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 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.
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.