flare gas, Oil & Gas Glossary

What Is Flare Gas?

Flare gas (also called flared gas or vent gas) is natural gas or hydrocarbon vapor that is burned in a flare stack at the surface rather than being captured, sold, or reinjected, either because of equipment limitations, safety requirements during well testing and operational upsets, or the absence of gas gathering infrastructure. Routine flaring — the continuous burning of associated gas produced alongside crude oil — is increasingly regulated globally and regarded as a waste of a valuable energy resource and a significant source of greenhouse gas emissions.

Key Takeaways

Approximately 140-150 billion cubic meters (BCM) of gas are flared globally each year, equivalent to roughly 4% of world natural gas production and enough energy to supply sub-Saharan Africa's entire electricity demand.
Russia, Iraq, Iran, the United States, and Venezuela account for the majority of global flaring volumes, with Russia and Iraq alone representing about one-third of the total.
Flaring converts methane to CO2 during combustion, reducing the greenhouse warming impact compared to venting; however, incomplete combustion still releases unburned methane, black carbon, and toxic volatile organic compounds.
The World Bank's Zero Routine Flaring by 2030 initiative and the U.S. EPA OOOOb/c rules are the two major regulatory frameworks driving flare reduction efforts.
Flare gas monetization options include pipeline gathering, liquefaction to LNG or CNG, onsite power generation, and gas-to-liquids conversion, all of which can turn a waste stream into revenue.

Why Flaring Occurs

Associated gas is natural gas dissolved in crude oil that comes out of solution as pressure drops during production. In mature producing basins with established gas gathering systems, this gas is captured and sold or reinjected. In remote or newly developed fields, however, gathering infrastructure often lags oil production. Operators facing the choice between shutting in oil production (forgoing revenue) or flaring the associated gas almost universally choose to flare, because the economic value of the associated gas does not justify the capital cost of a gathering line when production volumes are low or uncertain.

Safety flaring is a separate category and is unavoidable: refineries, LNG plants, gas processing facilities, and offshore platforms all require flare systems as pressure relief devices. When a process unit trips, a compressor fails, or an emergency shutdown occurs, gas that cannot be safely routed elsewhere is directed to the flare. Well testing also generates flaring — when a new well is flowed to surface to evaluate reservoir performance before permanent facilities are in place, the produced gas is burned. These safety and operational flares are generally accepted as unavoidable and are treated differently from routine associated gas flaring under most regulatory frameworks.

Fast Facts: Flare Gas

Global volumes flared: ~140-150 BCM per year (World Bank/NOAA satellite data)
Share of world gas production: ~4%
Top flaring countries: Russia, Iraq, Iran, United States, Venezuela
CO2 equivalent per BCM flared: ~1.9 million tonnes CO2 (assuming 98% combustion efficiency)
Incomplete combustion byproducts: Methane, black carbon, benzene, toluene, VOCs
Key regulation (U.S.): EPA OOOOb/c — limits routine flaring at new and existing oil and gas sites
Key global initiative: World Bank Zero Routine Flaring by 2030
Breakeven for flare capture: Typically 0.5-2 MMscf/d at wellsite; varies with gas price and distance to market

Field Tip:

Satellite-based flare detection (NOAA VIIRS instrument) can identify individual flares down to approximately 10 MMBtu/hr thermal output and is used by regulators and investors to monitor operator compliance. Operators in the Permian Basin and North Dakota Bakken should assume all flares larger than a pilot flame are visible from space and may trigger regulatory inquiry or ESG scoring penalties.

Flare System Components and Types

A typical elevated flare system consists of a knockout drum (removes liquid droplets from the gas stream to prevent burning liquid from raining down), a water seal or molecular seal (prevents flashback from the flare tip into the piping), the flare stack itself (elevated to disperse combustion products), and an ignition system with a continuous pilot flame. Smokeless operation requires steam or air injection at the flare tip to promote turbulent mixing and complete combustion. Ground flares — either open pit flares or enclosed combustors — are used at some oil sands operations and gas plants where elevated stacks would be aesthetically or operationally impractical. Enclosed ground flares achieve higher combustion efficiency (99%+) and are sometimes required in populated or ecologically sensitive areas.

Offshore platforms and FPSOs (floating production, storage, and offloading vessels) carry boom-mounted or elevated flare systems that must handle emergency gas volumes from the entire topsides process. The design basis for these systems is typically the maximum credible blowdown scenario, which may be 10-20 times the normal operating throughput. This means the flare tip is often undersized for routine operations, contributing to incomplete combustion and visible smoke during upset conditions.

Flare Gas Reduction and Monetization

Pipeline gathering remains the lowest-cost and most scalable solution when a field produces sufficient volumes to justify infrastructure. In the Permian Basin, major midstream companies including Enterprise Products, Targa Resources, and DT Midstream have expanded gathering networks to reduce Permian flaring from over 4% of gas production in 2019 to below 1% by 2023. North Dakota's Bakken flaring, which peaked at over 30% of produced gas in 2014, fell below 5% by 2022 following state regulations tying drilling permits to flaring compliance.

Where gathering infrastructure is uneconomic, operators can monetize flare gas through compressed natural gas (CNG) or liquefied natural gas (LNG) micro-facilities that serve local power or transport markets, onsite power generation using reciprocating engines or micro-turbines to produce electricity for artificial lift or water disposal, and virtual pipeline trucks that transport compressed or liquefied gas to market. Gas-to-liquids (GTL) technology converts methane to liquid hydrocarbons including diesel and naphtha, but GTL is capital-intensive and only economic at large scale. Emerging small-scale GTL units targeting remote flare gas are under development by companies including Velocys and CompactGTL, though commercial deployment remains limited.

Flare gas is also referred to as:

Flared gas — the past-tense or noun form used in production accounting and regulatory reports.
Associated gas — the broader term for gas co-produced with oil; most routine flaring involves associated gas specifically.
Vent gas — hydrocarbons released directly to atmosphere without combustion; venting is generally more harmful than flaring due to methane's higher global warming potential versus CO2.
Waste gas — informal term used in ESG reporting contexts to describe gas that is neither sold nor reinjected.

Frequently Asked Questions About Flare Gas

Is flaring better or worse than venting from a climate perspective?

Flaring is generally better than venting from a near-term climate standpoint. Methane has a global warming potential approximately 80 times that of CO2 over a 20-year timeframe. When flaring combustion efficiency is high (above 98%), converting methane to CO2 significantly reduces the warming impact per unit of gas disposed. However, flares operating at low efficiency — common during upsets, low-flow conditions, or with poorly maintained equipment — release substantial unburned methane and may provide little climate benefit over venting. Complete capture and sale of the gas remains the preferred outcome from both economic and environmental perspectives.

What is the World Bank Zero Routine Flaring initiative?

The World Bank launched the Zero Routine Flaring by 2030 (ZRF) initiative in 2015 as a voluntary commitment by oil-producing governments, state oil companies, and private operators to eliminate routine flaring at oil production sites by 2030. Signatories include major producers such as Norway's Equinor, BP, Shell, Total, and Saudi Aramco, as well as the governments of Norway, the United States, Iraq, and several African producers. The initiative does not cover safety flaring or well-test flaring, only the continuous routine burning of associated gas that has no capture pathway. Progress is tracked annually using NOAA satellite data.

How does U.S. EPA OOOOb/c regulation address flaring?

The EPA's OOOOb (new sources) and OOOOc (existing sources) rules, finalized in December 2023, require oil and gas operators to reduce methane emissions including from flaring across the U.S. oil and gas sector. The rules require operators to route gas to sales lines or combustion devices achieving 95% or higher destruction efficiency, conduct routine inspections using optical gas imaging or equivalent methods, and demonstrate compliance with emissions limits. The OOOOc rule extending requirements to existing sources was a landmark change, covering hundreds of thousands of existing facilities for the first time.

Why Flare Gas Matters in Oil and Gas

Flare gas has moved from an operational afterthought to a front-line issue for regulators, investors, and operators. ESG scoring by major index providers now penalizes high flaring intensity, and institutional investors including Norway's Government Pension Fund and BlackRock have issued engagement letters to operators with above-average flaring rates. In jurisdictions where carbon pricing applies — including Canada's federal carbon levy and the EU Emissions Trading System — flaring generates direct financial costs per tonne of CO2 equivalent. Operators who reduce flaring ahead of regulation protect future production permits, reduce carbon costs, and capture incremental revenue from gas that would otherwise be burned.