Natural Gas & The Smell of Safety

natural gas and the smell of safety

Why measure odorant level in natural gas?

Unlike modern industrial zones, where safety regulations demand constant monitoring of ambient gases, people in residential areas typically have only one recourse for detecting natural gas buildup: their noses.

On its own, natural gas is technically odorless. The distinctive smell is artificially added solely for the purpose of human detection: US law, for example, requires that all natural gas be detectable by a human with a normal sense of smell when the gas concentration exceeds 1/5 of its lower explosive limit (LEL), i.e. well below the threshold at which natural gas can ignite in air.

To odorize the natural gas, distribution companies inject chemical odorants (typically blends of mercaptans) into their pipeline system. This injection is a sensitive procedure: too little odorant makes the gas unsafe for distribution, but too much odorant makes the product overly unpleasant and wastes resources.

In order to monitor the odorant level in natural gas, distributors have traditionally dispatched designated “sniffers” – humans who sniff gas samples and assess odor rating at a specific pipeline sampling point. Aside from being an unhealthy practice, this method is imperfect because sniffers are subjective; humans can have inconsistent olfactory response due to diet, sickness, or developed tolerance. Even the most objective sniffers will be thwarted by chemical phenomena in the pipeline such as adsorption or odorant fading/masking.

The future of odorant analysis

With safety regulations growing increasingly stringent, many pipeline operators are turning to modern analytical methods to supplement or replace the human sniffer method. Using dispersive UV-Vis absorbance spectrophotometry, the OMA-300 measures the concentration of up to 5 odorant species simultaneously in a continuously drawn natural gas sample.

Critical advantages of the OMA over human sniffing include (1) objective analysis normalized regularly by Automatic Zero; (2) 24-hour analysis for rich trend data; (3) fast response to sudden changes in odorant level; (4) reduced exposure of humans to toxic samples; (5) reduced cost of operation by slashing travel time and workload of human sniffers.

The safety of OMA

Watch this video demo which explains why the OMA is the world’s safest online analyzer for toxic sulfur compounds such as the species monitored in odorant analysis.

More information
1. Application Note   2. OMA Series 

Our Tail Gas Probe v3 Now Available!

Tail Gas Probe v3

Since 2014, we have been field-testing a major update to the probe design for our TLG-837 Tail Gas Analyzer — the most trusted H2S/SO2 ratio monitor in the sulfur recovery industry. We are excited to announce the official launch of DEMISTER Probe v3!

The New Isolation Valve

On previous probe versions, the ball valve allows the user to retract the probe from the process pipe to perform maintenance. In DEMISTER Probe v3, we introduced a bonnet-style shutoff valve directly in the probe head with which you can internally seal the process at the sample entrance port. This safe, quick method to access the sample flow cell completely eliminates the need to retract the probe during maintenance!

Our case studies exceeded our own expectations: engineers reported that the maintenance procedure of cleaning the optics (recommended monthly) is 75% faster when using the isolation valve than when retracting the probe.

Redesigned Cooling Extensions

On the TLG-837, the cooling extensions increase the distance between the fiber optic collimators and the flow cell, protecting the optics from damage due to conductive heat transfer. Thanks to user feedback, we relocated the sealing o-rings from the probe head to the body of the removable cooling extension itself, making them much more accessible for routine inspections. Don’t worry — the new cooling extensions retrofit into all of our previous DEMISTER Probe versions.

No other tail gas analyzer manufacturer takes the needs of the user as seriously as we do. We are now shipping the best version of the safest, most advanced tail gas analyzer in the world.

Get in touch with us today to learn more about DEMISTER Probe v3.

Featured Application: Photometric Color Analysis

pass-fail color analysis
Pass-fail photometric color analysis

Earlier in 2016, our team collaborated with a Great Lakes-region paints and coating manufacturer to produce a highly specialized solution for analyzing paint mixing bases. We calibrated an OMA-300 Color Analyzer to give a pass/fail reading on over 50 different paint mixing bases, allowing the manufacturer to rapidly correct product quality issues.

Running a custom software build set to streamline cuvette measurements, the system logs the quality data for each run. The OMA provided the team at the manufacturer with a fully-automated quantitative color measurement and rich, continuous data about product quality variance.

It also demonstrated the intrinsic flexibility of the OMA Color Analyzer, which can handle custom calibrations as easily as industry standards like APHA and Saybolt.

OMA InGaAs version released! Many new applications including Wobbe Index

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We’re proud to announce the new InGaAs version of the highly successful OMA analyzer platform, adding hundreds of measurement applications to the OMA’s domain. The first product to use this technology is the OMA Wobbe Index Analyzer, the world’s only all-optical solution for measuring interchangeability of natural gas.

InGaAs Technology

The infrared-range sensor inside the InGaAs OMA capitalizes on recent major advancements in InGaAs (indium gallium arsenide) semiconductor technology to provide accuracy equivalent to gas chromatography at far lower manufacturing costs and operational complexity. Joining the UV-Vis and the SW-NIR versions of the OMA, the InGaAs model monitors real-time sample absorbance from 1550 to 1850 nm, targeting alkane hydrocarbons and other molecules that were previously out of reach for the OMA platform.

The New OMA Wobbe Index Analyzer

One of the major verified applications for the new InGaAs-driven system is the online measurement of Wobbe Index in natural gas, which allows operators to quickly determine the interchangeability of gases. This measurement has historically been performed through residual oxygen analysis, a complex method involving burning precise amounts of the sample fluid and measuring the unused oxygen to indirectly derive the Wobbe number.

The OMA Wobbe Index Analyzer shifts the paradigm for this application as the first entirely optical solution: the system measures the concentrations of each Wobbe-contributing component in the natural gas (typically methane and ethane) and directly derive the gas density as well as the real-time Wobbe number.

Since most conventional Wobbe Index monitors on the market are designed and priced very similarly to Applied Analytics’ own legacy CVA-100 model (combustion-based), the OMA Wobbe Index Analyzer’s performance was benchmarked against this system during development. Under eligible stream conditions, the OMA provides superior accuracy and faster response time than the CVA-100, promising a more reliable measurement at a fraction of the end user price.

Announcing Remote Support! Instant Help with Your AAI Analyzers

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Remote Support

Did you know? Our engineers can log in to your Applied Analytics analyzers remotely to perform various tasks.

Do you need your analyzer calibrated for a new measurement range? Need a walkthrough for how to zero your analyzer? If your system is configured with software-operated relays, our engineers can even turn the valves on your sampling system remotely!

Best of all, we can service your analyzer with no travel delay. Continue reading “Announcing Remote Support! Instant Help with Your AAI Analyzers”

pH-Independent Measurement of Hydrogen Sulfide in Liquids

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You’ve been measuring H2S in Water the Wrong Way

Measuring hydrogen sulfide concentration in a pH-volatile liquid (such as water) is much more difficult than in a medium like natural gas. As the pH increases, the H2S dissociates into its ions HS (bisulfide) and S2- (sulfide), which are not measured by a typical H2S sensor. A reading that doesn’t account for the presence of these other ionic forms is meaningless at high pH because it would grossly understate the total H2S loading of the fluid when the pH drops. Continue reading “pH-Independent Measurement of Hydrogen Sulfide in Liquids”

Get an Inside Look at our Patented DEMISTER Probe Technology

TLG-837 DEMISTER Sampling Probe Animation

In a new demo from our design department, we answer some common questions about one of our most innovative products: the sulfur mist-removing DEMISTER Probe.

This device solves a very specific and persistent problem in sulfur recovery optimization: how do you obtain a sample from Claus process tail gas without sulfur mist plugging your instrument? Our demo will show you how our in situ probe uses steam to selectively condense elemental sulfur right at the tapping point, eradicating the problem of sulfur mist.

Continue reading “Get an Inside Look at our Patented DEMISTER Probe Technology”

Why Measure Chromium Concentration in Liquids?

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Hexavalent Chromium Contamination

In 1952, Pacific Gas & Electric (PG&E) started adding hexavalent chromium (Cr6+) to cooling water in order to suppress rust in a Hinkley, California compressor station. The toxic metal was stored in unlined pools, allowed to percolate into the ground and contaminate the water supply. Unexplained illnesses (including respiratory cancer and organ damage) in the town sparked an investigation (as dramatized in the film Erin Brockovich), ultimately resulting in a blockbuster settlement of $333M in 1996.

The Cr6+ levels in Hinkley groundwater were reported at 0.58 ppm in 1993, high above the 0.1 ppm legal limit of the time; due to widespread violations exposed since the Hinkley case, some states are planning to implement Cr6+limits as low as 0.06 ppb. A 2010 study found that 21 US cities suffered from chromium-contaminated groundwater. There is currently no enforced contamination limit for Cr6+ in drinking water, but legislation for this purpose is in progress. Continue reading “Why Measure Chromium Concentration in Liquids?”

Crude Oil Is Getting More Sour. Are Your H2S Analyzers Ready?

Applied Analytics H2S in Crude Oil Analyzer

Crude Oil is Getting More Sour

The ‘sourness’ of crude oil technically refers to its hydrogen sulfide (H2S) content before processing. Crude can naturally contain up to 14% sulfur content by weight, but this percentage is comprised of myriad sulfur compounds; only a small ratio is H2S. Unfortunately, even very low levels of H2S in crude can cause excessive corrosion and degrade catalysts in the refinery. Continue reading “Crude Oil Is Getting More Sour. Are Your H2S Analyzers Ready?”