Where SF6 Gas Is Used in Substations (Equipment, Applications, and Risks)
Quick Answer
SF6 (sulfur hexafluoride) gas is primarily used as an electrical insulator and arc‑quenching medium in high‑voltage substation equipment. Its most common applications include gas‑insulated switchgear (GIS), high‑voltage circuit breakers, and gas‑insulated lines (GIL). Because SF6 is a potent greenhouse gas, its use is strictly regulated by the EPA to minimize leaks and environmental risk.
While we’ve previously covered What Is SF6 Gas and Why It Matters in Substations, this article focuses specifically on where SF6 is used inside substation equipment and the risks associated with those applications.
What equipment in a substation uses SF6 gas?
SF6 gas is used in substation components where high dielectric strength and reliable arc interruption are required in compact spaces. In our field observations, SF6 is most commonly found in the following equipment:
High‑Voltage Circuit Breakers
SF6 circuit breakers rely on the gas to quench electrical arcs that form when contacts separate under load.
Common designs include:
Dead Tank Circuit Breakers – The interrupter is enclosed in a grounded metal tank filled with SF6 gas.
Live Tank Circuit Breakers – The interrupter is energized and insulated from ground using SF6.
Puffer‑Type Interrupters – Mechanical energy compresses SF6 gas to blow out the arc during interruption.
These breakers are widely used at transmission and sub‑transmission voltage levels due to their reliability and fast interruption capability.
Gas‑Insulated Switchgear (GIS)
Gas‑Insulated Switchgear uses SF6 gas to insulate busbars, disconnect switches, and circuit breakers inside sealed enclosures.
GIS is typically deployed when:
Space is limited (urban substations)
Environmental conditions are harsh
High reliability is required
Gas‑Insulated Lines (GIL)
In some high‑capacity installations, SF6 is used in gas‑insulated transmission lines, where conductors are enclosed in grounded metal tubes filled with insulating gas.
Why is SF6 used in high‑voltage circuit breakers instead of air?
SF6 is used instead of air because it offers superior insulating and arc‑quenching properties.
Key advantages include:
Dielectric strength approximately 2–3 times greater than air
Rapid arc extinction, reducing equipment damage
Stable performance across temperature ranges
Compact equipment design, reducing substation footprint
Air‑insulated designs require significantly more clearance, which increases land use, structural complexity, and exposure to environmental contamination.
How does Gas‑Insulated Switchgear (GIS) compare to Air‑Insulated Switchgear (AIS)?
The choice between GIS and AIS is often driven by space constraints, reliability requirements, and long‑term maintenance considerations. Rather than looking at this as a simple technology swap, operators typically evaluate how each option performs across several practical dimensions.
Physical Footprint
GIS: Extremely compact, making it well‑suited for urban substations, indoor installations, or sites with limited real estate.
AIS: Requires large clearances between energized components, resulting in a much larger overall footprint.
Reliability and Exposure
GIS: Sealed enclosures protect components from moisture, dust, salt, and wildlife, which generally results in higher operational reliability.
AIS: Exposed components are more susceptible to environmental contamination and weather‑related issues.
Maintenance Requirements
GIS: Typically requires less frequent inspection, but maintenance activities demand higher precision due to sealed gas compartments.
AIS: Requires more frequent visual inspections and cleaning, but individual components are easier to access.
Environmental Considerations
GIS: Relies on SF6 gas, which introduces greenhouse‑gas risk and strict regulatory oversight if leaks occur.
AIS: Uses ambient air for insulation and does not introduce greenhouse‑gas compliance concerns.
Typical Use Cases
GIS: Commonly used in dense urban areas, indoor substations, offshore platforms, and harsh environments.
AIS: Commonly deployed in rural or open areas where space is not a limiting factor.
While GIS offers clear operational and spatial advantages, its reliance on SF6 means utilities must implement rigorous leak management, monitoring, and compliance programs.
What are the primary environmental and safety risks of SF6 leaks?
SF6 itself is non‑toxic and non‑flammable, but its byproducts and environmental impact present serious risks.
Environmental Risks
SF6 has a global warming potential over 23,000 times greater than CO₂
Leaks contribute disproportionately to greenhouse gas emissions
The EPA mandates reporting, tracking, and leak reduction programs for utilities
Safety Risks During Electrical Arcing
When SF6 gas is exposed to high‑energy electrical arcs, it can decompose into hazardous byproducts, including:
Thionyl Fluoride (SOF₂) – Toxic and corrosive
Hydrofluoric Acid (HF) – Extremely corrosive, capable of causing severe chemical burns
In practice, we typically see these risks arise during:
Fault interruptions
Improper maintenance procedures
Undetected slow leaks inside sealed compartments
This is why controlled handling, gas recovery, and post‑fault inspection procedures are critical.
Why understanding SF6 applications matters for compliance and reliability
Knowing where SF6 gas is used inside a substation helps operators:
Identify high‑risk leak points
Prioritize inspection and monitoring
Maintain compliance with EPA standards
Reduce unplanned outages and environmental exposure
As regulatory pressure increases, understanding these application‑level details is no longer optional—it’s a reliability and compliance requirement.
What’s next: Managing and detecting SF6 leaks
This article focuses on where SF6 gas is used. In our upcoming pillar guide, we’ll cover:
How SF6 leaks are detected
Repair strategies and best practices
Regulatory reporting requirements
How this article was researched
This content was developed using a review of industry standards and guidance, including IEEE, EPA greenhouse gas reporting rules, and CIGRE publications, combined with real‑world field observations from substation environments.
Last fact‑checked: January 5, 2026