Send Us Your Dark, Your Complex, Your Viscous Samples! Our Headspace System is Now Patented.

 

We are proud to announce a new patent for our headspace sampling technology — the ultimate tool for analyzing opaque, complex liquids.

When we first started building analyzers, many customers asked if we could measure H2S in crude oil, frustrated with the unreliable products on the market. The fluid was far too dark and dirty to transmit the UV light pulse that our OMA analyzer used to measure chemical absorbance; we had a serious technical challenge on our hands.

The inspiration for the headspace design came from a very well-known unit operation in chemical engineering that had simply never been applied to measurement. Absorption/Desorption (A/D) is used widely in the chemical industry to separate entrained gases from liquids: most relevantly, oil refineries use A/D as a very stable process for removing H2S from incoming crude (our exact application on an industrial scale).

We built a vertical column that flowed crude oil against a counter current of nitrogen carrier gas, creating an equilibrium between phases and stripping out H2S molecules entrained in the oil. The resulting vapor exiting the column contained — thanks to Henry’s Law — an H2S concentration that could be reliably correlated with the H2S concentration in the oil pipeline.

The system worked beautifully, but we still had a long way to go. To ensure the column was breaking the oil and preventing any wax buildup, we redesigned the mass transfer media with Raschig rings that maximized liquid-gas contact. From working with an early customer who was measuring ammonia in filthy wastewater, we learned that the back-calculation from vapor phase concentration to liquid concentration was unnecessary: our verification readings provided an extremely stable linear correlation to the liquid analyte concentration which accounted for any hidden variables in the complex liquid.

Today, 20 years later, the headspace system is a perfect representation of our ethos at AAI: sound, creative engineering that evolves over decades of experimentation and customer experience. Our team is proud to be the legal owner of this invention, and the world’s sole provider of the headspace sampling technology.

Your friends at Applied Analytics

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What’s 19 inches wide and measures up to 5 chemicals at once?

Meet the OMA-406 Rackmount.
Our trusted OMA multi-component technology,
engineered to integrate perfectly into your analyzer house.

In this new video from AAI Engineering, let us show you around the OMA-406, covering:

Hardware

Software

Theory

Applications

Play Video or Read Specs

Need to take OMA on the road? Let us pack your suitcases.

OMA-206 Portable Analyzer

 

Portable Sampling System

AAI’s Complete Solution to Analysis of Total Sulfur and BTEX–Rising Volume of Natural Gas Exportation Requires Compositional Analysis and Control

LNG Process

Natural gas production has surged over the last decade with the discovery of large new gas wells and gas plant expansions. The abundance of natural gas reserves has led to low domestic trading prices and a need to export for all major natural gas producing countries. Natural gas is also viewed as a placeholder as political agendas are pushing for less reliance on coal and development of renewable energy technologies. U.S. News forecasts a “20% increase in demand for U.S. natural gas by 2020”. The U.S. is expected to be the third largest exporter of LNG by the end of the decade only behind Australia and Qatar.

For transportation and storage, natural gas is cooled and compressed into a liquid called liquefied natural gas (LNG). There is about a 600:1 volume change from gas phase to liquid phase which equates to more efficient use of storage and transportation resources for exporters. Contaminants in natural gas which need to be removed prior to liquefaction include Total sulfur and BTEX.

Increasingly strict reporting regulations and tariffs on the sulfur content of sales quality natural gas has boosted the need for analyzers with a fast response time and multi-component measurement capabilities. In addition, natural gas process producers often need to comply with contractual pipeline agreements and are interested in corrosion prevention on their liquefaction equipment.

Benzene, toluene and xylenes (BTEX) in pre-liquefied natural gas readily freezes at the cold temperatures required in the liquefaction process. The liquefaction equipment can become blocked or coated by these solids which requires shut down for maintenance. As a preemptive measure, LNG producers remove BTEX from the natural gas before liquefaction. Validation of the BTEX concentration in pre-liquefied natural gas ensures efficient BTEX removal to protect downstream equipment.

Applied Analytics offers an automated and continuous measurement solution for monitoring total sulfur and BTEX in pre-liquefied natural gas. Our equipment is designed with a focus on high accuracy, low maintenance and a fast response time. The OMA-300 is a complete solution for monitoring H2S, COS, MeSH, and EtSH to sum to a total sulfur measurement and determining BTEX concentrations in pre-liquefied natural gas.

Please see our video demonstrations of the applications:

Demo: Sulfur Measurements in Natural Gas

Demo: BTEX Measurements in Natural Gas

For more information on all our products and applications, please contact our sales team.

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

H2S and ions in water (animation)

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”