On-Line Monitoring of H2s in Refinery Gas Streams Using Tunable Diode Laser Absorption Spectroscopy (TDLAS)

by W. Gary Engelhart, Product Line Marketing Manager, SpectraSensors, Inc.

IntroductionCrude oil is composed of a complex mixture of hydrocarbon compounds along with lower concentrations of organic sulfur compounds (mercaptans, sulfides, and thiophenes), dissolved H2S, and other heteroatomic compounds. The sulfur content of crude oil varies based upon the geological formation it is extracted from, ranging from less than 0.05 to 10 wt%.1,2 Most often the sulfur content of crude oil will be in the 1 – 4 wt% range. Crude oil containing less than 1 wt% sulfur is termed low sulfur or sweet, and crude oil containing more than 1 wt% is termed high sulfur or sour.2 As a general observation, the higher the density of crude oil (or lower the API Gravity) the higher the sulfur content.1

Refinery gas streams contain contaminants that can adversely affect operational efficiency, process yields, and operating margins. On-line monitoring and control of H2S levels in refinery gas streams is critically important for improving process control, meeting product specifications, hydrotreating and desulfurizing unit feedstocks, mitigating corrosion and catalyst poisoning, and complying with environmental regulations.

Overview of H2S monitoring in refinery operationsMost of the H2S present in refinery gas streams is produced within the refinery. The specific function of some refinery unit operations is to breakdown and convert organic sulfur compounds into H2S that can be removed by treating the gas streams. In other cases residual amounts of organic sulfur compounds remaining in treated feedstocks form H2S as an unwanted by-product of various process reactions. An overview of these refinery unit operations is therefore helpful in understanding H2S monitoring requirements.

2

Hydrodesulfurization of petroleum fractionsCrude oil entering a refinery is heated and undergoes atmospheric and vacuum distillation to fractionate it into petroleum fractions according to their boiling points. The hydrocarbon compounds found in a distillation fraction is related to their molecular weight (number of carbon atoms) and corresponding boiling point range. The boiling point range for C1 to C4 gases is 0 – 30 °C, 30 – 180 °C for the C5 to C10 naphtha fraction, 180 – 260 °C for the C10 to C16 kerosene fraction, and 260 – 350 °C for the C16 to C60 gas oil fraction.

Organic sulfur compounds in the crude oil partition into the distillation fractions based upon their molecular weight and volatility. The lighter mercaptans and thiophenes are found in the naphtha fraction used to produce gasoline, benzothiophenes in the kerosene fraction used to produce heating and jet fuels, and dibenzothiophenes in the gas oil fraction used to produce diesel fuel.

Refineries use catalytic hydrodesulfurization processes (hydrotreating and hydrocracking) to remove sulfur from petroleum distillation fractions before they are fed to unit operations used to convert them into products. Removing the sulfur helps protects catalysts in downstream refinery processes, and reduces SO2 emissions from combustion of the fuel products (gasoline, diesel fuel, jet fuel, fuel oil) to comply with ultra-low sulfur fuel regulations.

Hydrodesulfurization involves feeding a liquid petroleum distillate fraction into a hydrotreating reactor packed with a catalyst to react sulfur compounds with hydrogen for conversion into H2S according to the generalized reaction below.

[R-S] + H2 → catalyst → [R-H] = H2S 300 – 450 °C

Effluent from the reactor is cooled and sent to a high-pressure separator, which separates desulfurized liquid hydrocarbons from a gaseous mixture of hydrogen and H2S. The hydrogen gas stream is sent to an amine treatment unit to remove H2S before it is recycled to the process. The H2S concentration is monitored in gas entering and exiting the amine treatment unit to ensure the scrubbing process is efficiently removing H2S from the hydrogen before it is recycled and combined with make-up hydrogen as depicted in Figure 1.

Figure 1. H2S measurement points at the inlet and outlet of an amine treatment unit in a refinery hydrodesulfurization system

3

The concentration of H2S in hydrogen exiting a hydrodesulfurization reactor is a function of sulfur content in the petroleum fraction being fed to the reactor and conversion efficiency within the reactor. Accordingly, H2S levels in hydrogen entering an amine treatment unit may range from approximately 100 ppm up to a low percentage level.

Refinery fuel and flare gasRefinery fuel gas is composed of a mixture of hydrogen and C1 to C5 hydrocarbons recovered from different unit operations within a refinery for use as a fuel source in fired heaters and boilers, as depicted in Figure 2.

Figure 2. H2S measurement points in refinery fuel and flare gas systems

In the United States sulfur emissions from refineries are regulated under the Clean Air Act & Amendments (CAAA). The U.S. Environmental Protection Agency (EPA) is responsible for issuing specific regulations and applicable test methods for regulatory compliance enforcement. Regulations covering sulfur (SO2) emissions from combustion of fuel gas are defined in 40 CFR 60 Subpart Ja. Similar regulations aimed at reducing SO2 emissions have been promulgated in Europe, the Middle East and Asia.

The U.S. EPA recognizes that measurement of H2S gives a good approximation of the total SO2 that is generated from combustion of refinery fuel gas. The required measurement range is 0 - 320 ppmv. The regulatory limit for H2S in refinery fuel gas is 162 ppmv. One measurement every 15 minutes (96 times per day) is required to meet U.S. EPA requirements for continuous emission monitoring. A daily two-point validation check is also required to confirm the analyzer is operating properly within its calibration range.

U.S. EPA regulations for flare gas are similar to those for fuel gas. Measuring H2S in the gas sent to the flare header gives a good approximation of the SO2 produced during combustion. The required measurement range is 0 – 300 ppmv. H2S levels must not exceed 162 ppmv over a three-hour rolling average time period (equal to approximately 500 lbs. of SO2 in any 24-hour period). A daily two-point validation check is required to confirm the analyzer is operating properly within its calibration range.

Refinery off gases (ROG) are typically sent to a gas treatment unit to separate fuel gas components from other hydrocarbons (olefins, aromatics, etc.) recovered for use elsewhere in the refinery or a companion petrochemical complex. The H2S concentration in fuel gas is reduced in an amine treatment unit to meet the regulatory requirement. If the H2S level is close to or exceeds the regulatory limit the fuel gas may be blended with clean natural gas to lower the concentration below the regulatory limit.

AX

AX

AX

FCC Off GasCrude Off Gas

Fractionator Off Gas Naphtha Flash Gas

Catalytic Reformer Off GasHydrotreater Off Gas

Isomerization Off Gas

To Refinery Heaters / Boilers

Gas Treatment

RefineryFuel Gas

Refinery Off Gas (ROG)

Flare Headers

Knock OutDrum

Flare Gas

PetrochemicalPlant

DehydrationOlefins

fractionation & Recovery

4

Catalytic reformer hydrogen recycle gasA catalytic reformer unit converts naphtha into high-octane aromatic compounds termed reformates used in gasoline blending and yields large quantities of hydrogen that is recycled to the reformer and used in other process units (Figure 3). The naphtha feed stream to a catalytic reformer has undergone hydrodesulfurization to remove organic sulfur compounds from this distillation fraction. The hydrodesulfurization process removes most, but not all sulfur from naphtha. Consequently, the remaining sulfur compounds are broken down with the liberated sulfur forming H2S as the naphtha passes through catalytic reactor beds performing dehydrogenation, isomerization and hydrocracking reactions.

Figure 3. H2S measurement point in hydrogen recycle gas to a semi-regenerative catalytic reformer

The resulting H2S is entrained in the hydrogen gas and reformate product stream. This stream is cooled and liquid product separated from the hydrogen, a portion of which is recycled, with the excess or net hydrogen directed to other units in the refinery. The H2S concentration in the recycle hydrogen stream is monitored to avoid a build-up to levels that would poison the platinum/rhenium (Pt/Re) catalyst in the reactors causing a decrease in reaction yields and catalyst life.

AX

Net Hydrogen

HydrogenRecycle Gas

Off Gas

Liquid

Reformate

Recy

cle G

as

Fired Heater Fired Heater Fired Heater

Fixed Bed Reactor

Naphtha and Hydrogen

Recycle Gas

Feed (Naptha)

Cooler

Gas Separator

Fixed Bed Reactor

Fixed Bed Reactor

5

Fluid catalytic cracking unit (FCCU) C3 gasesFluid catalytic cracking units (FCCU) are a major source of propylene (C3H6) used in petrochemical plants. The yield of propylene from an FCCU (Figure 4) varies with the feedstock and operating conditions. Refineries operate FCCUs to achieve a balance between gasoline and propylene production according to demand.

Figure 4. H2S measurement points in C3 gas streams from an FCCU

The feed to an FCCU is typically a vacuum distillation gas oil fraction which has undergone hydrotreating to remove organic sulfur compounds. Hydrotreating removes most, but not all sulfur from the vacuum gas oil fraction. Fluid catalytic cracking is a high temperature catalytic process that breaks high molecular weight compounds in the gas oil feed into a complex mix of lower molecular weight compounds. The catalytic cracking reactions break down sulfur compounds remaining in the gas oil feed, liberating sulfur and forming H2S. The resulting hydrocarbon mixture is passed through a series of fractionation and separation columns to recover individual liquid and gas product streams. The vapor pressure of H2S falls between ethane and propane, causing it to partition and concentrate in the light gas fractions. A portion of the H2S carries through the debutanizer, depropanizer and C3 splitter columns. H2S is monitored in the C3 mix to the C3 splitter and the propylene and propane product streams. Further processing may be required to remove residual H2S and ensure these products meet purity specifications for downstream processes.

Traditional H2S measurement technologiesRefineries have employed several different technologies to measure H2S in gas streams, including gas chromatography (GC), lead acetate tape analyzers, and ultraviolet (UV) absorbance analyzers. The operating principle, analytical interferences, analyzer response time, installation requirements, analyzer uptime / availability, and CAPEX and OPEX all factor into selection of an appropriate technique and analyzer for a specific process gas stream.

Gas chromatography (GC)Gas chromatography is widely used in refineries for compositional analysis of complex hydrocarbon mixtures, and for monitoring the presence and level of sulfur compounds in gas streams. A GC equipped with a sulfur-selective detector generates a separate chromatogram of sulfur compounds present in a sample after they elute from a GC column.

The most common type of sulfur-selective detector is the flame photometric detector (FPD). In operation, sulfur compounds in the sample are combusted in a hydrogen-rich flame inside a quartz combustor as they elute from the GC column. During combustion sulfur forms an excited-state sulfur dimer (S2) which emits a characteristic light energy as it returns to the

6

ground state. The emissions from the S2 dimer range from very weak to very strong and encompass spectral wavelengths from 300 to 500 nm. The emissions are detected by a photomultiplier tube (PMT). The response of the PMT is quadratic and proportional to the amount of sulfur.

Sulfur selectivity is achieved by using a narrow-band transmission filter that transmits a single band of light from the S2 dimer at 394 nm. All other sulfur emissions are blocked. An optical shield is sometimes used with an FPD to minimize hydrocarbon emissions from interfering and causing false positives or high background interference. Hydrocarbon quenching of the sulfur response in an FPD arises from combustion products (CO, CO2, H2O, S2O), incomplete combustion of hydrocarbons, and poor separation of hydrocarbons in the GC column.3

FPDs exhibit good selectivity and sensitivity for low level measurement of sulfur species (H2S, COS, CS2, and mercaptans). A drawback of the FPD is that in normal operation soot builds up on the inside of the quartz combustor tube from combustion of samples. Soot deposits interfere with transmission of the sulfur emission to the photomultiplier tube reducing detector response and measurement sensitivity. Regular maintenance is required to clean and remove soot deposits from the combustor tube.

The retention time for H2S and other sulfur compounds will shift over time. This is attributable to changes in the column and condition of GC sample injection valves. A shift in analyte retention time can result in increased cross-interferences and decreased measurement accuracy. Correcting for these effects requires regular calibration checks and maintenance. Roughly 80% of GC maintenance involves troubleshooting, repairing, replacing analysis valves and/or valve components.4

Lead acetate tape analyzersThe photometric technique for measuring H2S in natural gas and gaseous fuel samples using lead acetate impregnated paper tape has been in use over 40 years.5 Lead acetate tape analyzers feed a paper tape into a chamber where it is exposed to a gas sample containing H2S which reacts with lead acetate forming PbS (according to reaction below), causing a brown stain to develop in the paper tape. After an exposure time under controlled gas flow and tape feed rate conditions, the tape advances into a sensor block.

H2S + Pb(CH3COO)2 → PbS + 2CH3COOH (Chemical reaction employed in lead acetate tape analyzers)

While lead acetate tape analyzers are relatively simple devices they have several drawbacks for monitoring H2S in refinery gas streams. The proprietary tape used in these analyzers is a consumable item requiring replacement every 4 to 8 weeks. Acetic acid used to moisten the tape and promote the reaction must also be replenished on a regular basis. The annual cost of consumables for a lead acetate analyzer falls in the $900 to $2,500 range (depending upon the manufacturer and application requirements).

If the tape breaks it must be replaced immediately. A spike in H2S concentration can fully expose the entire tape requiring immediate replacement.

These types of issues reduce the availability (uptime) of lead acetate analyzers in applications requiring continuous, uninterrupted operation such as monitoring H2S in fuel gas for environmental compliance, and in hydrogen recycle streams in hydrotreating and catalytic reformer units.

It should also be noted that lead acetate paper tape (CAS 6080-56-4)6 is classified as a hazardous waste according to U.S. and EU regulations (RCRA Code D002/D003, EU 16 05 067) requiring hazardous waste disposal. Proper disposal of used tape in a lab pack waste container incurs additional operating cost, and failure to do so can lead to a violation and a fine.

7

UV absorbance A variety of compounds absorb UV energy including; sulfur compounds, unsaturated hydrocarbons, aromatic hydrocarbons, alcohols, alkenes, alkynes, ketones, amines, ammonia, mercury, and halogens. The UV absorbance spectra of H2S, carbonyl sulfide (COS), methyl mercaptan (MeSH), and natural gas are shown in Figure 5.8 Many refinery gas streams contain multiple compounds with overlapping UV absorbance spectra. Measurement of H2S and other sulfur species is complicated by the presence of UV absorbing matrix interferences in a gas sample.

Figure 5. UV absorbance spectra of H2S, COS, MeSH, and natural gas showing spectral overlap in the 210 – 270 nm wavelength range8

For this reason, UV absorbance analyzers have been specifically excluded from use by process licensors in some refining and petrochemical applications requiring measurement of low ppm concentrations of H2S in process streams containing compounds with known UV absorbance interferences, (olefins, aromatics, etc.).

UV absorbance analyzers use cathode lamps which emit a broad wavelength output over a nominal range of 200 to 700 nm (depending upon lamp construction). This broad wavelength output requires use of a narrow band width spectral filter to minimize interferences by filtering out UV wavelengths that would be absorbed by other components in the sample gas stream. A filter wheel mechanism allows selection and positioning of the wavelength filter in the light path to the measurement cell. The filter blocks a broad spectrum of UV wavelengths and allows a narrow band of wavelengths to pass through. While the narrow band of wavelengths passing through the filter reduces many potential interferences, it is not a single high-resolution analyte-specific wavelength the eliminates all interferences.

There are some technical and operational concerns with the use of a hollow cathode lamp as a UV light source in a process gas analyzer. The UV lamp output progressively decreases in continuous 24/7 operation. Decreasing UV lamp output causes measurement drift which must be compensated for with a daily zero calibration, so lower lamp output energy isn’t misinterpreted as UV absorbance from the target analyte.

Some UV analyzers are equipped with two different hollow cathode lamps outputting different wavelengths. In this design a particular wavelength (326 nm) from both lamps is used to provide some drift compensation, with other output wavelengths and a selection wheel with 6 optical bandpass filters used to measure H2S, COS, and methyl mercaptan (MeSH).

8

At some point the decreasing energy output from the lamp is insufficient for performing accurate UV absorbance measurements and the lamp must be replaced. In continuous 24/7 operation this is likely to occur one or more times per year. The replacement cost of a UV lamp from an OEM manufacturer can be as high as $2,000 or more.

To further minimize UV-absorbing interferences, one manufacturer has incorporated hardware to perform frontal elution chromatography on the sample stream. Interfering compounds entrained in the sample gas are separated and retained in a porous polymer column, while H2S elutes first from the column, followed by COS and MeSH. While this approach improves measurement selectivity, it adds to overall system complexity, maintenance, and operating costs.

UV absorbance analyzers are commonly used to monitor and control the H2S:SO2 ratio in Claus sulfur recovery units (SRUs) to maximize the yield of elemental sulfur and minimize sulfur compounds in the tail gas exiting the process.8 In this application the sample stream contains fewer components with UV-absorbing interferences.

Tunable diode laser absorption spectroscopyMany refineries have transitioned from older H2S measurement technologies to TDLAS analyzers over the last 10 years. TDLAS analyzers are designed to selectively and specifically measure H2S and other analytes (H2O, CO2, C2H2, NH3, and HCl) in hydrocarbon process streams. The basic design of the measurement cell in a TDLAS analyzer is depicted in Figure 6. The principal components of the cell are; an optical head housing the laser with thermo-electric cooler (TEC) and a solid-state detector, the cell body with a mirror positioned at the end opposite the laser, gas inlet and outlet connections, and temperature and pressure sensors.

Figure 6. The Measurement Cell in a TDLAS Analyzer

In operation, process gas from a sampling probe is introduced to the sample cell of the TDLAS analyzer. A tunable diode laser emits a wavelength of near-infrared (NIR) light that is selective and specific for the target analyte into the sample cell where it passes through the gas and is reflected back by the mirror to a solid-state detector. A window isolates the laser source and solid-state detector components from the sample gas stream flowing continuously through the cell. This design allows measurements to be performed with absolutely no contact between the process gas (and entrained contaminants) and critical analyzer components. Analyte molecules present in the gas sample absorb and reduce the intensity of light energy in direct proportion to their concentration according to the Lambert-Beer law. The difference in light intensity is measured by the solid-state detector and this signal is processed using advanced algorithms to calculate analyte concentration in the process gas.

TECOptical Head CoverOptical HeadLaser

Window

Pressure Sensor

Temperature Sensor

Inlet

Metal Mirror

Detector

Outlet

9

Differential spectroscopy for low-level H2S measurementsSpectraSensors developed and patented a spectral subtraction technique that enables low ppm level measurements of H2S (and H2O or NH3) to be made when a process a gas stream contains very low levels of an analyte and background gas interferences.9,10,11,12

In operation the TDLAS analyzer performs a sequence of steps to obtain a “zero” spectrum and “process” spectrum that are used to calculate analyte concentration by spectral subtraction as depicted in Figure 7. The zero spectrum is obtained by passing the process gas sample through a high-efficiency scrubber which selectively removes trace amounts of H2S, without altering the process gas composition and background absorbance. The analyzer records the resulting H2S-free spectrum of the process gas and automatically switches the sample flow path to bypass the scrubber and collect the process gas spectrum (with H2S). Subtraction of the recorded zero spectrum from the process spectrum generates a differential spectrum of H2S that is free of background interferences. The concentration of H2S is calculated from the differential spectrum.

Figure 7. Differential Spectroscopy using Spectral Subtraction

A particular advantage of the Differential Spectroscopy technique for low level H2S measurements in refinery gas streams is that it dynamically corrects for changes in gas stream composition, temperature, or pressure, when spectral distortion from such changes exceed preset values in the analyzer firmware.

Differential Measurementa - b = H2S Spectrum

b. H2S - Free Zero Spectruma. Process Gas Spectrum with H2S

Gas with H₂S H₂S - Free Gas

Wavelength Wavelength Wavelength

Abs

orba

nce

Abs

orba

nce

H2O

Abs

orba

nce

10

Figure 8 provides an example of Differential Spectroscopy applied to H2S measurement in a simulated catalytic reformer hydrogen recycle gas stream. The composition of the stream was 80% hydrogen, 10% isobutane, 8.5% methane, and 1.5% ethane. The upper box shows the spectrum of the sample with 20 ppm H2S and the zero spectrum with the H2S removed by the scrubber. The lower box shows the 20 ppm H2S differential spectrum with background interference removed and an improved signal-to-noise ratio.

Figure 8. Differential spectrum of 20 ppm H2S in a simulated catalytic reformer hydrogen recycle gas stream

11

The repeatability and linearity of H2S measurements obtained by applying differential spectroscopy at concentrations of 20, 10, 5, 2.5, and 1.25 ppm are shown in Figure 9. The average 2σ repeatability is < 148 ppb, and linearity 0.9999.

Figure 9. Repeatability and linearity results for H2S measurements at 20, 10, 5, 2.5, and 1.25 ppm in a simulated catalytic reformer hydrogen recycle gas stream (80% H2, 10% C4H10, 8.5% CH4, and 1.5% C2H6).

Factory calibration and field validationEvery SpectraSensors TDLAS analyzer is factory tested and calibrated using a test mixture blended to simulate the customer’s process gas stream. The dilution ratio of the H2S standard and mixing ratio of the background stream gases are controlled by digital mass flow controllers with NIST certifications.

The resulting calibration report is included in the documentation package shipped with the analyzer. Customers can elect to have a Factory Acceptance Test (FAT) to witness analyzer calibration at SpectraSensors’ manufacturing site in Rancho Cucamonga, California.

The solid-state laser and detector components used in TDLAS analyzers are intrinsically stable, so no field calibration is required over the lifetime of the analyzer. Users perform periodic validation checks to verify the analyzer is operating properly within its factory-certified calibration range and ensure measurements are accurate for the intended process control, product quality, or environmental compliance purposes.

The purpose of validation is stated in section 3.3 of API RP 555; “Validation is observing and noting the difference (if any) between the analyzer reading and the agreed analysis of a standard introduced into the analyzer, but with no adjustment made to the analyzer.”13

SpectraSensors TDLAS analyzers for H2S measurements in fuel and flare gas can be equipped to perform a daily two-point automated validation check to meet U.S. EPA compliance reporting requirements.

12

Field proven applications of TDLAS analyzer in refineriesSpectraSensors TDLAS analyzers are installed and performing critical on-line H2S measurements in dozens of refineries around the world. Table 1 contains a list of field-proven TDLAS analyzer H2S measurement applications.

Table 1. Field-proven TDLAS Analyzer H2S Measurement Applications

Application Typical Measurement Range / (Purpose)

H2S in hydrotreater hydrogen recycle gas at outlet of an amine treatment unit

0 – 50 / 0 – 100 / 0 – 200 ppm (Process control)

H2S in semi-regenerative catalytic reformer (SRR) hydrogen recycle gas

0 – 50 ppm (Process control and catalyst protection)

H2S in continuous catalytic reformer (CCR) hydrogen recycle gas

0 – 50 ppm (Process control and catalyst protection)

H2S in fluid catalytic cracker unit (FCCU) (C3 gases C3 mix / propylene / propane)

0 – 10 ppm (Product purity)

H2S in refinery fuel gas 0 – 320 ppm (Environmental compliance)

H2S in refinery flare gas 0 – 10 through 0 – 300 ppm (Environmental compliance)

SummaryOn-line monitoring of H2S provides refineries with the data needed to improve process control, meet product specifications, mitigate corrosion and catalyst poisoning, comply with environmental regulations, and remove H2S from hydrogen and off gas streams used throughout the refinery.

A number of design and performance characteristics make TDLAS analyzers well suited for on-line measurement of H2S in refinery gas streams.

• The high-resolution diode laser enables selective and specific measurement of H2S in complex hydrocarbon gas streams

• Sample gas flows continuously through the measurement cell of a TDLAS analyzer providing an exceptionally fast response to H2S concentration changes

• Laser and detector components are isolated and protected from process gas and contaminants providing superior accuracy and reliability (analyzer availability > 95%)

• Patented Differential Spectroscopy technique provides accurate low ppm H2S measurements in complex hydrocarbon streams, and when the stream composition changes significantly

• Factory calibration using a gas mixture blended to simulate a customer’s process stream composition ensures accurate measurements and stable long-term operation in the field, with no recalibration required

• TDLAS analyzers require virtually no consumable items resulting in a lower maintenance and service burden, and lower operating expenses than other types of H2S analyzers

Contact

4333 W. Sam Houston Pkwy N. Suite 100Houston, TX 77043

Tel +1 713 300 2700 +1 800 619 2861Fax +1 713 856 6623

sales@spectrasensors.comservice@spectrasensors.comwww.spectrasensors.com O

n-Li

ne M

onito

ring

of H

2s in

Re

finer

y Ga

s Stre

ams U

sing

TDLA

S

References1. The Chemistry and Technology of Petroleum, 2nd Edition, 1991

2. Fundamentals of Petroleum Refining, Elsevier B.V., 2010

3. Gas Chromatography: an Accurate, Fundamental Tool in Sulphur Analysis, Petro Industry News, October / November 2013

4. Minimize Gas Chromatograph Downtime, Chemical Processing, September 2016

5. Process Analyzer Technology, John Wiley & Sons, Inc., 1986

6. CAS Registry Number 68308-27-0, Chemical Abstract Service, American Chemical Society

7. EINECS Number 269-640-8, European Inventory of Existing Commercial Chemical Substances, European Chemicals Agency

8. Combining Spectroscopy and Separation Science in Process and Emissions Monitoring, ISA 55th Analysis Division Symposium, 2010, New Orleans, LA

9. U.S. 7,704,301 B2

10. U.S. 7,819,946 B2

11. U.S. 8,152,900 B2

12. U.S. 8,500,849 B2

13. API Recommended Practice 555 – Process Analyzers, Downstream Segment, 2nd Edition

About the AuthorGary Engelhart is Product Line Marketing Manager for SpectraSensors. He is responsible for TDLAS analyzer applications in the hydrocarbon processing industry (natural gas processing, LNG, refining, and petrochemicals), and has 25 years of experience in analytical instrumentation and chemical process equipment.