Operators have options to capture and monetize associated gas, yet global flaring hit ~151 bcm in 2024 — the highest since 2007 — squandering an estimated $63 billion and driving major emissions. Here’s the playbook to cut the flame, the pressure to act, and the kit to clean gas for sale.
In an oil boom, the wrong fire often grabs the spotlight. Oil companies torched roughly 151 billion cubic meters (bcm, billion cubic meters) of gas in 2024 — the highest level in almost two decades — despite oil output growing only ~1% (World Bank, www.worldbank.org). The World Bank pegs the lost energy at about $63 billion in 2024 — roughly equivalent to the entire annual gas consumption of Africa — and calls out that more than a billion people still lack reliable power (www.worldbank.org) (www.worldbank.org).
The paradox: associated gas — natural gas co‑produced with oil — can be gathered, sold, or used as fuel. In practice, about 75% is used (re‑injected for pressure maintenance, used on‑site for power, or piped to market), while roughly 25% is wasted — about 150 bcm flared plus ~55 bcm vented in 2019 (www.iea.org). As the IEA bluntly puts it, “if there is no productive outlet… associated gas… can end up being flared or (even worse) vented” (www.iea.org).
And the trendline is stubborn: in 2023, companies globally flared ~148 bcm, followed by ~151 bcm in 2024 (www.worldbank.org).
Associated gas utilization options
Pipeline gathering and transport remain the gold standard: connect fields to gas pipelines or processing facilities and flaring can often be eliminated. Regions with robust infrastructure (e.g., the US Gulf Coast, Australia) pipe most associated gas to market. Countries with gas‑collecting systems tend to flare at much lower intensity than remote fields in Russia or Iraq — “ten times lower than Russia,” per IEA data — a pattern also tracked by the World Bank (www.iea.org) (www.worldbank.org).
Re‑injection for reservoir pressure or enhanced oil recovery (EOR) is another workhorse. Equinor (formerly Statoil) re‑injects much of its North Sea associated gas; Petrobras in Brazil has said it will seek to reduce re‑injection where possible to sell more gas (Reuters, 2024‑08‑28). The trade‑off: re‑injection avoids flaring but can sideline gas volumes temporarily or permanently.
On‑site power is often the fastest path from flame to value. Gas turbines or reciprocating engines can convert flare gas to electricity for field operations or nearby communities, displacing diesel. Many projects add a flare gas recovery unit (FGRU — compression plus conditioning) to route captured gas to generators or facility fuel systems; the FGRU market was ~$1.3 billion in 2025 and is projected to reach $6.8 billion by 2033 (8.9% CAGR), driven by regulations and cost savings (www.alliedmarketresearch.com) (www.alliedmarketresearch.com). One analysis finds using flare gas for on‑site power “is often an economically justifiable option,” and converting a flare to productive use can cut CO₂ emissions by ~90% compared to flaring (www.sciencedirect.com) (www.sciencedirect.com).
Where pipelines are absent, liquefaction or conversion is an alternative. Mobile CNG/LNG (compressed/liquefied natural gas) units can capture stranded gas; Nigeria, for instance, licensed its first floating LNG plant to harness gas from flaring fields. GTL (gas‑to‑liquids) can turn gas into fuels at scale — a route deployed in only a few places such as Qatar’s Pearl GTL — but with higher capex.
Venting and flaring are the waste bins of last resort. Flaring (combustion) emits CO₂ but is far preferable to venting because methane (CH₄) is ~25× more potent as a greenhouse gas than CO₂ over a typical comparison period. Venting is increasingly banned; most jurisdictions allow only routine flaring or emergency safety flaring (both regulated). The World Bank’s Zero Routine Flaring by 2030 initiative codifies the end goal. Yet the practice persists, with ~148 bcm flared in 2023 and ~151 bcm in 2024 (www.worldbank.org).
Environmental and economic drivers
The emissions ledger is stark. The CO₂ from 150–151 bcm/year of gas flared equates to roughly 389 million tonnes of CO₂‑equivalent (CO₂‑eq, a common metric for comparing greenhouse gases) in 2024, including ~46 Mt from incomplete combustion of methane (www.worldbank.org). The IEA notes that 150 bcm flared in 2019 corresponded to ~300 Mt CO₂ — about Italy’s annual emissions — while routine flaring also releases black carbon and NOₓ (www.iea.org). If flares operate suboptimally, venting or slip can add up: 55 bcm of methane vented would be ~1,180 Mt CO₂‑eq (www.iea.org). Cutting routine flaring is therefore central to the Global Methane Pledge target of a 30% reduction by 2030; both the World Bank and the IEA flag flaring’s role in net‑zero pathways (www.iea.org).
The economic case is just as clear. Beyond the World Bank’s ~$63 billion estimate (www.worldbank.org), flared gas is lost revenue that could supply local electricity or displace imports. Penalties are rising: Nigeria enforces steep flare fees (up to tens of dollars per Mcf, thousand cubic feet) under its Petroleum Act, and Alberta (Canada) exceeded its 670 Mm³ (million cubic meters) flaring ceiling by ~36% in 2024, flaring ~913 Mm³ even as the province subsequently eliminated the limit. Regulatory uncertainty adds cost: starting Jan. 1, 2025, Nigeria will require new oil license applicants to demonstrate “low carbon emissions” in line with its net‑zero pledge.
Investor and public pressure are sharpening the incentive to capture gas. The U.S. EPA finalized a fee of $900/tonne on excess methane from oil and gas facilities (rising to $1,500/tonne by 2026). Countries endorsing the World Bank’s Zero Routine Flaring by 2030 have seen flaring intensity drop ~12% since 2012, while non‑endorsers saw it rise ~25% (www.worldbank.org). Health impacts are not abstract: one U.S. study estimated $77 billion per year in damages from oil and gas air pollution (not solely from flaring) (www.axios.com).
Indonesia’s regulatory turn
Indonesia is showing how policy can bend the curve. Flaring volumes fell from about 3.5 bcm in 2012 to 1.7 bcm in 2022 — a halving even as oil output declined by only ~30% over the period (flaringventingregulations.worldbank.org). The country endorsed the World Bank’s Zero Routine Flaring initiative in 2017 and, in its 2022 NDC, pledged a 32% unconditional emissions reduction by 2030 partly via methane control (flaringventingregulations.worldbank.org).
Ministerial Regulation ESDM 17/2021 tightened the screws: contractors must prepare flare gas management plans and prioritize utilization over burning (flaringventingregulations.worldbank.org). They must identify, measure, and report all flared volumes (meters or engineering methods), obtain approval for any routine flaring, and adhere to limits (e.g., 2 MMscf/day, million standard cubic feet per day, on average per oil field) (flaringventingregulations.worldbank.org). Noncompliance can escalate from warnings to license cancellation or executive suspension; conversely, the government recognizes firms that “optimize flare gas management” with annual awards (flaringventingregulations.worldbank.org) (flaringventingregulations.worldbank.org).
Industry is responding. SKK Migas counts about 370 flare stacks nationwide (mid‑2024) flaring ~207 MMSCFD (~5.9 Mm³/d), with gas roughly ~73% methane and ~7.3% CO₂ impurities; projects are moving to convert this fuel to higher‑value products (indonesiabusinesspost.com). One program aims to capture 32 MMSCFD of fuel gas now used at the Bontang LNG plant and instead pipe or liquefy it as LPG/LNG (indonesiabusinesspost.com). As a result, Indonesia’s flaring intensity (flared volume per barrel) has mostly declined over 2012–2022 (flaringventingregulations.worldbank.org).
Gas processing to sales spec
To turn associated gas into a marketable product, impurities must go. The big three are hydrogen sulfide (H₂S), carbon dioxide (CO₂), and water. Gas may also contain heavier hydrocarbons (C₃+), mercury, sulfur compounds, and particulates. Sales gas typically targets <4 ppm H₂S, a few percent CO₂, and a hydrocarbon and water dew point within pipeline limits.
Acid gas removal (“gas sweetening”) is usually done with amine scrubbers — aqueous solutions of MDEA, MEA, or DEA that chemically absorb H₂S/CO₂ in tall absorber towers before thermal regeneration. Dozens of sweetening processes exist, but “regenerative absorption into a liquid agent” is overwhelmingly used; amine plants routinely achieve H₂S below pipeline specs (typically <4 ppm) (gasprocessingnews.com) (gasprocessingnews.com). Commercial packages such as CO₂/H₂S removal amine solvent are specified in this role.
Sulfur recovery typically follows. The H₂S‑rich “acid gas” from amine units is converted to elemental sulfur in a Claus plant; modern Swiss‑site installations achieve >99% recovery, producing sulfur (S₈) for sale into fertilizer value chains.
Hydrocarbon dew‑point control protects pipelines and monetizes liquids. Low‑temperature processes or lean‑oil absorption pull out NGLs (ethane, propane, butanes), leaving “sales gas” within dew‑point specs while yielding valuable liquids.
Water removal is essential because raw produced gas is fully saturated with vapor. Almost all gas is dehydrated, most commonly via TEG (triethylene glycol) contactors that deliver typical water contents below ~7 lb/MMscf. For ultra‑dry service — e.g., LNG feed requiring very low dew points (below around −80°C) — molecular sieve (zeolite) adsorption beds are used with periodic hot‑gas regeneration (onepetro.org).
Trace contaminants demand targeted polishing. Mercury, when present even at minute levels, can poison downstream catalysts; it is removed using adsorbents such as activated carbon or specialty zinc‑sulfide media. Other impurities like mercaptans (RSHs) or particulates are handled with tailored scrubbers or filters as required by spec.
Process selection follows the gas. Very high raw CO₂ may justify physical solvents (e.g., Selexol) or hybrids. Emerging methods — membranes or ionic liquids — are under development but are not yet widespread upstream; in advanced fields, membrane pre‑removal of CO₂ ahead of amines can cut energy use (gasprocessingnews.com). In Indonesia, gas with >50% “impure” components often triggers a technical/economic study to justify sale or flaring under ESDM 17/2021 (flaringventingregulations.worldbank.org).
The bottom line on flaring
Maximizing capture and use of associated gas is technically feasible and frequently economic. The toolkit spans pipelines and re‑injection to FGRUs, on‑site power, LNG/CNG, GTL, and full‑spec processing trains. The emissions upside is immediate: one study estimates that converting a flare to productive use can reduce CO₂ by ~90% relative to flaring, while on‑site power from flare gas is “often economically justifiable” (www.sciencedirect.com) (www.sciencedirect.com). The constraint, as the IEA emphasizes, is infrastructure and policy — if there is no outlet, gas is flared or, worse, vented (www.iea.org).
With regulators pricing methane, the World Bank pushing Zero Routine Flaring by 2030, and case studies like Indonesia’s decline from 3.5 bcm (2012) to 1.7 bcm (2022), the path is clear: capture the gas, clean it, and sell it — so the world stops lighting billions on fire (flaringventingregulations.worldbank.org) (www.worldbank.org) (www.iea.org).
