Acid Gastreatment & Sulfur Recovery

Gas Treatment & Sulfur Recovery

Process Engineer

Outline 

Introduction  

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Gas Treatment   

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Some Definitions. Hazards of (H2S).

Amines. Amine Process. Operational Problems.

Sulfur Recovery  

Claus Process. Interesting Aspect.

Introduction What are the goals of Gas Treatment ( Gas sweetening)? The goals are:  To produce sweet gas.  To control corrosion and prevent poisoning of catalyst in down stream facilities.  To meet consumer gas specification.  To meet environmental requirements and regulations. 

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What about Sulfur Recovery? To recover the sulfur to be used in fertilizers industry.

Definitions 

Absorption: a separation process involving the transfer of a substance from a gaseous phase to a liquid phase through the phase boundary.

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Adsorption:

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Sour Gas :

the process by which gaseous components are adsorbed on solids because of their molecular attraction to solid surface. gas containing undesired quantities of hydrogen sulfide,

carbon dioxide, and/or mercaptans.  

Sweet Gas: gas without sulfur content. Acid Gas : feed stream to sulfur recovery plant consisting of H2S, CO2, H2O, and usually less than 2 mol % hydrocarbon.

Hazards of H2S

Highly toxic colorless and flammable gas.  Heavier than air.  At low concentration, it smells like “rotten eggs”.  Human sense of smell cannot be relied on to detect hazardous concentration of it. 

Concentration & Reaction by Human body Slight symptoms after several hours exposure 1 hour without serious effects Dangerous after 30 min to I hr Fatal in less than 30 min

ppm

%

Symptoms

1

0.0001

Detected by odor

10

0.001

Occupational Exposure Level, Threshold Limit Value (TLV)

100

0.01

Kills sense of smell in 3 to 5 minutes. May burn eyes and throat.

200

0.02

Kills sense of smell rapidly. Burns eyes and throat after one hour.

500

0.05

Dizziness, loses sense of reasoning, breathing ceases in few minutes. Needs prompt artificial resuscitation

700

0.07

Will become unconscious quickly. Breathing will stop, death will result if not rescued promptly. Immediate artificial resuscitation

1000

0.1

Unconscious at once; followed by death

Gas Treatment (Amines) •

Types of Amines: • • •

•

Monoethanolamine (MEA). Diethanolamine (DEA). Methyldiethanolamine (MDEA).

Primary Secondary Tertiary

MDEA is better. Why? •

•

HOC2H4NH2 (HOC2H4)2NH (HOC2H4)2NCH3

Highest selectivity for H2S over CO2

Selectivity is defined as ratio of (mole percent of H2S removed to mole percent of H2S in feed gas) to (mole percent of CO 2 removed to mole percent of CO2 in feed gas).

MDEA  More 

    

Advantages:

Useful in upgrading acid gas feed to sulfur recovery unit. Low solvent losses due to low vapor pressure. High resistance to degradation. High energy efficiency. Low capital and operating cost. Less corrosive operation.

Amine Process Schematic

Process Description 

Sour gas enters the base of the amine absorber, which is sweetened by the lean amine flowing down the absorber tower. The sweet gas leaves the top for further treatment.

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Rich amine leaves the base flowing to the low pressure amine flash tank, where the dissolved gases and entrained hydrocarbon come off the solution.

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The outgoing gas “flash gas” can be sweetened to be used as fuel gas.

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The rich amine leaves the flash tank to the rich-lean exchanger to cool down the lean amine, then continues to the amine regenerator.

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H2S and CO2 are stripped off from the amine by the steam coming from the reboiler. The vapor flow to the top of regenerator, condensed by the condenser, then proceed to the reflux separator, where the gas is separated from the liquid.

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The acid gas flows to the sulfur plant, while the condensed liquid is pumped back to the regenerator as reflux.

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The regenerated amine solution flows to the rich-lean exchanger to get cooled. It gets to the surge tank, cooled and pumped to the absorber to repeat the absorption process.

Operational Problems  The

usual problems in all amine systems are related to:     

Corrosion. Solution degradation. Solvent losses. Plugging and Fouling. Foaming.

Corrosion 

Potential problem, it is a function of temperature and liquid velocity.

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Combination of H2S and CO2 with water practically ensures that corrosive conditions will exit in portions of the plant.

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Gas streams with high H2S to CO2 ratios are less corrosive than those having low H2S to CO2 ratios. Why? H2S dissociate in water to form a weak acid. The acid attacks iron and form insoluble iron sulfide. The iron sulfide will adhere to the base metal and may provide some protection from further corrosion. On the other hand, CO2 will react with water to form carbonic acid. The acid attacks the iron to form a soluble iron bicarbonate which, upon heating will release CO 2 and an insoluble iron carbonate to iron oxide.

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H2S concentration in the ppmv (parts per million by volume) range with CO2 concentration of 2 % or more tend to be practically corrosive.

Corrosion 

Because of the temperature relation to corrosion, the reboiler, the rich side of the amine-amine exchanger, stripper overhead condensing loop tend to experience high corrosion rates.

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Hydrogen sulfide stress cracking (SSC) is a critical form of corrosion during the few months of operation. It takes place in pipes, valves and fittings. This is typically the outcome of improper material choice and no consideration to stress relieving or critical piping.

Some Guidelines to Minimize The Problem 

Using of corrosion inhibitors in combination with operating practices, which will offer potential saving in both capital and operating costs.

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Some Guidelines are the following:  Maintain the lowest possible reboiler temperature. 

Minimize solids and degradation products through reclaimer and effective filtration.

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Keep oxygen out of the system by providing a gas blanket on all storage tanks and maintain a positive pressure on the suction of all pumps.

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Monitor corrosion rates with coupon or suitable corrosion probes.

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Maintain adequate solution level above reboiler tube bundle and fire tubes; a minimum submergence of 6 “ is recommended.

Foaming 

The most troublesome problem on a day-to-day basis.

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When foaming occurs, there is poor contact between the gas and the chemical solution.

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It reduces treating capacity and sweetening efficiency, possible to the point that outlet specification cannot be met.

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Symptoms 

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Sudden increase in differential pressure across the absorber/regenerator. Amine carry over. Unstable temperature in the absorber and regenerator. Unstable flash tank level and flow to regenerator. Unstable acid gas flow to the Sulfur Recovery Unit.

Foaming Reasons 

Suspended solids.

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Organic acids in the feed gas.

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Condensed hydrocarbons.

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Corrosion inhibitors.

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Make-up water impurities.

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Amine degradation products.

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Lube oil.

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Soap-based valve greases.

Foaming Guidelines 

Contaminants from upstream operations can be minimized through adequate inlet separation.

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Condensation of hydrocarbons in the absorber can usually be avoided be maintaining the lean solution temperature at least (10 ° F) above the hydrocarbon dew point of the outlet gas.

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Temporary upsets can be controlled by the addition of antifoam chemicals ( silicon or long-chain alcohol ).

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Foaming tests should be done to check the compatibility and effectiveness of new anti-foam before using them.

Sulfur Recovery

Sulfur Recovery 

H2S should be converted to non-toxic and useful elemental sulfur that can be used in fertilizer industry.

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Clause Process : a process in which 1/3 of the H2S in the acid gas feed is burned to SO2 which is then reacted with the remaining H2S to produce sulfur.

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The modified Claus process, developed by London chemist Carl Friedrich Claus in 1883

Claus Process  Sulfur

is recovered by 3 steps:   

Thermal. Catalytic. Cold Bed Adsorption.

Claus Process Schematic

Cold Bed Adsorption Schematic

Claus Process 

Thermal: The H2S is partially oxidized with air,

producing the H2S and SO2 in a 2:1 ratio. This is done in a reaction furnace at high temperatures (1000-1400 °C). Sulfur is formed, but some H2S remains unreacted, and some SO2 is made. H2S + 3/2 O2 Overall



 SO2 + H2O

(1)

2 H2S + SO2  3/n Sn + 2 H2O

(2)

3 H2S + 3/2 O2  3/n Sn + 3 H2O

(3)

This step gives sulfur recovery of about 60 % .

Claus Process 

Catalytic : The remaining H2S is reacted with the SO2 at lower temperatures (about 200-350 ° C) over a catalyst to make more sulfur. 2 H2S + SO2  3/n Sn + 2 H2O (2)

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The most widely used Claus catalyst in sulfur recovery units is non-promoted spherical activated alumina, such as Al2O3

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Properties associated with optimum non-promoted Claus catalyst include high surface area, appropriate pore size distribution, and enhanced physical properties.

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This step gives sulfur recovery of about 35 % ,so the overall sufur recovery is 95%.

Claus Process 

Cold Bed Adsorption: The CBA reactor is operated at low temperature (121-148 ° C) initially so that it is below the sulfur dewpoint of the reaction products, The H2S and SO2 in the gas will react via reaction (2) to form sulfur, which condenses due to the low operating temperature and is adsorbed on the catalyst.

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Each CBA reactor contains a 36"-48" deep bed of sulfur conversion catalyst, usually alumina-based.

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The tailgas from the second CBA reactor is routed to a Tailgas Thermal Oxidizer to incinerate all of the sulfur compounds to SO 2 before dispersing the effluent to the atmosphere.

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This step gives overall sulfur recovery of about 98-99 %.

Interesting Aspect of Claus 

The strange behavior of molten sulfur.

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The temperature of molten sulfur must be controlled carefully. If the sulfur is allowed to cool too much it can begin to polymerize.

Characteristic Viscosity Curve Associated with Molten Sulfur