• • Mercury occurs naturally in all hydrocarbons, even at trace levels (as low as 0.001 ppb in natural gas)
  • At cryogenic temperatures, mercury amalgamates with aluminum, causing rapid and catastrophic failure of brazed aluminum heat exchangers
  • Mercury also deactivates sulfur removal catalysts, driving down efficiency and accelerating costly replacements
  • ASTM D6350 is the gold standard for mercury analysis in natural gas, using atomic fluorescence spectroscopy (AFS) for detection down to 0.0001 ppb
  • SPL Energy Labs operates ASTM D6350-compliant sampling and analysis

The United States is the world’s largest natural gas producer and its leading LNG exporter. Infrastructure investment is accelerating to match that ambition. New liquefaction trains, pipeline expansions, and export terminals are coming online at a pace not seen in decades. And threaded through all of it is a contaminant so small it’s measured in parts per billion, or smaller, that has the potential to bring an entire facility to a halt.

That contaminant is Mercury.

Mercury Is More Than a Trace Concern
Mercury occurs naturally in organic matter. In crude oil, concentrations typically run between 2 and 100 ppb. In natural gas, the range is far lower, generally 0.001 to 0.2 ppb. Those numbers can make mercury feel like a footnote in a feed gas analysis report. But they obscure the severity of what even trace quantities can do inside an LNG facility.

The core problem is thermodynamic and metallurgical. To produce LNG, feed gas must be super-cooled to approximately -160°C. At cryogenic temperatures, elemental mercury amalgamates with aluminum, forming a mercury-aluminum alloy that aggressively degrades the base metal. The component most at risk: brazed aluminum heat exchangers (BAHX), the large, intricate cryogenic units at the heart of every NGL recovery unit and LNG liquefaction train.

BAHX failures attributed to mercury contamination are not theoretical. Several well-documented incidents at major LNG facilities, including sites in Algeria and Southeast Asia, have resulted in extended plant shutdowns, costly equipment replacement, and serious safety consequences. These are not recoverable events in the short term. BAHX units take months to replace and cost tens of millions of dollars. When mercury is the culprit, the damage is done before most operators know they have a problem.

Mercury creates a second, less catastrophic but equally costly issue further upstream: catalyst deactivation. Many natural gas processing facilities use catalyst beds to remove hydrogen sulfide and other sulfur compounds before the gas reaches the liquefaction stage. Mercury competes with sulfur for the active sites on these catalysts, binding irreversibly and reducing their effectiveness. The result is a catalyst bed that degrades faster than expected, requires more frequent replacement, and drives up operating costs on a recurring basis.

ASTM D6350: The Method That Makes the Data Reliable
The most accurate and widely recognized method for mercury measurement in natural gas is ASTM D6350, the Standard Test Method for Mercury Sampling and Analysis in Natural Gas by Atomic Fluorescence Spectroscopy.

The method covers both field sampling and laboratory analysis, which is important because representative sampling is often where mercury data goes wrong. The sampling procedure works by regulating the gas stream to 100 to 200 ml/min, purging the system for 30 minutes to eliminate carryover contamination from prior events, then directing the gas through two gold-coated silica sorbent filters connected in series. Mercury forms stable amalgams with gold, which efficiently captures it from the gas stream so it can be safely transported to the lab.

In the lab, the filters are analyzed one at a time using an atomic fluorescence spectroscopy (AFS) instrument. An argon carrier gas flows through the filter while the gold-mercury amalgam is heated to 500°C, releasing the mercury in vapor phase into the detector. The AFS instrument reads the resulting fluorescence signal, producing a chromatogram-style peak whose area and response factor are used to calculate mercury concentration. Results from both filters are summed and reported in micrograms per cubic meter.

The AFS detection approach has a meaningful technical advantage over the older atomic absorption spectroscopy (AAS) method used in ASTM D5954. AFS detectors are positioned at a 90-degree angle from the UV light source, measuring fluoresced photons directly. AAS detectors sit in line with the source, measuring attenuation, which requires Zeeman correction or split-beam compensation schemes to manage interferences. AFS sidesteps those compensation requirements entirely, making results more straightforward and less susceptible to analytical interference.
The method achieves a detection limit of 0.0001 ppb, well below the concentrations that cause operational problems, which gives operators the visibility they need at concentrations that actually matter.

So Where Does This Leave Operators?
If your facility handles natural gas destined for cryogenic processing, NGL recovery, or LNG production, mercury testing belongs in your analytical program.

SPL Energy Labs has invested in ASTM D6350-compliant mercury sampling and analysis capabilities across all of its facilities. Our teams participate in the ASTM D03 Gaseous Fuels committee that governs the method, which means our protocols stay current with evolving best practices, not just with what was written a decade ago.

If you haven’t characterized your feed gas mercury concentration, or if your last measurement was taken before a significant change in supply source or operating conditions, now is the time.

Ready to know what’s in your gas?

Contact SPL Energy Labs to learn more about ASTM D6350 mercury testing and what the results mean for your operation.