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Reminder: ACHEMA in 2 Weeks!
Visit the Applied Analytics team at ACHEMA to get your free t-shirt!
Don't miss out -- we'll be showcasing our patented DEMISTER Probe and new products at our booth.
The details:
Hall 4.2 Stand N77
June 15 - 19 Frankfurt am Main, Germany
Get an Inside Look at our Patented DEMISTER Probe Technology
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. Other solutions are bulky, restrictive in how they can be installed, and require electricity / sample lines. The DEMISTER Probe is less than half the weight of its leading competitor, requires only steam for demisting, and allows for 6 meters of fiber optic distance to the analyzer. Click the demo below to learn how this sampling design functions and perfectly complements our UV-Vis spectrophotometric analysis technology.
Looking for more info on the DEMISTER Probe or our TLG-837 Tail Gas Analyzer?
Check out more of our product demos on our Vimeo channel.
Happy Lunar New Year!
Sulfur in the News - From the Farthest Reaches of Our Solar System to Our Backyard
Rosetta Mission
Last month, the European Space Agency landed an analyzer-sized probe (Philae) on a comet known as Comet 67P. This was the first time humanity had ever soft-landed an object on a comet. The Rosetta orbiter, the probe’s delivery vehicle, travelled more than 6.4 billion miles to rendezvous with the galactic iceberg. An all-around groundbreaking achievement. Scientists are using Rosetta and Philae to study, among other things, the chemistry of comets. Based on previous measurements from telescopes, we know the nuclei of comets are made up mostly of dust, rock, and water ice. Small amounts of organic compounds such as hydrogen cyanide (HCN), formaldehyde (CH2O), mercaptans, and aromatics are also present. Earlier this fall, while orbiting Comet 67P, the mass spectrometers onboard Rosetta detected the presence of Hydrogen Sulfide (H2S), Sulfur Dioxide (SO2), and Carbon Disulfide (CS2). It seems that the need for sulfur analyzers is not bound to the earth, or even our solar system!
Moscow “Mystery” Fog
A massive “hellish” cloud engulfed the Russian Capitol for a day last month. The mysterious cloud of odorous gas and smoke filled the air in the early morning. Its sudden appearance triggered an uproar on social media, where Muscovites scrambled to notify others and find answers. One resident tweeted, “Guys, who knows what the reason for such a stink in Moscow?” Despite recommendations from the local authorities to stay indoors and close their windows, residents still could not escape the pungent smell. “The smell even travels through closed windows” tweeted another local Russian. Even politicians working in the Russian parliament noted the stench. All who experienced the cloud described it as an intense, rotten egg odor. The smelly cloud’s source was later confirmed to be a major leak at a nearby sulfur recovery plant. Environmental authorities confirmed the cloud was made up primarily of Hydrogen Sulfide (H2S) and Sulfur Dioxide (SO2). Both sulfur compounds are common in the processing of fossil fuels. They are both pollutants, toxic to humans, and exhibit a rotten egg odor.
Measuring Sulfur Compounds with the AAI Process Analyzers
Both of these stories remind us that sulfur compounds are everywhere, from our back yard to the farthest reaches of the solar system. Every day here at Applied Analytics, we deliver equipment for measuring sulfur compounds across the globe. Hydrogen Sulfide (H2S) and Sulfur Dioxide (SO2) occur abundantly in fossil fuel reserves and are produced by various biological processes. In order to generate clean-burning fuels, prevent acid rain, protect pipelines from corrosion, and keep workers safe from disaster, H2S and SO2 levels are constantly monitored and controlled in refineries and sulfur recovery plants. Built around a high-resolution UV-Vis spectrophotometer, the OMA-300 monitors the absorbance of a liquid or gas sample and outputs real-time concentration readings. Using fiber optics to transmit the signal to and from the sample, the OMA-300 design is inherently safe and convenient. The TLG-837 Tail Gas analyzer takes this measurement technique a step further. The TLG-837 is a solid state, in situ solution for monitoring Claus process efficiency in the Sulfur Recovery Unit. The critical point of innovation is the patented in situ probe, which automatically condenses sulfur vapor out of the sample gas in a controlled manner, thereby neutralizing the problem that cripples most tail gas analyzers. AAI process analyzers are exceptionally versatile devices, capable of measuring hundreds of different compounds in many harsh and demanding environments. Who knows, someday soon we might move beyond measuring sulfur compounds at your local refinery and start measuring chemicals beyond the confines of earth!
Watch Our Newly Released OMA-300 Demo Video
Video: an engineer demonstrating the OMA-300 UV-VIS process analyzer.
Why Measure Chromium Concentration in Liquids?
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.
HOW IS CHROMIUM MEASURED?
There are various methods for measuring chromium, but most are difficult to operate because they require titrations, pulling samples, and/or extensive training. US EPA Method 218.6 calls for ion chromatography to separate the chromate out from the sample and optical analysis under very strict sample conditions.
Using a high-resolution UV-Vis spectrophotometer, the OMA-300 Metal Ion Analyzer provides an automated chromium measurement in real time. Much easier to operate than ion chromatography and colorimetric systems, the OMA defeats cross-interference between metals by using data-driven multi-component analysis. Water backgrounds are transparent in the UV wavelength domain, making the OMA ideal for environmental applications.
Absorbance Curve of Hexavalent Chromium (Source: OMA-300 Process Analyzer)
Due to the strong UV-Vis absorbance curve of Cr6+, the OMA can be used to monitor either low contamination (i.e. continuous groundwater analysis) or higher concentrations. High chromium measurement is particularly useful for electroplating applications where resource loss in the plating bath translates directly to financial losses; in these cases, the bath composition can be kept constant using vigilant chemical monitoring.
Crude Oil Is Getting More Sour. Are Your H2S Analyzers Ready?
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.
The reasons why one source of crude would be sour (e.g. Venezuelan crude) and another source would be sweet (e.g. Libyan crude) are complex. The sulfurization of crude occurred during its initial formation, when ancient kerogen (decomposed organic matter which has polymerized) was cooked into oil by subterranean heat; the sulfur content of the living matter in that region was thus transferred to the oil reserve. Another sulfur enrichment factor is the presence of special hydrocarbon-degrading bacteria known as OHCB which reduce the hydrocarbon:sulfur ratio. The concentration of H2S in the crude rises with overall sulfur content, and thermal reactions (both geologic and during refining) can produce H2S from reactions with elemental sulfur and decomposition of unstable sulfur compounds.
Regardless of the complex reasons why, the trend is clear. The crude oil coming out of our world's reserves is growing increasingly sour:
U.S. Sulfur Content (Weighted Average) of Crude Oil Input to Refineries (%) Source: Energy Information Administration
While the trend in the US is offset by the sweet, light crude being produced from shale plays, American oil refineries have spent decades optimizing their operations for the inexorable rise of sour, heavy crude, making it highly impractical for these refineries to start inputting sweet crude. This is why US oil companies are pushing for the export ban to be lifted--they can make more money selling the high-quality light crude to overseas refiners while importing cheaper sour crude.
THE NEED FOR BETTER H2S-IN-CRUDE ANALYTICS
In aggregate, and especially noticeable in countries that have historically refined sour crude, the oil input is containing increasing levels of H2S. The H2S concentration in crude oil is of great concern to anyone transporting that oil in their pipelines, buying oil of a certain sourness specification from a producer, or receiving that oil as feed to a refinery. While the oil industry is driven by incredibly advanced technology and innovation, this critical metric is often handled by the archaic paper tape technology developed in the 1950's. This method requires a lot of user maintenance, from replacing the tape drives to diluting the sample, and stands stubbornly against the growing automation of petroleum processing.
USING OMA HEADSPACE TECHNOLOGY FOR H2S-IN-CRUDE MEASUREMENT
The OMA H2S Analyzer is a totally solid state, automated solution for real-time H2S-in-crude monitoring. This system uses a high-resolution UV-Vis spectrophotometer to measure the absorbance curve of hydrogen sulfide in the 200-300nm range; since crude oil is too opaque to transmit a light signal, Applied Analytics' unique 'headspace' sample conditioner heats the crude oil and flows in a carrier gas to produce a vapor-phase sample. In accordance with Henry's Law, the measured H2S concentration in the vapor is correlated to the concentration in the crude oil, providing an extremely accurate, fast analysis.
Find out how to replace your paper tape with an automated OMA solution today.
(Applied Analytics Headspace Technology Demo)
Why Measure Bisphenol A Continuously in Effluent Water?
The BPA Controversy, In Brief The international fight over banning Bisphenol A from use in consumer products has now spanned decades with no sign of either side backing down. BPA is known to mimic estrogen in the human body, but the strength of its effects and the levels of real exposure are heavily disputed. Studies have variably linked BPA to male infertility, breast cancer, and behavioral disorders, fueling concern among the scientific community and wary shoppers alike.
However, BPA is quite entrenched as industry's chemical of choice for strengthening polycarbonate plastics and producing resins—4.6 million tons of it were manufactured globally in 2012, a figure that will only rise with demand from emerging markets. While some regulatory legislation has been successful, particularly in banning BPA-constructed baby bottles due to infants' heightened susceptibility to low-dose effects, we still live in a world that will likely continue producing BPA on a massive scale for decades to come. The question, then, is what can we do to effectively mitigate exposure in our communities?
Why Measure BPA Online in Effluent Water? The public debate generally centers on how much BPA leaches out of our food and beverage packaging into our diets. This testing is the realm of research institutes and, while extremely necessary, does not answer the whole question.
We are addressing an entirely separate but critical measurement: continuous analysis of the effluent from BPA production sites (primarily polycarbonate plants) to ensure that the chemical is not leaking into our environment. For these factories, BPA is a valuable raw material and not to be wasted, but real-world processes have upsets and inefficiencies that can translate into a toxic effluent stream. If BPA can enter waterways and ecosystems through this point source origin, then leachate from our bottles and cans is only one piece of the exposure puzzle.
The research on how easily BPA biodegrades in natural waters is contentious. In streams where the microbes are sufficiently acclimated, BPA can have a half-life of a few days to a week. Wastewater treatment plants that accept the BPA-laden effluent depend on acclimated microbes to break down the chemical, where biodegradation up to 90% is expected as a best case. When the concentration of BPA spikes above the threshold that this treatment is designed for, much greater breakthrough can be expected.
How can we be sure that our methods of cleaning up point source BPA waste are working? As usual in our newsletters, the answer is continuous chemical analysis. Measurement of BPA concentration in the effluent of production sites is a critical line of defense against exposure and merits just as much vigilance as the fight against leach-prone consumer products.
The Method Luckily, Bisphenol A has strong absorbance in the UV region (where water is transparent). Therefore, the concentration of BPA in effluent can easily be monitored by UV spectroscopy.
The OMA Process Analyzer uses a high-resolution UV-Vis spectrophotometer to measure BPA concentration in real time. With a rugged, solid-state design and simple, automated performance, the OMA provides a low-cost solution for implementing the much-needed effluent analysis. Due to the intrinsically wide dynamic range of the technology, the same instrument can monitor low range (0-20 ppm), high range (0-100%), or anything in between with seamless accuracy.
In the specific application of measuring BPA in water, the pH of the stream normally complicates the analysis. Depending on the acidity of the stream, the chemical exists as an acid or a salt, each of which has a unique absorbance spectrum. Less intelligent systems require the operator to adjust the pH with consumables and thus kill the variation. Using powerful multi-component analysis, the OMA simultaneously monitors the absorbance curves of both forms of Bisphenol A. This approach provides a direct, pH-independent analysis with a drastically reduced margin of error.
Will Li-S Batteries Change the Economics of Sulfur Recovery?
The Advent of Lithium-Sulfur Batteries
With slow progress in electric vehicle driving range and smartphone stamina, the limitations of current lithium-ion (Li-ion) batteries have become glaring. First commercialized by Sony in 1991, the now dominant Li-ion technology is struggling to improve the performance of the existing chemistry, its incremental gains outpaced by consumer demand. As the next breakthrough in battery design is hotly anticipated, one technology shines with promise due to superior performance and the practicality of its materials: Li-S.
The lithium-sulfur (Li-S) battery design provides a theoretical energy density (amount of energy stored per volume) which is five times that of Li-ion. Despite sharing an element, the chemistry is quite different: while Li-ion depends on the intercalation of current-carrying Li+ ions into the graphite layers of its carbon electrode during charge, the Li-S battery uses a sulfur-based electrode where Li+ ions react (reversibly) to produce lithium polysulfides, decreasing in state from Li2S8 to Li2S as the battery is discharged. The energy density of the Li-S system is higher because the reaction assimilates more Li+ ions per host atom than the carbon intercalation used in Li-ion.
While the Li-S concept has been kicked around since the 1970’s, poor endurance and safety prevented commercialization—until now. In the past, the biggest problem was that intermediate polysulfides (with more than two sulfur atoms) are soluble in the liquid electrolytes; in other words, the transport medium which allows ion flow between the electrodes also dissolves part of the sulfur electrode, irreversibly decreasing the useful sulfur material in the battery and causing fast degradation. Recent developments (including a new solid electrolyte and the use of nanocomposite material which protects the sulfur from electrolyte contact) have nearly realized the goal of an Li-S battery that survives as many charge cycles as Li-ion and meets flammability regulations.
The implications of Li-S inheriting the battery crown stretch beyond tech because of the materials used. Much publicized is the fact that this technology repurposes the elemental sulfur waste product generated by refining petroleum. While this will surely make the battery cheaper to produce, what effect could it have on the global sulfur market?
When the Battery Industry Meets Sulfur Recovery
The refining of crude oil and gas requires the removal of naturally occurring (and extremely toxic) H2S; this removed stream (known as acid gas) must undergo Claus processing to convert the H2S to harmless elemental sulfur. Enormous amounts of sulfur are generated by this process: the Alberta oil sands operations (1.6 million bpd) produce 1.5 million tons per year of sulfur. While there is significant global demand for sulfur, the price fluctuates heavily, such that the sulfur buildup often presents the refinery with an unwanted storage and transportation headache.
If Li-S technology successfully replaces Li-ion, the battery industry will have heavy demand for sulfur. As a precedent, rechargeable batteries accounted for roughly 27% of global lithium consumption last year, up from 8% in 2002. Moreover, if electric vehicle production soars on the heels of Li-S batteries (due to huge increases in drive distance between charges), this sector will introduce sulfur demand faster than any other. To give a sense of the electrode material required for this use, a current Li-ion battery for an electric vehicle consumes up to 40kg of lithium carbonate equivalent, compared with 30-40g in a laptop battery. Ironically, a future of Li-S powered vehicles will significantly increase revenue from recovered sulfur while potentially reducing dependence on petroleum in the transportation sector.
Global oversupply of sulfur is looming due to increased fossil fuel refining while traditional sulfur markets are not growing fast enough to match. The agrochemical industry, which uses sulfuric acid to produce phosphate fertilizers and accounts for 46% of global sulfur consumption, has cyclical demand which contributes to unstable sulfur pricing (fluctuating between $800/t and zero in the past few years).
Given this volatility, it makes sense that refineries have been reluctant to put effort into selling and transporting recovered sulfur—it’s viewed as overhead. It also illuminates how new, steady demand from Li-S batteries could change the economics of sulfur recovery, adding a highly reliable financial incentive to offset the cost of an incredibly important, environment-preserving process.
Our Role in Sulfur Recovery
Applied Analytics provides the process analyzers which are necessary to optimize the Claus process and maintain high conversion efficiency to elemental sulfur. Our flagship solutions include tail gas analysis for measuring the H2S/SO2 ratio in the catalytic step, feed forward analysis for measuring H2S level in the feed gas, and sulfur pit analysis for detecting fires and other hazards.
Since sulfur recovery units (SRU’s) are our biggest customers, we strive to think like SRU operators and anticipate their future concerns so that we can best serve their analysis needs.
More Information
OMA H2S Analyzer
TLG-837 Tail Gas Analyzer
TLG-837 Sulfur Pit Analyzer
References
1. Sheng S. Zhang, Liquid electrolyte lithium/sulfur battery: Fundamental chemistry, problems, and solutions, Journal of Power Sources, Volume 231, 1 June 2013, Pages 153-162. 2. Tudron, Frank B., James R. Akridge, and Vincent J. Puglisi. Lithium-Sulfur Rechargeable Batteries: Characteristics, State of Development, and Applicability to Powering Portable Electronics. Tech. Tuscon: n.p., 2004. Sion Power Corporation. 3. Bullis, Kevin. "Materials Boost Lithium-Ion Battery Storage." MIT Technology Review. 22 May 2009. 4. James R. Akridge, Yuriy V. Mikhaylik, Neal White, Li/S fundamental chemistry and application to high-performance rechargeable batteries, Solid State Ionics, Volume 175, Issues 1–4, 30 November 2004, Pages 243-245. 5. "New All-solid Sulfur-based Battery Outperforms Lithium-ion Technology." Phys.org. 05 June 2013. 6. Ju, Anne. "Food Inspires Lithium-Sulfur Battery Breakthroughs." Cornell Chronicle. Cornell University, 24 Oct. 2013. 7. Cope, Gordon. "The Calm Before the Storm." Hydrocarbon Engineering. Oct. 2012. 8. "The Lithium Market." Fox-Davies Resources Specialist, Sept. 2013.
In Brief: How do Process Analytics Yield Stronger PVC?
The VCM 'Balanced Process' of Producing PVC
PVC is a plastic favored in many industries due to its properties (light weight, chemical resistance, versatility). It is produced by polymerizing vinyl chloride (VCM), a highly toxic/explosive chemical intermediate which is manufactured strictly for this purpose. VCM is typically made by thermal cracking of ethylene dichloride (EDC), which is produced on site from feed stocks of ethylene and chlorine.
Without analytics, it is impossible to run this process at full efficiency: the EDC/VCM will have impurities that degrade the PVC strength, equipment will get corroded, coke formation will foul reactors, and catalysts will be poisoned. Through decades of field experience, we have fine-tuned an analytics arsenal that enables operators to optimize the complete VCM production process and eradicate these problems.
The OMA-300 for Monitoring FeCl3 and Cl2
In direct chlorination, ethylene and chlorine are reacted in the presence of a catalyst to produce EDC. Using a high res UV-Vis spectrophotometer, the OMA-300 continuously measures ferric chloride and chlorine concentrations in the emerging EDC stream.
These measurements test the purity of the EDC, but they are also excellent early indicators of problems that can be avoided. By monitoring the ferric chloride level, you can prevent coke formation in the EDC cracker, minimize pipe corrosion, and prolong degradation of the oxychlorination catalyst (which is used to produce additional EDC from waste gas).
The MicroSpec MCP-200 for Monitoring Moisture
Any appreciable amount of moisture in EDC or VCM is known to aggravate the corrosive behavior of these process streams. It is common for plant operators to measure 0-200 ppm moisture in multiple sampling points.
The MCP-200 is a reliable, compact NDIR moisture analyzer. Designed for ease of use, this device reads directly into the OMA interface and performs Auto Zero. Operators trust the MCP-200 as an indispensable tool for controlling corrosion throughout the VCM plant.
More Information
Read More
Download Application Note
In Brief: Natural Gas & The Smell of Safety (Measuring Odorant Level in Natural Gas)
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.
In Brief: Online Measurement of Trace Moisture in Liquids
Monitoring Trace H2O in Liquid Product on Process – Where Titrations end and IR begins
Challenge
Karl Fischer Titrations have been the default technique for measuring trace amounts of moisture in liquid samples. While remaining specific to water, flexible for a wide range of applications, and well-studied, accuracy, however, is one philosophical and subjective question that remains to be addressed. Operating a lab with KF analyzers, users can quickly find themselves asking the following questions:
How do I know that I am gathering representative samples consistently?
Are the surroundings impacting my measurement?: (i.e. low ppm, hygroscopic samples, moisture contamination).
Can I isolate operator error, maintain analyzer stability, and use just enough reagent to have the precise data that I need?
How many samples can I take in one day? What is the best response time that I can get?
Do I have an alternative to perform this measurement on process?
Solutions
Capitalizing on the large absorbance bands that give water its unique spectral fingerprint, AAI offers an online IR (infrared) based solution for a wide range of applications with the following advantages:
Fully automated measurement. No operators necessary.
Instant response with streaming moisture in liquid data ranging from % concentration levels to ppm.
No consumables required for reaction.
One time calibration with a Zero-offset technique to provide flexibility when choosing a proper zeroing medium.
The MCP-200 is the dedicated analyzer for the job. It utilizes NDIR (non-dispersive infrared) technology with no moving parts to perform the measurement. Please click here if you would like to learn more about the measurement. The following are examples of applications that the MCP-200 can perform for trace moisture in liquid:
PVC Manufacture: Trace moisture in VCM (vinyl chloride monomer)
Extraction processes: Solvency power of NMP, DMF, Phenol, Furfural
Fiber spinning efficiency
Moisture in hydrocarbons
Pharmaceuticals
Semiconductors and specialty metals
In Brief: Why Measure Sulfides at a Beer Brewery?
The Reason
Prior to filling, beer bottles are purged with CO2 to remove air and protect the taste against oxidation. In the fermentation process, yeast consumes sugar and expels a large amount of CO2 which can be "reclaimed" and used for this bottle purging purpose. Unfortunately, fermentation often also produces toxic, odorous sulfides which can foam up into the piping and contaminate the reclaimed CO2.
In order to continue using the great resource of CO2 byproduct yet avoid contaminating the bottled beer with foul-smelling toxins, the reclaimed gas is run through sulfide removal skids. However, sulfide breakthrough can occur if the gas does not spend enough time in the scrubber. Employees are sometimes tasked with sniff-testing the reclaimed CO2, but this is an unhealthy practice and is too discrete to vigilantly prevent product contamination. An automatic, continuous analysis solution is required in order to immediately divert contaminated CO2 from use in bottling as well as provide feedback control for the sulfur removal processing time.
The Method
The OMA Process Analyzer is used to continuously measure concentrations of hydrogen sulfide (H2S) and dimethyl sulfide (DMS) in the fermentation byproduct gas. This system uses a full-spectrum UV-Vis spectrophotometer to detect the absorbance of sulfides in the reclaimed CO2 stream, an ideal method as CO2 has zero absorbance in the UV spectrum. The OMA provides fast-response alarms to high-concentration threshold which allows immediate diversion of contaminated CO2.
For this application, the OMA is typically multiplexed to automatically cycle analysis between multiple sampling points. This maximizes system value by allowing one unit to monitor the raw fermentation gas entering the reclamation system, gas coming off the acid aldehyde scrubbers, and the bottling gas coming off of the sulfur removal beds -- all with sample stream switching at user-defined intervals.
Using the OMA system, a brewery enables intelligent CO2 reclamation which continuously prevents sulfide contamination of the beer product.
More Information
Read about the OMA Process Analyzer and the technology used.
Read about measuring proof and color in whiskey.
Read about measuring H2S in biogas produced from distillation operations.
In Brief: Analyzing Biogas Produced by Rum Distillation
In Brief: Analyzing the Biogas Generated by Modern Distillation Operations using the world's safest continuous H2S analyzer.
Permits to Profits in Rum – No More Prohibition
Breweries and distilleries have historically been the targets of trade embargoes, prohibition, and--most recently--environmental regulations. While the world demand continued to increase, the generated waste from production skyrocketed; efforts to curb the waste included converting portions of the spent product into animal feed. However, as operations continued to escalate to astronomical levels, entrepreneurial rum manufacturers developed an ingenious and green concept.
To produce rum, sugar syrup and molasses is extracted from sugar cane at various concentrations. The sugary molasses is then sent into a fermenter where yeasts react with the sugar to produce alcohol. To purify the alcohol, the rum is distilled in a copper column, where the purified alcohol is captured at the top and the dreaded waste is discharged at the bottom. FACT: Alcohol produced above 96% cannot be classified as rum.
World class companies such as Bacardi have reached the economy of scale and technical know-how to actually turn a profit on the waste from their operations. Starting after the distillation step, the bottoms (waste) product is sent through a stage of evaporators followed by an anaerobic digester. This process produces BIOGAS, rich in methane and a source of fuel to produce electricity, steam, and heat. Estimates of energy recovery have approached as high as 50%. However, biogas can incidentally contain over 10,000 ppm of extremely dangerous H2S.
To be allowed to run a biogas burning operation, the EPA, Department of Permits and Natural Resources, or other local environmental agencies grant permits for operation. This requires that the H2S be scrubbed and monitored to acceptable levels. One bad report can lead to plant shutdown or incur unplanned costs. Therefore, plant operators rely on the OMA Series H2S analyzer to perform continuous measurement on biogas after the scrubber. The system satisfies their need for an H2S specific measurement, reliability, and low cost of ownership.
With this technology, the operators of biogas-producing distilleries can worry less about the waste generated by their process and focus entirely on making a quality product.
In Brief: Measuring H2S in Fracked Shale Gas
In Brief: Measuring H2S in Fracked Shale Gas using the world's safest continuous H2S analyzer.
THE REASON
If you received this news brief, you likely already know about "fracking," i.e. hydraulic fracturing (if not, here's a primer). The technique targets shale gas, the natural gas trapped within deep rock layers. Much like historic drilling rushes, the fracking craze of the past decade has been characterized by wide speculation over reserve sizes, disputes over valuable land rights, proprietary extraction technologies, and different region-by-region legislation. The undeniable allure of domestic shale gas--especially for countries dependent on foreign oil--has led to the fast-tracked acceleration of fracking projects around the world. And due to this "new frontier" fracking landscape, the shale gas industry is filled with many eager players, with projects ranging from massive operations to small 'wildcat' rigs in highly populated areas.
This variety of sources means that the shale gas can vary wildly in quality and composition--specifically, sulfur content. Yet the energy companies that purchase the extracted gas are still responsible for making sure the incoming feeds from fracking operations meet quality standards before distributing the gas to consumers. The logistical challenge is to validate sulfur content in these diverse gas sources without slowing distribution or increasing costs.
THE METHOD
The facility at which natural gas is physically delivered from one company to another (i.e. from a frack site to a pipeline operator) is known as a "custody transfer point." At this station, the gas purchaser must measure hydrogen sulfide concentration in the feeds or risk pipeline damage, work hazards, and providing contaminated gas downstream to consumers.
Using online UV spectrophotometers, the hydrogen sulfide concentration of an incoming shale gas feed is continuously monitored in real time; a multiplexed configuration uses a single analyzer unit to watch H2S levels in several incoming streams simultaneously. Furthermore, full-spectrum background correction (unique to Applied Analytics' OMA-300 Series) secures the measurement accuracy against the high variation in shale gas composition, specifically the fluctuation of chemicals that would cause cross-interference in a more rudimentary analytical system. Most importantly, the fully automated nature of these systems means that they are integrated at the custody transfer point with no effect on the process, other than seamless sulfur monitoring.
In Brief: Measuring Caffeine in Decaf Coffee
In Brief: Measuring Real-Time Caffeine Concentration in Dacaffeinated Liquids using the OMA-300 Process Analyzer
The Reason
While it may mystify those of us that need strong coffee to get through the workday, some people actually drink decaf (decaffeinated coffee), whether for health reasons (high blood pressure, hypertension, sleep difficulties), pregnancy cautions, or personal preference. In lieu of more firm legal standards, decaf is supposed to have its caffeine content reduced by no less than 97.5% of the source coffee (USDA guideline). Accurate validation of the caffeine levels in decaffeinated coffee bean batches would reduce sensitive consumers' health risks by preventing the wildly inconsistent caffeine levels among available "decaf" blends (as documented by the Journal of Analytical Toxicology1). Moreover, producers can use real-time caffeine monitoring to conclude the decaffeination cycle as soon as the specified caffeine threshold is achieved, thus wasting no more caffeine solvent or production time than absolutely necessary.
An online analysis solution would provide continuous, live caffeine measurement in an automated fashion. The High-Performance Liquid Chromatography currently used in some caffeine applications is quite costly to own and maintain while delivering slow response.
The Method
While certain selective solvents are extremely effective at removing caffeine from coffee beans, many of these chemicals have been classified as carcinogenic or toxic. Though less powerful, the supercritical CO2 extraction method is a harmless decaffeination process common in large-scale operations. Supercritical CO2 fluid is a hybrid gaseous/liquid resource maintained by exceeding the critical temperature (31 °C) and pressure (73 atm) of CO2; for the supercritical CO2 to act as an effective solvent for caffeine molecules, it actually has to be kept at more extreme conditions (around 94 C and 225 atm). These conditions are expensive to maintain, and the 10-hour process cycle is time-consuming; the caffeine extract is sold off to pharmaceutical and soft drink companies, but this only partially alleviates process cost.
With real-time caffeine monitoring at ±1 ppm accuracy, the OMA-300 Process Analyzer allows decaf coffee producers to automatically end an extraction cycle when the specified caffeine maximum is reached. Doing away with the preset 10-hour cycle, this method banishes both overprocessing (which wastes production resources) and underprocessing (which upsets customers). While highly suitable for monitoring the 0-1,000 ppm caffeine range established by international standards as "legally" decaf, the OMA-300's UV-VIS spectrophotometer has a true detection limit of 2 ppm caffeine, thus theoretically capable of validating a cup of perfect decaf.
More Information
Read about the OMA-300 Process Analyzer, a real-time, optical caffeine analyzer.
In Brief: The EPA's New H2S Regulation
In Brief: The EPA's New Emission Reporting Requirement for H2S
What Happened
In 1993, the Environmental Protection Agency issued a list of toxic chemicals that require release reporting (i.e. continuous measurement of how much toxic substance a given facility is releasing into the environment); hydrogen sulfide was included in that list, but was immediately given exemption status so that the EPA could research its deleterious effect on human health. Earlier this week, the EPA officially removed the 16-year exemption with the following statement: "Hydrogen sulfide can reasonably be anticipated to cause serious or irreversible chronic human health effects at relatively low doses and thus is considered to have moderately high to high chronic toxicity."
Why It Matters
Hydrogen sulfide is a universal nuisance in industrial processes and is especially problematic for the energy industry (occurring naturally in crude oil and natural gas). To comply with the now-active regulation, countless facilities must soon invest in monitoring technology that will continuously verify if H2S emissions are below the legal threshold and supply that data to the EPA. The first H2S release reports are due July 1, 2013 for the previous year of activity.
How Applied Analytics Can Serve You
AAI technology is where the momentum of industry meets social responsibility with simple harmony. Hydrogen sulfide monitoring has been our foremost expertise and our highest-volume application since we began. With detection limits as low as ±0.1 ppm, solid state design (no moving parts or consumables), and full-spectrum background correction for volatile stream composition, the UV-VIS absorbance spectrophotometry used in our analyzers is arguably the most effective H2S online monitoring technique in existence. While other offerings scan fixed-wavelength absorbance peaks, our systems measure across a broad, high-res ultraviolet-visible spectrum and thus truly reads absorbancestructure. Our Eclipse software automatically stores and compiles the measurement data over time to make the reporting process as painless as possible.
More Information
Read about the OMA-300 H2S Analyzer, the trusted solution that streamlines EPA compliance. References: http://www.bna.com/epa-removes-exemption-n12884903896/ http://www.epa.gov/tri/triprogram/whatis.htm
In Brief: Measuring H2S in Landfill Gas
The Reason
Our trash is sent to landfills and ultimately decomposed in airtight cells underground; the bacteria that digest the waste release what is known as "landfill gas," a varying mixture comprising mostly methane and CO2. Formerly regarded as a flammable/environmental hazard, this gas is increasingly being tapped as a natural energy source. Landfill operators direct the gas to a common header, filter out large particles, and then use the stream to fuel special generator engines which create electricity that can be sold to the power grid. The problem with this exciting energy source is that the bacteria also produce other compounds such as hydrogen sulfide, which combusts to SO2 (a highly regulated pollutant) and must legally be removed from natural gaseous fuels.
The Method
The composition of landfill gas, including its H2S content, varies greatly with the composition of the garbage that we collectively feed to the underground microbes that digest it. From Applied Analytics, Inc., the OMA-300 H2S Analyzer continuously monitors H2S concentration (range: 0-1,000 ppmv) in the landfill gas stream before it gets fired in the generator engines. The diode array technology inside the OMA-300 has the proven capability to isolate H2S absorbance from the interfering absorbance of unknown compounds in a stream of volatile composition. Providing highly reliable, real-time H2S measurement, this system allows operators to determine when their landfill gas stream rises above legal H2S limits and should not be fed to the generators, thus avoiding fines, shutdowns, and socially irresponsible emissions.
More Information
The OMA-300 H2S Analyzer brochure.
References:
1 http://news.ncsu.edu/releases/wms-delosreyes-methanogen/