Jones D.S.J., Pujado P.R. Handbook of Petroleum Processing

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1156 CHAPTER 19

main attraction is its high selectivity in its product make. The most generally accepted

theory for this is the carbonium ion mechanism. It is believed that the carbonium ion

in this cracking mechanism is initiated from an oleﬁn’s early contact with the catalyst

at the high riser temperature condition. Once formed the ion reacts to:

Crack larger molecules to smaller ones

React with other molecules

Isomerize

React with the catalyst to terminate a chain

The cracking reaction then tends to follow the following route where the C

C bond

in the β position relative to the carbonium ion is severed to form the oleﬁn and the

reactive positively charged ion. This is illustrated as follows:

C C C C C C

⏐

--->

C C C R C C C

Carbonium ion Olefin Carbonium ion

The oleﬁn may form new carbonium ions while the R ion reacts to form secondary

and tertiary carbonium ions. The tertiary ion is the more stable, and is probably the

more active in this cracking mechanism. A more detailed account of this mechanism

is provided by Venuto P.B. and Habib E.T. in their paper “Catalyst–feed stock—

engineering interactions in Fluid Catalytic Cracking”.

Formation of coke on the catalyst. The formation of coke on the catalyst is an un-

avoidable occurrence of the catalytic cracking process. The mechanism of the coke

formation is also very complex as was the case in the cracking mechanism itself. It is

likely that coke is formed by the dehydrogenation and condensation of poly aromatics

and oleﬁns. Its deposition on the catalyst however tends to block the active pores

which will reduce the effectiveness of the catalyst. The only recourse to this is to burn

off the coke with air to form CO and CO

. The heat of reaction for this coke burn

off becomes important to the process as it provides the heat of reaction on its transfer

from the regenerator to the reactor riser.

Typical yields and the effect of feedstock types. This item gives typical yield structures

for various FCCU feed stocks and severities of operation. These were based on 100%

zeolite catalyst processes and are included here as a guide to conventional FCCU

process capability.

Note while these data may be used in study work and comparative process analysis,

they should not be used for any deﬁnitive design work. For this deﬁnitive work speciﬁc

licensor data from pilot plant test runs on the design feed stock must be used.

A DICTIONARY OF TERMS AND EXPRESSIONS 1157

Hydrotreated Gas Oil (520–630

◦

Conversion vol% 50 60 70

Yields vol%:

Gas 3.8 4.0 4.2

Propylene 4.3 6.0 8.0

Butylene 6.9 10.0 17.5

Propane 2.5 2.7 3.0

i-Butane 3.6 5.0 7.5

n-Butane 1.5 1.6 1.8

-Naphtha 28.9 31.4 34.6

Light cycle oil 44.5 35.9 26.0

Heavy cycle oil 2.2 2.2 2.2

S wt% 1.2 1.2 1.2

Straight Run Diesel (520–650)

Conversion vol% 30 40 50

Yields vol%:

Gas 3.0 3.3 3.9

Propylene 3.0 4.2 6.0

Butylene 5.5 6.1 8.4

Propane 2.0 2.4 2.8

i-Butane 2.4 3.8 5.2

n-Butane 1.3 1.4 1.6

-Naphtha 17.5 20.0 23.0

Light cycle oil 68.5 54.5 49.0

Heavy cycle oil 2.8 2.8 2.8

S wt% 1.4 1.4 1.4

Hydrocracker Gas Oil (650–750

◦

)

Conversion vol% 70 80 90

Yields vol% :

Gas 4.2 4.8 5.0

Propylene 8.0 10.0 13.0

Butylene 15.0 24.0 41.0

Propane 3.1 3.5 3.9

i-Butane 7.0 9.0 12.0

n-Butane 1.5 1.8 2.3

-Naphtha 40.0 49.5 52.0

Light cycle oil 23.0 16.0 9.0

Heavy cycle oil 3.0 3.0 3.0

S wt% 1.1 1.1 1.1

1158 CHAPTER 19

Hydrotreated Visbreaker Gas Oil (380–650

◦

Conversion vol% 60 70 80

Yields vol% :

Gas 3.0 3.6 4.0

Propylene 3.8 5.0 6.8

Butylene 5.0 6.8 8.0

Propane 2.0 2.3 3.0

i-Butane 2.6 4.0 6.0

n-Butane 1.6 1.8 1.9

-Naphtha 50.0 53.0 60.0

Light cycle oil 37.0 28.5 18.5

Heavy cycle oil 2.0 2.0 2.0

S wt% ←−−−−−−− Neg−−−−−−−−→

Fired heaters

Generally ﬁred heaters fall into two major categories:

Horizontal type

Vertical type

The horizontal type heater usually means a box type heater with the tubes running

horizontally along the walls. Vertical type is normally a cylindrical heater containing

vertical tubes. Full details of both these heater types are given in Chapter 18.

Horizontal box types are preferred for crude oil heaters, although vertical cylindrical

have been used in this service. Vacuum unit heaters should have horizontal tubes

to eliminate the static head pressure at the bottom of vertical tubes and to reduce

the possibility of two-phase slugging in the large exit tubes. Occasionally, several

different services (“coils”) may be placed in a single heater with a cost saving. This

is possible if the services are closely tied to each other in the process. Catalytic

reforming pre-heater and re-heaters in one casing is an example. Reactor heater and

stripper reboiler in one casing is another example. This arrangement is made possible

by using a refractory partition wall to separate the radiant coils. The separate radiant

coils may be controlled separately over a wide range of conditions by means of their

own controls and burners. If a convection section is used, it is usually common to the

several services. If maintenance on one coil is required, the entire heater must be shut

down. Also, the range of controllability is less than with separate heaters.

Each of these types may be shop fabricated if size permits. Shop fabrication reduces

costs. However, shop fabrication should not be forced to the extent of getting an

improperly proportioned heater.

A DICTIONARY OF TERMS AND EXPRESSIONS 1159

As ﬁred heaters have a live source of energy they are designed and manufactured to

strict codes. Details of these are also given in Chapter 18. These codes set the param-

eters for heater tube thickness, tube, and heater dimension, Inspection requirements,

and ﬁre protection.

Thermal rating. Thermal rating of ﬁred heaters is a complicated and specialized

procedure. While this procedure is described in Chapter 18 it is not detailed. For most

basic design and evaluation studies the following rules of thumb may be used:

Btu/hr sqft

Horizontal, ﬁred on one side 8,000–12,000

Vertical, ﬁred on one side from bottom 9,000–12,000

Vertical, single row, ﬁred on both sides 13,000–18,000

Heater efﬁciency. The efﬁciency of a ﬁred heater is the ratio of the heat absorbed

by the process ﬂuid to the heat released by combustion of the fuel expressed as a

percentage.

Heat release may be based on the LHV (Lower Heating Value) of the fuel or HHV

(Higher Heating Value). Process heaters are usually based on LHV and boilers on

HHV. The HHV efﬁciency is lower than the LHV efﬁciency by the ratio of the two

heating values.

Heat is wasted from a ﬁred heater in two ways:

with the hot stack gas

by radiation and convection from the setting

The major loss is by the heat contained in the stack gas. The temperature of the stack

gas is determined by the temperature of the incoming process ﬂuid unless an air pre-

heater is used. The closest economical approach to process ﬂuid is about 100

◦

F. I f

the major process stream is very hot at the inlet, it may be possible to ﬁnd a colder

process stream to pass through the convection section to improve efﬁciency, provided

plant control, and ﬂexibility are adequately provided for. A more common method

of improving efﬁciency is to generate and/or superheat steam and preheat boiler feed

water. The lowest stack temperature that can be used is determined by the dew point

of the stack gases. The ﬁgures in Chapter 18 may be used to estimate ﬂue gas heat

loss. Heat loss from the setting, called radiation loss, is about 1

to 2% of the heat

release.

The range of efﬁciencies is approximately as follows:

Very high −90%+. Large boilers and process heaters with air pre-heaters.

High −85%. Large heaters with low process inlet temperatures and/or air pre-heaters.

1160 CHAPTER 19

Usual—70–80%.

Low—60%.

Burners. The purpose of a burner is to mix fuel and air to ensure complete combustion.

There are about 12 basic burner designs. These are:

Direction —vertical up ﬁred

vertical down ﬁred

horizontally ﬁred

Capacity —high

low

Fuel type —gas

oil

combination

Flame shape —normal

slant

thin, fan-shaped

ﬂat

adaptable pattern

Hydrogen content —high

Excess air —normal

low

Atomization —steam

mechanical

air assisted mechanical

Boiler types

Low NO

High intensity

Various combinations of the above types are available.

Details of gas, oil, and combination burners are given in Chapter 18, together with

burner controls and heater noise.

Chapter 18 under the section on ﬁred heaters continues with a description and dis-

cussion on refractories, stacks, and stack emission. Finally the chapter describes the

speciﬁcation for a typical ﬁred heater.

Flash points

The ﬂash point is a measure of the tendency of the, material to form a ﬂammable

mixture with air under controlled laboratory conditions. It is however only one of

several properties that must be considered in assessing the overall ﬂammable hazard of

A DICTIONARY OF TERMS AND EXPRESSIONS 1161

the material. The ﬂash point is used to establish the ﬂammable criteria in transporting

the material. Generally shipping and safety regulations will be based on the ﬂash point

criteria. The ﬂash point should not however be used to describe or appraise the ﬁre

hazard or risk under actual ﬁre conditions. Test method (D93 provides the closed cup

ﬂash point test procedures for temperatures up to 698

◦

F). Details of the apparatus

used and the laboratory method for determining a ﬂash point is given in Chapter 16

of this Handbook. The ﬂash point of two or more blended components is determined

by the volume composition of the components in the blend and the use of the ﬂash

point index curve. This method and the index curve is given in Chapter 1 of this

Handbook. A simple estimate of a material’s ﬂash point can be calculated from its

ASTM distillation by the equation:

Flash Point

◦

F = 0.77(ASTM 5% − 150

◦

F).

Flash zone

A ﬂash zone is associated with the distillation of crude oil, both atmospheric and

vacuum, the main fractionating towers of the ﬂuid catalytic cracking unit, visbreaker

or thermal cracking units. The ﬂash zone is the area in these distillation towers where

the distillate vapors are allowed to separate from the un-vaporized liquid. The transfer

line from the heater enters the ﬂash zone. The vapors rise up through the tower to be

condensed by cold reﬂux streams coming down. Steam enters the ﬂash zone from the

bottom product stripper section located below the ﬂash zone.

Flash zone conditions, particularly ﬂash zone temperature is difﬁcult to measure

accurately. This is due to the proﬁles set up in the ﬂash zone by turbulence of the

feed entering and vapor disengaging. Knowledge of ﬂash zone conditions is, however,

essential when designing these units, evaluating their performance or trouble shooting

them. The item in Chapter 3 of this Handbook deals with a calculation procedure to

establish these ﬂash zone conditions for atmospheric and vacuum distillation crude

distillation towers.

Fractionation

This is a unit operation in chemical engineering which separates components from

mixtures in which they are contained. In petroleum reﬁning this separation process is

a major means of separating precise groups of petroleum components from the crude

oil feed and other intermediate reﬁning processes. Separation by fractionation is

accomplished by heat and mass transfer on successive stages represented by carefully

designed trays. These trays are designed to enhance the heat and mass transfer by good

mixing of hot vapors rising through the trays with colder liquid entering the tray. The

mixing tends to achieve a phase equilibrium between the liquid and vapor trafﬁc.

1162 CHAPTER 19

Fractionation as a separating tool is used extensively throughout the process industry.

It can be a simple process separating just two components (such as water and alcohol)

of very complex separation of multi components. It is the later that is required in the

petroleum processing industry. The calculation of the number of stages required for

the simple binary fractionation can be accomplished graphically using the McCabe

Thiele diagram, the number of stages required for the multi-component separation

is achieved by using a number of complex equations, and the individual equilibrium

constants for the various components. The rigorous method for calculating the number

of fractionation stages in multi component separation is by stage to stage calculation

with ‘trial and error’determination of the temperature and pressure conditions on

each stage. The calculation is complete when convergence of phase equilibria is met

on the feed input stage. This is the method used in developing the computer simulation

program for multi-component fractionation.

The method is simpliﬁed for manual computation by a correlation developed by

Gilliland (reference Maxwell’s Data Book on Hydrocarbons). This is a corre-

lation which relates minimum stages at total reﬂux to minimum reﬂux at inﬁ-

nite number of stages. Figure 4.2, Chapter 4, is reproduced below to show this

correlation.

The Gilliland correlation for calculating theoretical trays.

A DICTIONARY OF TERMS AND EXPRESSIONS 1163

Where:

N = actual number of trays.

= minimum number of stages at total reﬂux.

R = actual reﬂux

= minimum reﬂux at inﬁnite number of stages.

There are two equations that deﬁne the items R

and N

these are:

The Fenske equation which is used to calculate the minimum trays at total reﬂux.

m+1

= Log



Lt Key

Hy Key





Hy Key

Lt Key





÷ Log φ

Where:

= minimum number of theoretical strays at total reﬂux. The + 1isthe

reboiler which is counted as a theoretical tray

LT Key = is the mole fraction of the selected light key

HY Key = is the mole fraction of the selected heavy key

D = fractions in the distillate product

W = fractions in the bottom product

φ = KLt Key/Khy key

KLt key = the equilibrium constant of the light key at mean system condition of

temperature and pressure

KHy key = the equilibrium constant of the heavy key again at mean system con-

ditions

The Underwood equation which establishes the minimum reﬂux at inﬁnite stages.

The Underwood equation is more complex than the Fenske equation and requires

trial and error method for its solution. The equation itself is in two parts. The ﬁrst

looks at the vapor volatility (ratio of K’s) of each component in the feed to one of

the selected keys. Then by trial and error arriving at an expression for a factor ‘B’

that forces the equation to zero.

This ﬁrst equation is written as follows:

(φi)(X

F )

F − B

= 0

= is the relative volatility of component i

F = is the mole fraction of component i in the feed

B = is the factor that forces the sum of the expression for each component to

zero

1164 CHAPTER 19

The second equation uses the Factor B calculated from the ﬁrst equation to determine

the minimum reﬂux. This equation is

m+1

(φ

)(X

D − B

where

φi = is the relative volatility of component i

D = is the mole fraction of component i in the distillate

B = is the factor obtained from ﬁrst equation

= minimum reﬂux at inﬁnite trays (R

m+1

include the reboiler)

R is taken as 1.5 × R

while N is taken as 1.5 × N

Fractionation in the atmospheric and vacuum crude distillation towers

The method of Gilliland is impractical for use in the complex fractionation that is

experienced in the main reﬁnery towers handling the crude feed and other similar

streams in the reﬁning process. Packie J.W. developed an empirical method based on

ASTM distillation gaps to deﬁne the fractionation between adjacent cuts. This degree

of fractionation is measured by the temperature difference between the ASTM 95% of

the lighter cut and the 5% temperature of the adjacent heavier cut. These differences

can be positive or negative. That is the 5% temperature of the heavier cut can be

higher than the 95% temperature of the lighter cut. This difference is called an ASTM

Gap. On the other hand some adjacent cuts may demonstrate the reverse that is the

5% temperature of the heavier cut may be lower than the 95% temperature of the

lighter cut. This difference is called an ASTM Overlap. Thus in a typical crude unit

speciﬁcation the fractionation may be quoted as follows:

The fractionation in the crude atmospheric distillation tower shall be:

95% naphtha ASTM temperature and the 5% temperature of the kero shall have a gap

of 25

◦

95% kero ASTM temperature and the light gas oil 5% temperature shall have a gap

of 0

◦

95% LGO ASTM temperature and the heavy gas oil 5%temperature shall have an

overlap of no more than 15

◦

F(a–15

◦

F gap).

The number of the fractionation trays required to meet the respective fractionation gaps

(overlaps) between cut draw-off in these main columns is based on a correlation. This

correlation is a series of curves based on the 50% distillation temperature difference

between the total vapor entering the draw off tray and the liquid leaving the tray. There

are two sets of these curves, the ﬁrst with steam present and the second based on no

100

150

200

250

1 FOR OVHO-TCP SIDESTREAM ONLY

NOTE: REFLUX RATIO-GALS HOT OVERFLOW/TO T. GALS

PRODUCT VAPORS ENTERING TOP PLATE.

2 SOLID CURVES FOR NO STEAM- DOTTED CURVES

FOR MAX. STRIPPING STEAM GENERALLY USED

3 NUMBERS ON CURVES REPRESENT OF DIFF. IN 50%

DISTILLATION POINTS BETWEEN OVHO AND TOP 55.

100

908070605040302010

FRACTIONATION: 1% –15% DISTILLATION POINTS

F REFLUX RATIO % NUMBER OF PLATES

Fractionation Curves for Overhead to Top Sidestream Products.

−10−20−30−40−60

100

150

200

300

350

200

250

1 FOR SIDESTREAM–SIDESTREAM ONLY

NOTE: REFLUX RATIO-GALS HOT OVERFLOW/TO T. GALS

PRODUCT VAPORS ENTERING TOP SS DRAW OFF PLATE.

2 SOLID CURVES FOR NO STEAM STRIPPING–DOTTED

CURVES FOR MAX. STRIPPING STEAM GENERALLY USED

3 NUMBERS ON CURVES REPRESENT-OF DIFF. IN 50%

DISTILLATION POINTS BETWEEN TOTAL PROD. VAPORS

ENTERING THE UPPER SIDESTREAM DRAW OFF PLATE

AND LIQUID DRAWN OFF AT LOWER SIDESTREAM

100

908070605040302010

FRACTIONATION: 5% –95% DISTILLATION POINTS

Fractionation Curves for Sidestream to Sidestream Products.

−10−20−30−40−60

ASTM gaps and overlaps.

1165