Technical Article: Reduce Sulfur Emissions From Claus Sulfur Recovery Unit Tail Gas Treaters Reprint : Printed April, 1994 Reduce Sulfur Emissions

From Claus Sulfur Recovery Unit Tail Gas Treaters by William L. Echt Union Carbide Corporation Houston, Texas and Carl J. Wendt, Jr. The Ralph M. Parsons Company Pasadena, California Prepared for Presentation at AlChE Spring National Meeting Gas Processing: Sulfur Recovery and Tail Gas Cleanup March 28th to April 1st, 1993 Houston, TX 1994 Union Carbide Corporation All Rights Reserved

Unpublished AlChE shall not be responsible for statements or opinions contained in papers or printed in its publications UCARSOL is a registered trademark of Union Carbide.

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Introduction

Environmental regulatory agencies are continuing to promulgate more stringent standards for sulfur emissions from oil and natural gas processing facilities. Most large scale processes use a Claus-type sulfur recovery unit (SRU) to recover elemental sulfur from process gas streams containing hydrogen sulfide (H2S). Normally, Claus SRU's recover 95 to 97 percent of the sulfur in their feed gases. A significant amount of sulfur remains in the SRU off-gas which, frequently in the past, had been incinerated and released to the atmosphere. One method of improving sulfur recovery involves addition of a hydrogenation reactor and an amine unit to treat tail gas from the Claus SRU. The residual sulfur recovered from the tail gas stream is recycled as H2S to the front of the Claus SRU, resulting in a total sulfur recovery efficiency of over 99.9 percent. This corresponds to less than 250 parts per million by volume (ppmv) of H2S in the off-gas going to the incinerator or thermal oxidizer. This paper focuses on tail gas hydrogenation and amine systems. This technology is known as the Beavon Sulfur Removal (BSR) Process, after the inventor, David K. Beavon. Experience with performance amine solvents is discussed. Case studies are presented which show that when using specially manufactured UCARSOL Solvent HS-103, treated off-gas H2S levels of less than 10 ppmv can be consistently achieved. Fuel gas savings, due to venting the off-gas in lieu of incineration, are documented. The primary factors that determine the overall success of this process, which is most often used for Claus SRU tail gas treating, are the choice of amine solvent, the selection of operating conditions, and special considerations taken in the equipment selection and design. This paper will address all of these topics.

Overall Process Description

Figure 1 shows a block flow diagram of a typical sulfur recovery system consisting of a Claus SRU, a BSR tail gas hydrogenation section, a UCARSOL Solvent tail gas treater, and a thermal oxidizer. The feed to the Claus SRU can come from a variety of acid gas removal processes including refinery amine and sour water stripping systems or a natural gas sweetening unit. The basic Claus process is typically used for acid gas streams containing 35 volume percent or more hydrogen sulfide. The balance of the typical acid gas feed stream consists mainly of carbon dioxide (CO2), small quantities of hydrocarbons, and saturation water vapor. Claus SRU's have been built to produce from only a few to over 1500 tons of elemental sulfur per day. A number of variations of the Claus process have been developed to treat streams containing lower concentrations of H2S. The Recycle Selectox process will handle feed gases with hydrogen sulfide levels from less than one to over 30 volume percent1.

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Sulfur Recovery Unit Figure 2 is a simplified flow diagram of a Claus SRU that could be used with an H2S -rich acid gas feed. One-third of the H2S in the feed is burned to sulfur dioxide (SO2) with air in the reaction furnace. Then the H2S and SO2 mixture is converted to sulfur and water, both in the furnace and in the two or three converter stages containing alumina catalyst. Sulfur vapor is condensed and removed as a liquid product after the furnace and each converter stage. Process gas is reheated to reaction temperature before each converter stage. Liquid sulfur product is drained from the condensers through seals, and collected in a pit. The sulfur compounds that are not recovered in the Claus SRU consist of unreacted H2S and SO2, uncondensed sulfur vapor, and small amounts of carbonyl sulfide (COS), and carbon disulfide (CS2). In the past, this "tail gas" stream was incinerated to convert all sulfur compounds to SO2 and vented to the atmosphere through a tall stack.

Tail Gas Treating Unit Additional treatment of the Claus SRU tail gas has resulted from mandates for lower sulfur emissions to the atmosphere. Many facilities now utilize a catalytic hydrogenation/hydrolysis reactor to convert sulfur compounds in Claus SRU tail gas to H2S, followed by a selective H2S recovery unit that recycles most of the hydrogen sulfide to the front of the Claus SRU. Figure 3 is a simplified flow diagram of a BSR/MDEA tail gas treating unit. This process utilizes a reducing gas generator where fuel gas is burned substoichiometrically to produce hydrogen (H2) and carbon monoxide (CO) for the hydrogenation reactions as well as heat. The SRU tail gas is mixed with the combustion gases in the reducing gas generator and then is fed to the hydrogenation/hydrolysis reactor. In the reactor almost all of the sulfur compounds are catalyctically converted to H2S. The reactor effluent is first cooled by generating steam and then flows to a desuperheater/contact condenser. In the bottom of the column the gas is cooled by adiabatically saturating it with a pump-around water stream. The gas is then cooled in the top of the column to near ambient temperature by direct contact with a circulating cooled-water stream. Reaction water from the Claus SRU is condensed and purged from this loop. The cooled effluent from the desuperheater/contact condenser is contacted in the absorber with a selective, MDEA-based performance solvent such as UCARSOL Solvent HS-101 or HS-103, to absorb most of the H2S while rejecting the bulk of the CO2. Regulations require that the treated off-gas from the absorber must be routed through a thermal oxidizer before being vented to the atmosphere, if it contains more than 10 ppmv hydrogen sulfide. Incineration ensures that all sulfur species are converted to SO2 prior to venting. The H2S- rich amine from the absorber is preheated by exchange before entering a reboiled regenerator where the absorbed acid gases are stripped from the aqueous solution. A direct-contact condenser is used in the regenerator to reduce pressure drop and regenerator bottom temperature. The lean solvent is recycled to the absorber after being cooled. The capacity and efficiency of the Claus SRU is improved by rejecting as much carbon dioxide into the treater off-gas as possible, thereby enriching the hydrogen sulfide content of the recycled acid gas and minimizing carbon dioxide buildup in the system.

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Tail Gas Amine Treating

Solvent Selection The development of alkanolamine solvents for acid gas treating is summarized in Figure 4. Monoethanolamine (MEA), diethanolamine (DEA), and, to a lesser extent, diglycolamine (DGA) were used initially for total acid gas removal. Common applications included refinery process streams, hydrogen plants, natural gas liquid extraction facilities, ammonia plants. and ethylene plants. Many of these facilities still use these generic amines. The need for selective sweetening was identified as energy costs increased dramatically in the early 1970's, and improved sulfur plant operations were desired.2,3 Selectivity refers to preferentially absorbing H2S while "slipping" CO2 into the treated gas stream. Methyldiethanolamine (MDEA), a tertiary amine, eventually became the most common selective solvent due to its resistance to degradation and low tendency for corrosion. The final development in amine technology was the introduction of performance solvents which are based on tertiary amines. Proprietary additives are combined with the tertiary amine to give even greater selectivity and lower energy consumption. Additives can also be used to achieve removal of organic sulfur compounds such as carbonyl sulfide. Additionally, some of the performance solvents are manufactured to provide more efficient, CO2 removal versus MEA and DEA. The chemistry of amine selectivity is based on the relative rates of reaction between the compounds. All amines react rapidly with hydrogen sulfide. However, different classes of amine react at significantly different rates with carbon dioxide because of amine structure and the mechanism of the reaction. Referring to Figure 5, primary and secondary amines react directly and fairly rapidly with CO2 to form a carbamate ion. Tertiary amines can not form a carbamate ion, due to the lack of a free hydrogen radical on the nitrogen atom. The CO2 must first dissolve in and react with water to form carbonate before reacting with the tertiary amine. This step reduces reaction rates between CO2 and tertiary amines, producing their selectivity toward H2S.

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Diisopropanolainine (DIPA) a secondary amine, was the first selective solvent used in low pressure applications. DIPA's selectivity is based on the large isopropanol radicals surrounding the available hydrogen radical on the nitrogen atom in the molecule. Steric hinderance reduces reaction rates with carbon dioxide to yield some selectivity toward H2S. Performance UCARSOL solvents, based on MDEA, offer superior hydrogen sulfide selectivity, lower energy consumption, and the ability to treat the tail gas to lower H2S levels. The energy savings that are gained with performance solvents stem from a reduction in sensible heat and a lower heat of reaction. Tertiary amine-based solvents can operate at 50 weight percent solution strength without increased concern for corrosion. Therefore, circulation rates can be lowered, and the sensible heat requirement in the regenerator reboiler is reduced. The heat of reaction between a tertiary amine and H2S or CO2 is lower than for the reaction with primary and secondary amines. This reduces the amount of energy needed to regenerate a performance solvent. Most performance solvents are able to achieve off-gas hydrogen sulphide levels of 50-200 ppmv from an absorber that operates at, or very close to, atmospheric pressure.

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One performance solvent, UCARSOL Solvent HS-103, is able to achieve levels less than 10 ppmv in the treated off-gas stream, enabling the off-gas to be vented rather than incinerated. Substantial fuel savings are obtained by putting the incinerator on warm standby. Performance Solvents Three case histories will demonstrate the advantages of performance solvents in the operation of a tail gas treater (Figure 6). An existing tail gas treater was operating with 27 weight percent DIPA and the operators were interested in improving the H2S concentration of the recycle gas fed back to the front of the Claus SRU reactor, while also achieving energy savings in the tail gas unit. This was accomplished by converting to UCARSOL Solvent HS-101. The CO2 slippage improved from 48 percent with DIPA to 95 percent with the new solvent. The concentration of H2S in the recycle stream increased from 35 volume percent to 66 volume percent. In addition, a 49 percent energy savings was achieved through reduced regenerator reboiler steam. The operators of another existing tail gas treater (Figure 7) wanted to reduce H2S emissions to below 10 ppmv from the current level of more than 100 ppmv. The environmental regulatory agency for the refinery would permit the temperature in their thermal oxidizer to be reduced from 1200°F (650°C) to 600°F (315°C) if the lower H2S level could be attained. UCARSOL Solvent HS-103 was employed to treat the Claus SRU tail gas to the lower specification. The incinerator temperature was reduced and the fuel gas consumption is now one-half the design rate. When combined with lower regenerator reboiler steam requirements, the calculated energy requirement is 55 percent lower with the new solvent.

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A third example illustrates the proven performance of UCARSOL Solvent HS- 103 in consistently meeting a 10 ppmv treated gas H2S specification. A new tail gas unit was added to a Claus SRU at a Los Angeles, California refinery under than strict control of the South Coast Air Quality Management District. As part of the BSR/ UCARSOL Solvent HS-103 design, treated gas from the amine absorber was to be vented directly to the atmosphere without being routed through a thermal oxidizer. The only provision made for upsets was to divert absorber feed to the original SRU incinerator. This unit operated successfully as designed with direct atmospheric venting for two years. The incinerator must be kept warm and ready but is normally bypassed. The H2S in the treated gas from the absorber is continuously monitored and consistently has been below 10 ppmv. The design gas stream to the absorber is 3.0 mmscfd (3349 Nm3/h) at 17.2 psia (119 kPa) and 100°F (38°C). Lean amine to the absorber is maintained at or below 100°F (38°C). In addition to offering the latest in amine treating technology, Union Carbide provided valuable technical services, free-of-charge, in support of these conversions to UCARSOL Performance Solvents. These services included computer simulations of the amine treating unit, solution analyses, and engineering assistance in optimizing and trouble-shooting the amine systems. Using the experience gained by servicing over 300 facilities worldwide (including over 30 tail gas amine systems), the Union Carbide engineers were able to prevent problems and quickly identify remedial actions when problems did occur. The analytical and engineering services are ongoing for as long as UCARSOL Solvent is used in the amine system.

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Hydrogenation/Hydrolysis Design Considerations There are several design features incorporated in the BSR hydrogenation/hydrolysis system that are worthy of consideration in any new design. First, although this processing step operates with a different catalyst and at a higher temperature, its configuration is almost the same as an SRU converter stage. In a new plant design, the hydrogenation/hydrolysis step logically becomes an extension of the SRU and is designed and laid out like another SRU stage. This results in a compact plot arrangement and a minimum capital cost. Second, in virtually all circumstances the BSR reducing gas generator produces sufficient hydrogen and carbon monoxide for the reduction of sulfur vapor and SO2 to H2S. This means that an external source of hydrogen is not needed. Although providing hydrogen in a refinery is normally not a serious problem, it can add significant costs in a field gas plant or other facility where hydrogen is not readily available. Good instrumentation and controls on the Claus SRU and an excess hydrogen analyzer downstream of the BSR have proven adequate to assure complete hydrogenation in a number of operating units. Finally, separation of the desuperheater and the contact condenser water circulation loops in the BSR unit adds only a modest cost, but makes it possible to keep the desuperheater circuit alkaline, to minimize the possibility of an acidic carryover into the amine absorber. This provides a final guard against SO2 breakthrough from the hydrogenation reactor that could result from a rare major upset in the upstream Claus SRU. This alkaline water inventory gives the plant operator time to divert gas flow from the MDEA-based solvent absorption system before it can be seriously degraded by SO2. Alkalinity in the water loop is provided by adding sodium hydroxide, which rapidly equilibrates with H2S and CO2. in the gas being quenched, to form a mixture of sodium carbonate, bicarbonate, and bisulfide. Since SO2 is a much stronger acid than H2S or CO2 it is absorbed by these compounds, freeing absorbed H2S and CO2. The alkalinity of the desuperheater water is checked periodically and after any known upset, to determine if it is necessary to purge some of the solution and add more caustic.

Amine Unit Design Considerations

Key considerations in the operation of a tail gas amine unit include control of SO2 breakthrough from the hydrogenation/hydrolysis reactor and the Iean amine temperature. Also, many of the problems common to tail gas amine unit operation can be avoided or minimized by installation of equipment that will reduce the amount of contaminants entering the system, by removal of contaminants that do get into the system, and by recovering solvent which would otherwise be lost from the system. Due to higher amine cost per pound of solution when using performance solvents, loss reduction becomes critical. Finally, the overall pressure drop of the Claus SRU and tail gas treating system must be minimized to avoid the need for a booster blower for the main gas stream. Some compromises, such as the use of packing in the amine absorber where trays might be more desirable, become attractive. Design features considered important by both Union Carbide Corporation and The Ralph M. Parsons Company are reviewed in the remaining discussion. Control of SO2 Breakthrough The most common problem facing the tail gas amine system is the breakthrough of SO2 from the hydrogenation/hydrolysis reactor.

Sulfur dioxide reacts with any amine in the presence of H2S to form sulfate and thiosulfate

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anions. Side reactions can result in the formation of acetate and forinate anions. These acidic anions form amine salts which are called “heat-stable” because they do not dissociate at regenerator temperatures. A breakthrough of SO2 from the hydrogenation reactor, resulting from an infrequent, major Claus SRU upset, will cause corrosion in downstream equipment and severely contaminate the amine solution with heat-stable salts. The resulting solution has less amine available for acid gas removal and can be corrosive at reboiler temperatures, depending on the level of contamination and the metallurgy of the reboiler tubes. Some heat-stable salts can promote foaming, which can result in off-specification treated gas and high amine losses. It may be necessary to reclaim or discard the amine following a large breakthrough of SO2. Maintaining excess hydrogen in the catalytic hydrogenation/hydrolysis reactor will insure complete reduction of all the sulfur compounds exiting the Claus SRU unit. A hydrogen analyzer on the quench tower overhead stream can determine excess H2, and can be used to adjust the flow of fuel gas to the reduction gas generator as well as to monitor and control Claus SRU operation. Maintaining a separate alkaline desuperheating circuit provides a final degree of safety. These measures should prevent the breakthrough of sulfur dioxide into the amine contactor. Lean Amine Temperature At the very low pressures, on the order of 15.2-17.2 psia (105-119 kPa), encountered in a tail gas treater the driving force for the acid gas/amine reaction is substantially reduced relative to higher pressure applications. Low amine temperatures, in the range of 90-100°F (32-38°C), have been successful in increasing the H2S pickup in these units. Theoretically, there are no hydrocarbons in the tail gas exiting the quench tower. However, severe foaming due to hydrocarbon contamination has been observed in this application when impure refinery H2 is used for hydrogenation. Experience indicates that the lean amine temperature should be maintained 5°F higher than the inlet gas temperature to prevent condensation of hydrocarbons that may be present in the gas. The design and control of the upstream quench tower is very important because it determines the gas temperature entering the amine contactor. In order to meet an off gas specification of 10 ppmv H2S, the lean amine cannot exceed 100°F (38°C) when using UCARSOL Solvent HS-103. The feed gas temperature should, therefore, be maintained at or below 95°F (35°C) when there is any possibility of hydrocarbon contamination. When Parsons' BSR technology is employed, the tail gas and lean amine can often be operated at the same temperature, due to the lack of hydrocarbon contamination. Amine Filtration Particulate filtration is essential for maintaining good solution quality. Solids in the amine will cause foaming, resulting in high amine loss. Also, equipment fouling and plugging due to particulates can result in damage to pumps, exchanger, and tower intemals through erosion and/or corrosion. A variety of filter designs can be successfully employed. A cartridge filter located on the rich amine stream is recommended, though in many designs lean amine is filtered to protect workers from exposure to H2S when changing filter elements. When rich amine is filtered, provisions should be made to displace the contents of the filter with fresh water before it is opened. This is also desirable with lean side filters to minimize losses of amine. Filtration of

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the entire stream is desirable, although a 15 - 30% slip stream filter is acceptable for large systems with high circulation rates. An activated carbon bed or basket-type carbon filter removes surface-active contaminants and impurities that promote foaming. A properly sized slip stream carbon filter will improve the unit's overall reliability by reducing amine losses due to foaming. Carbon filters are normally sized at 20 to 25% of the particulate filter flow rate. Most units place the carbon bed downstream of the particulate filter to prolong the life of the carbon. When a granular bed carbon filter is used, a post-filter or guard-filter is needed to catch carbon fines. Sump and Tank Blanketing All amine units should be provided with a closed drain and sump system. These drains minimize losses of valuable chemicals and prevent amine contamination of sewers, run-off water, and the ground around the unit. The sump should be fuel- or inert-gas purged and vented to the thermal oxidizer to prevent H2S leakage or oxygen contamination of the amine. Oxygen dissolved in the amine-water solution reacts with dissolved hydrogen sulfide to form acidic heat-stable salts and elemental sulfur. Surge and storage tanks at atmospheric pressure should also be blanketed with inert gas to prevent oxygen contamination. These atmospheric tanks can normally be vented to the atmosphere, since they contain only fresh or well-stripped amine solutions. Abosorber Overhead Separation and Water Wash Some form of treated gas separator is necessary between the amine absorber and the thermal oxidizer to separate and contain any mist or foam entrainment from the absorber, or heavy liquid carry-over resulting from absorber flooding. This separator is needed both to protect the hot oxidizer refractory from liquids and to minimize solvent losses. In addition, a simple water wash is desirable to recover amine vaporization losses and to assist in entrainment removal. Although the vapor pressure of most amines is quite low at absorber operating temperature, the high volume of gas being treated and the near atmospheric absorber operating pressure contribute to vaporization losses that warrant recovery. Parsons generally provides a pump-around water wash with a co-current spray in the absorber overhead piping. The absorber overhead knock-out drum acts as a separator and surge drum for this system. A small, continuous water make-up is added to keep the amine in the water at less than 0.5 to 1.0 weight percent. A water and recovered-amine slipstream is bled from the wash water circulating pump discharge to the rich amine line exiting the absorber. Absorber Trays versus Packing In general, a trayed absorber with multiple liquid feed points is preferred over a packed absorber, when very high selectivity for H2S absorption is required.

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However as more equipment is added with the tail gas treating unit, the total pressure drop through the Claus SRU and tail gas system increases to a point where SRU inlet pressure becomes excessive. The options then are to add a tail gas blower 4 somewhere in the system, or to look for ways of reducing pressure drop. Tail gas blowers are undesirable since they are expensive and prone to a number of operating problems. One way to reduce pressure drop is to use a packed absorber rather than a trayed absorber. This reduces overall pressure drop by 1.0 to 1.5 psi (7 to 10 kPa) which is normally enough to eliminate the need for a booster blower. Parsons has successfully used packed absorbers in several units designed without blowers, with no significant loss in H2S absorption selectivity. Regenerator Condenser System Most amine regenerators use air or water coolers to cool the acid gas and condense water from the column overhead vapor upstream of a reflux accumulator. Parsons generally prefers using a circulating water contact condenser. With the contact condenser, cooled water is countercurrently contacted with the hot, water-saturated gas over trays or a small packed bed on top of the regenerator. The heated water is recirculated through a cooler to the top of the condenser selection, while net condensate drains back to the regenerator. The contact condenser has three main advantages over the conventional system. First, the total pressure drop with the contact condenser is 1.5 to 2.0 psi (10 to 14 kPa), less than with a conventional condenser. This allows a higher acid gas delivery pressure or, at constant delivery pressure, a 2 to 3°F (1 to 2°C) lower reboiler temperature. The second advantage comes when air coolers are used in cold climates. The potential for cooler plugging and damage due to freezing is substantially less with a contact condenser versus a conventional overhead condensing system where a small amount of water is condensed from a large gas stream. Finally, the cooler in the direct contact condensing system is less subject to corrosion and fouling. Hot and wet acid gases are corrosive, and fouling is promoted by the low gas velocity needed to minimize pressure drop in conventional condensers.

Summary BSR/MDEA tail gas systems significantly Improve sulfur recovery efficiencies for Claus SRU'S. One performance solvent based on MDEA, UCARSOL Solvent HS-103, has been successful in reducing hydrogen sulfide emissions from tail gas treaters to levels below 10 parts per million by volume. At this H2S level, continuous incineration of vent gases is not required and considerable fuel gas savings can be realized. When proper consideration is given to the total Claus SRU and tail gas treating unit design, a facility can be built that will operate smoothly and trouble-free. Conversion of existing tail gas treating systems to utilize new and improved technology can also result in more reliable operation, increased capacities, and reduced operating costs.

Literature Cited 1. Selectox Process for Sulfur Recovery Offshore, Bertram, R.V., et. al., Proceedings of the Gas Processors Association Sixty-Eight Annual Convention, March 1989

2. Process Screening and Selection for Refinery Acid Gas Removal Processing,. Gupta,

S.R., et.al., Energy Progress, 6:4, p.239-47, December, 1986. 3. Tertiary Ethanolamines More Economical for Removal of H2S and Carbon Dioxide,

Riesenfeld, F.D., et, al., Oil & Gas Journal , P. 61-65, September 29, 1986.

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