how to improve the efficiency of tail gas treating in sulphur plants

8/2/2019 How to Improve the Efficiency of Tail Gas Treating in Sulphur Plants

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How to Improve the Efficiency of Tail

Gas Treating in Sulphur Plants

Mahin Rameshni, P.E.

Vice President, Global Manager

Sulphur Technology & Gas Processing

WorleyParsons181 W. Huntington Drive, Suite 110

Monrovia, California 91016 USA

[email protected]

626-803-9058, 626-227-4854

IntroductionThe WorleyParsons BSR-Amine process for Claus tail gas treatment clearly represents Best Available Control

Technology (BACT), potentially achieving 99.99+% overall sulphur recovery with un-incinerated emissions of < 10

ppm H2S and 30 ppmv total sulphur. Achieving that goal requires optimization of both the hydrogenation reaction

and amine treating sections. In order to improve the efficiency in the tail gas unit, it would be required to have im-

proved design in the Claus sulphur recovery unit as much as possible to have a better efficiency in the tail gas unit.

If we categorize these items in summary the following are the items will improve the Claus unit operation.

Titania Catalyst in SRU first bed to improve COS & CS2 hydrolysis

Improve demister design in the sulphur condensers

SRU Final Sulphur Condenser Closed Loop

Provide ammonia wash section in the amine acid gas K.O. drum

Since the emphasis on this paper is about the improved efficiency of the tail gas unit therefore, the improvement on

the hydrogenation reactor, low temperature catalyst, start up blower, amine selection absorber internals and the

incineration design.

HydrogenationCobalt/moly-on-alumina catalyst in the TGU hydrogenation reactor (1) hydrogenates SO2 and Sx to H2S, (2) hydro-

lyzes COS and CS2 to CO2 and H2S, and (3) hydrolyzes CO to CO2 and H2 by the water gas shift reaction. Since

the hydrolysis reactions require higher initiating temperatures than do the hydrogenation reactions, catalyst activity

loss from age and/or abuse is first evidenced by higher residual COS, CS2 and CO. Conversely, tracking the con-

centrations of one or more of these components in the absorber offgas at least weekly provides early warning of

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deactivation. For a while at least, normal gradual deactivation can be compensated for with higher reactor inlet

temperatures. Fresh catalyst should result in the nominal absorber emissions in Figure 1.

Table 1 – Residual Reduced Sulfur with Fresh Catalyst

Contaminant PPMV

Carbonyl sulphide (COS) < 20

Carbon monoxide (CO) < 200

Carbon disulphide (CS2) < 1

Methyl mercaptan (CH3SH) < 1

Residual CS2, due to low reactor temperature or catalyst deactivation, will typically be accompanied by its hydro-

genation product, methyl mercaptan. The distinction between the two is of little consequence as long as the TGUtail gas is incinerated. As discussed later, however, some plants are able to avoid incineration by treating to < 10

ppm H2S, in which case a little mercaptan goes a long way nuisance-odor wise. In one incident, 40 ppmv methyl

mercaptan in the vent gas prompted innumerable complaints at least ¼ to ½ mile downwind. In Stretford TGUs, it

is believed that the absorbed mercaptide is oxidized to disulphide oil (DSO) with potential adverse impact on froth

formation.

Excessive hydrocarbons in the SRU feed gas can easily overload the TGU reactor with COS, CS2 and CO. A good

example is the incident in Figure 1 resulting from rich DEA emulsions. Acid gas air demand increased 30%, TGU

absorber offgas flow increased 35% and total reduced sulphur (excluding H2S) in the TGU tail gas went from 25 to

190 ppmv. Similar episodes occurred sporadically for several weeks until it was discovered that inadequate cool-

ing of the flare gas recovery compressor discharge resulted in presumed aromatics carrying through to the aminecontactor rather than being washed out by hydrocarbon condensate.

How to Improve the Efficiency of Tail Gas Treating in Sulphur Plants 2



Figure 1 – Impact of Hydrocarbons in Amine Acid Gas

Gradual catalyst deactivation due to hydrothermal aging is unavoidable. Barring overheating, the most common

cause of accelerated deactivation is sulphation by sulphuric acid (SO3 + H2S → H2SO4) vapor or O2. SO3 predomi-

nantly results from burning NH3 with excess air in a 2-zone reaction furnace. It can also be made in acid-gas-fired

auxiliary reheat burners, albeit in much smaller quantities. If, however, the amine acid gas contains appreciable

NH3, NO2 made in the aux burner will subsequently oxidize SO2 to SO3.

In one TGU with a booster blower, vacuum conditions at the TGU inlet resulted in air from the standby incinerator

leaking into the SRU tail gas line via the SRU tail gas diverter valves. The most common source of O2, however, is

the natural-gas-fired TGU reheater. Many such reheaters are operated at stoichiometric or only slightly sub-

stoichiometric air. Many people do not realize that stoichiometric equilibrium O2 is nominally 0.6 vol-%, and only

goes to zero below 90% stoichiometric air. In the real world, of course, burner mixing and air/gas flowmeter accu-

racy are less than perfect. WorleyParsons operates the fired reheater as a Reducing Gas Generator (RGG) ideally

burning natural gas at 80% stoichiometric air, thus reasonably minimizing O2 leakage while also maximizing sup-

plemental H2. To avoid potential soot make, LP steam in the ratio of 1/1 lb/lb steam/fuel is injected into the burner

– usually via the combustion air or a dedicated nozzle. The steam essentially hydrolyzes incipient carbon particles

to CO and CO2, analogous to a so-called smokeless flare.




On new units in particular, it is important to verify flowmeter accuracy in order to ensure the proper fuel/air ratio.

This must be done before introducing H2S, and cannot be accomplished by recycling TGU tail gas. Typically, natu-

ral gas must be combusted sub-stoichiometrically in the SRU reaction furnace to generate O2-free tail gas for the

RGG. The RGG fuel/air ratio is then varied incrementally over the nominal range of 80-120% of stoichiometric air.

After a reasonable stabilization period following each change, outlet % O2 and Δ ppmv CO are recorded and plot-

ted as a function of gas/air ratio. Because of the low absolute pressures, flow signals (gas in particular) should be

at least pressure compensated, and preferably also temperature compensated. In the absence of pressure com-

pensation, actual line pressures should periodically be compared against design. For an orifice meter or analogous

head-type device, a pressure greater than design understates flow (in proportion to the square root of the absolute

pressure) and vice versa.

Clients generally operate at 1.5-3.0 vol-% residual H2. The excess is not required to drive the hydrogenation reac-

tions to completion, but essentially serves as a cushion for process fluctuations. In the absence of supplemental

H2, the Claus unit can be operated at tail gas H2S/SO2 > 2/1 if necessary to maintain the desired H2 residual. Any

conversion efficiency penalty will typically be negligible for a 3-stage (air-only) SRU, but may be noticeable for a 2-

stage unit. Supplemental H2, if used, should be relatively pure as opposed to catalytic-reformer H2 which can con-

tain C6+ hydrocarbons conducive to catalyst fouling.

An advantage of operating without supplemental H2 is that the operators quickly recognize the value of the H2 sig-

nal as a diagnostic tool. If, for example, the Claus air demand analyzer is out service, “off-ratio” conditions will be

evidenced by abnormal H2 levels and, conversely, Claus combustion air can be adjusted to maintain a normal H2

level. Also, abnormal H2 levels when the SRU is on-ratio suggest possible RGG air or gas flowmeter error or hy-

drocarbons in the acid gas. We contend that plants without supplemental H2 often tend to be better operated be-

cause there is greater incentive for the operator to optimize Claus air demand, and they become conditioned to

recognize abnormal H2 levels as early warnings of potential upsets.

Off-ratio SRU operation can overload the hydrogenation reactor with SO2, generating high exotherms and resulting

in “SO2 breakthrough” from the reactor once available H2 is depleted. Unmanageable breakthroughs can cause

serious acid corrosion of the quench water system and poison the amine with thiosulphate heat stable salts. The

best insurance against SO2 breakthroughs is reliable H2 indication. A stand-alone thermal-conductivity analyzer is

very reliable, low-maintenance and relatively inexpensive. Unfortunately, many new projects, for whatever reason,

integrate H2 measurement with gas chromatographic (GC) measurement of other components. Invariably, the GC

is often down awaiting service, and with it the H2 signal.

Startup Blower DesignWorleyParsons provide a start up blower on the contact condenser overhead to eliminate flaring large quantities of

H2S to atmosphere and to prevent violation of the emission. For those cases that a booster blower required then

booster blower will have dual function as a start up blower and as a booster blower.

Start Up Blower – reduce the emission during start up to the stack, to eliminate violating the emission during

the start up

Blower is robust equipment with less maintenance





Catalyst PresulphidingAs received, conventional catalyst is an alumina substrate impregnated with oxides of cobalt and molybdenum

which must be converted to the active sulphided state. To convert the cobalt oxide to the sulphide, a simple ex-change of the oxide with H2S is all that is necessary:

CoO + H2S → CoS + H2O

Converting molybdenum trioxide to the active disulphide, however, requires a change in oxidation number that also

requires hydrogen:

MoO3 + 2 H2S + H2 → MoS2 + 3 H2O

If the unit has an RGG, operation at 90% of stoichiometric air with tail gas recycle will generate sufficient H2, but

80-85% of stoichiometric is preferred to reasonably ensure no residual O2. In the absence of an RGG, H2 can be

imported or generated by sub-stoichiometric natural gas combustion in the upstream Claus unit. Sulphiding in this

manner nominally requires at least 16 hours with 1-2% H2S and 3-5% H2.

Only minor quantities of H2S are required for presulphiding, as whatever slips through the reactor can be recycled

via the amine circuit. If H2S is unavailable, sulphiding can be accomplished with Claus tail gas by maintaining

H2S/SO2 > 7/1. Minimization of SO2 is important to avoid elemental sulphur accumulation within the catalyst pores,

thus impeding the sulphiding reactions. Reactor temperatures must initially be limited to 200°C to avoid exposing

the catalyst to H2 in the absence of H2S and thus potentially over-reducing the metals. Once H2S is introduced, the

reactor inlet temperature is still limited to 200-240°C until most of the sulphiding has been achieved. COS/CS2 c

version will consequently be very poor until up to normal temperature.

on-

With “presulphurized” catalyst, such as Criterion actiCAT TG, ~ 1/3 of the metal oxides have already been sul-

phided, and the remainder converted to various complex metal oxysulphides. During “activation” with moderate

heat and H2, the oxysulphides break down to directly sulphide some of the metal oxides, while also releasing H2S

which eventually ensures complete sulphiding. Activation of presulphurized catalyst is initiated at 150°C (com-

pared with 200°C or higher with conventional catalyst). Consequently, higher initial heat-up rates are possible so

that sulphiding can typically be completed within 8 hours.

Presulphurized catalyst is considered relatively non-pyrophoric at ambient temperature, but should be N2-blanketed

once loaded to avoid oxidation and, hence, sulphation resulting in permanent activity loss. Catalyst loading should

thus be deferred pending completion of commissioning steps such as test-firing the RGG, verifying accuracy of the

natural gas and combustion air flowmeters, steam generator boilout and refractory cure. However, we have seen

more than instance on new construction projects where this important consideration was overlooked and the pre-

sulphurized catalyst loaded prematurely, thus precluding the aforementioned air/gas flowmeter verification. In one

case, fundamental meter errors overstated the gas/air ratio by a factor of roughly two, initially resulting in several %

residual O2 after lighting the burner in the course of initiating activation of the presulphurized catalyzed. Since TGU

tail gas was being recycled to the RGG, it was not immediately evident whether the O2 source was excess combus-

tion air or residual O2 in the recycle loop. Fearful of going fuel-rich to the point of making soot, 2-3 hours elapsed

before the proper gas/air ratio was established. By that time sufficient catalyst sulphation had occurred that subse-

quent absorber emissions during normal operation included 1000 ppmv CO and 40 ppmv methyl mercaptan, indi-

cating appreciable deactivation.



Eurocat can offer fully-presulphided catalyst from any manufacturer. It is reportedly “passivated” by a proprietary

process to render it non-pyrophoric at low temperatures, but handling precautions are arguably comparable to Cri-

terion’s presulphurized product. The main advantage is faster heat-up to normal temperature.

Low Temperature CatalystWithin the last five or so years, Axens and Criterion have offered “low-temperature” hydrogenation catalysts report-

edly capable of matching conventional catalyst performance at an inlet temperature of 210-240°C (410-464°F) –

easily achievable with 600# indirect steam reheat. The primary advantage (in a new unit) is elimination of the

RGG, translating to (1) lower capital cost, (2) operating simplicity, (3) improved turndown, (4) reduced TGU tail gas

volume, (5) reduced CO2 recycle to the SRU, and (6) elimination of risk of catalyst damage (soot or sulphation) by

RGG misoperation.

On the other hand, maximization of COS/CS2

conversion can become increasingly important as the regulators con-

tinue to ratchet down SOx limits. If conversion efficiency gradually declines with age – as is reasonable to expect –

the steam reheater will substantially limit the extent to which temperatures can be increased, effectively shortening

catalyst life. In view of these concerns, WorleyParsons and others often opt for a bottom layer of titania catalyst in

the SRU 1st

converter for enhanced COS/CS2 conversion before the TGU. However, this does not promote CO

conversion.

One recent SRU/TGU project in the Los Angeles area has such tight emission limits that contingency provisions

are included to caustic scrub SO2 from the incinerated TGU tail gas.

Amine SystemThe most common TGU solvent is 40-45 %-wt MDEA (Dow UCARSOL HS-101 or similar), designed for a maxi-

mum rich loading of 0.1 mol acid gas (H2S + CO2) per mol amine with typical emission reduction to ~ 100 ppmv

H2S. Cooling of the lean amine to at least 100°F (38°C) is desirable for minimization of emissions and amine circula-

tion rate.

Enhanced TGU amines are essentially MDEA which has been pH-suppressed to facilitate stripping to lower re-

sidual acid gases for treatment to < 10 ppm H2S, potentially obviating incineration unless necessary to oxidize

COS and CO. CO2 slip is also improved. These products are variously marketed as Dow UCARSOL HS-103,

Ineos Gas/Spec TG-10 and Huntsman MS-300. Lean amine cooling becomes even more critical when attempting

to meet 10 ppm H2S. With trayed absorbers at least, reducing the lean amine temperature from 100°F to 85°F has

been found to progressively increase H2S absorption capacity. At least one vendor advises against operating be-low 100°F with packed absorbers, presumably due to increased viscosity, but to what extent this rule-of-thumb is

universally held is unclear. Compared with generic, ability to meet 10 ppm H2S with enhanced MDEA may require

a modest increase in regenerator stripping stages or, alternatively, reboiler duty.

WorleyParsons favors packing over trays in the absorber for reduced pressure drop (nil vs. 1.5-2.0 psi) and im-

proved CO2 slip by virtue of lower liquid residence. In our experience, CO2 slip is typically 70-80% with trays vs.

85-90% with packing. Two beds are provided, whereby the upper bed is the shorter and lean amine can be di-

verted to the lower bed if necessary to improve CO2 slip – contingent of course on acceptable H2S removal.




The regenerator is usually trayed, but random packing has been used successfully. One client with two 75%

packed regenerators cleans the towers at 2-year intervals by overflowing the tower with service water via the over-

head condenser and reflux accumulator while agitating with plant air. The packing is completely clean after 4-8

hours.

It is sometimes assumed that TGU carbon filtration of the lean amine is not required given the absence of hydrocar-

bons. This has proven untrue, likely due to the generation of surfactant amine degradation products. Carbon ven-

dors generally advise heat-soaking fresh carbon with hot condensate for several hours to desorb O2 prior to com-

missioning, but this is often disregarded. We believe that failure to do so prematurely fouls the carbon pores with

polymerized amine oxidation products (aka shoe polish).

An alternative to MDEA is ExxonMobil’s Flexsorb SE, a proprietary hindered amine patented by Exxon in partnership

with the Ralph M. Parsons Company. The main advantages are a 20-30% reduction in circulation rate and resistance

to the solvent degradation typical of MDEA. The solvent is considerably more expensive than MDEA, and also re-

quires a license agreement with ExxonMobil. Flexsorb SE Plus is enhanced in a manner similar to the MDEA sol-

vents for treatment to < 10 ppmv H2S, while also reportedly achieving > 90% CO2 slip.

Plate ExchangersWorleyParsons favors welded plate exchangers such as Alfa Laval Compabloc for TGU lean/rich amine exchang-

ers and lean amine coolers. Cost aside, one advantage is true countercurrent flow resulting in relatively close tem-

perature approach, whereas conventional shell-and-tube exchangers will typically require three or four single-pass

shells in series to approach the same LMTD. Another advantage is controlled velocity on both sides. Compabloc,

for example, claims enhanced turbulence resulting in overall heat transfer coefficients two to four times greater

than for a shell-and-tube.

Gasketed plate exchangers are a cheaper alternative. Their disadvantage is the potential for leakage of the elas-

tomeric gasket to atmosphere due to improper re-assembly following cleaning or inadvertent thermal shock. Reli-

ability is likely improved by sending the entire bundle to the vendor for cleaning and re-assembly, which will typi-

cally include heat-curing of the gasket adhesive. With regard to thermal shock, switching to a spare exchanger

during operation should be accomplished by introducing a slipstream of the cold fluid first.

While many users report good performance with plate exchangers, many also remain prejudiced against them due

to reported experiences with fouling – often without an understanding of the mechanism. There are basically two

types of fouling: (1) trapped debris, and (2) boundary layer deposition of polymerized amine degradation products

or cooling water mineral scale. The former adversely impacts hydraulics, while the latter can impact both hydrau-

lics and heat transfer. The former can be addressed by an upstream strainer and/or backflushing (to the amine

sump or, in the case of cooling water, the trench). In theory at least, the latter should be minimized by the inher-

ently high turbulence in a properly designed exchanger and the stainless steel heat transfer surfaces which are

less prone to surface roughness from corrosion.

In any event, 100% spare plate exchangers are typically provided – still requiring less plot space and likely less

capital expense than the shell-and-tube alternative.




SRU Final Sulphur Condenser Closed LoopA small increase in Claus recovery efficiency translates to a significant reduction in TGU sulphur load. Sulphur

condensation in the final condenser is ideally maximized by closed loop-generation of 15-20 psig steam which iscondensed in an air cooler and drained back to the sulphur condenser.

A SS wire mesh demister at the final condenser outlet is also important. In older plants with separate coalescers

and sulphur seals, the entrained sulphur collected by the demister can be surprisingly significant. It is important to

neither undersize nor oversize the demister flow area. An unduly low flow velocity will achieve inadequate im-

pingement of entrained droplets on the mesh for effective coalescing.

Some clients have reportedly alleviated chronic fouling of the mesh pads with internal steam coils. The nature of

the original deposits is unclear.

IncinerationWhen CO destruction is not required, WorleyParsons typically designs the TGU incinerator to operate at 1200°F

(649°C). In practice, a properly designed incinerator should adequately destroy TGU tail gas H2S at 1000°F

(538°C) or less.

CO destruction typically requires around 1500°F (816°C). Under optimal conditions, the TGU reactor should re-

duce CO to < 200 ppmv. Since H2 is a reaction product of CO hydrolysis, excessive H2 levels can suppress CO

conversion. Regardless, most regulations these days probably limit CO emissions to 100 ppmv, thus requiring

higher incineration temperatures.

With the general trend toward tighter regulations, NOx has increasingly become a concern, and the higher tem-peratures required for CO destruction also tend to increase NOx. It is estimated that 60-70% of clients request low

NOx burners these days. In general, according to them, "low NOx" can mean the followings.

High-intensity high-swirl (recirculating vortex) which tends to draw tail gas into the flame zone. Forced air is

strongly recommended.

Low-intensity long, lazy flame (natural draft) which is fine in a boiler, for example, with ample firebox residence

for complete combustion, but is ill-advised in an incinerator where combustion products are prematurely

quenched with tail gas.

Staged Nox burner, if the NOx has to be less than 20 ppm, staged NOx burner technology by John Zink or

similar should be offered.

If CO destruction is required then the temperature of at least 1500 F is required for CO destruction.

The following is WorleyParsons typical BSR/TGU / amine tail gas treating process flow diagram.




Figure 2 – WorleyParsons BSR/TGU - Low Temperature catalyst & Start up Blower

SRU TAIL GAS

HYDROGENATION

REACTOR

CONTACT

CONDENSER

RECYCLE

WATER

SOUR WATER

BLOWDOWN

TREATED TAIL GAS TO ATMOSPHERE OR INCINERATOR

REDUCED TAIL GAS

ABSORBER

REGENERATOR

INTERMITTENT

PURGE TO SWS

ACID GAS

RECYCLE

TO SRU

RICH AMINE

LEAN AMINE

PROCESS

STEAM

REFLUX

10% NaOH

DESUPERHEATER

HP STEAM

H2 STARTUP

BLOWER


how to improve the efficiency of tail gas treating in sulphur plants

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