Is there a specific standard limiting the use of radar for point level measurement? Some oil and gas companies does not accept this practice.

 

Radar, whether guided wave (rod or rope), pulse (non-contact) or FMCW (non-contact) by nature, provides a continuous level signal. I suppose somewhere in the world, some vendor could offer a point level radar, but I haven't run into it yet.

Is the O&G prohibition based on using continuous radar and calling it point level because there's a relay output with a level setpoint?

Many places want a different technology for point level than for continuous for the sake of diversity. to avoid common-mode failures.

 

O&G industry is rather conservative and hooked to "good old times" practices: still today differential pressure is the benchmark against more up to date technologies. I don't beleieve any standard states explicitly such limitation
Some manufacturers provide radars with double output: continuous analog or fieldbus plus digital switch programmable for limit point level
Then, W&M certified Tank Gauging radars can have up to 6 safety relays, SIL2/3 compliants
Another example: European directive UNI EN 12952 for water-tube boilers allows the use of GWRs in 2oo3 architecture for conti, LL and HL

 

I am from Oil & Gas industry. As far as I know there is no such prohibition in the industry. It all depends on the application. May be the application you are indicating doesn't allow GWR or non-contact level to use technically. If you can give more details about the application then we may see if there is any difficulty to use radar there.
If there is no such difficulties then continuous radar level measurement with software alarm at the switching point height is more convenient since tomorrow if you want to change the switching point that is easily possible with the same arrangement.

 

Hi Andy,

That's a great question. While radar level measurement is widely used for continuous level monitoring, its application for point level detection does raise concerns in some industries—especially oil and gas—due to potential safety standards, environmental factors, or company-specific protocols.

In many cases, companies may prefer guided wave radar or even traditional technologies like tuning forks and floats for point-level applications where a simple high/low threshold is needed. This preference often stems from factors like dielectric constant of the product, tank geometry, or the criticality of the alarm point in safety systems (like SIL-rated systems).

On a related note, we’ve been exploring how Building Information Modeling (BIM) can help standardize and simulate such instrumentation setups in complex oil and gas facilities—especially during retrofit or brownfield projects. It’s proving valuable in visualizing component placements, clash detection, and ensuring compliance with operational standards.

 

Is there a specific standard limiting the use of radar for point level measurement? Some oil and gas companies does not accept this practice.

While radar level measurement offers many benefits—high accuracy, noncontact operation, immunity to vapor, foam, temperature and pressure changes—it is not universally accepted due to some practical and regulatory limitations:

• Standards & Accuracy Demands
  Custody transfer in oil and gas often requires tight manual verification—e.g., API MPMS Chapter 18.1 mandates three consecutive manual readings within 0.25 inches. Only guided-wave radar (GWR) reliably meets such precision (±0.125 inches) and can handle interface detection (e.g., oil–water) when properly configured.
• Installation & Process Constraints
  Radar performance can degrade due to poor installation—such as bent still-pipes, obstructions, or nozzle geometry mismatches—and by process conditions like foam, emulsion layers, or low-dielectric, turbulent liquids.
• Special Regulations for Floating‐Roof Tanks
  In the U.S., radar on external floating-roof tanks may need FCC Part 90 licensing and special design elements (like horizontal reflectors) to ensure accuracy

 

While radar level measurement offers many benefits—high accuracy, noncontact operation, immunity to vapor, foam, temperature and pressure changes—it is not universally accepted due to some practical and regulatory limitations:

• Standards & Accuracy Demands
  Custody transfer in oil and gas often requires tight manual verification—e.g., API MPMS Chapter 18.1 mandates three consecutive manual readings within 0.25 inches. Only guided-wave radar (GWR) reliably meets such precision (±0.125 inches) and can handle interface detection (e.g., oil–water) when properly configured.
• Installation & Process Constraints
  Radar performance can degrade due to poor installation—such as bent still-pipes, obstructions, or nozzle geometry mismatches—and by process conditions like foam, emulsion layers, or low-dielectric, turbulent liquids.
• Special Regulations for Floating‐Roof Tanks
  In the U.S., radar on external floating-roof tanks may need FCC Part 90 licensing and special design elements (like horizontal reflectors) to ensure accuracy

I have some doubts on above statements. Best GWRs radars on the market achieve +/- 2 mm (0,08 inches) in reference conditions. But this is still not sufficient in custody transfer where all standards (API, ISO, OIML) requires +/- 1 mm in refernce conditions or +/- 3 mm on field. Good Custody transfer Tank Gauging radars achieve +/- 0,5 mm in reference conditions. Servo displacers can even reach +/- 0.4 mm

 

All instruments work well when tested in ideal conditions. Of course in actual service all bets and claims are at best provisional.