Introduction to Petroleum Refinery Oil
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Transcript of Introduction to Petroleum Refinery Oil
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5
FUELS
HYDROTREATING
INTRODUCTION
Hydrotreating is a process which improves the quality of a variety of petroleum
stocks by treating with hydrogen in the presence of a catalyst. Hydrotreating may
be applied to a variety of solvents, distillate fuels and residual fuels. When
referring to residual fuels, the process is termed Hydro-desu lfurization (HDS)
since the sole object is sulfur removal. W hen treating other stocks , the process
is referred to as Hydrofm ing. When treating stocks other than residual fuels,
depending on the precise feed and purpose of the opera tion, Hydrofining will
improve the odor, color, stability, combustion characteristics and other important
quality characteristics. It also removes sulfu r, nitrogen and other nonhydrocarbon
components. When applied to catalytic cracking feed stocks, Hydrofining
significantly improves cracking quality. Carbon y ield is reduced, gasoline yield
is increased, and the quality of the catalytic cracking products is significantly
better. The need for low sulfur residual fuel oils to alleviate the air pollution
problem has led to the development of the required hydrotreating technology. The
subsequent chapter describes the Hydrotreating process.
THE
HYDROTREATING PROCESS
Figure
1
shows a schematic diagram of a Hydrotreater. Feed stock is mixed with
a hydrogen containing gas and heated to reaction tempera ture in a furnace and
passed to the top of a reactor
(s).
The reactor
contains
he catalyst in the form of
extrudates or pills. The oil and hydrogen containing gas pass dow nward through
the reactor. Depending upon the feed stock and operating conditions, all of the
oil may be vaporized or as much as
SO-90%
may remain in the liquid phase .
In
6
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Q
2
x
9
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v
w
w
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6 Pressure
Safety Design
Practices
the case of residual fuel oils, the feed rem ains essentially all liquid . The reactor
effluents are cooled and passed to a gas-liquid separator wherein the hydrogen
containing gas is separa ted and recycled to the feed for reuse. The recycled gas
is usually scrubbed to remove the HIS. This is done because of the inhibiting
effect of H,S
on
the kinetics of hydrotreating and also to reduce corrosion in the
recycle circuit. Sometimes, when treating a light stock with a very low sulfur
content, the recycle gas is not scrubbed because the H,S is at an acceptably low
leve l. The liquid is passed to a stripper to remove res idual H,S and other light
gases; then
it
may be fractionated into several cuts. In many cases, the liquid
products are given a light caustic wash to assure com plete removal of H,S. Small
quantities of H,S, if left in the product, will oxidize to free su lfur upon exposure
to air , and will cause the product to exceed corrosion specifications.
The Hydrofining process is actually one of many processes that exist, but
all are very similar in nature.The main difference in the various processes is in
know how . Each process differs by catalysts, equipment and/or m ethods, but
these are ra ther narrow since the general field of hydrogenation is
an
old and well
established art.
Figure
2
shows three different types of reactions that occur during
Hydrofining. Group I shows hydrodesulfurization of four su lfur types:
mercaptans, disulfides, thiophenes and benzothiophenes. The mercaptans and
disulfide types are represenative of a high percentage of the total sulfur in lighter
virgin oils, such as virgin naphtha and heating oil. Thiophenes and
benzothiophenes appear as the predominant sulfur form in heavy v irgin oils and
even more in cracked stocks of all boiling ranges. By a fair margin, thiophenic
sulfur is the hardest to remove.
Group I shows the reactions of oxygen compounds. Phenols (and
thiophenols) occur in catalytic cracking products. Peroxides are often found in
cracked stocks after exposure to air. Oxygen compounds and poor storage
stability go hand in hand. Hydrofining provides stable and clean burning fuels,
and the Hydrofinates are almost always free of oxygen compounds.
While not shown here, Hydrofining also removes nitrogen from various
nitrogen com pounds. Nitrogen is one of the causes of instability. Removal of
nitrogen is much more difficult than sulfur removal.
Group I show s the Hydrofining reactions of a straight chaii monoolefin
and a diolefin. These reactions are typical for all
kinds
of olefins. Diolefins and
certain o r all of the cyclic olefins are found to be most reactive with respect to
gum
formation. Thus, Hydrofin ing improves stability by removing (saturating)
reactive hydrocarbons as well as oxygen containing compounds.
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Fuels
Hydrotreating 63
Group ulfur Reduction
Mercaptan RSH +
H
RH + H 2 S
Disulfide
RSSR+ 3&*RH + RH
+ H S
c - c
Benzothiophene
C
/ c
II
C9 C C
+
3H
CH3CH2 C
c cAs/
c+c/c
HZS
Group
amoval
of
Oxygen
Stability
6 Combust ion
Improvomentl
C % + H 2 + C
C H2O
C
R OOH 3H2 RH
+
2HzO
,c*
C OH
C C\&C
Phenol
\
Peroxide
Group aturation o f Olofims
R - C = C + Hz -C-C
R - C
=
C-C
=
C
+
2H2 -C-C-C-C
OiC
igure 2.
Typical
hydrofining
reactions.
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6 Pressure
Safety
Design
Practices
Saturation of o lefins other than reactive olefins usually is not desired. The
added hydrogen is often expensive or useful elsew here, and it does not provide
any real improvement in product quality. Actually, product quality may be
reduced in the case of gasolines. Research octane number losses may be
correlated with increasing olefin saturation.
So
in many cases,
hydrodesulfurizationconditions are selected with an eye tow ard minimizing olefin
saturation over and above that needed for product quality improvem ent. There
is one exception: saturation of certain olefins show s substantial improvem ents in
Motor octane number. This is true for iso- and n-pentenes and to a lesser extent
for higher boiling isoolefins. The higher n-olefins show octane losses upon
saturation.
The ranges of operating conditions that are used in Hydrotreating vary
sigruficantly m an ly because of the very broad application of Hydrotreating. The
ranges are wide due in part to the fact that light products such as naphthas require
much lower treating severity than that required to desulfurize gas oils o r residual
fuel oils. W ithin a given boiling range, say heating oil, treating conditions can
vary dependmg on the nature of the stock, virgin or cracked, and the specific
purpose of the Hydrofining operation, sweetening, deep desulfurization, or
improvement in burning characteristics (lowering carbon residue on 10
bottoms). When treating virgin naphtha, for example, 99 desulfurization can
be obtained at conditions of 550 F, 4 V/hr/V feed rate, 400 psig and IO00
SCF/B treat gas. These same conditions applied to diesel oil would give only
about 25 desulfurization although the carbon residue would show adequate
improvement. Additionally, if the temperature for the diesel oil were increased
to 700 F, which is approaching the maximum allowable from a catalyst
deactivation standpoint, the desulfurization would be about 8 (the other
conditions being held constant).
The discussion that follows will show the effects of several operating
variables on product inspections. The effects of the variables are illustrated best
by deep desulfurization of heavier gas oils.
Effect of Feed Rate: The effect of feed rate on hydrodesulfurization of
vacuum gas oil is shown in Figure
3.
Halving the feed rate in this range
approximately halves the product su lfur.
Effect
of
Pressure: Figure
3
shows the effect of pressure on product sulfur.
In the 400-800 psig range, doubling the pressure reduces the product sulfur by
about one third. Pressure also has an effect on catalyst life. In genera l, as the
pressure is increased the catalyst deactivates at a lower rate. H owever, beyond
a certain point, further increases in pressure have only a small effect on
deactivation rate. An example of this is for atmospheric resids; typical data
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Fuels
Hydrotreathg
65
Figure
3. Effect of feed rate on product
sulfur.
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66 hessure Safety Design Practices
indicate about the same deactivation rate at pressures of 800 psig and higher
(such stocks are not processed below 800 psig).
Effect of Hydrogen Concentration:The effect of hydrogen concentration
is very similar to the effect of total pressure, i.e., increasing hydrogen
concentration increases the sulfur reduction. Hydrogen partial pressure (total
pressure multiplied by hydrogen concentration) correlates the data quite well.
However, there appears to be an effect of concentration over and above its factor
in partial pressure. High hydrogen concentrations, like high total pressure,
improve catalyst life.
Effect
of
Treat Gas Rate: Treat gas rate is usually expressed as SC F/B at
the reactor inlet. Very low rates provide inferior resuits and probably shorten
catalyst life. Above about 1.5-3 MSCFlB, changes in rate do not usually change
results. The effects of gas rate, if any, are probably related to a reduction in
hydrogen concentration as the gas passes through the reactor. The reaction
consumes hydrogen and manufactures light hydrocarbon diluents. At high gas
rates, changes in concentration are quite small and indiscernible. At low gas
rates, serious drops in hydrogen concentration occur and product sulfur rises
because of this loss in concentration as shown earlier. The effect of gas rate is
also probably related to the reduction in H,S concentration as gas rate is
increased. Hydrogen sulfide is a product of the hydrodesulfurization reactions
and has an inhibiting effect. Since the H,S formed is fixed, the concentration falls
off as the gas rate increases.
Effect of H,S, Carbon Oxides Etc.: Hydrogen sulfide in the treat gas has
an inhibiting effect on the kinetics of hydrotreating. Being a product of the
desulfurization reactions, H,S must diffuse from the catalyst surface into the bulk
gas stream. Any H,S present beyond that formed, further slows dow n the rate of
diffusion with a consequent decrease in the amount of desulfurization for a given
amount of catalyst. Therefore, additional catalyst would be required.
The H,S can be removed by a process such as MEA scrubbing of the treat
gas. However, the economics must be justified for each case.
Carbon monoxide has been found to poison cobalt molybdate catalysts. It
causes not only instantaneous deactivation but a cum ulative deactivation as well.
It should be removed from treat gas entirely or at least reduced to a very low
value. Carbon dioxide also must be rem oved since it is converted to
CO
in the
reducing atmosphere employed in Hydrofining. Liquid water can damage the
structural integrity of the catalyst. Water, in the form of steam does not
necessarily hurt the catalyst. In fact
30
psig steamlair mixtures are used to
regenerate the catalyst. Also, steam appears to enhance the catalyst activity in
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Fuels
Hydrotreating 67
residual fuel oil desulfurization.
The presence of oxygen in treat gas would be expected to be
innocuous,
since it would be expected to combine with hydrogen and form water upon
contact with the catalyst. However, the presence of oxygen does degrade product
color and should be removed where color is important, for example, kerosenes,
gasoline, etc. The oxygen also may catalyze polymerization reactions in the
preheat circuit and some
o this
polymer may pass through the reactor and
degrade product color.
Effect
of
Catalyst:
The catalysts used in hydrotreating are: molybdena on
alumina, cobalt molybdate on alum ina, nickel molybdate on alumina o r nickel
tungstate. Which catalyst is used depends on the particular application. Cobalt
molybdate catalyst is generally used when sulfur removal is the primary interest.
The nickel catalysts find application in the treating of cracked stocks for olefin
or aromatic saturation. One preferred application for molybdena catalyst is
sweetening, (removal o mercaptans). The molybdena on alumina catalyst is also
preferred for reducing the carbon residue of heating oils.
APPLICATIONS
OF HYDROFINING
As mentioned earlier, Hydrofining may
be
applied to a host of products to
improve their quality. Subsequent paragraphs will show the results that can be
obtained.
Virgin
Naphtha
Hydrofining is applied to virgin naphthas mainly in the form of a pretreatment
step for the feed to catalytic reform ers (Powerforming). Sulfur levels of parts
per million (ppm) or less are required to avoid deactivation of the platinum
reforming catalyst.
Virgin naphtha hydrofining processing conditions have been standardized at
550 F, 4 V/hr/V, 300-400 psig and
400-500 SCF/B
of 70 H, treat gas. Such
conditions will make a 4 ppm sulfur product of most stocks of interest.
Cracked Naphthas
On cracked naphthas, Hydrofining provides not only desulfurization, but also
improvements in gum, stability, and engine cleanliness characteristics.
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68
Pressure Safety Design
Practices
Hydrofininghas all the advantages of acid treating without the disadvantages. For
example, acid treating does not readily remove refractory sulfur compounds such
as thiophene; the treated products must be rerun to remove polymers with a
consequent yield loss; and disposal of the acid sludges is a se rious problem.
In treating cracked stocks such as steam cracked naphtha or visbreaker
naphtha, which are highly olefinic in nature , nickel molybdate or nickel tungstate
catalysts are generally employed . These catalysts have much higher activity for
olefin saturation reactions than does cobalt molybdate.
Solvents
Hydrofining has been applied to Varsols and various other solvents for the
control of odor, sulfur, and corrosion characteristics. For exam ple, Hydrofining
of Iranian and K uwait distillates dem onstrated its effectiveness as a means of
producing White Spirit , a high-quality solvent naphtha distributed in the United
Kingdom.
Kerosene
With higher boiling
stocks,
mild Hydrofining of kerosene effects desulfurization,
color improvem ent, and a reduction in wick char. Hydrofining improves odor
and by reducing sulfur content makes the kerosene less corrosive.
It
should also be noted that this process does not alter the smoke point.
Smoke point is a function
of
arom atics content and mild Hydrofin ing does not
hydrogenate arom atics. To accomplish this, treating over a m ore active catalyst
such as nickel tungstate at pressures of a t least
800
psig is required.
Heating Oils
Both virgin and cracked heating oils respond to very mild Hydrofining. The
process provides tremendous improvements
in
odor largely because
of
mercaptan
removal. Color is also improved. As mentioned earlier, Carbon Residue on 10
bottoms is indicative of the burning characteristics of heating oils. Hydrofining
improves not only the CR-10% level, but also the stability. In addition, it has
been found that certain heating oils when blended show incompatibility in CR -
10 .For example, the CR-10% of a blend can
be
higher than that on either
component of a two component blend. Hydrofining corrects this incompatibility
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Fuels Hydrotreating 69
problem.
Diesel Fuel
Hydrofining is employed to desulfurize high sulfur diesel stocks , both virgin and
cracked. The stability of cracked diesel stocks is also improved. In the diesel
range, operating conditions become more severe. Compared to naphthas,
temperatures are increased from the 550-600F level to 700F .
Conventional Hydrofining of diesel oils does not improve octane number
because octane number improvement, like smoke point improvement in
kerosenes, requires saturation of aromatics. Higher p ressures are needed to gain
appreciable aromatics saturation and cetane number improvem ent.
Heavy
Gas
Oils and Residual Oils
Hydrofining is also applicable to heavy atmospheric gas oils , atmospheric residua
and vacuum gas oils. For the latter two stocks, the process is usually referred to
as hydrodesulfurization rather than hydrofin ing. Hydrotreating of the gas oils
(atmospheric and vacuum) improves their catalytic cracking characteristics and
also produces low sulfur fuel oil blending stocks. The hydrotreating of
atmospheric residua is done strictly for the purpose of producing a low sulfur fuel
oil. In treating these stocks, substantially more severe conditions are required
than for the lighter stocks previously discussed. Tem peratures up to 76 0F are
employed at pressures of 800 psig and higher. Feed rates can be as low as
0.2
0.3
V/hr/V . Further, catalyst regeneration is required due to the fouling which
occurs at these severe conditions. With some atmospheric residua, the fouling of
catalyst is severe enough to preclude regeneration for future reuse. In such cases
the entire catalyst charge is replaced at the end of each cycle.
It should be noted that the atmospheric residuum has a very high metals
content,
320
ppm. This
is
a major fac tor in the difficulty of desulfurizing such
stocks. Middle East residua can be fairly easily desulfurized to the 75-80% level
at similar conditions. Even though the feed sulfur levels for M iddle East stocks
are higher (ca
4-4.5
w t
sulfur), the metals level is lower (ca 100 ppm ).
Hydrotreating reduces the sulfur, nitrogen, aromatic rings and Conradson
carbon. The effect of this is to increase the gasoline yield in cat cracking and
reduce the coke deposited on the cat cracking catalyst.