel • Process efficiency does not reach 100% without recycling and tail gas treating	Desulfurizing creates crystalized elemental sulfur, which the main source for industrial applications
Biologics	• Sensitive to process changes and upsets, not good for intermittent production scenarios • Chemistry is high-alkalinity which must be diluted with water for HS&E concerns • Requires larger footprint than other methods	• Biological regeneration is a green process
Flaring/Combusting	• Routine flaring wastes a valuable natural resource that could otherwise be sold • Reduced asset values • Negative impact on community relations	• Flaring sour gas produces sulfur dioxide (SO2) emissions, a cause of acid rain • Makes it more difficult to achieve environmental performance goals (e.g., achieving net zero)

As the next generation Redox process, Streamline’s VALKYRIE® H2S treating units use our patented TALON® chemistry, to provide a green solution for gas sweetening without the negatives associated with other gas treating alternatives.

VALKYRIE® units have the widest operating envelope of any treating technology relating to pressure, gas volume and H2S concentration with the lowest total lifecycle cost per pound of sulfur removed compared to all other competitors. The VALKYRIE unit provides numerous tangible ancillary benefits.

Educational, Permian Basin, Valkyrie

March 21, 2022New Commissioning

Field-Wide Deployment of VALKYRIE® H2S Treatment Solution Continues in Permian Basin for Franklin Mountain Energy

SAN ANTONIO, TEXAS (March 29, 2022)

Streamline Innovations Inc. (Streamline) is proud to have recently deployed two new VALKYRIE® 1.0 LTPD Skid Units in Lea County New Mexico for Franklin Mountain Energy.

*Standard VALKYRIE™ 1.0 LTPD Skid Unit for treating hydrogen sulfide (H₂S) at a multi-well pad in the Delaware Basin in New Mexico.*

Franklin Mountain Energy is now using four Streamline VALKYRIE units with five additional units on order. Onsite gas sweetening with the VALKYRIE allows Franklin Mountain Energy to avoid operational issues and extra cost for sweet gas buy-back, allowing them to use their own gas for gas lift.

“Streamline has been an instrumental partner in unlocking our resource value in a sour field. Since commissioning our first VALKYRIE unit in August 2021, we have brought online an additional three units. The VALKYRIE technology is working effectively and is providing a safe and reliable solution for H₂S removal from our gas stream.”
-Travis Hutchinson, Director of Facilities at Franklin Mountain Energy

Processing capacity in the area has been limited by the substantial time and capital expenditures needed for the midstream companies to develop large-scale H₂S treating or Acid-Gas Injection wells and extend sour lines to the operators. Historically, acid gas or separated H₂S could be flared, but pressure to reduce routine flaring has grown significantly and prevailing commodity prices have made sweetened gas more valuable. With the VALKYRIE technology, operators have been able to overcome the constraint of limited sour take-away, while realizing more revenue from gas sales, in high performance, economical, environmentally sustainable manner.

“VALKYRIE technology is an environmentally friendly way to convert a sour gas waste stream into revenue,” said Randy Rohlfs, Chief Commercial Officer at Streamline Innovations. “Traditional methods for treating hydrogen sulfide are typically expensive and often have negative operational and environmental effects. VALKYRIE units use a green technology that permanently dismantles the H₂S molecule into harmless substances, eliminates flaring and allows for use of the sweetened gas for gas lift operations.”

VALKRYIE technology is changing how leading companies manage high H₂S, providing a headache-free solution for operators.

About Streamline Innovations

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

Streamline’s environmentally forward H₂S treating solutions help achieve the “E” in ESG. H₂S is present in many industrial processes throughout the world. Our technology can be applied across industries, delivering a sustainable solution that eliminates H₂S, a leading cause of human inhalation accidents and source of SO₂ emissions, a primary cause of acid rain. Talon treats effectively in both gas and water phases.

Streamline believes that achieving ESG directives requires data. Creating intelligent systems that operate effectively and efficiently without human intervention is critical to measuring and reducing emissions that harm the environment. We integrate advanced process control, data collection 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.

New Commissioning, Permian Basin, Valkyrie

What are The Hidden Costs of Decentralized H2S Removal?

What are the Benefits of a Centralized H2S Treatment Model?

The Overlooked Line Item: Sweet Gas Buyback

Where Centralized H2S Removal Makes the Most Sense

What to Weigh Before You Commit to a Centralized H2S Removal Strategy

VALKYRIE® H2S Removal – The Regenerative H2S Treatment Solution for Centralized Facilities

Valkyrie Next-Generation Liquid Redox

Benefits of Valkyrie H2S Treatment

Features and Capabilities

Summary

The Problem with Traditional H₂S Treatment

ThunderOx: A Fundamentally Different Approach to Produced Water Treatment

Why “Green” Matters in Produced Water Treatment

Cost-per-Barrel Economics Reinforce the Environmental Case

ThunderOx is Field-Proven, Scalable, and Operationally Simple

The Bottom Line

When Encountering High Concentrations of H₂S: Speed Matters

Reaction Speed Is Critical in Produced Water Treatment

Rapid Sulfide Elimination with ThunderOx

ThunderOx Field Test Results

Real-Time Performance in Active Operations

Rapid Treatment Enables Automation

Faster H2S Treatment for Produced Water = Lower Operating Costs

Safety Benefits of Rapid Sulfide Removal

Transforming Produced Water Treatment for Sour Resources

More Options for Maximizing Operational Efficiency

Successful Initial Deployments

Benefits of VALKYRIE Gas Treating Technology

Contact

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

Contact

About Streamline Innovations

Benefits of Gas Lift

Sweet Gas Buyback

Fuel Gas Conditioning – Dealing with H2S

Next Generation Liquid Redox (VALKYRIE®)

Summary

Contact

About Streamline Innovations

VALKYRIE H2S treatment technology helps oil and gas producers overcome the constraint of limited sour take-away capacity, allowing the operator to produce and sell more oil and gas. Streamline’s technology safely and effectively treats H2S without flaring or injecting acid gas.

About Streamline Innovations

Contact

The comparison guide below summarizes the major differences between gas sweetening methods, including their pros and cons.

Franklin Mountain Energy is now using four Streamline VALKYRIE units with five additional units on order. Onsite gas sweetening with the VALKYRIE allows Franklin Mountain Energy to avoid operational issues and extra cost for sweet gas buy-back, allowing them to use their own gas for gas lift.

VALKRYIE technology is changing how leading companies manage high H2S, providing a headache-free solution for operators.

About Streamline Innovations

What are The Hidden Costs of Decentralized H₂S Removal?

What are the Benefits of a Centralized H₂S Treatment Model?

Where Centralized H₂S Removal Makes the Most Sense

What to Weigh Before You Commit to a Centralized H₂S Removal Strategy

VALKYRIE® H₂S Removal – The Regenerative H2S Treatment Solution for Centralized Facilities

Benefits of Valkyrie H₂S Treatment

Faster H₂S Treatment for Produced Water = Lower Operating Costs

VALKYRIE H₂S treatment technology helps oil and gas producers overcome the constraint of limited sour take-away capacity, allowing the operator to produce and sell more oil and gas. Streamline’s technology safely and effectively treats H₂S without flaring or injecting acid gas.

VALKRYIE technology is changing how leading companies manage high H₂S, providing a headache-free solution for operators.