Selection Criteria for Claus Tail Gas Treating Processes

8/22/2019 Selection Criteria for Claus Tail Gas Treating Processes

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Selection Criteria for Claus Tail Gas Treating Processes

Mahin Rameshni, P.E.

Technical Director, Sulphur Technology and Gas Processing

181 West Huntington Drive, Monrovia, California 91016, USA

[email protected]

Introduction

With the sulphur content of crude oil and natural gas on the increase and tightening sulphur content in fuels, refiners and gas processors are pushed for additional sulphur recovery capacity.

At the same time, environmental regulatory agencies of many countries continue to promulgate

more stringent standards for sulphur emissions from oil, gas and chemical processing facilities. It

is necessary to develop and implement reliable and cost effective technologies to cope with the

changing requirements. In response to this trend, several new technologies are now emerging to

comply with the most stringent regulations.

Typical sulphur recovery efficiencies for Claus plants are 90-96% for a two- stage, and 95-98%

for a three- stage plant. Most countries require sulphur recovery efficiency in the range of

98.5% to 99.9+%. Therefore the sulphur constituents in the Claus tail gas need to be reduced

further.

The key parameters effecting the selection of the tail gas clean-up process are:

f Feed Gas composition, including H2S content and hydrocarbons and other contaminants

f Existing equipment and process configuration

f Required recovery efficiency

f Concentration of sulphur species in the stack gas

f Ease of operation

f Remote location

f Sulphur product quality

f Costs (capital and operating)



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Various aspects and considerations when choosing the most optimum process configuration for

tail gas treating are discussed. There are several key features effecting the selection of the tail

gas clean-up process that three steps should be taken. When required recovery efficiency and

concentration of sulphur species in the stack gas is known, selection of the tail gas process is one

step closer. The first step is one the most important criteria for the selection of the tail gas treating

processes. When the required sulphur recovery is established, the selection of the tail gas

process will be limited. Table 1 represents the various tail gas clean-up process with the recovery

will be achieved. When concentration of impurities in the acid gas such as COS and CS 2, H2S

content, and feed gas composition, and finally treated gas specifications are established, the type

of amine used for a particular application could be selected in step two. Finally the third step is

the evaluation between the identical process chosen for ease of operation, capital and operating

cost, and remote location. For revamp units, minimum equipment modifications and process

configuration should be considered as a main key factor.

The WorleyParsons BSR Amine process for Claus tail gas treatment clearly represents Best

Available Control Technology (BACT), potentially achieving 99.99+% overall sulphur recovery

with emissions of < 10 ppmv H2S and 30 ppmv total sulphur.

There are other processes such as direct oxidations processes, Sub dew point processes that are

able to achieve higher sulphur recovery from the conventional 3-stage Claus unit up to 99.8 %

depending on the feed compositions to the Claus unit.

WorleyParsons offer DEGSULF a sub dew point process with partnership with DEG-ITS for those

applications with the relaxed overall recovery.

Brief History

Under the leadership of David Beavon of the Ralph M. Parsons Company, Parsons and Union Oil

of California (Unocal) co-developed the Beavon Sulphur Removal Process (BSRP) in San Pedro,

California, in the late 1960s, for which US Patent 3,752, 877 was awarded to Parsons in 1973.

The fundamental process, still employed today, typically heats the Claus tail gas to 550-650°F (~

290-340°C) by inline sub-stoichiometric combustion of natural gas in a Reducing Gas Generator

(RGG) for subsequent catalytic reduction of virtually all non-H2S sulphur components to H2S.

Conversion of SO2 and elemental sulphur (Sx) is by hydrogenation:

SO2 + 3 H2 → H2S + 4 H2O + ΔH

Sx + x H2 → x H2S + ΔH

Conversion of COS and CS2 is by hydrolysis:

COS + H2O → H2S + CO2 + + ΔH

CS2 + 2 H2O → 2 H2S + CO2 + ΔH



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CO is essentially hydrolyzed to yield additional H2 according to the “water gas shift” reaction:

CO + H2O → H2 + CO2 + ΔH

CO and H2 naturally present in the Claus tail gas will typically satisfy up to 70% of TGU demand,

with the balance generated in the RGG.

A cobalt-moly catalyst, similar to hydrodesulphurization catalyst, is typically employed. As

received, the catalyst is an alumina substrate impregnated with oxides of cobalt and molybdenum

which must be converted to the active sulfided state. To convert the cobalt oxide to the sulfide, a

simple exchange of the oxide with H2S is all that is necessary:

CoO + H2S → CoS + H2O + ΔH

Converting molybdenum trioxide to the active disulfide, however, requires a change in oxidationnumber that also requires hydrogen:

MoO3 + 2 H2S + H2 → MoS2 + 3 H2O + ΔH

The reduced tail gas is then cooled to 90-100°F (~ 30-40°C) to condense most of the water

vapor, which accounts for ~ 35% of the stream. While Beavon recognized the potential for H2S

recovery using an alkanolamine, he was concerned about formation of heat stable thiosulfate

resulting from SO2 breakthroughs. Consequently, Parsons adopted the Stretford redox process

which employed an alkaline vanadium salt solution to oxidize absorbed H 2S to elemental sulphur

particles which were subsequently removed by froth flotation, filtered and melted.

The Beavon Stretford process actually had some advantages over amine absorption:

f No acid gas recycle to the Claus unit

f No steam consumption

f < 5 ppm residual H2S, obviating incineration

f Temporary high capacity for excessive Claus tail gas H2S or SO2 resulting from off-ratio

operation

However, these were outweighed by poor sulphur quality, high chemical makeup costs, highdisposal costs from purging of byproduct thiosulfate, absorber fouling, oxidizer foaming,

inconsistent froth formation, troublesome filter operation and atmospheric corrosion. By the

1980s, Parsons essentially abandoned the Stretford process in favor of MDEA absorption/

regeneration. Today, WorleyParsons retains the BSR trademark in reference to the catalytic

reduction stage and subsequent cooling/condensation. A typical BSR Amine system is shown in

Figure 1. Figure 2 is a typical BSR amine system including the start up blower.



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Reducing Gas Generator (RGG)

Many competitors use the inline burner design in Figure 3. Burner vibration is common, the

extreme temperature gradient between the combustion and tail gas mixing zones makes it difficultto optimize skin temperatures at the transition, and a combustion zone shell leak resulting from

localized refractory failure forces a shutdown.

The proposed BSR unit comprises of three process steps:

f Reducing Gas Generation (RGG) and tail gas preheat

f Hydrogenation/Hydrolysis of SO2 and other sulphur species to H2S

f Gas cooling and waste heat recovery

f WorleyParsons proprietary RGG design provides process gas reheating and reducing gas

(H2 and CO) generation in one single process unit. No external supply of hydrogen gas is

required. This feature enhances the reliability of the process unit by eliminating the

uncertainties associated with the availability of external hydrogen supply and the quality of

hydrogen gas.

WorleyParsons design has the following advantages compare to the other licensors.

WorleyParsons Conventional BSR Section

f Start Up Blower – reduce the emission during start up to the stack

f Caustic wash – reduce breakthrough of SO2 to amine during start up and prevent

degrade of the solvent, No SO2 breakthrough to the amine unit

f Stable operation for different mode of operation

f Good Turn down

f No external hydrogen required

f Less pressure drop

f Less heat loss in RGG configuration

f Could be started up independently from SRU’s

f No vibration in RGG Burner

f No heat Loss in RGG



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f No Refractory damages as the results of un-uniform heat distribution

f Proprietary RGG design provides process gas reheating and reducing gas (H2 and CO)

generation in one single process unit. External supply of hydrogen gas is not required inmost cases.

f Start up blower, to eliminate violating the emission during the start up



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Figure 1 – WorleyParsons BSR Amine Flow Scheme



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Figure 2 – WorleyParsons BSR Amine Flow Scheme with start up blower



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Figure 3– Common TGU Feed Heater

By comparison, the WorleyParsons design (Figure 4) employs a brick-lined internal combustion

zone for stable combustion unaffected by downstream turbulence. Optimum outer-shell skin

temperatures are easily ensured, heat loss is minimized and potential leakage through thecombustion zone wall does not result in atmospheric release. Some units have been in service

for 30+ years with no major refractory repairs. The RGG is typically elevated so that minor

entrained sulphur will free-drain to the reactor (and vaporize).

Figure 4 – WorleyParsons Reducing Gas Generator (RGG)

Industry consensus is apparently lacking with regard to the optimum air/fuel ratio. Many

competitors’ units operate at stoichiometric air and rely on supplemental H2 for hydrogenation of

SO2 and Sx. Perhaps contrary to intuition, equilibrium O2 is nominally 0.6 % at stoichiometric air,

and only goes to zero at < 90% of stoichiometric. There is experience to suggest that chronic O2

leakage leads to catalyst sulfation, although there is disagreement within the industry on this

point. Nonetheless, WorleyParsons generally recommends operating at 80% of stoichiometric to

avoid, or at least minimize, O2 leakage (and also maximize H2 yield).

The advisability of supplemental H2 is also a source of controversy. Many clients consider the

availability of import H2 necessary to minimize the risk of SO2 breakthroughs, whereas in reality it

is as easy to reduce Claus combustion air (with the same effect) as increase H 2 addition. In the

absence of supplemental H2, the operator quickly learns the value of monitoring residual H2 as a



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sensitive indicator of Claus tail gas ratio, and arguably is more likely to routinely optimize Claus

air demand when constrained by a limited H2 supply. Three-stage Claus units clearly do not need

supplemental H2, while residual H2 may be marginal with 2-stage units, in which case

supplemental H2 may be advisable to ensure ability to optimize the Claus tail gas H2S/SO2 ratio.

H2 analyzers based on thermal conductivity measurement are very reliable, with minimal

servicing. Where the TGU is coupled to a single Claus train, the H2 analyzer can in fact supplant

the Claus air demand analyzer. Where multiple Claus trains are coupled to a single TGU,

combustion air to a Claus unit whose air demand analyzer is out of service can be temporarily

adjusted based on TGU residual H2.

LP steam injection to the burner in the nominal ratio of 1/1 lb/lb steam/fuel is generally advisable

for soot inhibition when firing sub-stoichiometrically, by virtue of the following reactions:

C + H2O → CO + H2 - ΔH

C + 2 H2O → CO2 + 2 H2 - ΔH

While modern high-intensity burners may be operable at as low as 80% of stoichiometric air

without steam injection, injection is still prudent in view of the possibly of lower air/gas ratios

resulting from meter error or localized fuel-rich zones due to burner damage or fouling. With high

intensity burners, steam injection via a dedicated steam gun is preferred. Otherwise, injection

into the combustion air is the most practical.

Figure 5 – WorleyParsons Reduc ing Gas Generator (RGG) Details



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Hydrogenation Reactor

With good catalyst activity and no excessive HCs in the acid gas feed to the Reaction Furnace,

organic residuals in the Absorber offgas should be as shown in Table 1:

Table 1 – Residual Sulphur with Fresh Catalyst

Contaminant PPMV

Carbonyl sulfide (COS) < 20

Carbon monoxide (CO) < 200

Carbon disulfide (CS2) 0

Methyl mercaptan (CH3SH) 0

With fresh conventional catalyst, temperatures of 400-450°F (204-232°C) are typically required toinitiate the hydrogenation reactions, and 540-560°F (282-293°C) for hydrolysis. As the catalyst

loses activity with age, progressively higher temperatures may be required. Typically, activity

loss is first evidenced by (1) reduced COS, CS2 and CO conversion, and (2) potential methyl

mercaptan formed by the reaction of CS2 and H2, while hydrogenation of SO2 and Sx may still be

complete because of the lower initiation temperatures required.

The potential formation of methyl mercaptan at low temperature or impaired catalyst activity is

perhaps not widely appreciated. In cases where the TGU tail gas is discharged without

incineration, nominal mercaptan levels can result in serious nuisance odors. In Stretford units,

there is reason to expect that the mercaptan is oxidized to disulfide oil (DSO) which can impair

froth formation.

Excessive HCs in the SRU acid gas feed will tend to increase the carbon-sulphur compounds in

the Reactor effluent. In the Figure 4 example, HCs in the amine acid gas are evidenced by (1)

increased air demand per volume of gas, (2) increased tail gas volume resulting from the

additional air and HC combustion products, and (3) increased Total Reduced Sulphur (TRS) in

the Absorber offgas – predominantly COS, but also potentially including CS2 and methyl

mercaptan (RSH). (While TRS also includes H2S, the H2S content did not increase in this case.)

Low Temperature Hydrogenation Catalyst

WorleyParsons has started offering low temperature catalyst if requested by client asapplicable and meet the project emissions. Low temperature catalyst eliminate of using the

reducing gas generator and indirect heating system could be used instead. Low-temperature

TGU catalysts reportedly capable of operating at inlet temperatures of 210-240°C (410-464°F),

achievable with steam reheat, have recently become available. 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 by RGG misoperation.



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Historically, Claus tail gas treating units (TGTU) have required reactor inlet temperatures of ~

550°F for appreciable hydrolysis of COS, CS2 and CO, typically requiring preheat by inline firing

or heat exchange with hot oil or heat transfer fluid.

Vendor claims of energy savings are questionable since they tend to (1) assume the plant is long

on LP steam, and (2) disregard the cost of HP steam. Long term performance of low-temperature

catalysts is still uncertain. The following considerations should be taken into account:

f A steam reheater will limit the ability to compensate for normal catalyst activity loss with

age, potentially limiting its useful life.

f A bottom layer of titania in the first Claus converter may be required for COS/CS2

hydrolysis.

f Higher residual CO levels could mean operating the incinerator at 1500°F (~ 800°C)instead of 1200°F (~ 650°C).

f Incomplete CS2 destruction, and hence methyl mercaptan formation, can result in serious

nuisance odors if the TGU tail gas is discharged without incineration.

Reactor inlet temperatures are only half the story; outlet temperatures are the other half. Any

catalyst will probably initiate SO2 hydrogenation at 400-450°F (~ 205-230°C) and, with sufficient

temperature rise and excess catalyst, will subsequently achieve virtually complete hydrolysis.

New catalysts by Criterion and Axens require lower activation temperatures achievable by indirect

reheat by 600# steam, thus reducing investment cost, operating complexity and, in some cases,

energy consumption. In addition, lower reactor outlet temperatures may obviate the downstream

waste heat boiler.

While reduced investment and complexity are a given, whether the claimed energy savings is real

is site-specific. Reduced feed preheat energy only constitutes a savings if the plant is already

long on low-pressure waste heat steam (40-70 psig). Otherwise, incremental heat input is fully

recovered. Furthermore, in the absence of a steam surplus, elimination of the waste heat boiler

may have forfeited recoverable BTUs.

Relative COS, CS2 and CO conversion efficiencies need to be compared. It is not necessarily

sufficient to achieve regulatory compliance.

COS, CS2 and CO Hydrolysis using low temperature catalyst

Relative COS, CS2 and CO conversion efficiencies can be critical. It is not necessarily sufficient

to achieve regulatory compliance.

f Regulations could become more stringent in the future.



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f Some plants must also buy emission credits per pound of SO2 discharged.

f Excessive CO residuals could require higher incinerator temperatures, or require

incineration otherwise obviated in units able to achieve TGTU absorber H2S emissions <10 ppm by the use of acid-aided MDEA.

Hydrolysis of COS, CS2 and CO typically requires higher temperatures than hydrogenation of SO2

and Sx. Perhaps accordingly, COS, CS2 and CO conversion efficiencies are the first to suffer as

conventional catalysts lose activity with age. Higher reactor inlet temperatures will tend to

compensate for deactivation, thus extending catalyst life considerably. Depending on the design

limits, temperatures can generally be increased by 50-150°F (28-83°C).

Assuming the same holds true for the low temperature catalysts, a steam reheater will

substantially limit the extent to which temperatures can be increased, in effect potentially

shortening catalyst life. The lower initiation temperature of the Criterion 734 at start-of-run is thussignificant, as it affords the greatest margin for increase.

At 464°F (240°C) – generally the limit of a 600# steam reheater – hydrolysis of CO, COS and CS2

approaches that of conventional high temperature catalysts. At 428°F (220°C), however, Axens

concedes that COS/CS2 conversion must be accomplished in the 1st Claus stage by (1)

supplementing the alumina bed with a bottom layer of expensive titania catalyst, or (2) increasing

the inlet temperature to 550-600°F (288-316°C). The latter will nominally

f reduce Claus recovery efficiency from

f

increase SRU tail gas rate

f increase TGTU sulphur load

However, the 1st stage will not effect CO conversion.

Conventional cobalt-moly catalyst will generate minor, but significant, levels of methyl mercaptan

by the reaction of CS2 and hydrogen at 480°F (249°C) when in good condition, and at much

higher temperatures if the catalyst is aged or damaged. While the manufacturers claim no

residual mercaptans with the low temperature catalysts, there is some uncertainty – in the

author’s view – as to whether that will remain true a few years into the run.

Hydrogen Balance using low temperature catalyst

Compared with firing the feed heater at stoichiometric air and importing H 2, a steam reheater will

of course have no impact on the H2 balance. However, many plants avoid the need for

supplemental H2 by the use of a reducing gas generator (RGG), typically burning natural gas sub-

stoichiometrically to generate H2 and CO.



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In the absence of an RGG, the alternative is to operate the SRU more air-deficient as necessary

to maintain, say, 2% residual H2 downstream of the TGTU reactor. This will nominally

f reduce Claus recovery efficiency

f increase SRU tail gas rate

f increase TGTU sulphur load

CO2 Balance using low temperature catalyst

Eliminating the inline burner has the benefit of reducing the TGTU tail gas volume (for the

assumed basis with an RGG). Assuming 85% CO2 slip, the acid gas load on the TGTU amine is

reduced.

Energy Balance using low temperature catalyst

A steam reheater will not only eliminate the following natural gas required by the RGG, but will

also reduce incinerator fuel by virtue of the reduced tail gas rate:

f RGG fuel savings

f Incinerator fuel savings

Assuming H2S/SO2 = 2 in the SRU tail gas, of supplemental H2 will be required to maintain a 2%

residual in the TGTU tail gas. As a rule-of-thumb, the value of relatively pure (non-reformer) H2 is

four times that of natural gas.

Figure 6 represents WorleyParsons BSR/amine with the low temperature catalyst.



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SRU TAIL GAS

HYDROGENATIONREACTOR

CONTACTCONDENSER

RECYCLEWATER

SOUR WATERBLOWDOWN

TREATED TAIL GAS TO ATMOSPHERE OR INCINERATOR

REDUCED TAIL GAS

ABSORBER

REGENERATOR

INTERMITTENTPURGE TO SWS

ACID GAS

RECYCLETO SRU

RICH AMINE

LEAN AMINE

PROCESSSTEAM

REFLUX

10% NaOH

DESUPERHEATER

HP STEAM

H2 STARTUPBLOWER

Figure 6 – WorleyParsons BSR Amine Flow Scheme with Low Temperature Catalyst



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Figure 7 – WorleyParsons Impact of Hydrocarbons in Acid Gas to SRU

In the event of a burner trip, there is usually ample time to relight the RGG before the reactor bedcools to the point of SO2 breakthrough. In the Figure 7 example, relight was delayed by a

plugged pilot fuel gas restriction orifice, and the main burner was down ~ one hour (65 minutes).

At all times at least one point in the bed was 510ºF or higher, which likely explains the absence of

an SO2 breakthrough. By the end of, say, a 2-hour outage, all temperatures would have been <

400ºF, and it is possible that serious SO2 breakthrough would thus start to occur within 1½-2

hours.

The reactor contained 37.5 Mlb of Criterion 534 cobalt-moly catalyst, a 2-Mlb top layer of ½”

alumina and a 4.5-Mlb support layer of ceramic balls.



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Reactor Temperatures

200

300

400

500

600

700

800

8 : 0 0

8 : 0 5

8 : 0 9

8 : 1 4

8 : 2 0

8 : 2 5

8 : 3 0

8 : 3 5

8 : 4 0

8 : 4 5

8 : 5 0

8 : 5 5

9 : 0 0

9 : 0 5

9 : 1 0

9 : 1 4

9 : 2 0

9 : 2 5

9 : 2 9

9 : 3 4

9 : 3 9

9 : 4 4

9 : 4 9

9 : 5 4

9 : 5 9

1 0 : 0 5

1 0 : 0 9

1 0 : 1 5

1 0 : 2 0

1 0 : 2 4

1 0 : 2 9

1 0 : 3 4

1 0 : 3 9

1 0 : 4 4

1 0 : 4 9

1 0 : 5 5

1 1 : 0 0

T e m p e r a t u r e , F

Figure 8 – WorleyParsons Hydrogenation Reactor Bed Temperatures During RGG Outage

The total tail gas rate is shown in Figure 9. There are actually two identical reactors in parallel,

with only half of the indicated flow through each.



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TGTU Tail Gas Rate

1000

1050

1100

1150

1200

1250

1300

1350

1400

8 : 0 0

8 : 0 5

8 : 0 9

8 : 1 5

8 : 1 9

8 : 2 4

8 : 2 9

8 : 3 5

8 : 4 0

8 : 4 5

8 : 4 9

8 : 5 4

8 : 5 9

9 : 0 4

9 : 0 9

9 : 1 4

9 : 1 9

9 : 2 4

9 : 2 9

9 : 3 5

9 : 4 0

9 : 4 4

9 : 5 0

9 : 5 5

1 0 : 0 0

1 0 : 0 4

1 0 : 0 9

1 0 : 1 5

1 0 : 1 9

1 0 : 2 4

1 0 : 2 9

1 0 : 3 4

1 0 : 3 9

1 0 : 4 4

1 0 : 4 9

1 0 : 5 4

1 1 : 0 0

T a i l

g a s r a t e , M S C F H

Figure 9 – WorleyParsons TGU Tail Gas Rate During RGG Outage

Resultant TRS (measured at the absorber outlet) and SOx emissions are shown in Figure 10.



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Emissions

0

50

100

150

200

250

300

350

400

8 : 0 0

8 : 0 4

8 : 1 0

8 : 1 4

8 : 1 9

8 : 2 5

8 : 3 0

8 : 3 4

8 : 4 0

8 : 4 5

8 : 5 0

8 : 5 5

9 : 0 0

9 : 0 5

9 : 1 0

9 : 1 5

9 : 2 0

9 : 2 5

9 : 3 0

9 : 3 4

9 : 3 9

9 : 4 5

9 : 4 9

9 : 5 4

9 : 5 9

1 0 : 0 4

1 0 : 0 9

1 0 : 1 4

1 0 : 1 9

1 0 : 2 4

1 0 : 2 9

1 0 : 3 5

1 0 : 3 9

1 0 : 4 4

1 0 : 4 9

1 0 : 5 4

1 0 : 5 9

P P M , c o r

r e c t e d t o a i r - f r e e b a s i s

absorber TRSF-754

Figure 10–WorleyParsons Impact of RGG Outage on Emissions

Contact Condenser (2-Stage Quench)

Common industry practice is to cool the reduced tail gas from the reactor by the generation of LP

waste heat steam followed by direct quench with a recirculating water stream to cool it to 90-

100°F (~ 30-40°C), thus condensing most of the water vapor which accounts for ~ 35% of the

stream.

WorleyParsons utilizes a unique 2-stage tower comprised of a bottom Desuperheater section and

top Contact Condenser.

f The contact condenser has 2 sections, the first section de-superheats the gas and scrub

any SO2 may breakthrough from hydrogenation reactor, and the second section cools the

gas and condensate the water, therefore there is no need for make up water to maintain

the caustic concentration. The condense water will provide the water to maintain the

caustic concentration. We do not have continuous purge, but we provide water make up

for the water is evaporated, just like any other quench system.



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f Tail gas is desuperheated in the lower section of the contact condenser by a circulating

water stream. This water is maintained alkaline to protect against any SO2 breakthrough

from the reactor. In the upper packed section of the tower, most of the water vapor in the

tail gas is condensed by direct contact with a circulating stream of cooled water. A pH

analyzer with a low-pH alarm is installed in the quench water circulation line and will

indicate when the pH of the quench water is reducing, from either a breakthrough of SO2,

or incomplete reduction of the sulphur compounds in the gas stream from the

Hydrogenation Reactor.

(Figure 1 and 2) A 10 %-wt NaOH solution is recirculated through the Desuperheater to capture

SO2 potentially resulting from a process upset, while also cooling it to its dewpoint of ~ 165°F (~

75°C). The only cooling is by vaporization. The gas is further cooled to 90-100°F (~ 30-40°C) by

direct contact with an externally cooled recycle water stream in the upper Contact Condenser

section. A recycle water slipstream is returned to the Desuperheater on Desuperheater level-

control via two bubble-cap wash trays to capture entrained caustic.

A blowdown slipstream of recycle water is purged, usually to sour water, on Contact Condenser

level-control. While the recycle water is usually classified as sour water, the H2S content is

typically < 50 ppmv by virtue of CO2 saturation. In situations where the increased load on the

plant sour water stripper is undesirable, a simple blowdown stripper is occasionally provided at

the TGU. This typically involves LP stripping steam injection (as opposed to a reboiler) and

return of the uncondensed overhead stream to the Desuperheater.

Startup Blower

WorleyParsons provide a start up blower on the contact condenser overhead to eliminate flaringlarge quantities of H2S to atmosphere and to prevent violation of the emission. For those casesthat a booster blower required then booster blower will have dual function as a start up blower and as a booster blower.

Booster Blower

Many of the Claus units that are in operation do not have enough pressure to handle a new tail

gas unit in other words the provision of operating the Claus unit at the higher pressure was not

considered, if the source pressure changed the existing amine unit requires higher reboiler duty

and in most cases required significant changes in the amine unit. WorleyParsons have been

offering a booster blower in the tail gas unit to overcome the pressure limitation.

Retrofit Tail Gas Units will typically require a booster blower downstream of the Contact

Condenser to overcome the additional pressure drop. The blower is located after the Contact

Condenser to minimize the actual volume (by virtue of cooling and condensation), and before the

Absorber to take advantage of the higher pressure.

With proper design and operation, booster blowers are inherently very reliable, requiring minimal

maintenance. Typically, the case is cast iron or carbon steel, with an aluminum impellor. N2-



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purged tandem shaft seals (typically carbon rings) eliminate process leakage to atmosphere on

the discharge end as well as air aspiration into the process on the suction end, which is typically

at a vacuum.

Though often viewed as a liability by clients, booster blowers arguably improve operability in

several ways:

f By recirculating tail gas, the TGU can be started up and shut down independent of the

SRUs.

f Tail gas recycle ensures process stability at high SRU turndown by (1) avoiding undue

RGG burner turndown potentially conducive to sooting due to poor mixing or air/gas

flowmeter inaccuracy, and (2) diluting potentially high SO2 levels often typical of high SRU

turndown. With advance warning, tail gas recycle can avoid RGG shutdown in the event of

an SRU trip.

f By routing the SRU and TGU tail gas to the incinerator via a common header, a vacuum

can be maintained at the RGG without risk of leaking air from the incinerator back into the

TGU, thus potentially further increasing SRU capacity. In the event that the tail gas

bypass valve leaks, clean TGU tail gas is recycled to the RGG rather than SRU tail gas

bypassing the TGU (as when the RGG pressure is positive). Any such reverse flow will

improve bypass valve reliability by excluding sulphur vapor, and the valve can be partially

stroked periodically to verify operability without increased emissions.

Figure 11– WorleyParsons RGG Vacuum Operation

In the absence of a booster blower, a single startup blower recycle is usually provided for tail gas

recycle. While these machines tend to be less sophisticated, N2-purged tandem shaft seals are

still required.



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The overall configuration of using the booster blower is shown in the Figure 10. This configuration

could be used with low temperature catalyst and indirect reheater instead of the RGG.

PC

FC

HC

TOINCINERATOR

BOOSTERBLOWER

RGG

SRU TAIL GAS


REACTOREFFLUENTCOOLER

HY-251

HY-250

XY-292

WATERWASH

ABSORBERCONTACT

CONDENSER

DESUPERHEATER

Figure 12 – WorleyParsons BSR-TGU with Booster Blower configuration



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Solvent Selection Criteria in the Tail Gas Unit

The most common solvent is 40-45 %-wt MDEA, (HS-101, or similar) designed for a maximum

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 important for minimization of

emissions and amine circulation rate. Specialty TGU amines are essentially pH-modified MDEA

to facilitate stripping to lower residual acid gases for treatment to < 10 ppm H 2S, potentially

obviating incineration. CO2 slip is also improved. These products are variously marketed as

f Dow UCARSOL HS-103

f Ineos Gas/Spec TG-10

f Huntsman MS-300.

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 advantage is a 20-30%

reduction in circulation rate. The solvent is much more stable than MDEA, but is also more

expensive. Flexsorb SE Plus is also available for treatment to < 10 ppmv H2S. Both solvents

require a license agreement with ExxonMobil.

It used to be assumed that TGU carbon filtration was not required in view of the absence of

hydrocarbons. For MDEA-based solvents, at least, this has proven untrue, presumably due to

the generation of surfactant amine degradation products.

f Solvent Applications

f FLEXSORB® SE Selective removal of H2S

f FLEXSORB® SE Plus Selective removal of H2S to less than 10 ppm

f FLEXSORB® SE Hybrid Removal of H2S, CO2, and sulphur compounds (mercaptans and

COS)

f In sulphur plant tail gas applications, FLEXSORB® SE solvents can use as little as one

half of the circulation rate and regeneration energy typically required by MDEA based

solvents. CO2

f Rejection in TGTU applications is very high, typically >90% rejection.

f Flexsorb solvents offer other advantages compare to the other amine solvents for

instance, most of applications requires no reclaiming, have good operating experience, low

corrosion, and low foaming due to low hydrocarbon absorption, by providing water wash of

treated gas at low pressure system amine losses are minimum.



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DEGSulf Sub Dew Point process by WorleyParsons& DEG-ITS

DEGSulf-SDP is a sulphur recovery process of the Claus type. A plant consists typically of a

Claus furnace plus downstream just 2 catalytic reactors and sulphur condensers. The reactorscontain a heat exchanger which keeps the operating temperature for each reactor at its optimum.

This simple system, described in detail below, allows reaching up to 99.85% sulphur recovery

rate.

Gas containing hydrogen sulfide (=H2S) is sent to the Claus furnace. There it is burned with a

stoichiometric deficiency of air so that one third of the H 2S is converted to SO2. The residual H2S

and the SO2 react to elemental sulphur according to the Claus reaction (I): (I) 2 H 2S + SO2 3/x

Sx + 2 H2O x = 2,4,6,8 indicates the different sulphur modifications Typically a recovery rate of

over 60 % is realized in the furnace. Gas from the waste heat boiler and sulphur condenser of the

Claus furnace is reheated by a hot gas bypass. It then flows via 4-way valve to the adiabatic part

of the first reactor, which is filled with a catalyst of high COS and CS 2 conversion capability.Residual traces of free oxygen from the Claus furnace are eliminated in this layer. The gas enters

the cooled section of the reactor bed at a temperature of between 300 and 350°C. Cooling takes

place by evaporating boiler feed water or hot oil. Here the Claus reaction continues further close

to the equilibrium at appr. 260 °C, which is slightly above the sulphur dew point at outlet

conditions. The gas leaves the reactor and passes via the second 4-way valve to the only

sulphur condenser of the catalytic part. The sulphur condenser operates at gas outlet

temperatures of between 135 °C and 150 °C and produces low pressure steam. The process gas

leaves the condenser through a mist eliminator. Total sulphur recovery up to this point exceeds

95 %. The gas is reheated again before entering the second reactor which can be regarded as

the tail gas treatment. In the steam jacketed pipe the temperature is raised by appr. 20°C in order

to be safely above the sulphur dew point. In the adiabatic zone of the second reactor the Clausreaction proceeds. Claus gas then enters the cooled part of the second reactor, where the

reaction temperature is lowered to 100 - 125 °C by the cooling coils. Elemental sulphur from the

adiabatic zone and formed in the cooled zone is adsorbed by the aluminum-based catalyst. The

coils keep the reactor outlet temperature at constant level throughout the complete adsorption

period. The evenly low temperature throughout the bed causes a substantial increase of the

sulphur recovery rate compared to state-of-the-art processes.





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Ammonia Destruction in a TGU (RACTM)

The general industry consensus is that the amount of ammonia that can be conventionally processed in

the SRU is limited to 30-35 %-vol on a wet basis. With what appears to be a trend toward higher-nitrogen

crudes, refiners are increasingly faced with the need for alternative processing schemes, as well as SRUdebottlenecking. With sour water stripping schemes such as Chevron’s Waste Water Treatment (WWT)

process for separating H2S and NH3, producing a pure marketable NH3 product is relatively difficult

compared with bulk separation of NH3 containing minor H2S.

WorleyParsons’ Rameshni Ammonia Conversion (RACTM) process, for which a patent is pending, sub-

stoichiometrically combusts a high-NH3 H2S-contaminated stream in the RGG. (Figure 14) Typically, the

NH3-gas heat release will exceed that required to reheat the Claus tail gas, thus necessitating a waste

heat boiler prior to the TGU reactor. A supplemental natural gas fire ensures process stability in the

event of NH3-gas curtailment. Sub-stoichiometric combustion of the NH3-gas generates supplemental H2

for the hydrogenation reactor and minimizes NOx. Most of any NOx that is made is reduced in the

reactor. Minor unconverted NH3 is automatically recycled to the sour water stripper via the ContactCondenser blowdown.

Table 2 defines the nominal feed bases for two hypothetical cases, where Case 1 involves a pure NH 3

stream, and Case 2 a high-NH3 low-H2S stream. Table 2 compares the nominal impact on key

parameters of routing those NH3 streams to the TGU (Cases 1b and 2b) as opposed to the SRU reaction

furnace (Case 1a and 2a).



- 26 -

Figure 14 – WorleyParsons Ammonia Destruc tion in TGU (RACTM

)



- 27 -

Table 2 – WorleyParsons RACTM

Hypothetical Feed Streams

Fresh Feed Gas, Mol %

Case 1 Case 2Component

Acid Gas NH3 Gas Acid Gas NH3 Gas

H2S 80 80 5

CO2 16 16

NH3 96 65

H2O 4 4 4 30

Total 100 100 100 100

Fresh feed, LTPD S 100 95 5

NH3 / total fresh feed, mol % 29 28

Table 3 – WorleyParsons RACTM

Impact on Key Parameters

Comparison

Case 1 NH3 Gas Route Case 2 NH3 Gas Route

Key Parameter Case 1A

SRU

Case 1B

TGU

∆

%

Case 2A

SRU

Case 2B

TGU

∆

%

Claus tail gas, MSCFH 689 364 -47 760 346 -54

Claus recovery, % 92.7 96.5 92.3 96.5

RGG fuel, MMBTU/hr 10.4 0.5 -95 11.4 0.5 -96

TGU amine AG, MSCFH 17.5 10.1 -42 18.1 15.3 -15

BSR Selectox

Selectox catalyst is a proprietary catalyst patented by WorleyParsons for low-temperature H2S-oxidationand Claus-reaction catalyst development by the Ralph M. Parsons Company and Unocal. Reduced tailgas from the BSR Contact Condenser is steam-reheated to about 400°F (~ 200°C) and combined with astoichiometric quantity of air in the reactor to produce elemental sulphur, which is subsequently

condensed. (Figure 15) Overall recoveries of 98.5-99.5% are achievable. The reactor inlet is limited to 5%-vol H2S, above which recycle dilution (or inter-bed heat removal) is necessary to limit the exothermic.



- 28 -

SRU TAIL GAS

COMBUSTION AIR

NATURAL GAS

RGG


CONTACTCONDENSER

RECYCLEWATER

SOUR WATERBLOWDOWN

TAIL GAS TOINCINERATOR

REDUCED TAIL GAS

10% NaOH

DESUPERHEATER

STEAMREHEATER

AIR

LP STEAM

SULFUR

SELECTOX

REACTOR

SULFURCONDENSER

Figure 15 – WorleyParsons BSR Selectox



- 29 -

WorleyParsons Current Case Histories

The following are the case histories of the different projects have been recently designed by

WorleyParsons.

Project Case 1

WorleyParsons designed a new tail gas unit for a US refinery to meet the emission requirements. Thefollowing were the key elements of the project.

f The existing sulphur plant did not have adequate pressure to handle the tail gas pressure

f Total H2S of less than 100 ppm

f COS, CS2 hydrolysis

f SO2 concentration at reactor outlet

f Hydraulic and unit capacity

WorleyParsons evaluated this project and the final design was based according to the following criteria.

f Reducing gas generator (RGG) was selected to achieve high temperature in the hydrogenation

reactor for COS and CS2 hydrolysis without changing any catalyst in the existing SRU.

f Flexsorb solvent was selected because it requires less circulation rate compare to the other tail

gas amine solvent Therefore, the capital cost reduced.

f A booster blower is provided to boost the pressure in the tail gas unit downstream of the quench

section. The booster blower has dual function where it will be used as a start up blower to

eliminate large volume of H2S to the flare and recycle back to the unit and the booster blower will

boost the pressure in the unit.

f The final design is according to the Figure 12 that is provided in this paper.

Project Case 2

WorleyParsons has designed two new tail gas units one for a US refinery and one for a Canadian refinerywith the following configuration.

f The existing sulphur plant did not have adequate pressure to handle the tail gas pressure





- 30 -



f Reducing gas generator (RGG) was selected to achieve high temperature in the hydrogenationreactor for COS and CS2 hydrolysis without changing any catalyst in the existing SRU.

f MDEA solvent was selected simply they do not need to deal with two different solvent for the

amine and tail gas unit and there was no cost saving to use other solvent.

f A booster blower is provided to boost the pressure in the tail gas unit downstream of the quench

section. The booster blower has dual function where it will be used as a start up blower to

eliminate large volume of H2S to the flare and recycle back to the unit and the booster blower will

boost the pressure in the unit.


Project Case 3

WorleyParsons has designed a new sulphur recovery and BSR/MDEA tail gas unit for a refinery in South America with the following configuration.





f Low temperature catalyst is selected in the tail gas unit and the first reactor bed in the Claus unit

will contain some Ti catalyst

f MDEA solvent was selected simply they do not need to deal with two different solvent for the

amine and tail gas unit and there was no cost saving to use other solvent.

f A n start up blower is provide only for start up purposes and will not be used at normal operation

except where is the very low turn down and may be used to boost the pressure.




References

1. Ammonia Destruction in a Claus Tail Gas Treating Unit, by M. Rameshni, presented at British

Sulphur Conference, Canada, 2007

2. Operating experience of a 2-reactor Claus plant for up to 99.85% sulphur recovery, by J. Kunkel,P.M. Heisel, LINDE AG, Ulf Nilsson, Peter Eriksson, NYNÄS AB

Documents

Selection Criteria for Claus Tail Gas Treating Processes