processing nh3 acid gas in a srp

8/20/2019 Processing NH3 Acid Gas in a SRP

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Processing NH3 acid gas in a sulphur

recovery unit

Today’s reneries are processing crude

slates with higher sulphur and nitrogen

contents. Some of these crude slates have

such high nitrogen contents that the feed to the

sulphur recovery unit (SRU) contains a farhigher sour water stripper (SWS) acid gas to

amine acid gas ratio than has been typical for

existing ammonia (NH3)-burning SRUs. In the

industry’s experience with NH3-burning SRUs,

the SWS acid gas is processed in the SRU along

with the amine acid gas for recovery of elemen-

tal sulphur from hydrogen sulphide (H2S), and

the NH3 content of the aggregate acid gas has

been low enough that the increase in SRU equip-

ment sizes to process the NH3 and the loss in

Claus sulphur recovery can be tolerated.For these low NH

3 content acid gas feeds, the

furnace temperature is, or can be designed, high

enough to ensure complete NH3 destruction, and

it is less expensive to process the NH3 in the

SRU than to employ a two-stage SWS that would

strip the H2S and NH

3 in separate towers,

enabling the NH3

to bypass the SRU.

With higher NH3 content in the SRU feed, the

rener must decide if a NH3-burning SRU is still

the optimum choice. The rener will recognise

that even higher temperatures are needed forNH

3 destruction, that the incremental mass ow

through the SRU to process the NH3 will be

proportionately larger, that the loss in sulphur

recovery from the additional N2 and H

2O will be

more severe, and that there is little operating

experience with high NH3 content SRU feeds.

Despite these disadvantages, it might still be

economical to select a NH3-burning SRU, lead-

ing to assessment of technical risk vs economics.

This article discusses the issues with high

Michael Quinlan and Ashok Hati KBR

content NH3-burning SRUs, and looks at the

technical and economic issues that the rener

must address in choosing between a single-stage

SWS with a NH3-burning SRU compared with a

two-stage SWS with a SRU that does not processthe NH

3.

SRU feed in a refinery The crude feed to a renery contains both

sulphur (S) and nitrogen (N) compounds. These

compounds are converted to H2S and NH

3 as the

crude is rened into nished products, such as

fuel gas/LPG, gasoline, diesel and coke. As

shown in Figure 1, amine and sour water remove

the H2S and NH

3 to meet nished product speci-

cations. The amine regeneration units (ARU)produce an acid gas containing H

2S with traces

of NH3. The SWS may employ single- or

two-stage strippers. In a single-stage SWS, H2S

and NH3 are stripped from sour water in a single

column, whereas a two-stage or double stripper

has the H2S and NH

3 strippers as two columns

in series. All of the amine acid gas is processed

in the SRU together with SWS acid gas (contain-

ing both NH3 and H

2S if a single-stage SWS, or

H2S only if the SWS is a two-stage stripper).

As the SWS acid gas increases as a propor-tion of the total acid gas feed, or as the NH

3

content of the acid gas feed increases as a result

of processing crudes with higher N/S content

ratios, there may be technical and/or economi-

cal reasons why the NH3 component of the SWS

acid gas should bypass the SRU.

The technical reasons why higher NH3 content

feeds may not be a good t for the SRU are

incomplete NH3 destruction, increased NO

x

formation and inadequate burner/furnace

www.digitalrefining.com/article/1000464 Gas 2010 1

The feasability and economics of a two-stage sour water stripper with an SRU

for NH3 contents of 25% and higher are discussed

http://www.digitalrefining.com/article/1000464




designs. The economical reasons are the

increased size of SRU equipment and the addi-

tional SRU equipment that may be needed to

compensate for the loss in sulphur recovery.

NH3destruction in a SRU

In a Claus SRU, about a third of the H2S is

burned to SO2 using air. The produced SO

2 then

reacts with uncombusted H2S to form elementalsulphur. The reactions are shown as Equations 1

and 2 below. The overall reaction is shown as

Equation 3:

H2S + 3/2 O

2 → SO

2 + H

2O (1)

2 H2S + SO

2 → 3 S + 2 H

2O (2)

3 H2S + 3/2 O

2 → 3 S + 3 H

2O (3)

2 Gas 2010 www.digitalrefining.com/article/1000464

While the H2S is only partially

oxidised in Equation 1, the NH3 is

completely combusted to nitrogen

and water, as shown by Equation 4:

2 NH3 + 3/2 O

2 → N

2 + 3 H

2O(4)

It is vital to destroy the NH3

,

meaning the residual NH3

leaving

the furnace should be 30 ppmv or

lower. If the NH3

is not sufciently

destroyed, NH3

-H2S salts can

form at the cold spots of the Claus

(for instance, in the nal sulphur

condenser) and can plug the SRU.

The reactions that occur in the Claus

furnace are complex and not fully

understood, and the destruction of

NH3

is governed by kinetics rather

than equilibrium. For NH3-burning

SRUs, the three Ts — turbulence,

temperature and time — are the key

to ensuring that the NH3 is suf-

ciently destroyed.

A number of different approaches

are available to destroy the NH3 in

NH3-burning SRUs. To achieve the

required turbulence, a high-intensity

burner is recommended. If the

burner is a high-intensity type (for

instance, Duiker or HEC), all of theamine acid gas may be combined

with the SWS acid gas and the

combined stream sent to the burner and a

single-zone combustion chamber, as shown in

Figure 2a. For low content NH3 feeds, a good

mixing of the high-intensity burner plus a mini-

mum combustion chamber temperature of

2250°F (1230°C) has been deemed adequate by

the industry to destroy the NH3. If the combined

acid gas stream is not sufciently rich in

combustibles, such that 2250°F is not attainable,air and/or acid gas preheat may be used to

achieve the minimum temperature for NH3

destruction. Even when the combustibles are

rich enough in the combined acid gas stream, it

is often considered a good idea to preheat the air

and/or acid gas anyway, as this ensures better

NH3 destruction.

An alternate approach to obtain an NH3

destruction temperature is to provide a two-zone

combustion chamber, with the amine acid gas

Crudedistillation

unit

Strippedsour waterfor refuse

Refinery units Amineregeneration

unit

Sulphurrecovery

unit

Sour waterstripper unit

(SWS)

S o u r w a t e r

SWS acid gas

Stripped sour water to WWT

NH3 (for 2-stage SWS)

H2S (for 2-stage SWS) Sulhur

ARUacid gasRich amine

Lean amine

Coke

Diesel

Crude

Gasoline

Fuel gas/LPG

S to H2S

N to NH3

Figure 1 Feed to sulphur recovery unit in a refinery

Combustionchamber

Burner

Air

SWSacid gas

ARUacid gas Combustion

chamber

Zone 1

Combustionchamber

Zone 2

Burner

Air

SWSacid gas

ARUacid gas

Figure 2a Single-zone furnace Figure 2b Two-zone furnace





component of the SRU feed

split between the two zones

(see Figure 2b). All of the

SWS acid gas and part of the

amine (ARU — amine regen-

eration unit) acid gas is sent

to the burner. The remaining

amine acid gas goes to the

rear zone of the combustion

chamber. This results in the

front zone (where all the NH3

is burned) having a higher

temperature than the second zone. The higher

temperature in the front zone ensures better NH3

destruction.

The furnace temperature is affected by a

number of factors. The combustibles (NH3, H

2S

and trace hydrocarbons) and inerts (CO2, H

2O

vapour) in the SRU feed determine the adiabatic

ame temperature. While the hydrocarbons willelevate the ame temperature and CO

2 decrease

it, the biggest factor may be the water content of

the SWS acid gas, which can be 30 mole% H2O

or higher, depending on the SWS acid gas feed

temperature.

Air is normally the oxidising medium in a SRU

but, if oxygen is available, the use of enriched air

will increase the furnace temperature. Kinetics

and reaction pathways are the other important

factors in determining the Claus furnace temper-

ature. There are multiple reactions(decomposition of H

2S and NH

3, formation of

CO, H2, COS and CS

2) that occur in the Claus

furnace in addition to those shown above, and

all of the reactions and their reaction pathways

are not fully understood. Furthermore, there is

now increasing evidence that SO2 and not O

2 is

the predominant oxidising medium for NH3

destruction:

2 NH3 + SO

2 → N

2 + H

2S + 2 H

2O (5)

The result is that the rener or SRU designer

has some uncertainty about what precisely is the

SRU Claus furnace temperature. However, it is

known (based on testing by SRU burner manu-

facturers or by actual SRU performance test

runs) that as the NH3 content of the SRU feed

increases, higher temperatures are needed to

destroy the NH3, but there is some uncertainty

about what that temperature is for a given NH3

content. Usually a design furnace temperature is


sought where there is condence that all the

NH3 will be destroyed and, if that temperature

cannot be attained, the NH3 will not be

processed in the SRU.

In addition to good burner mixing and

adequate temperature, ample residence time is

necessary to ensure complete NH3 destruction.

While residence time is always needed for theClaus reaction (see Equation 2 above), it is also

needed to destroy the NH3 (Equation 4 and/or

5). When SO2 is the predominant oxidising

medium for NH3, enough residence time must

be provided for the conversion of H2S to SO

2.

Furthermore, as the NH3

content of the SRU acid

gas feed increases, there is increasing competi-

tion between the NH3 and the uncombusted H

2S

for the produced SO2. Therefore, more residence

time is usually needed for the SRU furnace as

the SRU feed’s NH3 content increases.For a 200 tpd SRU, Table 1 shows the oxygen

(in air) requirements and simulated ame

temperature when the NH3 content of the acid

gas is varied from 5–45%. The basis is an amine

acid gas with 98% H2S, 1% CO

2 and 1% hydro-

carbons saturated with water at 120°F (49°C).

The SWS acid gas is 50% H2S, 50% NH

3 and

saturated with water at 185°F (85°C). No air or

acid gas preheat is assumed and the furnace has

a single zone.

Table 1 shows that the furnace temperatureincreases as the SRU feed’s NH

3 content

increases. The O2 for the H

2S is based on burn-

ing a third of the H2S to SO

2. The O

2for burning

the NH3 is based on combusting all of the NH

3.

The actual O2 is less than the sum of the O

2

required for H2S and NH

3, since some thermal

dissociation of H2S and NH

3 occurs. The table

shows that in the sub-stoichiometric SRU

furnace, the NH3 has to compete far harder with

H2S for combustion O

2 (or SO

2) and that, as the

NH3/ (NH

3 H

2S, NH

3, O

2for H

2S, O

2 for NH

3, Actual O

2, Furnace

+ H2S), mole% lbmols/h lbmols/h lbmols/h lbmols/h lbmols/h temp, °F

5 573 30 287 23 297 229410 573 64 287 48 318 231915 573 101 287 76 343 234420 573 143 287 107 370 236930 573 246 287 184 437 2418

40 573 382 287 287 510 243845 573 469 287 352 582 2486

O2 competition trends and predicted furnace temperature

Table 1





NH3

content increases, the NH3 is demanding an

increasing proportion of the O2 supplied to the

furnace. It can be postulated that the increase in

temperature increases the kinetics of NH3

destruction and causes more NH3 to thermally

dissociate, and this compensates for the lower

O2/NH

3 ratio.

High NH3 content SRU feeds

Over the last few years, KBR has been involved

in reneries that wished to process high-nitro-

gen crudes, including cases where the NH3

content to the SRU was 25% or higher. To assess

technical risk, a number of SRU licensors,

burner vendors and operating plants were

surveyed to determine if it is possible to process

this high NH3 content feed in the SRU. We also

looked at the NH3

destination options if a

two-stage stripper SWS is employed. After evalu-

ating the technical and operating risks of aNH

3-burning SRU operating with a high content

NH3 feed, we compared the economics of going

for the “safer” two-stage stripper SWS.

SRU licensor responsesLicensor A indicated that it is often possible to

process the high content NH3 feed in the SRU,

depending on furnace temperature. Licensor A

calculates the required NH3 destruction temper-

ature using an in-house formula that linearly

increases the temperature based on the NH3

content. If T is the required NH3 destruction

temperature, the formula is of the type:

T = A + b*(y-c)

where

A = minimum temperature (°F) for NH3 destruc-

tion at a SRU NH3

content feed of c%. A typically

is ~2250°F

b = increase in temperature for every 1% rise in

NH3 content; b is ~ 5 to 6 y = SRU feed % NH

3 content

c = SRU NH3 feed content at which a tempera-

ture greater than A is needed; c is ~2–5%

Licensor A then compares this temperature

with the simulated temperature. The simulated

furnace temperature is based on kinetic models

and reaction pathways that Licensor A believes

best represent the SRU furnace’s chemistry. The

water content of the SWS acid gas is often

crucial in determining if the simulated furnace

temperature is high enough to ensure complete

NH3 destruction. If the simulated temperature is

sufciently above the calculated NH3 destruction

temperature, Licensor A will guarantee the

NH3-burning SRU.

Licensor B indicated that NH3

contents above

25% are too high for processing in a SRU. Even

with air and acid gas preheat and a two-zone

reaction furnace, Licensor B does not feel

comfortable that the simulated furnace tempera-

ture is high enough to destroy all the NH3.

Licensor B therefore recommends a two-stage

stripper SWS, unless oxygen is available at the

SRU to elevate the furnace temperature.

Licensor C also indicated that a two-stage

stripper SWS is needed above 25% NH3. Neither

Licensor B or C was specic about what they

believed is the temperature needed for NH3

destruction at a given NH3 content, but it

appears the temperature is higher than required by Licensor A.

SRU burner vendors’ responsesThe two burner vendors contacted were Duiker

and HEC. In personal communication1 and on

its website,2 Duiker states that SRU licensors

allow 2–25 vol% of NH3 in the combined acid

gas stream, but that the company has experience

with NH3 content up to 30%. Duiker suggests

that higher temperatures and longer residence

times are needed at higher NH3 contents becausethese conditions promote higher NH

3 thermal

decomposition or dissociation. Table 1 indicates

that the amount of air required for the furnace

changes from 95.8% of stoichiometric require-

ments at 5% NH3 content to 91% at 45% NH

3

content. Duiker believes that adequate NH3

destruction may be possible for up to 45% NH3,

and that the dominant mechanism will be ther-

mal decomposition, but is uncertain what that

temperature will need to be for a given NH3

content.Duiker provided a reference list up to 2007 for

50 of its NH3 SRU burners. Some 22 of these

burners were operating on NH3

contents of less

than 10%, and 27 had NH3 contents between 10

and 20%. One burner has a NH3 content of

22.1%. Only one burner (at 30% NH3) was for

NH3 content greater than 25%, and NH

3 slip

downstream of WHB was <30 ppmv for this

application.

Duiker also alluded to two other commercial






installations. Total Vlissingen, according to local

operators, has operated the SRU occasionally on

SWS acid gas (containing 28% NH3) alone with a

Duiker burner 300. This suggests that it may

even be possible to operate a SRU on SWS acid

gas alone as long as there is sufcient H2S in the

SWS acid gas to provide the SO2 needed for NH

3

destruction and for the Claus reaction. NNPC

Kaduna has reportedly operated with up to 40%

NH3 using a Duiker burner 45.

In a personal communication,3 HEC indicated

that it seeks higher temperatures (>2450°F) and

residence times greater than one second when

the SRU feed’s NH3 content is greater than 25%.

However, HEC has no experience with NH3

contents above 25%, but does not believe it

would pose problems for the SRU in adequately

designed furnaces.

SRU operating plants feedback A European renery 4 has been intermittently

processing a SRU feed with a NH3 content of

28%. The renery frequently changes its crude

slate. One of the crude slates has a high nitrogen

content, resulting in a high NH3 content to the

SRU. The SRU is a Superclaus unit with two

Claus stages.

When processing an SRU feed with a high NH3

content, the renery ensures the Claus furnace

temperature is 2300°F (1260°C) or higher,

although its SRU licensor had suggested a mini-mum of 2400°F (1315°C). The renery

occasionally uses oxygen or fuel gas assist if this

furnace temperature cannot be achieved. The

renery reports no problems with plugging in

the SRU, suggesting that NH3 is being totally

destroyed at the maintained furnace tempera-

ture. However, the renery does report that it

takes some time after a crude switchover to get

the required 99% sulphur recovery.

It appears that the H2S content to the

Superclaus reactor varies after a crude slateswitch. The renery did not reveal the size of the

sour water tank nor whether the NH3/H

2S

content in the SWS acid gas changed with a

different crude slate. Assuming the SWS acid gas

composition is constant, it appears that only

NH3 dissociation differences can explain the

change in H2S content to the Superclaus reactor.

At higher NH3 contents, the destruction of NH

3

through dissociation or decomposition becomes

more important. As the NH3 decomposition

increases, less air or SO2 is needed to destroy

NH3. This means that the feed-forward air

demand for the SRU is slightly in error owing to

differences in NH3 dissociation at different

furnace temperatures.

For high NH3 content feeds, the required SRU

furnace temperature is probably in the 2400–

2500°F (1315–1370°C) range. Similar to an

enriched air SRU, it can be expected that both

H2S and NH

3 will dissociate at these tempera-

tures. The evidence from enriched air SRU

plants is that the H2 formed during these disso-

ciation reactions is higher at the furnace outlet

than at the waste heat boiler (WHB) outlet,

suggesting that some of the H2 formed recom-

bines with S2 vapour in the WHB to form H

2S.

Thus, for a high NH3 content SRU, the SRU

designer may need to look at the responsiveness

of the air control system and allow for H2S re-

association when calculating the WHB duty andsurface.

Despite the burner vendors’ condence that

NH3 contents greater than 25% could be

processed in a SRU using air as the oxidising

medium, there are only a handful of commercial

applications, and only one SRU licensor is

prepared to guarantee the SRU’s performance.

There are risks, therefore, in looking to the SRU

to handle these high content NH3 streams. These

risks may not be worthwhile if the cost of the

two-stage stripper is not much more than theincreased cost for the SRU. The differences

between single- and two-stage SWS strippers

and between fuel gas- and NH3-burning inciner-

ators need to be understood before the optimum

conguration can be selected.

Single-stage SWSFigure 3 shows a schematic of a single-stage

SWS. Sour water from the SW tank is preheated

and sent to the stripper. The stripper consists of

a column, a reboiler and an overhead condenser(pumparound condensing is also possible). The

stripper has usually 36 to 56 actual trays,

depending on product specication and steam

usage. The stripped sour water has a low H2S

content (<10 ppmw) and a small amount of NH3

(<50 ppmw).

Two-stage SWSFigure 4 shows a schematic of a two-stage SWS.

The two-stage stripping concept uses the boiling






point difference between NH3 and H

2S to remove

them as individual streams. The H2S stripperoperates at ~125 psig to remove H

2S from the

sour water. The column is equipped with a

reboiler, but does not have an overhead

condenser. For a trayed column, the number of

actual trays usually varies from 30 to 48.

Stripped sour water (or wash water) is used at

the top of the column to wash out NH3 from the

overhead stream. The overhead vapour is mainly

H2S with traces of NH

3 (~20–100 ppmv), and is

sent to the SRU’s Claus unit.

The NH3 stripper operates at low pressure.This column is equipped with a reboiler and an

overhead condenser for reux. The actual

number of trays is 40 to 44 or equivalent packed

bed. The NH3 stripper overhead vapour, mostly

NH3 and residual H

2S (~1500–3000 ppmv), is

sent to the incinerator and burned, assuming

there is no end use for the NH3. The NH

3 stream

can be incinerated directly or after H2S scrub-

bing. The need to scrub H2S from the NH

3

stream is dictated by the overall sulphur recov-

ery requirement, and/or whether

the local or environmental

authority judges the NH3 stream

to be a fuel gas source and thus

limits its allowable H2S content.

A small part of the stripped sour

water is sent to the H2S stripper

top as scrubbing water and the

rest is sent outside the unit for

reuse by the renery users or for

wastewater treatment. The

stripped sour water has low H2S

(<10 ppmw) and about 25–50

ppmw NH3.

Comparison of single- andtwo-stage strippersThe two-stage SWS conguration

requires an additional stripper,

reboiler and feed-bottomexchanger and, therefore, has a

higher capital cost and requires a

larger plot space. For an equimo-

lar H2S and NH

3 sour water feed,

the H2S stripper diameter is

~15% smaller than the single-

stage SWS. The design pressure

of the H2S stripper is higher and

may require 300# class anges.

The NH3 stripper has a diameter similar to the

single-stage SWS. The two-stage stripperconsumes more utilities. For example, the

reboiler duty for the combined H2S and NH

3

stripper is ~100% higher than for the single-

stage stripper. The overhead condenser in an

NH3 stripper has a higher duty than the single-

stage stripper’s overhead condenser.

NH3

destination optionsThe NH

3 stream from a two-stage stripper can

be used in several ways. The choice is usually:

• Liquid NH3 manufacture• NH

3 dissociator

• NH3 incinerator.

Liquid NH3 manufacture is usually not consid-

ered unless the NH3 quantity is above 30 tpd

and there is a market for the liquid NH3. In most

cases, these conditions do not exist but, if they

do, the NH3 overhead from the two-stage strip-

per must be treated to remove contaminants

(trace H2S etc) in the NH

3 stream. Chevron’s

WWT process has an optional add-on that uses a


Stripped sour water

SWS – AGto SRU

Refluxdrum

Refluxpump

Condenser

SWstripper

Sour waterfrom SW tank

Steam

CW

P =∼19 psig

SWfeed pump

CW

StrippedSw cooler

Figure 3 Single-stage sour water stripper





ator fuel. This stream is mostly NH3 (~96

mole%) with trace H2S (~1500–3000 ppmv).

Depending on the renery’s sulphur recovery

requirement, or whether the NH3 is considered a

fuel gas, the NH3 may need pretreatment to

remove H2S. If the incinerator stack SO

2 is not to

increase, a Superclaus unit must achieve higher

two-stage scrubbing system to

remove H2S from the NH

3 stream,

which is then liqueed to produce

anhydrous NH3.

The NH3 gas is dehydrated,

preheated by steam and cracked in

the NH3

dissociator. The dissocia-

tion of NH3

occurs at an elevated

temperature in the presence of a

catalyst. The cracked gases are

then cooled to generate steam

and/or preheat the feed gas. The

formed gas contains little dissoci-

ated NH3. This NH

3 may be

removed in an optional molecular

sieve unit. The formed gas is 75%

hydrogen and 25% nitrogen. The

hydrogen or formed gas is used for

the bright hardening of metals. It

is not known if this hydrogen-richgas could be used to advantage in

a renery, since the gas is low

pressure and has a signicant

nitrogen volume.

While some older plants ared

the NH3, this is no longer environ-

mentally acceptable (due to NOx

formation), and because the heat

content of the NH3 gas is not

recovered. Today, NH3 is mostly

sent to a NH3 incinerator that isdesigned for low NO

x and for

steam generation from NH3

combustion.

NH3 incinerator

The incinerator is used at the end

of the SRU to destroy residual H2S

in the SRU tail gas. For a NH3-

burning SRU, fuel gas is used. A

typical SRU incinerator that

includes optional waste heat recov-ery is shown in Figure 5.

Fuel gas is combusted with

excess air in the burner. The ue

gas goes to the incinerator furnace where SRU

tail gas is introduced. The waste heat boiler (and

steam superheater) is optional. The cooled incin-

erated gas is released to the atmosphere through

a stack.

When a two-stage SWS is used, the overhead

stream from the NH3

stripper is used as inciner-


NH3 toincinerator

Recycle to SW tank

NH3stripper

refluxdrum

NH3stripperboiler

NH3 Strippercondenser

NH3stripper

H2Sstripper

Sour waterfrom SW tank

MPsteamOff gas

LPsteam

CW

CW

P =∼19 psig

P =∼123 psig

SWfeed pump

StrippedSW pump

StrippedSW cooler

H2Sstripperboiler

H2S to SRUclaus train

NH3 stripperreflux pum

1st

feed/bottomexchanger

2nd

feed/bottomexchanger

Figure 4 Two-stage sour water stripper

Combustionair boiler

To atm.

Fuel gas

SRU tail gas

BurnerFurnace1450 °F

Steamsuperheater

700 °F

Waste heatboiler

BFW

HP steam

SuperheatedHP steam

Figure 5 Typical SRU incinerator





sulphur recovery when the NH3 stream is not

scrubbed of H2S. A NH

3-burning incinerator is

specially designed for low NOx emissions. There

are a number of low NOx-producing incinerator

designs available, such as the John Zink

Noxidizer and Duiker low NOx incinerator.

The Noxidizer5,6 uses phased combustion and

is a three-stage process consisting of reducing,

quench and re-oxidation sections (see Figure 6).

There are about ten Noxidizers operating as SRU

incinerators.

The NH3 stream and fuel gas (if required) are

burned at 70–90% of stoichiometry. Part of theSRU tail gas is admitted at the burner and

reduction chamber to reduce the temperature so

that the refractory is not thermally stressed. The

temperature in the reduction chamber is

controlled at ~2300°F (1260°C) with a residence

time of about two seconds. The high tempera-

ture causes the NH3 to dissociate, producing

nitrogen. The nitrogen and the combustibles,

competing for the limited quantity of oxygen

available, keep the nitrogen from being oxidised.

The products of combustion from the reductionstage, which contain uncombusted NH

3 and

uncombusted CO, H2 and H

2S in the SRU tail

gas, are cooled in the quench section by the

remaining SRU tail gas to ~1400°F (760°C). In

certain cases, cooled gases from downstream of

the waste heat recovery are recycled to the

quench section.

In the re-oxidation furnace, uncombusted

NH3, H

2 and CO are burned with excess air.

Enough secondary air is injected to give an

excess oxygen level of 2–3% by volume on a dry

basis in the nal ue gases. The temperature ismaintained at ~1900°F (1038°C) to limit the

formation of thermal NOx at about one second

residence time. The temperature difference

between the reduction and re-oxidation cham-

bers is controlled and depends on the

sub-stoichiometry used at the reduction stage.

High-pressure steam is generated from the

gases leaving the re-oxidation chamber. The

cooled ue gas from the waste heat boiler is

released to atmosphere through a stack and the

NOx emission is <150 ppmv.The fuel gas incinerator burns enough fuel gas

to meet the requirement for incinerator temper-

ature, whereas the NH3 incinerator burns all

NH3 from the NH

3 stripper even though that

exceeds the temperature to incinerate the SRU

tail gas. While waste heat recovery is optional

for a fuel gas incinerator, it is mandatory if the

heat of combustion from burning NH3 is to be

recovered. The Noxidizer requires bigger equip-

ment (greater residence time) and higher

temperature refractory.

Overall economics with a two-stage SWS optionIn the preceding paragraphs, the differences in

equipment and utilities of a single- or two-stage

stripper SWS, and in fuel gas or NH3-burning

incinerators, were discussed. However, the

economics of a two-stage SWS must also

consider differences in the SRU Claus, SRU

TGTU and NH3 treatment.

When the renery SWS is an integrated SWS


Combustionair boiler

Fuel gas

SRU tail gas

Burner

To atm.

Re-oxidationfurnace1900 °F

1 sec

Re-oxidationair blower

Reductionfurnace2300 °F2.0 sec

Quenchsection1400 °F

Steamsuperheater

700 °F

Wasteheat boiler

HP steam

SuperheatedHP steam

BFWNH3 rich gas

Figure 6 NH3-burning incinerator





that treats both

phenolic and non-phe-

nolic sour water,

increases in capital

cost are primarily due

to the addition of an

extra stripper and

reboiler, and the oper-

ating costs due to the

higher steam consump-

tion. If the renery

SWS uses segregated

strippers for non-phe-

nolic and phenolic sour water, it is often best to

keep the phenolic stripper as a single stripper,

because a far greater proportion of the total

NH3 in the sour water is associated with the

non-phenolic sour water. Economically, it is

best to provide an integrated SWS or, if segre-

gated SWS systems are in place or preferred for water reuse and management, to only use a

two-stage stripper on the non-phenolic sour

water.

With a two-stage stripper SWS, the NH3 from

the sour water no longer goes to Claus. This

reduces considerably the mass throughput in

Claus. It also reduces the mass throughput in

Superclaus or SCOT, assuming that these

processes need to be added to Claus, depending

on whether 99% (Superclaus) or 99.9% (SCOT)

sulphur recovery is needed. This is illustrated inTable 2 for a 200 tpd SRU, assuming the same

basis as in Table 1. This shows that a 45% NH3

SRU feed has almost double the mass through-

put of a 5% NH3 SRU feed. In fact, every tonne

of NH3 in the SRU feed is equivalent to ~2.5 tpd

of sulphur in terms of SRU mass throughput. As

shown in Figure 7, the SRU Claus will use two

catalytic stages as a minimum.

The level of two-stage Claus sulphur recovery will change, depending on whether a single- or

two-stage stripper is employed. Table 2 shows

that the sulphur recovery level decreases when

the NH3 content increases, because of the water

vapour in the SWS acid gas and the greater

concentration of N2 and H

2O in the Claus

process gas when the NH3 is combusted. If the

200 tpd two-stage Claus SRU (at 5% NH3) costs

$40 million, the cost would increase to $58

million if the NH3 content increased to 45%. The

process options (add-ons to a two-stage Claus)for either 99% or 99.9% recovery are shown in

Figure 8.


NH3/(NH

3 Amine AG, SWS AG, Air, SRU feeds, % sulphur recovery in Claus stages

+ H2S), % lb/h lb/h lb/h lb/h 2-stage 3-stage

5 19 511 1961 41 253 62 725 94.4 98.110 18 307 4140 44 263 66 710 94.1 97.915 16 961 6575 47 637 77 173 93.7 97.820 15 447 9314 51 442 76 203 93.2 97.6

30 11 769 15 967 60 704 88 440 92.0 97.140 6865 24 652 70 927 102 444 90.7 96.645 3671 30 482 80 800 114 953 89.8 96.1

SRU mass throughput and recovery % vs NH3 content

Table 2

ARU acid gas

SW H2S + NH3 gas (IF 1–stage SWS)

SW H2S gas (IF 2–stage SWS)

RF

Condenser

WHB

Air BFW

BFW

LP steam

S

Condenser

BFW

LP steam

Converter 1 Converter 2

LP steam Claus tail gas

S

Condenser

BFW S

HP steamHP

steamRH 1HP

steamRH 2

Figure 7 Two-stage Claus sulphur recovery unit






conguration, but more hydrogen

and amine will be needed in

SCOT, and the recycle ow to the

Claus inlet will increase as the

SRU feed’s NH3 content increases.

Additionally, the amount of water

removed by the SCOT quench

section will increase with a rise in

the NH3 content. These will

increase the SCOT and SWS costs.

The amount of steam generated

in Claus is less with a two-stage

stripper SWS. With a single-stage

SWS, the heat from the combus-

tion of NH3 is largely recovered in

the SRU. For operating costs, the

value of the additional steam is

usually worth more than the addi-

tional power that is needed for the

SRU’s air blower to deliver theincremental air to combust the

NH3.

Finally, the fuel gas-burning

SRU incinerator for a single-stage

SWS will become a NH3 fuel incin-

erator for a two-stage stripper

SWS. It can be seen that the NH3

incinerator will be more expensive

than the fuel gas incinerator. For

a two-stage stripper SWS, the heat

from the combustion of NH3 isrecovered at the incinerator rather

than at the SRU, as is the case for

a single-stage SWS.

The NH3 that goes to the inciner-

ator contains about 2500 ppmv

H2S. This can represent as much as

0.2 wt% of the inlet sulphur. If

99% sulphur recovery is needed,

this may require the Superclaus

unit to achieve 99.2% recovery,

which may be beyond its capability and wouldrequire that Superclaus be upgraded to Euroclaus.

If 99.9% sulphur recovery is needed, it will be

necessary to treat the NH3 to remove the H

2S.

The differences in capital and operating costs

are shown in the following example for a 200

tpd SRU processing a SRU feed with a 45% NH3

content, when the required sulphur recovery is

99% and 99.9%, respectively.

In Table 3, only one Claus and Superclaus or

SCOT train is assumed. Even with the most

With a two-stage stripper, only two Claus cata-

lytic stages may be needed upstream ofSuperclaus, whereas a single stripper will require

three Claus stages. Typically, the additional

Claus stage will add 15–20% to the unit’s costs.

Even if Claus is designed to accept the small

amount of NH3 in the phenolic SWS acid gas,

the NH3

quantity may be small enough that a

two-stage Claus upstream of Superclaus may be

sufcient. For 99.9% sulphur recovery using

SCOT, the Claus will generally only require two

catalytic stages regardless of the phenolic SWS

3rd stageclaus

2nd stageclaus tail gas

Option

SW

S

Acid gasto SRU

Hydrogenation+

quench

Aminetreating

SCOT99.9% recovery

Superclaus99% recovery

Toincinerator

Figure 8 SRU options for 99.0/99.9% recovery

Single-stage SWS plus SRU 2-stage SWS plus SRUSWS1 35 60SRU Claus (2-stage) 58 40Add 3rd-stage Claus 9 66

Superclaus 11 8SCOT 48 33Incinerator 2 15 18Total for 99% sulphur recovery3 128 132

Total for 99.9% sulphur recovery4 165 151

Notes:1. Cost depends on SWS capacity2. Both fuel gas and NH

3 incinerators generate HP steam

3. Sum of SWS, SRU Claus, third stage, Superclaus and Incinerator 4. Sum of SWS, SRU Claus, SCOT and Incinerator 5. Cost of treating NH

3 for H

2S removal not included

6. 3rd Claus stage often not needed for 2-stage stage SWS

Capital costs comparison

Table 3






nearly always be cheaper than using a two-stage

stripper at the SWS.

• A two-stage stripper at the SWS is usually

more expensive than a single stripper and

requires a lot more steam. However, these

increased capital and operating costs are offset

by a smaller SRU.

• The economics of a single stripper with a

larger SRU against a two-stage stripper with a

smaller SRU depend on several factors, such asSWS ow, NH

3 quantity, SRU recovery and NH

3

destination. Under the most favourable circum-

stances, the capital cost for a two-stage stripper

is the same, but usually the capital cost is

anywhere between 5% and 25% more.

• In cases where the cost increase is no more

than 15%, it may be best to use a two-stage strip-

per and avoid the potential operating difculties

of a NH3-burning SRU.

References1 Email and phone conversation with Dennis van de Giessen at

Duiker, Netherlands.

2 Statement concerning NH3 decomposition in Claus reaction

furnaces, www.duiker.com.

3 Email and phone conversation with Nick Roussakis at HEC,

Calgary, Canada.

4 Phone conversation with Cees Koopman.

5 Noxidizer brochure, www.johnzink.com.

6 Incineration of nitrogen bearing wastes, International

Conference on Environmental Control of Combustion Processes,

Honolulu, HI, Oct 1991.

favourable conditions (NH3

content at 45%), the

two-stage stripper’s capital

costs for 99% recovery are

the same or slightly more

than for the single-stage

SWS. For 99.9% recovery,

the unloading of the NH3

from the SRU helps reduce

both Claus and SCOT costs,

and, at very high NH3

contents, the two-stage strip-

per can be slightly cheaper.

Table 4 shows that the

additional stripping steam

for the two-stage stripper is

not fully offset by savings in

fuel gas and by the lower

Claus blower power. Overall,

Tables 3 and 4 show that atwo-stage SWS can be

economic with a single-stage stripper. There are

several variants that affect the cost comparison,

but a two-stage SWS will usually look most

attractive when the SWS capacity is high, the

NH3 content is near maximum and when 99.9%

sulphur recovery is required. Based on our expe-

rience, the cost of a two-stage stripper is a

minimum of 5% greater, and sometimes can be

as high as 25% greater than a single-stage SWS

when NH3 content is 25% or less and when only99% sulphur recovery is needed.

Conclusions• For NH

3-burning SRUs, the industry standard

— that a minimum temperature of 2250°F

(1230°C) is needed to guarantee NH3 destruction

— needs to be modied and correlated with NH3

content. In fact, minimum temperatures of

2400°F (1315°C) or higher may be needed for

NH3 contents of 25% and above.

• High-intensity burner manufacturers such asDuiker and HEC believe that their burners can

achieve these higher temperatures if water

vapour content is not excessive, and that a SRU

feed NH3 content of greater than 25% can be

processed in a SRU.

• There are few NH3-burning SRUs operating

with a NH3 feed content above 25%.

• If oxygen is available, enriched air can be used

at the SRU and ensure that temperatures of NH3

destruction at the SRU are achieved. This will

Unit Single-stage SWS 2-stage SWS plus SRU plus SRUSWS reboiler steam2 MMBtu/h 83 160SRU 2-stage Claus steam MMBtu/h -97 -46SCOT steam MMBtu/h 14 7Incinerator fuel gas MMBtu/h 58 2

Incinerator steam MMBtu/h -48 -53Total for 99% sulphur recovery3 MMBtu/h -4 62

Total for 99.9% sulphur recovery4 MMBtu/h 10 69Electrical (blower) powersSRU Claus blower power hp 1140 550Incinerator blower power hp 160 150

Notes:1. All positive values are consumption; negative values represent production2. Depends on SWS capacity3. Sum of SWS, SRU Claus and incinerator 4. Sum of SWS, SRU Claus, SCOT and incinerator 5. Cost of treating NH

3 for H

2S removal not included

Operating costs comparison1

Table 4






is a registered Professional Engineer in Texas and holds a BTech

in chemical engineering from IIT, Kharagpur, India.

Email: [email protected]

Mike Quinlan is a Senior Process Manager with KBR, Houston,

where he is responsible for gas/liquid treating and sulphur.

He has over 30 years’ experience in acid gas removal and has

designed and started up numerous amine, sour water stripper

and sulphur recovery units. He has a bachelor’s degree in

chemical engineering from University College, Dublin.

Email: [email protected]

Ashok Hati is a Senior Technical Advisor with KBR, Houston.

He has 26 years’ technical experience ranging from conceptual

process development to design engineering and plant operation,

the last ten years in gas/liquid treating and sulphur recovery. He

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