Process Safety · Lesson 49 · 8 min read

A Vapour System Must Be Protected From Liquid Carryover

A vapour system is not automatically safe from liquid. When a separator, tower or drum overfills, liquid can enter piping and equipment designed for gas service. The event can damage compressors or burners, carry flammable material to unexpected locations, and create a difficult abnormal situation in which familiar indications no longer describe the real inventory.

How liquid crosses into a vapour system

Gas-liquid separation depends on available volume, stable interfaces, suitable internals, drainage and operation within the equipment's design envelope. High feed rate, foaming, slugging, blocked or restricted liquid outlets, incorrect valve line-up, failed level measurement, unsuitable control tuning or a changing fluid composition can reduce the margin before carryover.

Once liquid reaches a gas outlet, the hazard may travel. A compressor can experience damaging forces or loss of performance. A fuel-gas drum can send liquid toward furnaces or boilers. A vent, flare or drain arrangement can receive a composition and quantity outside the condition assumed by operators. The initiating vessel may still be pressurised, so draining without knowing the material and destination can create a second release path.

HSE's offshore guidance on changes from dry-gas to wet-gas operation warns that changing fluid condition can introduce release and integrity concerns that require safety and operating arrangements to be reconsidered. Liquid carryover is therefore not only an equipment-performance issue; it can defeat several downstream barriers at once.

Official incident: liquid filled a normally vapour-only drum

The U.S. Chemical Safety Board investigated the fatal 20 September 2022 fire at the BP-Husky refinery in Oregon, Ohio. During a prolonged process upset, liquid naphtha flowed into and filled a fuel-gas mix drum that normally contained fuel-gas vapour. The drum overflowed into vapour piping connected to furnaces and boilers, creating additional fire and explosion potential.

Workers later released liquid from the pressurised drum to the ground. CSB found that they may have believed it was an amine-water solution rather than flammable naphtha. The material vaporised, a flammable cloud formed and reached an ignition source. Two workers were fatally injured. CSB identified liquid-overflow prevention, abnormal-situation management, alarm flooding and learning from incidents as important safety issues.

This refinery event does not describe an FPSO design or procedure. Its transferable lesson is that teams must establish the real material, inventory, flow path and safe means of control. Urgency is not a substitute for a verified disposal route.

Hypothetical FPSO example: unexpected liquid reaches the gas system

Hypothetical example—not a documented incident: An FPSO compressor suction scrubber shows a rapidly rising level during a production upset. The normal level trend becomes uncertain, and vibration is reported downstream. The team does not assume the liquid is ordinary condensate or open a drain to an unverified destination.

They reduce and isolate the incoming source under approved procedures, confirm the actual process paths, identify the likely liquid from samples and operating history, verify the closed-drain or recovery route, and declare affected safeguards impaired. Restart is withheld until the cause, protective functions and downstream equipment condition are understood. This example supplies no universal trip level, response time or permission to drain hydrocarbons.

Critical controls

Define the overflow scenario. Process hazard reviews should trace where liquid goes if normal control fails during steady operation, startup, shutdown, slug arrival, foaming or utility loss. Include downstream vapour piping, compressors, fired equipment, relief systems and drains.

Maintain dependable level protection. Verify the sensing point, transmitter or switch, logic, alarms, shutdown action and final element. Protection should provide the risk reduction required by the approved design basis and should not be defeated by the same fault that causes the demand.

Protect separation performance. Keep vessels within their operating envelope, maintain internals and outlets, control solids and foaming, and challenge unexpected changes in interface, differential pressure, carryover or downstream vibration. Production stability does not prove effective separation.

Use a verified disposal route. Before removing unexpected liquid, identify what it is, the pressure and temperature, the receiving system's availability and capacity, and how transfer will be controlled. Never improvise an atmospheric release because the inventory is inconvenient or poorly understood.

Manage abnormal operation. Give operators clear shutdown criteria, prioritised alarms, accessible guidance and authority to reduce or stop feed. A long-running upset, repeated alarm or recurring liquid accumulation needs leadership attention before work becomes rushed field intervention.

Operational and leadership actions

Operators should compare level, pressure, flow, temperature, valve status and downstream behaviour rather than relying on one display. Unexpected liquid at a compressor, fuel-gas drum or vapour header should trigger early escalation and verification of upstream sources.

Leaders should confirm that overflow scenarios remain in current hazard reviews, protection is proof-tested end to end, safe drain destinations are available, and previous carryover events produced corrective action. When alarms or uncertain indications weaken decisions, leaders must support a controlled shutdown.

Three practical actions

• Trace the carryover path: choose one separator or drum and follow credible overflow into every downstream vapour user and disposal system.
• Prove the protection: review the latest end-to-end evidence for high-level detection, alarm or trip logic, final action and restoration after test.
• Verify the drain decision: confirm who must identify unexpected liquid, approve its destination and stop draining when conditions disagree with the plan.

Official video: Alarming Mistakes, Deadly Decisions

The official CSB video reconstructs the process upset, liquid overflow into the fuel-gas mix drum, alarm burden, field draining decision and fatal release. View the official CSB video page.

Takeaway and team discussion

Key takeaway: when liquid enters a vapour-only system, stop the source and verify the whole path before trying to remove the symptom.

Discussion question: which vapour-only system on our installation has the weakest current evidence that liquid carryover will be detected and stopped before it reaches downstream equipment?

Continue in the Process Safety hub, and connect this lesson with instrument reliability, independent overfill protection, alarm response and verified disposal paths.

Verified primary references

1. UK HSE: Health and safety issues associated with changes from dry gas to wet gas operation—official offshore guidance on reassessing integrity and operating risk when liquid enters a gas-service context.
2. UK HSE: Offshore process integrity—official framework covering hazard analysis, safe limits, plant protection, operations, instructions and training.
3. U.S. CSB: BP-Husky final investigation report—official analysis of liquid overflow, abnormal-situation management, alarm flooding and the fatal release.
4. U.S. CSB: BP-Husky recommendations—official recommendations addressing pressure-vessel overflow and fuel-gas mix-drum safeguards.
5. U.S. CSB official video: Alarming Mistakes, Deadly Decisions—official incident reconstruction released 1 October 2026.

Published and sources checked 31 October 2026. Educational discussion only: apply the installation's approved safety case, process design basis, performance standards, alarm philosophy, impairment controls and operating procedures. No universal level set point, shutdown time or permission to drain hydrocarbons is supplied.

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