SULFUR REMOVAL Typical legislative actions have been the setting of limits on the allowable sulfur content of the fossil fuel being burned or on the SO 2 emission rates of new sources..
Trang 1The amount of pollutants, especially sulfur oxides and
par-ticulates emitted to the atmosphere may be reduced by
treat-ing fuels prior to combustion This approach may be more
energy effi cient than treatment of fl ue gases as per Vapor and
Gaseous Pollutant Fundamentals More than thirty million
tons of sulfur dioxide are discharged annually in the United
States, 75% of which is the result of fuel burning
FOSSIL FUEL PRODUCTION, RESERVES AND
CONSUMPTION
The world’s production of oil in 1980 was 66 million barrels
per day with a projected value of 77 MBPD for the year 2000
The relatively small anticipated increase refl ects increased
con-servation and alternate fuel source application The overall oil
output of the USSR was about 14 MBPD 1 as compared to about
12 MBPD for combined US and Canadian production (1980)
About 2500 trillion cubic feet of natural gas reserves are
estimated to exist worldwide The US reserves are 200 TCF
with an annual consumption of about 20 TCF Soviet bloc
production was about 15 TCF in 1980 Most oil and natural
gas reserves fall in a crescent shaped area extending from
Northern Algeria Northward to West Siberia Lynch 2 felt
that the level of surplus capacity would remain stable for
the early ’90s with the then world stock level of about 100
gigaliters (1.3 giga barrels)
Coal is consumed at a rate of 600 million tons annually
in the US utility industry Only a small portion of Eastern
US coals fall in the low (less than 1% sulfur) category—see
world’s 780 billion tons of presently recoverable coal reserves
The US has about one quarter of the total Coal accounts for
90% of the US’s proven reserves. 3
Consumption of fuel might be measured in “quads” or
quadrillion Btu’s It has been estimated that US electric
con-sumption was 13 quads and nonelectric industrial about 16
quads for the year 1980. 3 Total US fossil fuel consumption is
about 76 quads, most in the non-industrial sector Worldwide
energy consumption is predicted to double over the next 25
years according to the World Energy Council. 3a The
pre-dicted fossil fuel usage in terms of billions kwh electric
gen-eration in the year 2015 is for coal-2000, natural gas-1000,
nuclear-400, and petroleum-less than 100 Renewables are
estimated at 400 billion kwhs Divide these numbers by 100
to estimate the number of quads; assuming a plant effi ciency
of current Rankine cycle plants (about 34%) or by 170 if a combined cycle (Brayton Rankine) is assumed
SULFUR REMOVAL Typical legislative actions have been the setting of limits on the allowable sulfur content of the fossil fuel being burned or on the SO 2 emission rates of new sources In California, regula-tions have limited the use of fuel oil to those of 0.5% or less sulfur Since 1968, a limit of a 0.3% sulfur oil has been in effect
in New York City In 1980, Massachusetts set a 1% sulfur limit
on the coal to be burned This limit is being considered for other Atlantic seaboard states as coal conversion is increasingly encouraged Chemical and physical desulfurization of fossil fuels can be used to produce levels of sulfur which comply with government standards To reduce a 3% sulfur coal to a 1% sulfur coal may add about 10% to the cost of coal F.O.B., but may save on transportation and fl ue gas desulfurization costs The amount of sulfur dioxide emitted worldwide might double in the next decade due to increased energy demands (approximately 3.5% annually) and the use of more remote crudes having higher sulfur concentration
The chemical and power industries must strike a delicate balance between the public’s dual requirement of increased quantities and preparation of fossil fuel More fuel must now
be desulfurized more completely and/or more sulfur diox-ide must be removed from stack gases The techniques for cleaning fossil fuels used throughout the petroleum, natural gas and coal production industries are covered in this arti-cle Treatment of stack gases to effect particulate and sulfur removal are discussed separately in other articles
PROCESSES INVOLVING THE BASIC FUELS The two most commonly combusted energy sources are coal and fuel oil having typical sulfur ranges of 1–4% and 3–4%, respectively; a 3% sulfur oil produces about the same SO 2 emission as a 2% sulfur coal when based on a comparable energy release Fuel oil desulfurization is used by most major oil producers Hydrogenation, solvent extraction, absorption and chemical reaction are used to varying extents at petro-leum refi ners Finfer 4 claims a possible sulfur reduction from 2.5 to 0.5% by a hydrodesulfurization process Coal contains sulfur which may be combined with either the organic or
Trang 2inorganic (pyritic and sulfate) matter The organics may be
removed by various cleaning processes, but little reduction
in organic sulfur has been found to occur by physical
clean-ing methods Currently an extraction process, followed by
hydrogenation, is being tried Some coals have been reduced
to S contents below 2%, and typical sulfur reduction
esti-mates are in the range of 20–40% reduction. 5,6,7 Even if these
reduced levels are achieved, a need for further removal of
sulfur from the fl ue gases might exist Cleaning, when
com-bined with fl ue gas desulfurization as a method of SO 2
con-trol, could eliminate the need for reheat and considerably
reduce the sludge handling requirements of the plant
Fuel Oil Desulfurization (General)
Before the ecological need for fuel oil desulfurization was
recognized, oil stocks were desulfurized for a number of
other reasons:
1) To avoid poisoning and deactivation of platinum cat-alysts used in most catalytic reforming processes 2) To reduce sulfurous acid corrosion of home burner heating equipment
3) To demetalize crude stocks (sulfur removal from crude is generally accompanied by a concomitant removal of such trace metals as sodium, vanadium and nickel)
4) To recover pure sulfur
5) To reduce or eliminate final product odor
By defi nition, hydrodesulfurization is the removal of sulfur by a catalytic reaction with hydrogen to form hydrogen sulfi de As carried out in the petroleum industry, the hydrode-sulfurization process is not a specifi c chemical reaction Various types of sulfur compounds (mercaptans, sulfi des, polysulfi des, thiophenes) with varying structures and molecu-lar weights are treated Obviously, they react at various rates
TABLE 1 Ash content and ash fusion temperatures of some U.S coals and lignite
Rank
Low Volatile Bituminous High Volatile Bituminous Subbituminous Lignite Seam Pocahontals No 3 No 9 Pittsburgh No 6
Location West Virginia Ohio West Virginia Illinois Utah Wyoming Texas Ash, dry basis, % 12.3 14.10 10.87 17.36 6.6 6.6 12.8 Sulfur, dry basis, % 0.7 3.30 3.53 4.17 0.5 1.0 1.1 Analysis of ash, %
by wt
Initial deformation
temperature, F
Softening
temperature, F
Hemispherical
temperature, F
Fluid temperature, F
Trang 3In addition, during the course of desulfurization, non-sulfur
containing molecules may be hydrogenated and in some cases
cracked
The fl ow design of hydrosulfurization process systems
is relatively simple Preheated oil and hydrogen under
pres-sure are contacted with catalyst The effl uent from the
reac-tor is passed to one or more separareac-tors to remove most of the
effl uent hydrogen and light hydrocarbon gases produced in the
operation These gases are generally recycles with or without
prior removal of light hydrocarbons by absorption The
separa-tor liquids may be stripped, rerun or otherwise treated to obtain
hydrogen sulfi de free products of the desired boiling range
Except in the case of residuum processing, plant design
options are few in number and relatively simple For
exam-ple, in the processing of distillates, correlation systems have
been developed which relate degree of desulfurization to
about three parameters which defi ne the charge stock,
reac-tor temperature, temperature, pressure, feed space velocity,
hydrogen rate and a catalyst activity parameter
When residuum stocks are considered, however,
general-izations are not so easily made The wide variance in
resid-uum properties (i.e., atmospheric or vacresid-uum type, viscosity,
Conradson carbon content, metal content and the paraffi nic
or aromatic nature of residuum) makes each case a special
one as far as process design Catalyst poisoning due to metals deposition on the catalyst surface can reduce overall desulfur-ization yields Catalyst must then be regenerated or replaced, thus adding to overall cost of the particular system employed
An alternative to desulfurization exists, that being the use of natural low sulfur fuel oils They may be used alone
or in blends with higher sulfur content material The major source of low sulfur fuel oil is North African crudes, princi-pally from Libya and Nigeria, and some Far Eastern crude from Sumatra Fuels made from these crudes will meet even very low sulfur regulations calling for 0.5% sulfur or less However, the highly waxy nature of these paraffi nic materi-als makes handling diffi cult and costly Therefore, the blend becomes a more palatable course of action
Blends of natural low-sulfur fuels oils with other high sulfur fuel oils will be adequate in some cases to meet more moderate sulfur regulations The fuel oil fractions of North African crudes contain about 0.3% S Thus signifi -cant amounts of higher sulfur fuel oils can be added to make blends calling for 1–2% sulfur These blends have physical properties which obviate the need for specialized handling (a must for existing industrial installations)
Before delving into specifi c desulfurization technology and applications, pertinent terms will be defi ned Figure 1
FUEL OIL
NAPHTHALEN
NO 6 FUEL OIL BENZENE TOLUENE
H
F E
L
ATM GAS OIL H
2
KEROSENE PREMIUM GASOLINE
RES GASOLINE BUTANE
NAT GASO
D C
NAPHTHA
CRUDE
LIGHT ENDS
LIGHT REFORMATE HEAVY REFORMATE
GENERAL FLOWSHEET - CRUDE OIL PROCESSING
LEGEND
A - CRUDE DISTILLATION
B - CATALYTIC REFORMER
C - BTX EXTRACTION
D - GASOLINE POOL
E - PYROLYSIS
F
G
H
I - HYDRODEALKYLATION
ALKYL NAPHTHALENE
FIGURE 1
Trang 4schematically represents a general fl owsheet for crude oil
pro-cessing Crude oil, as received from the source is fi rst
atmo-spherically distilled Light ends and mid-distillates from this
operation are further processed to yield gasolines and
kero-sene Atmospheric residuum can be directly used for No 6
fuel oil, or further fractionated ( in vacuo ) to produce vacuum
gas oil (vacuum distillate) and vacuum residuum After
atmo-spheric distillation, the average crude contains about 50% of
atmospheric tower bottoms, which is nominally a 650F oil
The vacuum distillation yields roughly equal parts of vacuum
gas oil and vacuum residuum The bottoms from this unit is
nominally a 975F oil, although the exact cut point will vary
for each vacuum unit
Desulfurization of vacuum residuum would be
appli-cable where a refi nery has use for the virgin vacuum gas
oil other than fuel oil, and sulfur restrictions or increased
prices make desulfurization of vacuum bottoms attractive
Another situation is where desulfurizing the vacuum gas oil
and blending back with vacuum bottoms no longer produces
a fi nal fuel oil meeting the current sulfur specifi cation
Present in the residuum (vacuum) is a fraction known
as asphaltenes This portion is characterized by a
molecu-lar weight of several thousand The majority of the
organo-metallic compounds are concentrated in the asphaltene
fraction Although many of the metals in the periodic table
are found in trace quantities, vanadium and nickel are
usu-ally present in by far the highest amounts Residual oils from
various crudes differ from each other considerably in regard
to hydrodesulfurization These differences reside to a great
extent in the asphaltene fraction
Light Oil Desulfurization
The G O-Fining Process The G O-Fining process is designed
for relatively complete desulfurization of vacuum gas oils,
thermal and catalytic cycle oils, and coker gas oil It represents
an extremely attractive alternative where a lesser degree of
sulfur removal from the fuel oil pool and/or a very low sulfur
blending stock is required The feed to the G O-Finer System
is atmospheric residuum This stream is vacuum fractionated and the resulting vacuum gas oil (VGO) is desulfurized using
a fi xed bed reactor system Resultant VGO is then reblended with vacuum bottoms to yield a desulfurized fuel oil or used directly for other applications Figure 2 shows quantitative breakdown of various process streams for a 50,000 barrel per stream day (BPSD) operation utilizing a 3% sulfur Middle East atmospheric residuum feed The process has the capa-bility of producing 49,700 BPSD of 1.72% S fuel oil There are currently a number of G O-Fining units in commercial operation
Investment and operating costs will vary depending on plant location and crude stock characteristics, but for many typical feedstocks (basis 50,000 BPSD) total investment is about 16.3 million dollars and operating costs average out at 60¢/barrel fuel oil (1989)
UOP ’ s gas desulfurization process Another light oil
desul-furization process is UOP’s gas oil desuldesul-furization scheme Unlike the previously discussed G O-Fining process, UOP’s scheme (already commercial) is designed for almost complete (⬃90%) desulfurization of a 630 to 1050; F blend of light and vacuum gas oils (approximate sulfur content of feed—1.5%) Vacuum residuum is neither directly nor indirectly involved anywhere in the process
In almost all other respects, however, UOP’s process parallels G O-Fining The current plant facility is of 30,000 BPSD capacity with above mentioned feed
Comparison of UOP and G O-Finer costs show that both are of the same order of magnitude and differ markedly only
in initial capital investment This is in part attributable to the fact that a G O-Fining facility requires atmospheric resid-uum fractionation whereas UOP’s does not
Stocks of high-sulfur content are diffi cult to crack cata-lytically because all or most of the catalysts now in com-mercial use are poisoned by sulfur compounds In recent years the trend has been toward processes that remove these sulfur compounds more or less completely The high sulfur
1100°F Vacuum Bottoms 16,600 BPSD
4.2 wt % s
700–1100°F VGO 33,400 BPSD 2.33 WT % S
MIDDLE EAST
700°F + RESID
50,000 BPSD
3.0 WT % S
33,100 BPSD 0.3 WT % S
400°F + Desulfurized Fuel Oil 1.72 WT % s THE GO–FINING PROCESS
FIGURE 2
Trang 5contents of petroleum stocks are mainly in the form of
thio-phenes and thiophanes and these can be removed only by
catalytic decomposition in the presence of hydrogen The
Union Oil Company has developed a cobalt molybdate
desulfurization catalyst capable of handling the full range of
petroleum stocks encountered in refi ning operations Even
the more refractory sulfur compounds associated with these
stocks are removed This catalyst exhibited excellent
abra-sion resistance and heat stability, retaining its activity and
strength after calcination in air at temperature as high as
1470F. 8 Cobalt molybdate may be considered a chemical
union of cobalt oxide and molybdic oxide, CoO · MoO 3 The
high activity of this compound is due to an actual chemical
combination of these oxides with a resultant alteration of the
spacing of the various atoms in the crystal lattice. 8 Catalyst
life is two to fi ve years Catalyst poisons consisted of carbon,
sulfur nitrogen and polymers Regeneration is accomplished
at 700 to 1200F using air with steam or fl ue gases
The fundamental reactions in desulfurization are as
follows:
General Reaction
CnHmSp x H 2 → CnHm 2x 2p p H 2 S
Desulfurization of ethyl mercaptan
C 2 H 5 SH H 2 → C 2 H 6 H 2 S ∆ H 19.56 kg cal/mole
Desulfurization of diethyl sulfi de
(C 2 H 5 ) 2 S 2H 2 → 2C 2 H 6 H 2 S ∆ H 36.54 kg cal/mole
Desulfurization of thiophene
C 4 H 4 S 4H 2 →C 4 H 10 H 2 S ∆ H 73.26 kg cal/mole
Desulfurization of amylene
C 5 H 10 H 2 →C 5 H 12 ∆ H −33.48 kg cal/mole
The change in heat content for all these reactions is negative,
indicating that they take place with evolution of heat The
sulfur content in Middle East Gas Oil, a typical feed, is 1.25%
by weight The pilot plant data shows that the heat effect is not
serious and whole process can be treated as isothermal
The chemical reaction process on the catalyst is
postu-lated to proceed on the surface of the catalyst by interaction
of the sulfur-bearing molecules and hydrogen atoms formed
through activated absorption of hydrogen molecules. 9 Oil
molecules are more strongly absorbed than hydrogen
mol-ecules, and therefore may preferentially cover part of the
surface, leaving less surface available for dissociation of
hydrogen molecules In the presence of diluent, namely, N 2 ,
it can also compete for free sites on the surface, and
accord-ingly may cause a reduction in the concentration of
hydro-gen on the surface, thus giving the lower rate constant when
working with H 2 −N 2 mixture
Conversion of the sulfur compounds to hydrogen sulfi de
and saturated hydrocarbons occurs by cleavage of the sulfur
to carbon bonds; essentially no C—C bonds are broken
Residuum Desulfurization The H-Oil-process ( Cities Service ) In order to meet the need
for an effi cient method of desulfurizing residual oils with-out the complexities encountered in the myriad of existing
fi xed bed catalytic systems, Cities Service developed what is known as the H-Oil system
Although fi xed bed catalytic reactors had been extensively used for desulfurizing distillate oils, desulfurization of residual oil in a fi xed bed reactor presented several diffi culties:
1) the high temperature rise through the bed tended
to cause hot spots and coking, 2) the presence of solids in the feed and the forma-tion of tar-like coke deposits on the catalyst tended
to cause a gradual build-up of pressure drop over they catalyst bed and
3) because of the relatively rapid deactivation of the catalysts, system shut down for catalyst replacement occurred often, on the order of six times yearly
To overcome these problems an ebbulated bed reactor was designed Figure 3 is a simplifi ed drawing of reactor workings
The feed oil is mixed with the recycle and makeup hydrogen gas and enters the bottom of the reactor It passes
up through the distributor plate which distributes the oil and gas evenly across the reactor
The reaction zone consists of a liquid phase with gas bubbling through and with the catalyst particles suspended
in the liquid, and in random motion It is a back-mixed, iso-thermal reactor, with a temperature gradient between any two points in the reactor no greater than 5F
Due to the catalyst suspension in liquid phase, cata-lyst particles do not tend to adhere to one another, causing blockage of fl ow Any solids present in the feed pass directly through the reactor Reactor pressure drop is constant One of the more important aspects of the ebbulated bed reactor system is that periodic shutdowns for catalyst replacement is not necessary Daily catalyst replacement results in a steady state activity
perfor-mance with atmospheric and vacuum residuals In addition, investment and operating cost data are shown to illustrate the important effect of feed stock characteristics on overall economics
Cases 1–3 describe processing of three atmospheric resid-ual feeds The Kuwait Residuum treated in case 1 is a high sulfur oil containing relatively low metals content (60 PPM) Therefore, the rate of catalyst deactivation is low and operat-ing conditions are set to minimize hydrocrackoperat-ing and maxi-mize desulfurization In fact, only 2–3% naphtha and 9–10% middle distillate are produced The actual chemical hydrogen consumption is fairly close to the estimated needed to remove the sulfur For many atmospheric residuals which are not too high in metals, this case is typical to give maximum production
of low sulfur fuel oil at minimum conversion and hydrogen consumption
Trang 6In case 2, although metals content is also low (⬃40 PPM),
hydrogen consumption is exceptionally high This is due to
the fact that conversion was not minimized and 7% naphtha
and 13% middle-distillate was produced by hydrocracking
Case 3 is characteristic of high metals content (⬃320 PPM)
oils from that area As noted previously, catalyst deactivation
increases with metals content Therefore, catalyst addition rates
are higher, resulting in increased operating costs To compensate
for the reduced catalyst activity, higher operating temperatures and/or residence times are used
Cases 4–6 summarize vacuum residua operations Desulfurization rates for vacuum residua are lower than for atmospheric The asphaltenes and metallic compounds reside
in the vacuum residuum, consequently increasing catalyst deactivation rates and therefore catalyst costs per barrel In all the cases depicted (4–6) hydrogen consumption, relative
FRESH CATALYST
REACTOR II REACTOR
I
FEED OIL
MAKE-UP
HYDROGEN
RECYCLE HYDROGEN
THE H-OIL PROCESS
LIQUID PRODUCT
FIGURE 3
TABLE 2 H-OIL desulfurisation of atmospheric and vacuum residuals Type-Feed (A-atmos) (V-vacuum) Case 1A Case 2A Case 3A Case 4V Case 5V Case 6V
Source Kuwait W Texas Venezuela Kuwait W Texas Venezuela
Consumption (SCI-/BBL)
Trang 7FLASH DRUM
LOW SULFUR FUEL OIL
MID-DISTILLATE
GASOLINE HYDROGEN
REDUCED CRUDE FEED
REACTOR
GASES RCD ISOMAX
FIGURE 4
WHOLE
CRUDE
(117, 000 BPSD)
TWO STAGE DESALTER
(50,000 BPSD)
REACTOR 650°F+
ATMOSPHERIC CRUDE DISTILLATION
HYDROGEN
FRACTIONATOR
C4
0.1% SULFUR MID DISTILLATE
1% SULFUR FUEL OIL
(40,000 BPSD)
TO SULFUR RECOVERY
350°F - (30,300 BPSD)
350–650°F - (36,400 BPSD)
RDS ISOMAX
FIGURE 5
Trang 8WHOLE CRUDE
(100,000 BPSD)
TWO STAGE DESALTER
CDS ISOMAX REACTOR
HYDROGEN
CDS ISOMAX
SYNTHETIC CRUDE FRACTIONATOR
0.1% SULFUR MIDDLE DISTILLATE (29,600 BPSD)
1% SULFUR FUEL OIL (40,000 BPSD)
C5
C4
FIGURE 6
REACTORS
FEED
FURNACE RECYCLE HYDROGEN
ABSORBER
HIGH PRESSURE
LOW PRESSURE SEPARATORS
TO GAS RECOVERY LIGHT GASOLINE HEAVY NAPHTHA
LIGHT GAS OIL
650°F+ BOTTOMS (1% S)
HDS
H2
FIGURE 7
Trang 9to that needed for desulfurization, is high indicating that high
sulfur content of feed precludes setting of operating
condi-tions to minimize conversion In fact, naphtha production
ranges from 7–15%, mid-distillates from 15–23%
The Isomax processes A broad spectrum of fi xed bed
desulfurization and hydrocracking processes are now in
oper-ation throughout the world They are characterized by their
ability to effectively handle a wide range of crude feedstocks
In addition, some of the processes are capable of directly
desul-furizing crude oil while others treat only residual stocks
Rather than discuss each process individually, a
compar-ative summary of the major ones is presented in Table 3
There are many other processes which in one way or
another effect a reduction in the amount of sulfur burned
in our homes and businesses All of them use some type
of proprietary catalytic system, each with its own peculiar
optimum operating ranges with regard to feed composition
and/or reactor conditions
The hydrodesulfurization process is still relatively
expensive (in 1989 more than 75¢/BBL) by petroleum
pro-cessing standards The capital investment for large reactors
which operate at high pressures and high temperatures, the
consumption of hydrogen during the processing and the use
of large volumes of catalyst with a relatively short life all
contribute to the costs In addition, processing costs also
depend on the feedstock characteristics
But when one considers the awesome annual alternative
of 30 million tons of sulfur dioxide being pumped into the
atmosphere, the cost seems trifl ing indeed
Desulfurization of Natural Gas
Approximately 33% of the natural gas in the United States
and over 90% of that processed in Canada is treated to
remove normally occurring hydrogen sulfi de The recovered
sulfur, which now accounts for about 25% of the free world’s
production is expected to increase in the future
Current processes may be classifi ed into four major categories:
1) Dry Bed—Catalytic Conversion, 2) Dry Bed—Absorption—Catalytic Conversion, 3) Liquid Media Absorption—Air Oxidation, 4) Liquid Media Absorption—Air Conversion
Dry bed catalytic conversion ( the Modifi ed Claus
Process ) The Modifi ed Claus Process is used to remove
sulfur from acid gases which have been extracted from a main sour gas stream The extraction is done with one of the conventional gas treating processes such as amine or hot potassium carbonate
The process may be used to remove sulfur from acid gas streams containing from 15 to 100 mole % H 2 S The basic schemes use either the once through process or the split stream process Figure 8 shows fl ow characteristics of the once-through scheme, which in general gives the high-est overall recovery and permits maximum heat recovery at a high temperature level
Split stream processes are generally employed where H 2 S content of the acid gas is relatively low (20–25 mole %) or when it contains relatively large amounts of hydrocarbons (2–5%)
Pertinent design criteria for dry bed catalytic conversion plants include the following:
1) Composition of Acid Gas Feed, 2) Combustion of Acid Gas, 3) For a Once-Through Process, Retention Time, of Combustion Gases at Elevated Temperatures, 4) Catalytic Converter Feed Gas Temperature, 5) Optimum Reheat Schemes,
6) Space Velocity in the Converters, 7) Sulfur condensing Temperatures
TABLE 3 Process RCD Isomax RDS Isomax CDS ISomac HDS Licensers UOP Chevron Chevron Gulf R & D General feed type Atmospheric Atmospheric Whole crude Residuum
Feed characteristics
Name Kuwait Arabian light Arabian light —
Process diagram Figure 4 Figure 5 Figure 6 Figure 7
Fuel oil product
Quantity (BPSD) 40,000 40,000 40,000 40,000
Economies (Relative)
Operating costs b 51 40–60 40–60 —
a Includes only cost for Isomax reactor/distillation and auxiliary equipment.
b Includes utilities, labor, supervision, maintenance, taxes, insurance, catalyst, hydrogen, etc.
Trang 10ACID GAS
AIR
2nd HOT GAS BYPASS 1st HOT GAS BYPASS
MODIFIED CLAUS PROCESS
TAIL GAS
LEGEND
B+RC - BURNER + REACTION CHAMBER
WHB - WASTE HEAT BOILER
R - CATALYTIC CONVERTOR
C - CONDENSER
SL - LIQUID SULFUR
SL
SL
SL
C1
C2
FIGURE 8
SWEET GAS
WASTE GAS
LIQUID SULFUR AS
AIR
SOUR GAS
LEGEND
R - ZEOLITE BED ABSORBERS
C1 - SULFUR CONDENSER
C2 - ARIAL COOLER
AS - ACCUMULATOR/SEPARATOR
B - SULFUR BURNER
C2
C1
B HAINES PROCESS
FIGURE 9