Choosing the Right H2S Analyzer for Your Specific Application

Not all H2S analyzers are created equal, and certain H2S analyzers work better on different applications than they do others.

Significant amounts of time, money and headaches can be saved by learning about the different H2S analyzer principles of operation and choosing the correct analyzer for your given application. Measurement of H2S (hydrogen sulfide) is a critical task for product quality control and personnel safety applications.

Higher H2S levels results in a less valuable product.

Specific H2S Analyzers for Different Applications
Photo by Rongy Benjamin (no alternations made)

It’s important to accurately measure the exact quantity of H2S in the natural gas / LPG and other products so that efficient scrubbing or scavenging of the H2S can occur which results in savings. Unfortunately, it’s not uncommon that major mistakes are made when choosing an H2S analyzer for different applications.

There are several different types of H2S analyzers that utilize different principles of operation. Not all H2S analyzers will work for every application so it’s important to learn the difference between them.

Electrochemical Cell H2S Analyzers

H2S Analyzers with electrochemical cells are frequently specified for hydrogen sulfide measurement applications due to their relatively low-cost. However, the low cost of these type of analyzers come at a high cost, technically speaking.

Electrochemical cells for detecting H2S suffer from significant cross-interference with ethyl-mercaptan, methyl-mercaptan and other light hydrocarbons and sometimes have serious issues handling LPG (Liquefied Petroleum Gas).

This results in “false positives” or artificially higher readings.

It’s not uncommon that you will find these type analyzer shutting in a pipeline unnecessarily due to a false high reading. This results in potentially tens of thousands of dollars in lost product each hour. Electrochemical cells must be regenerated on a regular basis requiring purging the sensor with clean air for as much time as analysis.

The analyzer will not give a new reading during this purge cycle time and the analyzer will simply hold the previous reading until a new reading is updated.

Due to deterioration, monthly (or more frequent) span and zero calibrations are required. This is especially true after a few months of operation because the rate of decay is more toward the end of the life of the sensor than the beginning.

Absorbance Spectroscopy/Spectrophotometry (including UV and Tunable Diode Laser) Method H2S Analyzers

Analyzers utilizing the absorbance spectroscopy methods are the newest players on the block when it comes to H2S measurement. There has been much fanfare in that past 5 years with this technology but within the past year the excitement has quieted noticeably due to lack of performance and inability to meet end-user expectations in many applications.

Analyzers using absorbance spectrometry got their start as the “anti-tape method” analyzer.

They were advertised as a low-maintenance, consumable free, and highly accurate analyzers. Apart from higher cost, it became apparent to many end-users that these analyzers suffered from cross-interference similar to electrochemical cells if the highly technical calibrations requiring chemometric modeling were not finely tuned enough for each and every specific application.

High cost consumables also became an issue. Due to the differential measurement flow path of some of the TDL laser based analyzers, a membrane separator/scrubber was required for proper operation. This consumable, normally filled with copper nano-particles, needed replacement approximately every six months to one year and with a significant price tag.

Furthermore, some concern was raised about the potential hazardous material inside these scrubbers and the exposure to personnel.

However, one issue reported that stands out more than the others was the inability for the analyzers to accurately and precisely measure in low ppm levels of H2S in numerous applications.

For pipeline operators, this is a major concern because a critical point of measurement is typically 4 ppm by volume. The UV and even laser based absorbance spectroscopy analyzers typically have difficulty at these levels.

Lead-Acetate Tape Method H2S Analyzers

Tape type H2S analyzers have been on the market since the 1960s and much improvement has been made in today’s tape technology including faster response time (30-90 seconds T90), longer tape life (3 to 6 months on a single tape roll), and 75% less moving parts (less maintenance).

There are two major benefits that end-users report with tape method H2S analyzers that has resulted in their recent resurgence in the H2S analysis market today including the natural gas pipeline industry.

The first is the ability of tape method H2S analyzers to measure very low concentrations of H2S (single digit ppm and even ppb levels) consistently, no matter the background gas. The second is the fact that these analyzers do not have any practical interference with other components. In nearly a century of use, lead-acetate tape analyzers are the only method that is innately specific only to H2S, proven by thousands of world-wide applications.

Detection of H2S concentrations by the use of H2S sensing tape is achieved by exposing the film to an H2S sample through an aperture in the sample flow system, called the sample chamber. The reaction of photographic film to the light is an analogy to the way that chemically saturated H2S sensing tape reacts to hydrogen sulfide. Then the rate of reaction (i.e. the rate of darkening) is linearly proportional H2S concentration. Measuring the rate of darkening is therefore directly equivalent to measuring the H2S concentration.

In summary, it is very important to choose the right H2S analyzer for your application.

If low level H2S concentrations are needed you should probably narrow your search to lead-acetate H2S analyzers. If you suspect you may have components in your product that may interfere with absorbance spectroscopic analyzers (including naturally occurring mercaptans you may not be aware of) you may also want to focus on lead-acetate tape analyzers. Either way, it can save not only significant amount of money but also headaches if you take your time to consider the right H2S analyzer for your application.

The measurement of hydrogen sulfide (H2S) in crude oil is a critical practice for quality control and safety purposes. Without precise quantification of H2S in a process, efficient processing of crude oil is not possible. To maintain safety when transporting crude oil and condensate, measurement of the H2S content is vitally important.

Measurement of hydrogen sulfide (H2S) is a beneficial practice for product quality control purposes and for personnel safety of those who may come in contact with sometimes fatal sour gas. Crude oil with low levels of H2S is more valuable than crude with high H2S as low H2S level oil can be more readily processed into petroleum products.

Without accurate quantification of H2S in a sample stream, efficient removal of the H2S is not possible. H2S analyzers are utilized for this quantification of H2S in various systems in order to optimize the process and cut costs.

Measuring H2S in crude oil

Safely transporting crude oil is becoming an increasingly important requirement in light of recent rail car derailments. Hydrogen Sulfide is a toxic and deadly gas that is often present in crude oil (sour crude) and condensate.

Even small amounts of H2S present a health risk to personnel transporting the sour crude oil and condensate as well as the public in case of accidents. The U.S. Occupational Safety and Health Administration (OSHA) warns H2S is an irritant and a chemical asphyxiant that can alter both oxygen utilization and the central nervous system.

Death can result from exposure to sulfide gas vapors at levels of just 100 ppm.

H2S is highly corrosive. Over time corrosion from H2S may occur in pipelines, rail cars, trucks and other transport vessels that deliver crude oil: which may lead to deadly accidents.

The Pipeline and Hazardous Materials Safety Administration (PHMSA) recently issued a safety alert on January 2, 2014 following the train car derailments that caught fire west of Fargo, ND, and Lac-Megnatic, Quebec, indicating crude oil being transported from the Bakken region “may be more flammable than traditional heavy crude oil.”

Although there is debate as to whether the flammability of the Fargo cargo was due to high H2S levels or simply the highly volatile properties of the crude oil, most rail, truck, and pipeline facilities are now requiring low H2S content in crude oil and condensate.

Some institutions and companies have implemented policies to turn away crude oil with more than 5 ppm H2S content.

The U.S. Federal Energy Regulatory Commission (FERC) is standing behind Enbridge Energy Partners by ruling that states Enbridge “reserves the right to reject crude that does not contain a hydrogen sulfide content of 5 parts per million (ppm) or less.”

The rule went into effect in May of 2013.

The FERC also approved a 5 ppm H2S limit by Tesoro Corp. effective January 1, 2014 and True companies at 10 ppm H2S limit effective April 1 of 2014.

OSHA has set the maximum exposure limits of hydrogen sulfide “at either 10 or 20 ppm… with an absolute prohibition of exposure above 50 ppm.”

Continuous online monitoring of hydrogen sulfide can pay for itself by preventing product loss, meeting sales specifications, and protecting personnel by verifying hazardous amounts of hydrogen sulfide are not present in the product before transportation. Continuous analyzers also eliminate costly and timely lab analysis costs which cannot offer real-time measurement of hydrogen sulfide in the crude.

Methods of Sampling Hydrogen Sulfide in Crude Oil

Due to the opaque nature and complex compositional characteristics of crude oil, direct optical measurement is difficult. To circumvent this problem, the composition of the crude oil (including the hydrogen sulfide) can be representatively “stripped” from the liquid phase into the vaporous gas phase for precise measurement by a gas detector.

Two primary methods exist for stripping (or recovering the composition of) the crude oil for measurement by a gas detector for continuous analysis:

The ‘headspace’ stripping column and the use of the Sample Transfer Stripper™ utilizing a variety of proprietary membrane technologies.

Both of these methods are based in part on Henry’s Law and partial pressures of the components in the sample:

“At a constant temperature, the amount of a given gas that dissolves in a given type and volume of liquid is directly proportional to the partial pressure of that gas in equilibrium with that liquid.”

The headspace stripping column requires crude oil to continuously flow into a temperature controlled pipe (several inches in diameter) while a stripping gas flows in the opposite direction against the crude oil.

The combining agitation of the stripping gas and the constant heat and pressure of the column persuade the compositional vapor of the crude oil to strip from the crude oil and into the stripping gas which then carries the vapor to the detector for analysis.

The headspace stripping column system requires a multitude of parts to maintain constant flow, heat and pressure of the crude oil sample. The column is normally a large component. Several feet of length is normally required to effectively serve its purpose. Oftentimes, multiple columns are required. Much care must be given to the headspace column to prevent the crude oil from “carrying-over” into the stripping gas line which requires cleanup of crude oil in the air sampling lines and the contaminated detector and/or flow cell.

Precise control of sample flow and pressure; carrier flow and pressure; and temperature becomes critical to the proper functionality of the headspace column stripper system. It is important the crude oil is evenly dispersed inside the column to ensure the stripping gas effectively contacts all of the crude oil sample. In reality, this is difficult to accomplish with the headspace column stripper system as the crude oil tends to clump to one side of the column instead of being evenly distributed. Inaccurate measurements are frequent with this method.

Alternatively, the membrane Sample Transfer Stripper™ is a simple and straight forward approach to extracting a proportional compositional vapor from the crude oil for quantification. The Sample Transfer Stripper™ employs the use of membranes to efficiently and proportionately separate the crude oil composition from the liquid sample for analysis. The device is a simple and elegant. At only 5″ high and 3.5” wide it provides an ultra-clean and dry sample to the detector for analysis without demanding valuable real-estate.

The Sample Transfer Stripper™ operates based in part on Henry’s Law and employs the partial pressure of the sample for compositional extraction into the vapor phase. The crude oil sample flows into the heated membrane stripper where it continuously sweeps one side of the membrane. The composition of the sample then permeates through the membrane into vapor-phase where the carrier gas sweeps the sample to the detector for analysis.

The membrane in the Sample Transfer Stripper™ acts as a physical block, preventing mists and other contaminants from passing through the carrier gas tubing lines and onto the detector. There is no risk of “carry-over” from the crude oil. This prevents buildup of contamination in the sample line which would otherwise cause in/out gassing and inaccurate readings over time due to gradual contamination of sample tubing walls. Because the membrane technology uses 90% fewer parts than the headspace column stripper, maintenance requirements are radically reduced.

Methods of Analysis of H2S in Crude Oil Headspace

Now that we have an effective method to extract the representative headspace in a reliable manner using the Sample Transfer Stripper™, we must now quantify the concentration of H2S accurately. Due to the complex compositional makeup of crude oil headspace, UV and laser absorption spectroscopy struggles to measure H2S, especially in single and double digit ppm levels.

This rules out UV and laser absorption spectroscopy as a reliable method to quantify the hydrogen sulfide in crude oil headspace.

The colorimetric-ratiometric tape method of analysis is the only proven method to measure hydrogen sulfide in crude oil headspace without any interference from components similar to H2S. The method is described in several ASTM methods including ASTM 4084-82.

There are several advantages to the tape method of analysis, including:

  • Automatic ‘zero’ affect. The analyzer never suffers from a ‘zero drift’
  • The tape method is specific only to H2S proven by thousands of worldwide applications
  • Tape roll life has been extended to 3-6 months
  • The analyzer does not require routine calibrations in the field. The factory calibration remains stable for years
  • The tape method offers a wide range ability including ppb, ppm and up to 100% saturation
  • The tape method is innately linear in response, no need to calibrate in the field

Conclusion

The Model 205 Analyzer utilizing the Sample Transfer Stripper™ membrane stripper and colorimetric-ratiometric tape method of detection has been shown to be the most reliably way to measure hydrogen sulfide in crude oil. Accurate measurement of low ppm levels of H2S in a complex liquid stream (such as crude oil) on line is a major challenge.

Consequently, the colorimetric-ratiometric paper tape combined with the proprietary membrane technology in the Sample Transfer Stripper™ method remains as sensitive and reliable a method as is practically achievable in today’s environment.

This article was adapted from a paper given at an ISA AD Symposium in 2015.

The title was “Measuring H2S in Crude Oil for Quality Control and Transport Safety“.

Over the years new process analyzers have been developed to measure hydrogen sulfide.

These include TDL (laser) and UV absorption spectroscopy and electrochemical cells.

However, in many applications these analytical methods are not meeting the user expectations and are now being replaced with tape method analyzers. So why, after several decades, are tape method analyzers still dominating the market for H2S analysis?

Four (4) Primary Reasons Why Tape Method Analyzers Dominate the Market for Analyzing Hydrogen Sulfide

1.) The tape method does not suffer from cross-sensitivities with components similar to H2S. This means the tape method analyzer does not produce ‘false positives’ that can shut-in a pipeline, causing unnecessary loss of money.

2.) The tape method does not require zero gas or zero calibrations. When an analyzer’s zero reading is off, the rest of the readings are off and higher than they should be. This could result in an unnecessary pipeline shut-in. However, the tape method analyzes never suffer from ‘zero drift’ and does not need a supply of zero air.

3.) Only the tape method analyzers are capable of precise low ppm measurements, no matter the background gas composition. Other H2S analyzers are easily confused in the presence of components that looks similar to H2S and will report false positives.

4.) Tape method analyzers never require complicated calibrations that implement chemometric models. Other methods require continuous upkeep of calibration models over time as the process changes. Because tape method analyzers only see H2S, there is no need for calibration models and the accuracy does not change as the process changes.

The Different Methods for Measuring H2S

There are three primary detection methods to continuously quantify hydrogen sulfide (H2S).

These methods are absorption spectroscopy, electrochemical sensor cell, and the colorimetric-rateometric tape method of detection.

Primary considerations for an analyzer include low maintenance and accurate measurements. Whereas low maintenance relies on the sampling system, the accuracy of the system also lies in the detection technology. Users demand a highly versatile analyzer that maintains accuracy despite process changes.

The absorption spectroscopic method operates in conjunction with Beer-Lambert law:

“The absorbance of a solution will depend directly on the concentration of the absorbing molecules and the path length traveled by light through the solution.”

The sample enters a flow cell where a light source is shined across the sample. As the light is absorbed by components of interest, such as hydrogen sulfide (normally in the UV region), the spectrometer quantifies the resulting absorbance as concentration.

H2S analyzers with electrochemical cells are also sometimes used to measure H2S. These cells measures concentrations of a component by oxidizing the component at an electrode and measuring the current that results.

Hydrogen sulfide is a difficult component to measure due to the presence of similar background components in samples such as methyl-mercaptan, ethyl-mercaptan and other sulfur species and organics. Problems arise with the aforementioned absorption spectroscopy and electrochemical sensor cells due to these interfering components. Attempts have been made to reduce ‘false positives’ with absorption spectroscopy but this requires complicated chemometric modeling that is static and not always reliable.

Furthermore, when the process stream naturally changes over time, even slightly, chemometric model updates and new calibrations are required. This is difficult to perform in the field and often requires the labor support of the manufacturer. Suppliers of absorption spectroscopy analyzers guard chemometric models as intellectual property and the user has little control over or access to these models. Unfortunately, the user usually cannot apply new modeling in attempt to negate interfering components and require the assistance of the manufacturer. Because many processes are time critical, time spent waiting for the arrival of a manufacturer’s representative becomes burdensome.

Zero reading ‘drift’ is routine with these methods of analysis. Manufacturers of electrochemical sensor cells offer disclaimers showing an array of interfering compounds with their sensor cells including hydrogen, ethyl-mercaptan, methyl-mercaptan, ammonia, carbon monoxide, ethylene, chlorine, methane, methanol, nitrogen dioxide and other sulfur species.

Attempts have been made to “scrub” out these interfering compounds. However, these scrubbers tend to unintentionally scrub the very H2S components attempting to be measured. Furthermore, as the scrubbing media becomes spent, the degree of scrubbing the components becomes less effective over time.

The colorimetric-rateometric tape method of detection is unique in its ability to measure hydrogen sulfide directly without any practical cross-interference from other components based on thousands of worldwide applications.

State-of-the-art developments have improved the tape method to a straightforward and simple design, resulting in reliable operation with very minimal maintenance requirements. Life span for a single tape reel is extended up to 6 months in some cases. Measurement of hydrogen sulfide concentration by the use of the ASTM approved colorimetric-rateometric tape is based on physical constants and chemical factors.

Detection of H2S concentrations by the use of H2S sensing tape is achieved by exposing the film to the H2S sample through an aperture in the sample flow system, called the sample chamber. The reaction of photographic film to the light is analogous to the way that chemically saturated H2S sensing tape reacts to hydrogen sulfide.

The rate of reaction (i.e. the rate of darkening) is linearly proportional H2S concentration. Measuring the rate of darkening is therefore directly equivalent to measuring the H2S concentration.

While several methods have been developed to measure H2S over the years, the ASTM approved tape method analyzer continue to lead the pack with precise and reliable measurement of hydrogen sulfide. The tape method analyzers take out the hassles involved with the UV/laser adsorption spectroscopic methods of analysis.

This article was adapted from a paper given at an ISA AD Symposium in 2015.

The title was “Measuring H2S in Crude Oil for Quality Control and Transport Safety“.

Wet weather can wreak havoc on process analyzers installed outdoors.

If it’s your responsibility to ensure process analyzers are running smoothly, there are easy steps you can take to prevent analyzer downtime in wet, rainy weather.

Weather protected outdoor H2S analyzer
This H2S analyzer is properly prepared for wet weather.
It is installed in a 3-sides shelter with a roof and has desiccant bags placed inside the analyzer’s cabinet.

Not all process analyzers installed outdoors in the field are protected from the elements. Many analyzers have no analyzer shelter to protect them and to build one would be cost prohibitive. This can cause a lot of trouble for you if it’s your job to keep the analyzers up and running. If you can’t afford a full analyzer shelter, consider installing a simple shelter with a sloping roof that blocks rain and direct sunlight from hitting the analyzer.

Perhaps you could even install “half-way” sides on the back and the sides of the simple shelter. This can go a long way in protecting your analyzer.

After a basic shelter for the analyzer has been installed, it’s still possible to get moisture buildup inside the analyzer’s enclosure due to condensation. Condensation occurs when the temperature outside is warmer than the temperature inside the analyzer’s enclosure. Condensation could lead to electrical shorts, tape breaks, and clouding of sensor optics or mirrors which requires cleaning. Moisture can also disable scrubbing media that may be used by your process analyzer.

One method of preventing condensation is to install a heater and thermostat in the analyzer’s enclosure. If this is out of the question, simply put desiccant bags inside the enclosure. A desiccant is a hygroscopic substance that induces or sustains a state of dryness (desiccation) in its vicinity, including any moisture that may build up in the enclosure. Just be sure to replace the desiccant bags periodically.

You should also ensure the sample going to your analyzer is clean and dry.

Remember, an analyzer is only as good as it’s sampling system.

To ensure your analyzer is receiving a clean and dry sample, we would be happy to design a sampling system for your analyzer. Just give us a call.

Pay careful attention to solid state type analyzers in wet weather including analyzers that utilize the UV and laser absorption spectroscopy method of analysis. The optics or mirrors in these types of analyzers have a tenancy to fog up or condense in wet weather which will result in inaccurate measurements without operator warning.

The optics or mirrors are located in the sample cells. When a cold sample (say LPGs) flows inside the sample cell and there is warm, wet weather outside the cell, condensation tends to form on the optics or mirrors. Clearing the condensation is often a laborious task that takes a skilled operator to perform.

Luckily, lead-acetate tape method analyzers that measure for hydrogen sulfide are very simple analyzers and few things can go wrong even in wet weather.

Unlike other analyzer types, tape method H2S analyzers only requires low moisture inside the analyzer’s cabinet so that the tape reels don’t become wet.

It is a simple task to keep the tape reels dry.

Following the tips mentioned above will result in a dry analyzer cabinet and will keep your analyzer online through all the wet weather your analyzer may experience.

If you operate an H2S analyzer, there are 4 things you must know for successful measurements.  If you haven’t considered the 4 steps listed below, it’s likely your gas H2S analyzer is not operating as accurately or as reliable as it could.

1.) Check the Material of the Wetted Parts

It’s far too often manufactures of H2S analyzers use wetted parts in their analyzers that readily absorb H2S. When H2S is absorbed into parts materials, a phenomenon called “in-gassing” will occur. In-gassing results when H2S is absorbed in materials before it reaches the detector. This results in lower H2S readings than what is actually in the sample.

Ensure the wetted part materials is inert such as 316L stainless steel or PTFE (Teflon). Stay away from materials such as brass, carbon steel or nickle.

2.) Be Aware of False High Readings

You could be experiencing a product shut-in even though your H2S levels are in check and not over your limit. These false high readings or “false positives” are very common in the analyzer industry. False positives occur when the H2S analyzer measures components that “look” similar to H2S but are not actually H2S.

The most common types of interference is ethyl-mercaptan and methyl-mercaptan.

You may be saying to yourself “we don’t inject mercaptans in our gas so we are fine.”

However, what many people fail to realize is that mercaptans is naturally occurring in the ground. You may not be aware of the presence of mercaptans in your sample.

The chart below shows which type of H2S analyzer methods suffer from cross-sensitive to components other than H2S.

ASI Keco offers the H2S tape method analyzer that never suffers from cross-interference.

H2S analyzer principle comparison

3.) Process Analyzers Are Only as Good as the Sampling System

It’s easy to focus so much of your time and attention on your analyzer you forget how important the sampling system is. If the sampling system is not set up properly, you analyzer will not perform. Verify the wetted part materials (see step 1). Also ensure there are no free liquids getting through the sample lines. H2S is readily absorbed in liquids.

We would be happy to design a sampling system for your analyzer. Just give us a call!

4.) Ensure the Vent Lines Out of the Analyzer are Clear

Back pressure on the analyzer’s vent lines can lead to false high readings. Dirt, debris and bugs can cause back pressure on the vent line. When bugs such as dirt dobbers smell hydrogen sulfide, they think its lunch. When they craw into the sample vent line they die quickly,  but this causes back pressure. Be sure to install “bug guard” screens at the end of the analyzer vent to prevent this from happening.

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westech industrial canada distributor

Analytical Systems Keco is pleased to announce the addition of our new, exclusive distributor in Canada, Westech Indsutrial.

Westech is a trusted partner to leading Canadian industries, supplying instrumentation and process control equipment and solutions that meet the unique industry needs of our customers. Over its 50 year-lifespan, the company has prospered in the Oil & Gas, Terminal, Petrochemical, Food & Beverage, Pharmaceutical and Municipal markets by providing customer-centered solutions in the form of best of industry products.

Westech will be selling and supporting our analytical products including H2S in crude oil analyzers, H2S in water analyzers, H2S in gas analyzers, NDIR carbon dioxide analyzers, total sulfur gas analyzers; and hydrocarbon in water analyzers.

Please visit www.westech-ind.com for more information.

HOUSTON, Texas -Analyzers produced by Analytical Systems Keco that measure for oil in water now have a new feature that will give users a new tool to more efficiently monitor their process. The new feature, called the ‘True Dual Stream’ system, allows the analyzer to measure two separate sample streams simultaneously.

The True Dual Stream feature allows one Oil in Water Analyzer system to measure two sample streams simultaneously without the need for troublesome stream switching systems.

Traditional analyzers only allow one sample stream to be analyzed at a time. If two or more sample streams need to be analyzed, traditional analyzers must switch between the streams. This results in “lag time” and therefore a slowed response time.

The True Dual Stream system made available in the oil in water analyzers by Analytical Systems Keco eliminate lag time and ensure continuously fast response on two streams independently.

The True Dual Stream system in the Model 204 Oil in Water Analyzer incorporates complete and true dual stream flow paths, dual standard sampling systems (including pressure regulators, needle valves, flow meters, and secondary filters), dual sensors, and readout electronics with no switch or lag time.

The Model 204 Oil / Hydrocarbon in Water Analyzer greatly enhances the ability to analytically quantify total hydrocarbons and volatile organic compounds (VOCs) in cooling towers, heat exchangers, holding ponds, run-off water, produced water and waste water due to the Sample Transfer Stripper (exclusive ASI Membrane Technology) and the tin oxide sensor technologies offered by Analytical Systems. This model’s system utilizes patented and exclusive features only available from Analytical Systems.

The field-proven analyzers maintain accuracy long term with very minimal maintenance requirements. The analyzers do not require calibrations in the field and have no moving parts and have no periodic supply items.

“The ability to measure two process streams simultaneously with only one analyzer saves users significant money,” said Wes Kimbell, Business Development Manager at Analytical Systems Keco. “And with no lag time, users will have uninterrupted monitoring of their process streams without missing a beat.”

In addition to Liquid Analyzers, Analytical Systems provides analyzers for both gas and crude oil. The company’s reliable gas, liquid and crude oil analyzers have been proven by countless installations and commercial-technical certificates from major oil and gas producers worldwide.

Leading Manufacturer of Liquid, Gas & Crude Oil Analyzers to Present and Exhibit at International Society of Automation (ISA) Analysis Division

Analytical Systems Keco, a Houston-based manufacturer of liquid, gas and crude oil analyzers will be in attendance at the May 2015 ISA Analysis Division Trade Conference.

The company will be present a paper on the 205 H2S in Crude Oil Analyzer for transportation safety and quality control purposes. In addition, Analytical Systems will be exhibiting at the trade conference.

Measurement of hydrogen sulfide (H2S) is a beneficial practice for product quality control purposes and for personnel safety who may come in contact with sometimes fatal sour gas.  Crude oil with low levels of H2S is more valuable than crude with high H2S, as low H2S level oil can be more readily processed into petroleum products. Without accurate quantification of H2S in a sample stream, efficient removal of the H2S is not possible. H2S analyzers are utilized for quantification of H2S in various different systems in order to optimize the process and cut costs.

Founded in 1945, ISA is a leading, global, non-profit organization that is setting the standard for automation by helping over 30,000 worldwide members and other professionals solve difficult technical problems, while enhancing their leadership and personal career capabilities. Based in Research Triangle Park, N.C., ISA develops standards, certifies industry professionals, provides education and training, publishes books and technical articles, and hosts conferences and exhibitions for automation professionals.

“We are excited to be attending the ISA Analysis Division trade conference this May,” said Wes Kimbell, Business Development Manager at Analytical Systems Keco. “Our goal is to disseminate any knowledge we can so that industries may continue to be more efficient; and, therefore, more sustainable to our world.”

Analytical Systems Keco was established in 1984, employing staff with over 40 years of analytical experience. The Houston based company provides field-proven, liquid and gas phase on-line continuous process analyzers to the gas processing, pipeline, refining and chemical, industries worldwide. Many ASTM methods, patents, and exclusive features are utilized with Analytical Systems’ analyzers. Products include H2S in Crude Oil Analyzers, H2S in Water analyzers, Oil in Water Monitors and Total Sulfur analyzers.

For more information, visit http://www.liquidgasanalyzers.com or call 281-516-3950.

Houston-based gas analyst unveils new technology aimed at preventing explosions when transporting crude oil.

gI_61834_analyzer-205w-pv6Analytical Systems Int’l. KECO, a Houston-based gas refining, manufacturing and transporting processes analysis firm, recently released the 205 H2S in Crude Oil Analyzer, a process analyzer that will quantify the amount of Hydrogen Sulfide (H2S) content in crude oil and other liquids.

Safely storing and transporting sour crude oil and condensate via roadways, rail, by sea or via pipeline can present a multitude of challenges. H2S, is a toxic and deadly gas that is often present in crude oil and condensate. Even a small amount of H2S presents a health risk to personnel transporting the sour crude oil and condensate. In case of accident-related spills, the public is also in danger of exposure to this toxic gas.

The U.S. Occupational Safety and Health Administration (OSHA) warns that H2S is an irritant and a chemical asphyxiant that can alter oxygen utilization and affect the central nervous system. Death can result from exposure to hydrogen sulfide gas vapors at levels of just 100 parts per million (ppm).

In addition to being harmful to health, H2S is also highly corrosive. Over time, the harmful gas can corrode rail cars, trucks, pipelines and other transport vessels that deliver crude oil, leading to an increased risk of spills, and loss of containment. H2S is also highly flammable, which can lead to explosions should accidents occur during the transport of sour crude oil and condensate.

On January 2, 2014, The Pipeline and Hazardous Materials Safety Administration (PHMSA) issued asafety alert following the rail derailments that caught fire west of Fargo, N.D., and Lac-Megnatic, Quebec, indicating crude oil being transported from the Bakken region: “…May be more flammable than traditional heavy crude oil.”

Most rail, truck and pipeline facilities are now requiring low H2S content in crude oil and condensate. Some institutions and companies have implemented policies to turn away crude oil with H2S content of more than 5 ppm.

In May of 2013, The U.S. Federal Energy Regulatory Commission (FERC) ruled that Enbridge Energy Partners: ”…Reserves the right to reject crude that does not contain a hydrogen sulfide content of 5 ppm or less.” The FERC also approved a 5 ppm H2S limit by Tesoro Corp. effective Jan. 1 2014 and the True Companies’ 10 ppm H2S limit effective April 1, 2014. OSHA has set the maximum exposure limits of hydrogen sulfide: “…At either 10 or 20 ppm…with an absolute prohibition of exposure above 50 ppm.”

“The 205 H2S in Crude Oil Analyzer will give transporters vital information about the H2S content in their cargo load before transportation takes place,” said Wes Kimbell, Business Development Manager at Analytical Systems KECO. “The 205 H2S in Crude Oil Analyzer is a field-proven analyzer with units installed or being installed across the country to prevent accidents when dealing with sour crude oil and sour condensate.”

About Analytical Systems Int’l. KECO

Analytical Systems Int’l. KECO was established in 1984, employing staff with over 40 years of analytical experience. Analytical Systems Int’l KECO provides field-proven liquid and gas phase on-line continuous process analyzers to the gas processing, pipeline, refining, chemical, offshore platforms, shipping vessels, petrochemical and water processing industries worldwide. Many ASTM methods, patents, and exclusive features are utilized with Analytical Systems’ analyzers. For more information, visit http://www.liquidgasanalyzers.com/.

Analytical Systems Keco Recently Releases the 205L Laboratory H2S in Liquids Analyzer

Analytical Systems Keco, a Houston-based gas refining, manufacturing and transporting processes analysis firm, recently released the 205L Laboratory H2S in Liquids Analyzer. The 205L Laboratory H2S in Liquids Analyzer has the ability to analytically quantify H2S liquids such as crude oil, fuel oil, naphtha, water, diesel, and gasoline.

Enhanced with Sample Transfer StripperTM, using exclusive ASI Membrane Technologies, and ratiometric colorimetric technologies, analysis is a quick procedure requiring only one push button.

One major defect in other analytical methods is they suffer from interferences with non-H2S sulfur chemicals, CO, H2, hydrocarbons, or other components which may be present in crude or other liquid samples. However, the 205L takes a rather simple and direct approach to solve this defect by offering a detector that responds only to H2S, proven by thousands of worldwide applications where this detector is utilized.

Other analytical methods also tend to calibrate using only a blended gas phase sample (which can compromise a true liquid to a gas phase conversion), whereas the 205L is fully factory calibrated with actual liquid samples in a process attributable to NISTstandards.

The U.S. Occupational Safety and Health Administration (OSHA) has issued warnings of H2S as an irritant and chemical asphyxiant that can alter both oxygen utilization and the central nervous system. Health and safety issues can arise through the transport and storing of sour crude oil and condensate in trucks, trains, pipelines, and vessels.

“Our new laboratory analyzer for H2S in crude oil ties in with safety because it allows users to test for H2S in their crude oil, condensate and other liquid products before they transport or store the product for safety purposes,” said Wes Kimbell, Business Development Manager at Analytical Systems Keco. “This can assist in preventing health risks to personnel transporting the sour crude oil and condensate as well as pedestrians in accident cases.”

About Analytical Systems Keco
Analytical Systems Keco was established in 1984, employing staff with over 40 years of analytical experience. The Houston based company provides field-proven, liquid and gas phase on-line continuous process analyzers to the gas processing, pipeline, refining and chemical, industries worldwide. Many ASTM methods, patents, and exclusive features are utilized with Analytical Systems’ analyzers. For more information, visithttp://www.liquidgasanalyzers.com.