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

March 5, 2026AOP

Cost Effective H2S Removal from Produced Water

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.

Full Case Study

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

In the Lea County application:

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)

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.

Download – ThunderOx for Produced Water Case Study

If you’re evaluating sulfide treatment strategies for high-H₂S produced water, don’t rely on theory, review the field data.

The full ThunderOx™ case study reveals:

Detailed before-and-after water quality data
Chemical loading ratios and dosing methodology
SCADA automation configuration
A breakdown of the $1+ million per month in chemical savings
Performance results at 5,500 BBL/day in a high-sulfide SWD system

See exactly how dissolved H₂S was reduced from ~200 ppm to <1 ppm at custody transfer with rapid reaction times and minimal additional infrastructure.

Download ThunderOx Case Study

AOP, Case Study, Educational, Liquid Redox, Oil & Gas, Produced Water

September 18, 2025AOP

Advanced Oxidation Process for Emergency Wastewater Treatment

A Rapid, Scalable Solution for Complex Contaminants

When industrial accidents or environmental emergencies strike, wastewater can quickly become contaminated with dangerous, persistent compounds. In these critical moments, conventional treatment systems often fall short—especially when dealing with hard-to-remove substances like persistent organic pollutants (POPs), BTEX, pharmaceuticals, and cyanide. These contaminants not only resist biological breakdown but pose significant health and ecological risks if left untreated.

The Advanced Oxidation Process (AOP) from Streamline Innovations offers a powerful and flexible solution for rapid response scenarios—delivering fast, effective treatment of contaminated water using our reactive chemistry.

Emergency Wastewater Treatment Scenarios

There are several scenarios that can result in an urgent need for water treatment:

Contaminated Water from Fire Suppression: Fighting large fires at industrial facilities, such as crude oil refineries, petrochemical plants, tank farms, and gas processing plants often requires substantial amounts of water, which then becomes contaminated with hydrocarbons, chemicals, and potentially toxic byproducts of combustion.

Pollutant Release: During an emergency, a facility upset can release oil, gas, leachate, and hazardous substances into the surrounding environment, potentially contaminating surface water, groundwater, and soil.
Wastewater Overflow and Spills: The influx of contaminated water from fire suppression or damage to containment systems can lead to overflows and spills of wastewater into nearby waterways.

Why Emergency Wastewater Treatment Needs a Better Approach

Emergencies demand immediate action. Whether from chemical spills, unplanned discharges, or compromised infrastructure, the resulting wastewater can’t wait for slow to implement, capital-intensive solutions. Many pollutants don’t degrade easily through traditional means.

The Power of Hydroxyl Radicals

AOP works by generating hydroxyl radicals (•OH) in situ—right within the contaminated water stream—using our catalyst and hydrogen peroxide. These radicals are among the most powerful oxidizers known, capable of breaking down a wide range of complex organic molecules quickly and thoroughly.

Unlike conventional oxidants, hydroxyl radicals:

Have a higher oxidation potential
React indiscriminately with most organic contaminants

The AOP process takes place at neutral pH, making it less complex and more environmentally preferred option than a traditional standard Fenton’s reagent.

Rapid Deployment. Minimal Footprint.

AOP is uniquely suited for emergency responses because it:

Requires low capital expenditure
Deploys quickly thanks to its liquid-to-liquid application
Scales easily to treat varying volumes and contaminant concentrations
Operates with minimal ongoing operational expense
Extends the integrity of wastewater infrastructure by reducing corrosive agents and hard-to-treat compounds

AOP is ideal for a wide range of critical and emergency uses, including:

Emergency Industrial Response. Rapid treatment of wastewater after spills, chemical releases, or unplanned discharges
Mining Operations. Destruction of cyanide and other persistent mining-related contaminants
Landfill Leachate. Effective treatment of complex organics in leachate streams
Pharmaceutical & Food Processing. Breakdown of pharmaceutical residues and organic loads from food production
Brine Water Treatment. Enhanced treatment of produced or flowback water in energy operations
Textile & Chemical Manufacturing. Elimination of dyes, solvents, and other refractory organics

A Smarter, Safer Path to Clean Water—Fast

In an emergency, the clock is ticking. AOP delivers a fast-acting, powerful, and environmentally preferred treatment solution that can be mobilized immediately and scaled to the challenge at hand. Whether responding to an industrial spill or treating contaminated process water, AOP offers peace of mind and proven performance when it’s needed most.

Ready to respond?
Contact us today to learn how AOP can support your emergency wastewater treatment plan.

AOP, Liquid Redox, Odor Control, Talon Sulfide Elimination System, Wastewater Treatment

December 19, 2024Case Study

CASE STUDY: Emergency Wastewater Treatment

Refinery Fire Incident. A lightning strike ignited a large above-ground crude oil storage tank. Putting out the fire involved millions of gallons of contaminated water and foam, which had to be sequestered and stored for treatment.

This case study covers how the Streamline ThunderOx Sulfide Elimination System (TSES™) was quickly deployed and treated millions of gallons of contaminated water and reclaimed faster than alternatives. The process yielded harmless elemental sulfur with no negative environmental impact.

Download:
E mergency Wastewater Treatment Case Study

Solutions Page: Emergency Wastewater Treatment

Contact
Clayton Sullivan
Vice President – Water
Streamline Innovations, Inc.
stewart.north@streamlineinnovations.com
(888) 787-6569

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.

Case Study, Chemicals & Refining, Liquid Redox, Odor Control, Talon Sulfide Elimination System, Wastewater Treatment

August 22, 2024Educational

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

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

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

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

The Constraint of Sour Takeaway

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

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

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

Debottlenecking – Removing Sour Gas Takeaway Constraints

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

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

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

VALKYRIE® H₂S Technology for Debottlenecking Sour Gas Production

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

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

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

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

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

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

VALKYRIE Technology Applications

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

Field gas conditioning for Gas Lift.
Tail Gas treating.

Benefits of the VALKRYIE gas treating system:

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

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

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

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

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

Meets the most stringent outlet specifications.

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

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

About Streamline Innovations

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

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

Educational, Liquid Redox, Oil & Gas, Valkyrie

August 8, 2024Educational

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

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

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

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

Fuel Gas Conditioning – Eliminating H2S and Reducing Emissions

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

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

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

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

VALKYRIE Next Generation Liquid Redox for Emissions Reduction

VALKYRIE Technology Applications

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

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

Tail Gas treating.

Benefits of the VALKRYIE gas treating system:

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

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

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

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

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

Meets the most stringent outlet specifications.

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

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

About Streamline Innovations

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

Educational, Liquid Redox, Oil & Gas, Valkyrie

July 25, 2024Biogas

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

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

How Sour is Sour?

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

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

How Does Sour Gas Cause Emissions?

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

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

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

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

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

Gas Sweetening

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

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

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

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

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

VALKYRIE Technology Applications

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

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

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

Benefits of the VALKRYIE gas treating system:

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

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

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

About Streamline Innovations

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

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

March 5, 2024Elemental Sulfur

Convert Acid Gas into CCS Tax Credits and Eliminate Flaring

Acid gas, also known as amine overhead gas, is a blend of acidic gases including carbon dioxide (CO2) and hydrogen sulfide (H2S), and a common byproduct of various industrial processes, including natural gas processing, refining and chemical production. These gases are considered “acidic” because they can dissolve in water to form acids, leading to a decrease in pH when released into the environment. These gases, known for their corrosive properties, pose significant risks to the environment, human health and industrial equipment if not properly managed.

Where Acid Gas Comes from – Amine Sweeting

In many industrial settings dealing with sour gas, sweetening processes are employed to remove hydrogen sulfide (H2S) using methods like amine scrubbing. Amine gas treating, or sweetening, is frequently used in high volume applications, such as natural gas processing plants and refineries. Amine sweetening systems, however, generates an acid gas stream that requires careful handling and disposal.

Traditional Acid Gas Disposal Methods (Pros/Cons)

Traditional methods of disposing of acid gas include flaring and injection into specialized Acid Gas Injection (AGI) wells.

Flares and Enclosed Combustors:

Pros: Flaring is simple and can use existing infrastructure.
Cons: Key drawbacks include the fact that flaring may not be a permitted use in some jurisdictions and burning acid gas produces harmful SO2 emissions.

Acid Gas Injection (AGI) Wells:

Pros: Can be safe and a permanent solution.
Cons: AGI may not be permitted in some jurisdictions, permitting may take 1-3 years, if at all. Additionally, it is expensive to get started and requires ongoing monitoring of the potential impact on groundwater and other long-term environmental concerns. AGI wells also present a potential single point of failure, increasing the risk of unplanned downtime.

Liquid Redox for Acid Gas Treating

Next generation Liquid Redox technology offers a revolutionary approach to acid gas treatment by utilizing a Reduction-Oxidation (Redox) chemical reaction. Acid gas containing H2S exits the Liquid Redox system sweet (without H2S) and the elemental sulfur is filtered out of the regenerated chemistry where it can be reused, further reducing costs. The sulfur can be used for organic food production. This process not only eliminates the need for flaring or AGI but also delivers pure CO2 for carbon capture and storage (CCS).

Pros: Eco-friendly, eliminate flaring, eliminate AGI, cost-effective, deliver pure CO2 for CCS or industrial use.
Cons: None.

VALKYRIE® Acid Gas Treating Units – Leveraging the Power of Liquid Redox Technology

VALKYRIE Acid Gas Treating Units (AGTUs) harness reliable, proven next generation Liquid Redox technology to deliver an eco-friendly solution to disposing of acid gas generated from H2S sweetening processes.

VALKYRIE AGTUs deliver these benefits:

Seamlessly integrate with existing H2S removal processes.
Can operate from 0-30 psig.
Can handle extremely high H2S concentrations (more than 80%).
Offer little to no pressure drop across the unit.
Effectively eliminates all remaining H2S from the gas stream and delivers elemental sulfur.
Ensure compliance with regulatory standards.

LEARN MORE: VALKYRIE® Gas Treating Technology

CCS Benefits

VALKYRIE AGTUs using next generation Liquid Redox chemistry deliver a multitude of benefits to CCS efforts:

Eliminates flaring of acid gas and associated emissions.
Eliminates need for an Acid Gas Injection (AGI) well.
Delivers pure CO2 for multiple uses, including CCS.
Pure CO2 for CCS increases storage capacity and maximizes carbon credits (45Q tax credit) .
Qualify for clean energy tax credits.

LEARN MORE: 45Q Tax Credit for Carbon Oxide Sequestration

LEARN MORE: IRA (Inflation Reduction Act) Tax Credit

The VALKYRIE Acid Gas Treating Advantage

VALKYRIE stands out as a true green solution with its use of non-toxic, eco-friendly chemicals and renewable or low-impact resources. Its energy efficiency, reduced waste generation, and compliance with regulations make it a cost-effective and environmentally responsible choice for acid gas treatment.

Advantages of VALKYRIE AGTUs for acid gas treating:

A true green solution with non-toxic and eco-friendly chemicals
Renewable or low-impact resources
Energy efficiency
Reduced waste and generation of byproducts
No harmful byproducts
Recyclability or reusability
Cost-effectiveness
Compliance with regulations

Summary

VALKYRIE liquid redox technology offers a sustainable and efficient solution for treating acid gas, mitigating environmental risks, and promoting carbon capture initiatives. By harnessing the power of chemistry, it not only addresses industrial challenges but also paves the way for a greener, more sustainable future.

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.

About Streamline Innovations

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

Elemental Sulfur, Liquid Redox, Talon Sulfide Elimination System, Valkyrie

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

March 20, 2023Chemicals & Refining

H₂S Treating Methods – Comparing Triazine and Next Generation Liquid Redox

Treating natural gas streams for hydrogen sulfide (H₂S) is a priority for Oil & Gas producers worldwide. In the United States, much of the associated gas produced from the strategically important producing regions in the Permian Basin and the Eagle Ford trend in southern Texas contains high levels of H₂S, making it “sour.”

These oil and gas producing regions are served by established infrastructure and the sour gas assets there play an important role in meeting the nation’s current and future energy needs.

But there is a problem with sour gas. Because H₂S is highly corrosive to infrastructure and presents a threat to human health, most pipelines have established strict limits on H₂S concentration requiring Oil & Gas operators to remove or otherwise destroy it. In our article Gas Treating – Processing Solutions for Multiple Industries, we reported that The University of Texas found that the interstate pipeline specifications for H₂S range between 0.25 grains per 100 cubic feet to 1.0 grain.

Although flaring or combusting associated gas contaminated with H₂S is one way to dispose of it, the practice produces harmful sulfur dioxide (SO₂), which is a major contributor to acid rain and regulated by the Clean Air Act. Alternatives to flaring are to capture or destroy the H₂S using chemical, biological, or mechanical processes that have different trade offs in terms of capital and operation expenses, and have significantly different waste streams.

In this article we compare the two most common H₂S Treatment strategies used by oil producers for treating H₂S in the field: Scavenger and Next-Generation Liquid Redox.

H₂S Scavengers

Using an H₂S scavenger to treat sour gas is a common legacy method for “sweetening” sour gas by removing H₂S from natural gas streams using a chemical reaction. A scavenger tower brings sour gas into contact with liquid or solid media, which captures the H₂S.

Triazine is commonly used to treat H₂S in natural gas streams. It is a clear to pale yellow liquid with a fishy smell. Because triazine cannot be used at full strength, it is usually mixed with other substances to bring the concentration down to field strengths ranging from 20-80%, depending on the application.

Triazine can be injected directly into gas streams or used in a contact tower (scavenger). H₂S scavengers using contact towers are considered up to 80% efficient, as compared to only 40% efficiency for direct injection.

Triazine works by binding itself to the H₂S molecule. The reaction is defined as one mole of triazine reacting with two moles of H₂S to form dithiazine. This is a one-time, non-reversible chemical reaction.

In a liquid H₂S scavenger using triazine, produced gas is fed into a tower vessel where it bubbles up through the liquid. As the H₂S contacts the triazine in the treating tower, it is rendered harmless.

Because triazine scavenging is a non-regenerative process, triazine must be replaced periodically and the spent liquid must be disposed of.

Triazine H₂S Treating Pros and Cons

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

Minimal installation cost.
Can be cost effective, depending on gas flow rate.
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:

Contact towers are typically only 80% efficient, direct injection only ~40% efficient.
Disposal of spent triazine can be problematic in some areas.
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 H₂S and/or high gas flow rates.
Worker exposure to chemicals at the worksite, potential health and safety concerns.

Next Generation Liquid Redox for H₂S Treating

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

Focus on Triazine Disposal

As previously noted, there are several downsides to H₂S scavengers using liquid triazine. Because the triazine-H₂S reaction is non-regenerative, the spent chemical must be replaced periodically and disposed of.

Dithiazine is the byproduct of using triazine to remove H₂S from oil and gas streams and has no secondary use. It is a liquid waste product that requires proper disposal, in saltwater disposal (SWD) wells along with produced water, if the SWD operator allows, or at a hazardous materials disposal facility.

Comparison – Triazine H₂S Scavengers vs. Next Generation Redox

We compare H₂S scavengers using liquid triazine with the latest generation of Liquid Redox.

Spent Media Disposal. Because treating H₂S using liquid triazine or solid media involve one-time, non-regenerative chemical reactions, the spent triazine must be replenished and the liquid byproduct disposed of properly. Solid media must also be periodically changed and disposed of at a hazardous materials landfill. Frequency of chemical and media changeouts is a function of several factors, including gas flow rates, H₂S concentration, scavenger vessel size and other variables.

Chemical Handling and Safety. Liquid triazine is typically transported in plastic totes and delivered to the well site or production pad. Field personnel can be exposed to triazine when moving totes around the well site, installing H₂S scavenger equipment and maintaining contact towers and injection equipment.

Exposure to triazine can cause skin rashes, eye irritation and the U.S. Environmental Protection Agency considers triazines as possible human carcinogens.

Operating Cost. Triazine H₂S scavengers are often more expensive than Next Generation Liquid Redox, especially for high levels of H₂S, because spent triazine must be replaced more frequently and can become overwhelmed at high concentrations, while TALON chemistry is regenerated, reducing the frequency of chemistry changes and chemical handling.

A Clear Advantage

The VALKYRIE Next Generation Liquid Redox system is the clear winner for treating high H₂S sour gas when all the risks and costs are taken into account.

Benefits of the VALKRYIE gas treating system:

A green solution that converts H₂S into the benign substances of water vapor and elemental sulfur.
Universal application for biogas, landfill gas, and oil and gas production.
Widest operating envelope of any H₂S 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 conditioning.
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.
Easily adjusted for variation in gas flow and H₂S concentrations.

We specialize in meeting the most stringent outlet specifications.

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.

Chemicals & Refining, Educational, Elemental Sulfur, Liquid Redox

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

The High Cost of “Conventional” Chemistry for H2S Removal

Selective Chemistry for H2S Removal = Lower Chemical Demand

Quantifiable Economic Impact of Streamline’s ThunderOx™ Sulfide Elimination System

Beyond Chemistry Costs

A Rapid, Scalable Solution for Complex Contaminants

Emergency Wastewater Treatment Scenarios

Why Emergency Wastewater Treatment Needs a Better Approach

The Power of Hydroxyl Radicals

Rapid Deployment. Minimal Footprint.

A Smarter, Safer Path to Clean Water—Fast

Download: Emergency Wastewater Treatment Case Study

About Streamline Innovations

The Constraint of Sour Takeaway

Debottlenecking – Removing Sour Gas Takeaway Constraints

VALKYRIE® H2S Technology for Debottlenecking Sour Gas Production

VALKYRIE Technology Applications

About Streamline Innovations

Fuel Gas Conditioning – Eliminating H2S and Reducing Emissions

VALKYRIE Next Generation Liquid Redox for Emissions Reduction

VALKYRIE Technology Applications

About Streamline Innovations

How Sour is Sour?

How Does Sour Gas Cause Emissions?

Gas Sweetening

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

About Streamline Innovations

Where Acid Gas Comes from – Amine Sweeting

Traditional Acid Gas Disposal Methods (Pros/Cons)

Liquid Redox for Acid Gas Treating

VALKYRIE® Acid Gas Treating Units – Leveraging the Power of Liquid Redox Technology

CCS Benefits

The VALKYRIE Acid Gas Treating Advantage

Summary

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

H2S Scavengers

Next Generation Liquid Redox for H2S Treating

Focus on Triazine Disposal

Comparison – Triazine H2S Scavengers vs. Next Generation Redox

A Clear Advantage

Faster H₂S Treatment for Produced Water = Lower Operating Costs

The High Cost of “Conventional” Chemistry for H₂S Removal

Selective Chemistry for H₂S Removal = Lower Chemical Demand

Download:
E mergency Wastewater Treatment Case Study

VALKYRIE® H₂S Technology for Debottlenecking Sour Gas Production

H₂S Scavengers

Next Generation Liquid Redox for H₂S Treating

Comparison – Triazine H₂S Scavengers vs. Next Generation Redox