Global gas flaring hit 167 billion cubic meters in 2025, the highest level since 2019 and the third straight annual increase, according to the World Bank's 2026 Global Gas Flaring Tracker. Indonesia isn't among the nine countries responsible for 83 percent of that volume, but its own flare sites, roughly 189 of them as of the last full count, still represent gas that was paid for, produced, and then burned instead of sold, processed, or fed back into the plant. For reliability teams already stretched across aging platforms and declining fields, the question isn't whether flare gas recovery is worth pursuing. It's whether it gets built into the maintenance program or left to sit as a standalone environmental initiative that nobody owns when budgets tighten.

Why Flare Reduction Keeps Losing to Core Maintenance Priorities

Indonesia has actually made real progress on flaring. National volumes fell from 3.5 bcm in 2012 to 1.7 bcm in 2022, a decline of roughly 51 percent, outpacing the 30 percent drop in oil production over the same stretch. That trend reflects genuine investment in vapor recovery units, compressor upgrades, and gas utilization projects across mature fields. The problem is that most of this progress happened as capital projects, funded once, commissioned, and then handed to operations teams with no clear line item in the routine maintenance budget.

That handoff is where flare gas recovery systems quietly degrade. A vapor recovery compressor that isn't on the same PM schedule as the main gas compression train drifts out of calibration. A flare gas recovery unit's control valves foul with liquid carryover and nobody notices until the flare stack lights up during a routine upset, at which point the incident gets logged as a process event rather than a maintenance failure. Reliability engineers see this pattern constantly: the equipment that reduces emissions or recovers value is treated as bolt-on infrastructure, inspected less rigorously than the assets it's attached to, because it doesn't sit on the critical path for production.

Regulation should have closed this gap. ESDM 17/2021 replaced the older ESDM 31/2012 framework and set flaring limits at 2 mmscf per day, averaged over six months, for oil fields, and 3 percent of daily feed gas volume for gas fields. Operators had two years to comply. But a compliance limit measured as a rolling average doesn't create daily operational discipline. It creates a reporting exercise that runs parallel to, rather than through, the CMMS.

Building Flare Gas Recovery Into the Core Maintenance Program

The fix is straightforward in concept and genuinely difficult in execution: treat flare gas recovery and energy efficiency assets as production equipment, not environmental add-ons, and manage them with the same rigor.

Asset criticality reclassification.

Most CMMS platforms still tag vapor recovery units, flare knockout drums, and waste heat recovery skids as auxiliary or non-critical equipment. That classification drives PM frequency, spare parts stocking, and response priority downward. Reclassifying these assets based on the actual financial and regulatory exposure they carry, not their position in the process flow diagram, changes how they get resourced. A flare gas compressor recovering 2 million standard cubic feet a day at even a conservative domestic gas price represents real monthly revenue at stake, comparable to a mid-sized rotating asset elsewhere in the plant.

Condition monitoring parity.

If the main gas compression train gets vibration analysis, oil sampling, and thermographic inspection on a defined cycle, the recovery compressor feeding off the same header should get the same treatment. This is a low-cost extension for teams that already run condition-based maintenance programs; it mainly requires adding these assets to the existing route rather than building new capability.

Corrosion and integrity tie-in.

Flare systems handle intermittent, two-phase, sometimes corrosive flow that's harder on piping and valves than steady-state production streams. Folding flare header inspection into existing risk-based inspection (RBI) programs, rather than running it as a separate environmental compliance check, catches wall-thinning and valve degradation before it becomes an unplanned flaring event that draws regulatory attention.

Energy efficiency retrofits as maintenance-funded projects.

Waste heat recovery on gas turbine exhaust, insulation upgrades on steam systems, and variable frequency drives on pumps and compressors all reduce fuel gas consumption, which directly reduces the volume available to flare during upsets. When these projects are funded and tracked through the maintenance capital plan instead of a separate sustainability budget, they get maintained with the same discipline as any other reliability improvement, and the savings show up in the same operating cost reports management already reviews.

What the Data Actually Shows When You Track It Properly

Teams that have integrated flare monitoring into their reliability programs report a consistent pattern: unplanned flaring events cluster around specific failure modes rather than random process upsets. Compressor trips account for a disproportionate share, followed by control valve failures on recovery lines and instrumentation faults that trigger unnecessary flaring as a safety default. This is diagnostic information, not just an emissions number.

• Compressor-related trips: typically the largest single category of unplanned flaring volume in fields with vapor recovery systems
• Control valve and instrumentation faults: second largest category, often tied to liquid carryover or sensor drift
• Planned turnaround flaring: predictable and manageable through sequencing, but frequently underestimated in TAR planning
• Third-party or upstream supply disruptions: smaller in frequency but often the largest single-event volumes

Once flaring events are categorized this way, the maintenance team has an actual work list instead of a compliance report. Compressor reliability improvements, valve upgrades, and instrumentation calibration cycles can be prioritized against real flaring volume reduction, which is a far more useful basis for capital requests than a generic emissions target.

Where This Goes as Indonesia's Upstream Sector Expands

The government's push to reactivate around 5,000 idle wells and add 200,000 barrels per day of output, alongside plans to bring new blocks online through 2028, means more wellhead gas entering systems that already have flaring exposure. Every new tie-in is a chance to build flare gas recovery into the design basis rather than retrofit it later, and every reactivated well is an opportunity to size gathering and processing capacity so associated gas doesn't default to the flare during commissioning.

For reliability leaders, the practical move is to get ahead of this now. Pull flare event logs alongside maintenance work order history and map the correlation. Identify which recovery assets are still classified as non-critical in the CMMS and push for reclassification with a cost-of-flared-gas justification attached. Bring the energy efficiency retrofit backlog into the same capital planning cycle as core reliability projects instead of running it through a separate sustainability committee. None of this requires new technology or a large standalone budget. It requires treating gas that's already been paid for as an asset worth protecting with the same discipline applied to everything else on the plant.

References

• 2026 Global Gas Flaring Tracker Report, World Bank (2026)
• Indonesia country flaring data, World Bank Flaring and Venting Regulations Database (2024)
• Indonesia's Oil and Gas Reforms: Reactivating Idle Wells and Boosting Energy Security Amidst Decarbonization Goals, Enerdata (2026)

Author: Jen Megah Bremanda Sembiring (Reliability Engineer)

Clarification Note: This article was developed with AI assistance for drafting, research support, and language refinement. The topic framework, technical direction, and key points presented were determined by the author.