Introduction to Petroleum Refinery Oil

8/10/2019 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

-

.

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.

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Introduction to Petroleum Refinery Oil

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