1. Heat integration projects for
refining processes
Heat integration projects can deliver substantial savings, but they require
detailed simulation and case-specific heat integration analysis
ALis¸AN DOg˘AN
Turkish Petroleum Refineries Corporation
Refining is a complex operation
involving many kinds of
processes. All these processes
have different principles; some
involve fractionation, some involve
different reactions and some have
both. All these processes have one
thing in common: they need
energy. It may be a need to heat
“cold streams”: energy to make the
required separation between cuts,
energy to strip off unwanted gases,
energy to perform a reaction and so
on. The processes also have ener-gy-
giving streams (hot streams):
column pumparounds, overhead
streams, reactor effluents and so
on, which are available to supply a
portion of the necessary heat;
furnaces burning fuel take care of
the rest. Some processes are inte-grated;
the product or residue of
one process may be the feed to
another. The better the heat integra-tion
in or between process units,
the less fuel is burned in furnaces,
which leads to more profit. In this
article, the basics of heat integration
studies performed in various heat
integration projects for different
refinery process units are consid-ered.
The methods, equipment and
approaches used for heat integra-tion
(pinch) studies of various
refining processes, their similarities
and differences are discussed.
In order to make a pinch study of
an existing unit, one should first
define the overall picture, which is
the energy balance and the temper-ature
profile of all the related cold
and hot streams. The heating cool-ing
curves and potentials saving
should be determined. A test run
performed in the unit will give all
the necessary information, such as
flow rates, temperatures and lab
results. Based on this test run, a
simulation model of the unit should
be made. For a start, only the heat
exchanger network consisting of
simple heat exchanger models may
be enough to define the overall heat
balance. However, when it comes
to adding equipment, making accu-rate
cost estimations and defining
design data for retrofits and new
equipment, a unit model with
rigorous heat exchangers, columns
and other equipment will be neces-sary.
Furthermore, a complete unit
model will let you find additional
and more accurate saving opportu-nities
through case studies and
trial-and-error studies. At the end
of the day, it is all about making
the necessary investment in an
existing unit to gain air- or water-cooled
waste heat to decrease
furnace loads or generate steam.
Case studies will be necessary to be
able to select the best investment
option. When deciding on the
design data of new equipment and
retrofits, rating them with a second
set of simulation data representing
the unit (or units) will be wise in
order to select the equipment based
on a range of operations.
Main steps to making a detailed
heat integration engineering study
are given below. The procedure
may change from study to study,
but the principles remain the same:
• Rigorous simulation modelling of
the existing unit or units within the
boundary
• Formation of base case heating –
cooling composite curves
• Determination of base case mini-mum
approach temperature and
potential savings
• Determination of possible retrofit
paths to achieve potential savings
• Making the necessary equipment
additions to the unit model and
simulating the new retrofit paths
• Repeating the first five steps for
another base case simulation
model, preferably a case at the
opposite end of the operation
envelope
• Rating the equipment to supply
the needs of both operation cases
• Determination of investment
costs and benefits of all the differ-ent
saving opportunities (options)
• Selecting the most appropriate
case
• Extracting the process data neces-sary
for new equipment design.
Savings may be further increased
during the latter simulation stages
by changing/shifting reflux duties
and operation variables.
Heat integration studies
performed on different refining
units will now be discussed, taking
into account similarities and differ-ences
in the approaches and their
effects.
Crude and vacuum distillation
processes
The first important step for a heat
integration study of a crude distil-lation
unit is drawing the
boundary: is the unit integrated
with the vacuum unit and, if not,
should it be? Integrating a crude
unit with the downstream vacuum
unit is, most of the time, more prof-itable.
Even if they are not
integrated, the overall boundary
should be drawn to include the
vacuum side — the atmospheric
residue (vacuum charge) preheat-ing
train.
www.eptq.com PTQ Q4 2013 113
2. residue preheating should be
included in the heat integration
study when drawing boundaries.
Including only the crude unit will
prevent one from seeing the poten-tial
modifications, retrofits and
benefits, which result in hotter
atmospheric residue going to the
vacuum unit.
Figure 2 is the composite curve
for the CDU unit in Figure 1, which
is not integrated with the VDU. The
hot-side pinch point is 129°C and
the atmospheric residue outlet from
crude preheating is at 127°C.
Therefore, the atmospheric residue
temperature is at the closest point
to the heating curve of the cold
streams. The minimum temperature
difference (DTmin) between the
curves is 30°C. Although there is 44
Gcal/h of waste heat, the saving
potential is limited to 7 Gcal/h
even when you target a minimum
temperature difference of 10°C,
which is very hard to achieve.
The reason for this is that if you
bring only the CDU into the
picture, it is not possible to gain
substantially from the waste heat
and keep the atmospheric residue
temperature close to 129°C at the
same time.
However, when atmospheric resi-due
preheating in the VDU is
brought into the picture, there is no
need to keep the atmospheric resi-due
temperature close to the cold
curve, because it is a cold stream
that is heated by VDU hot streams.
Sending atmospheric residue hotter
to the VDU is desirable, therefore a
potential is generated even when
the two units are not integrated. If
the units are to be integrated, the
potential is much higher.
Atmospheric residue will then be
going to the VDU furnace directly
in its hottest form, and the VDU
hot streams will be used in crude
heating (see Figure 1).
When atmospheric residue
preheating is added within the
boundaries, DTmin automatically
increases to 46°C, creating a poten-tial
of 15 Gcal/h for DTmin = 10,
already doubled even though the
same atmospheric residue tempera-ture
is targeted. The real potential,
in fact, is much higher than this,
considering that there is no
Crude Heating AR Heating
Crude unit
Unintegrated
357ºC 127ºC 300ºC
AR
duty
HVGOPA
duty
Integrated
VR
duty
AR
Crude unit
AR
~357ºC ~357ºC and unit
Figure 1 Drawing the CDU/VDU heat integration boundary
Drawing the boundary
In an integrated CDU/VDU config-uration,
vacuum unit hot streams
are used to heat the crude charge,
and hot atmospheric residue is sent
directly to the vacuum furnace to be
heated. In a non-integrated configu-ration,
atmospheric residue is sent
colder to the vacuum unit after heat-ing
the crude oil. Therefore, in a
non-integrated layout, atmospheric
residue is first a hot stream giving
energy to the crude side, then a cold
stream, which is heated by vacuum
unit hot streams such as the HVGO
pumparound and vacuum residue
run-down. This is an inefficient
design from a heat integration point
HVGOPA
duty
VR
duty
Vacuum
furnace
and unit
Vacuum
furnace
of view. Heat exchanger area is
needed to first cool down the hot
atmospheric residue in the crude
side, and additional area is needed
to heat it in the vacuum side.
Furthermore, the heat that could be
recovered would be higher in the
integrated case, the HVGO pumpa-round
(at high flow) and vacuum
residue (at high temperature) being
able to give more duty to the crude
side and the atmospheric residue
going much hotter to the vacuum
furnace directly from the atmos-pheric
column.
Even if integration of the CDU
and VDU is not desired for a
specific reason, atmospheric
dTmin = 30ºC
Pinch = 99ºC
Pinch = 129ºC
0 50 100 150 200 250
Enthalpy, Gcal/h
600
500
400
300
200
100
Temperature, ºC
0
Figure 2 Drawing the boundary and composite curves
114 PTQ Q4 2013 www.eptq.com
3. constraint on the atmospheric
residue temperature, and even
more when the units are to be
integrated.
In the example below, a heat inte-gration
study performed on another
CDU/VDU unit is explained in
detail. The configuration, number
of pumparound streams, reboiler
hot streams and so on may differ in
different process layouts.
Case 1: CDU/VDU unit
In the integrated unit discussed
below, the preheat train consists of
three different sections. Before the
desalter, the heat required is
provided by the atmospheric
column overhead and some portion
of the diesel pumparound duty.
After the desalter, crude is sepa-rated
into three streams to be
heated by product run-downs, the
diesel pumparound and the HVGO
pumparound. Afterwards, the
combination crude is further heated
by vacuum residue before going
into the atmospheric furnace. The
reboiler and naphtha splitter
reboiler duties are supplied by
HVGO and diesel pumparounds.
The DTmin of the light crude base
case is ~70°C, with nearly 62
Gcal/h of furnace process duty and
42 Gcal/h of wasted “hot stream”
energy.
The main waste heat streams in
this configuration are as follows:
• HVGO PA air cooler duty (after
crude heating)
• LVGO PA air cooler duty
• Atmospheric column overhead
duty after the top condenser
• Run-down air cooler duties (after
crude and desalter water heating),
especially heavy diesel run-down.
Basic design considerations for
the project are:
• Increasing the HVGO pumpa-round
duty in the vacuum column
automatically decreases the
air-cooled LVGO pumparound
duty. Even in the low HVGO
pumparound base case, a substan-tial
amount of duty is lost through
air coolers. The desired HVGO
temperature to the hydrocracker is
150°C. Therefore, a HVGO pumpa-round
temperature of 150°C is
targeted. In order to make up room
in the crude network for the exist-www.
Kero. LAD HAD
Desalter
OVHD HADPA2 HADPA1 VR
Desalter
Crude
Kero. LAD HAD1
OVHD HADPA2 HADPA1
LVGOPA HVGOPA1
Crude
Figure 3 CDU/VDU example crude preheat train before and after the project
ing air-cooled duty and this
additional duty in the HVGO
pumparound, some duty has to be
shifted towards the hotter side of
the train. Therefore, a new hot
HVGO pumparound exchanger is
added before the existing hot VR
exchanger, and the new cold
HVGO pumparound heat
exchanger is added to the cold side
to recover the additional duties
• The remaining LVGO pumpa-round
duty is partially recovered
before the HADPA exchangers in
the second branch
• A portion of the heavy diesel
duty is recovered in the second
branch, following the new LVGO
heat exchanger
• Additional surface area is added
to the HADPA heat exchanger. The
reason for this is that the crude
temperature is much higher now
because of the LVGO and heavy
diesel heat exchangers
• The new cold vacuum residue
exchanger drops the temperature to
its initial value before going to
steam production
• The overhead vapour duty after
the first condenser (crude oil
heater) is very high, and this is lost
through air and water coolers.
However, it needs a higher-grade
material heat exchanger to recover
because of its corrosive nature
• Putting an additional high-grade
material overhead exchanger and
recovering the energy across the
HVGOPA
To
furnace
VR1
VR2
HAD2
HVGOPA2
To
furnace
dew point was considered. This
would enable more heat recovery
by shifting the diesel pumparound
duty towards the hotter side of the
train, making room for the over-head
duty before the desalter.
Diesel pumparound duty would
be shifted by closing the bypass
and putting additional area on the
existing HADPA exchanger.
However, because of the tight
equipment layout, enough space
could not be found in the actual
unit conditions. This option is laid
aside for the time being as a
possibility.
The simplified crude preheat
train before and after the project is
shown in Figure 3.
The key to this study is that all of
the new heat exchangers are
considered to be plate-type heat
exchangers. All welded-type plate
heat exchangers, because of their
area and space efficiency (high heat
transfer coefficient), are well suited
to tighter applications. If shell and
tubes were to be selected for this
project, a huge number of shells in
series and the space they occupy
would have been required. This
would have increased the invest-ment
cost, pressure drop and space
requirements. With this project,
over 15 Gcal/h of furnace duty will
be saved even without the addi-tional
overhead exchanger. Overall
payback time of the project is
almost half a year.
eptq.com PTQ Q4 2013 115
4. To
column
Crude To
VR1
Kero. LAD HAD1
OVHD HADPA2 HADPA1 HADPA
LVGOPA HVGOPA1
Flash drum (new)
furnace
driving force effect creates room for
additional savings potential in the
cold side of the train and decreases
the heat exchanger investment to
be made. In this specific layout, the
cold preflash bottom temperature
makes HADPA duty shift to the
hotter side of the preheat train,
creating room for an additional
savings opportunity before the
desalter. The only air-cooled stream
available for this is the overhead
stream. Therefore, the driving force
effect would make additional
savings if overhead duty were to be
used. This effect also decreases the
investment cost of exchangers and
decreases the vacuum residue
temperature going to steam
production (by shifting some
portion of the vacuum residue
steam duty to crude oil heating
furnace duty). The additional
saving would be in the range of
2 Gcal/hour in the light crude case
and close to zero in the heavy
crude case. Based on these results,
the preflash drum option for this
study was laid aside because of its
low overall benefits and unit space
constraints.
Preflash example 2
Another example is the initially
non-integrated CDU/VDU unit
illustrated in Figures 1 and 2. The
effects of the preflash drum and
also the importance of drawing the
overall boundary correctly will be
discussed in this example. When a
typical non-integrated CDU such as
in Figure 1 is considered, atmos-pheric
residue is used in preheating
crude oil, and colder atmospheric
residue is heated again with
vacuum-side hot streams.
If there is an air-cooled pumpa-round,
introducing preflash vapour
VR2
HAD2
HVGOPA2
• If pumparound duty is used
directly in the preheat, potential
duty gained by bypassing the
furnace is lost as reflux duty in the
preheat train, cancelling out the
energy benefit
• If pumparound duty is air cooled,
the preflash vapour will decrease
this duty. Energy-wise, there will
be no loss and the furnace duty
will be decreased
• The saving related to the driving
force effect with the preflash option
depends on the waste heat availa-ble
in the heat integration study
and the configuration.
Simulations are made such that
there is no loss of valuable prod-ucts
to less valuable ones. Some
examples regarding the preflash
studies made are given below.
Preflash example 1
In the CDU/VDU study given as
the example project, a preflash
study was made. A brief summary
of the preflash option for this
particular unit follows.
When the preflash vapour is
given to the flash zone, duty gained
in the atmospheric furnace is lost in
the vacuum furnace.
When the preflash vapour is given
to the upper trays at a suitable
temperature, column pumparound
duty decreases. There is only one
pumparound in this particular unit
(HADPA) and all of the duty is used
in crude oil preheat. The potential
duty gained by preflash vapours
bypassing the furnace is lost in
crude oil preheating. The column
atmospheric residue temperature
increases and the vacuum furnace
load decreases. However, overall
saving in this aspect is close to zero.
There is a 20°C temperature drop
in the preflash drum bottom. This
Desalter
Figure 4 Preflash drum option for the project
Preflash drum option
The feasibility of adding a preflash
drum depends on the column oper-ation,
pumparounds and how they
are located in the structure of the
heat exchanger network and the
tray where preflash vapour is intro-duced.
Adding a preflash drum
changes the pinch structure, the
potential energy savings and the
additional area of new heat
exchanger needed. It is a case-specific
study, and it should not be
decided whether an option with the
preflash drum will be feasible or
not without making a detailed
study. However, the existing unit
column and heat exchanger
network structure will give a hint.
It is certain that preflash vapour
will bypass the furnace and the
liquid load will decrease.
Furthermore, the preflash drum
bottom temperature will be much
lower than the inlet. This will create
a driving force in temperatures and
make an opportunity for this
stream to be heated more effi-ciently,
which may result in duty
shifts and savings.
However, the main point to be
considered in a preflash drum study
is the cooling effect of preflash
vapour on the tray to which it is
introduced. If this vapour is given
directly to the flash zone, the
column bottom temperature will be
lower and the direct benefit will be
small. In fact, the only real potential
in this case is the temperature drop
in the preflash bottoms and the abil-ity
to heat this stream more
effectively. If preflash vapour is
given to the upper trays based on its
temperature, the pumparound duty
on the column will decrease.
Therefore, the question is where is
this pumparound duty used?
116 PTQ Q4 2013 www.eptq.com
6. Effluent
To
air-cooler
EFF1 EFF2 EFF3 EFF4 EFF5 EFF6 EFF7
Fractionator
bottom
product
Diesel
product
To reactor furnace To stripper HVGO feed Stripper feed Hydrogen
Figure 5 Hydrocracker project existing simplified network
Waste heat through air or water
coolers is in total 60.3 Gcal/h.
Nearly 24 Gcal/h is wasted
through the effluent air cooler
(operating from 190°C to 62°C). The
minimum temperature difference is
75°C between the curves. The hot
pinch is 230°C and the cold pinch is
154.5°C (see Figure 6).
The link between the high-pressure
and low-pressure heat
exchanger trains is the stripper
charge. Stripper feed is heated from
~60°C to ~110°C with fractionator
streams before going to the
high-pressure effluent exchangers,
where it is heated to 255°C.
Therefore, if the stripper charge
stream is further heated with addi-tional
heat exchangers on the
stripper-fractionator side (the
low-pressure side), there will be
available duty potential in the efflu-ent
side to heat reactor feed streams
or the fractionator feed stream. In
this way, a portion of the wasted
section will be discussed with
regard to the hydrocracker example.
Example: hydrocracker
In the unit studied, HVGO, hydro-gen
and stripper feed is heated
with reactor effluent. Before going
into this high-pressure network, the
stripper charge is heated with
diesel and fractionator bottom
product. Debutaniser and naphtha
splitter reboiler duties are supplied
by the diesel pumparound in the
fractionator. Kerosene pumpa-round,
kerosene run-down, stripper
and fractionator overhead streams,
and the reactor effluent stream
going to the air cooler are the main
sources of waste energy. There are
two furnaces: one reactor charge
furnace and the other fractionator
charge (stripper bottom) furnace. A
simplified existing heat exchanger
layout is shown in Figure 5.
In the base case, the furnaces
have a process duty of 26.4 Gcal/h.
in the upper trays creates a benefit,
as discussed in the previous
example.
If all pumparound duties are used
in preheating, one does not expect
large amounts of savings. However,
if you draw the boundary on the
CDU only, the results will be differ-ent.
The pumparound duties (there
may be more than one pumpa-round)
will be lower with the upper
tray preflash option. This would
automatically mean that crude inlet
temperatures to the existing atmos-pheric
residue exchangers would
decrease, creating a driving force
effect. This would also automatically
mean that more duty can be recov-ered
from atmospheric residue,
making up for the lost duty in
pumparounds, and the atmospheric
residue temperature leaving the
CDU will be lower. This is an
energy saving if you are only
considering the CDU. However, the
atmospheric residue is sent directly
to the vacuum unit, and this poten-tial
saving is lost in the vacuum
furnace. Therefore, if you draw the
boundary on the CDU only, you
will be evaluating a potential that is
not actually there. There will be
some shifts from steam production
duty to furnace duty, but this is not
an energy-saving potential in the
CDU/VDU. It is a matter of the
value of steam in that particular
refinery. If the unit is integrated,
project saving potentials are much
bigger. However, the effect of a
preflash drum will be similar.
Hydrocracker and
hydrodesulphurisation (HDS) units
A typical hydrocracker or a HDS
preheat train can be divided into
two sections: the reactor effluent
side with high pressure and
temperature; and the stripper–
fractionation side with run-downs,
pumparounds, reboilers and so on.
The main cold streams in this
layout are the reactor input
streams: HVGO for the hydroc-racker
(diesel for HDS), hydrogen
and stripper-fractionator feeds.
In hydrocracker and HDS heat
integration studies performed,
similar principles were followed
(except for the fact that there is no
fractionator in a HDS), therefore this
600
500
400
300
200
100
Temperature, ºC
dT = 75.38ºC
Qh = 26.4
Qc = 60.3
0
0 20 40 60 80 100 120 140 160
Enthalpy, Gcal/h
Figure 6 Hydrocracker project base case curves
118 PTQ Q4 2013 www.eptq.com
7. column overhead energy (together with other frac-tionation
side heat) will be recovered as furnace
duty. Once again, for the low-pressure side, weld-ed-
type plate heat exchangers are selected.
This approach can be applied either to keep the
reactor effluent temperature as it is (~190°C; after
wash water injection it is ~160°C) or maximise the
benefits by decreasing (gaining from) the reactor
effluent air cooler duty as well. The choice is a
matter of the additional heat exchange area required
in the high-pressure network to shift this duty to
feed streams and the furnace duty benefits achieved
from it. However, it is also a matter of corrosion. A
lower reactor effluent air cooler temperature means
that temperatures are shifted towards cold stream
heating. Therefore, corrosion mechanisms will be
shifted towards the existing or new heat exchangers.
On the low-pressure side, diesel pumparound has
a high flow rate and temperature to be able to heat
up the fractionator charge with a plate-type heat
exchanger. In order to achieve this, reboiler duties
have to be shifted as much as possible towards the
lower-grade heat sources. Air-cooled kerosene
pumparound, diesel run-down and kerosene
run-down are suitable to take a portion of this duty.
Therefore, lower-grade heat sources are used for
lower-grade heat, freeing up higher-grade heat to be
used elsewhere – in this case, for heating the frac-tionator
charge. The temperatures are tight, so
plate-type heat exchangers are suitable for this
purpose.
An alternative approach is to further raise the
fractionator feed temperature by introducing it to
the high-pressure reactor effluent network.
Including this stream on the effluent side by means
of the optional exchanger shown in Figure 7
increases the amount of savings made per amount
of additional investment. Furthermore, the saving is
directly from the furnace. However, introducing the
fractionator feed to the high-pressure network may
not be desirable because of relief load and safety
concerns.
In the HDS unit example without a fractionator, no
pumparound duty may be available. However, heat-ing
the stripper feed more effectively with stripper
overhead and diesel product before it enters the
high-pressure preheat train creates the opportunity to
further heat up the reactor furnace feed streams.
Therefore, the principle is similar.
Alternative options
Introducing a preflash drum
Similar to the crude preflash study, introducing a
preflash drum to the fractionator feed creates a 20°C
temperature difference driving force. This stream
can be heated with heavy diesel (heavy diesel
pumparound) or reactor effluent, or both. This driv-ing
force creates an additional energy-saving
opportunity and decreases the amount of additional
area needed. However, the main saving comes
because the kero pumparound is air cooled. Preflash
vapour duty directly decreases from the air cooler if
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8. To reactor
furnace
To fractionator
furnace
Effluent To air cooler
Optional EFF5 EFF6 EFF7
Fractionator
bottom
product
Diesel product
from deb. reb.
Fractionator
overhead
Hydrogen
hydrogen through stripper charge
and loss of hydrogen to fuel gas. It
also means loss of C3-C4 (LPG prod-uct).
Four separator designs can be
selected to lower the amount of
product lost, but cannot prevent it.
Therefore, even though steam
production is acceptable with the
low-pressure fractionation streams
and more energy is recovered over-all,
hydrogen and LPG losses,
together with major changes in the
high-pressure section of the unit
(adding two separator drums),
make this alternative much less
attractive among the other heat
recovery scenarios.
Targeting the reactor effluent
air cooler
The effluent air cooler is the biggest
source of waste heat in a hydroc-racker.
Introducing this source of
heat to the recovery options will
increase the potential overall savings
and decrease the overall investment
cost. However, the corrosive nature
of this stream and the modifications
that need to be done in the fraction-ation
section of the heat exchanger
network require a detailed analysis
and a change of approach.
Considering its positive effects on
unit shutdown periods as well, this
option may be a very good selec-investment
EFF1 EFF2 EFF3 EFF4
To stripper
HVGO feed
Stripper feed
Debut reboiler duty shifted to
HAD rundown.
Portion of naphtha splitter
reboiler duty shifted to kero
pumparound.
Figure 7 Hydrocracker project simplified network after possible modifications
costs. Payback times of
Fractionator feed
(Preflash bottom)
all the different scenarios are
around, or less than, one year.
Introducing a hot separator
The stripper feed can be described
as the cold reactor effluent stream
after the air cooler and pressure
separators. Therefore, in a way, it is
being cooled with an air cooler and
heated again with reactor effluent.
From an energy point of view,
instead of cooling it to 60°C, it can
be kept at the desired temperature,
say 255°C, with a new separator
configuration including a hot
separator. In this way, the effluent
air cooler duty will be lower and
duty will be transferred to the other
cold streams, decreasing furnace
loads. However, low-pressure side
hot streams heating the stripper
charge will be freed up, and they
have to be used in steam production
in order not to waste them and gain
some energy overall. Whether this
steam is needed or not is a critical
issue when evaluating this option. If
steam is not a good alternative in
the refinery’s utility balance, hot
separator designs do not bring any
energy benefit at all when compared
to other heat recovery scenarios.
Furthermore, introducing a hot
separator means more soluble
HADPA
vapours are introduced to the
upper trays according to the
temperature profile. Therefore, frac-tionator
furnace duty is decreased
directly. Together with the shifting
of reboiler duties to lower-grade
heat sources and using diesel
pumparound duty to heat up the
preflash bottoms (fractionator feed)
with a new heat exchanger, furnace
and air-cooled pumparound or
overhead reflux duties are
decreased substantially.
Taking into account all of the
design considerations discussed, a
simplified heat exchanger configu-ration
looks like the one shown in
Figure 7 (new positions are shown
in red).
The total furnace process duty
saved with this configuration, even
without affecting the reactor efflu-ent
cooler and without adding
additional area to the existing
exchangers, is 9 Gcal/h, which is
actually higher when furnace effi-ciency
is considered. Together with
kero run-down steam production
and considering firing efficiencies,
the total saving is nearer 13 Gcal/h.
By adding the new heat exchang-ers
shown and adding new shells
to the existing heat exchangers,
savings can rise to 18 Gcal/h,
taking into account increased
120 PTQ Q4 2013 www.eptq.com
9. Key performance indicators for ConSep trays
sometimes very critical in heat inte-gration
Texas, complex had a power surge
that triggered a small fire in a pipe
rack at the refinery’s chemical
plant. Power surges can cause fires
and cause breakdown in different
units. In April 2011, Sunoco’s
Philadelphia, Pennsylvania, refin-ery
the ebullated-bed reactor or fed to a
coker unit. studies. For this The study, freedom it was
to
considered that this stream is recy-cled
produce steam may bring addi-tional
types of switchgear are oil or gas
insulated. A stray spark can cause
these to catch on fire and fail.
Then there are the obscure
reasons that cannot be predicted
and happen so infrequently that it
is hard to protect against. In
November 2012, Valero’s Corpus
Christi, Texas, had a power loss
that led to flaring due to a rodent
contacting the primary power
transformer. Transformers that can
be accessed should be protected to
allow only those working on them
to get to them. In February 2010,
Western Refining’s Yorktown,
Virginia, had an unidentified unit
shutdown due a temporary power
blip caused by a goose flying into a
nearby power line. Unless power
lines are put underground, it is
difficult to protect them from
animals and debris.
Power surges and fluctuations
Power surges also occur frequently
and can be prevented with circuit
breakers or switchgear. In August
2009, ExxonMobil’s Baytown,
Parameters Design Test run
Froth backup/CS height, % 68 60
Tray pressure drop, mbar 12.3 9.2
Tube flood , % 73 60
Flow parameter 0.17 0.19
Overall column load factor, m/s 0.12 0.10
Flooding (CS tray), % 133 112
benefits to overall fuel
back to the hydroconversion
consumption in the refinery, or it
may not be needed at all.
In a heat integration study,
options should be evaluated with
detailed simulation and heat inte-gration
reactor, meaning that there is
complete overall residue conver-sion
even when the once-through
had a power surge that
conversion reported in Table 2 is
78%.
The fractionated products from
the VTB conversion step, along
with the corresponding VDU distil-lates,
knocked compressors offline. In
May 2011, Phillips analysis. 66’s Wilmington,
Evaluations
California, facility had a power
fluctuation occur, temporarily shut-ting
should be considered in a case-spe-cific
manner with creative thinking
3 De Villiers W E, Bravo J L, Wilkinson P M,
Summers D R, Further advances in light
hydrocarbon fractionation, PTQ Q3 2004.
Kaushik Majumder is Distillation Team Lead of
Shell Projects & Technology in Bangalore, India.
He holds a bachelor’s degree from Jadavpur
University, India, and a master’s and doctorate
from Indian Institute of Technology, Delhi.
Email: Kaushik.Majumder@shell.com
Giuseppe Mosca is the Global Refinery
Technology Manager of Sulzer Chemtech.
He holds BS and MS degrees in chemical
engineering from the University “La Sapienza”
Rome, Italy.
Email: Giuseppe.Mosca@sulzer.com
Kent Mahon is a Process Engineer at Refining
NZ. He was the Senior Process Engineer and
Commissioning Process Engineer during the
Point Forward Project.
Email: Kent.Mahon@refiningnz.com
and taking general guidelines into
account. Most of the time, heat inte-gration
down several refinery units.
require further hydrotreating
Normal operations were restored
the next day.
Multiple unit shutdowns
Since most refinery units are inte-grated
to reduce sulphur, nitrogen and
aromatic projects contents will for bring producing
large
suitable blending components for
SCO. The properties of the hydro-treated
amounts of savings involving
millions of dollars per year, with
usually less than one-to–one-and-a-half-
products and final SCO are
year payback periods.
and sometimes share the
provided in Table 4. The SCO has
no residue and very low sulphur
and nitrogen contents. The
coking-derived SCO is slightly
more aromatic than that derived
from the hydroconversion-based
scheme. Table 5 summarises the
details of the HDT units. It is
observed that the hydrotreating of
coker products requires higher
same power supply, power failures
could lead to the shutdown of these
integrated units and the production
loss of many refined products,
thereby magnifying potential
damages.
In June 2009, Tesoro’s Kenai,
Alaska, facility experienced a
power outage. The hydrocracker
and isomerisation unit were shut to
Alis¸an Dog˘an is a Process and Equipment
Development Superintendent in Head Office
Technical Services Management with Turkish
Petroleum Refineries Corporation (Tüpras),
specialising in heat recovery and heat
integration and process simulation. He holds
a BS in chemical engineering from Middle East
Technical University, Ankara, Turkey.
Email: Alisan.Dogan@tupras.com.tr
effectively from sources that would
otherwise prove very costly and
involve high pressure drops if shell
and tubes were to be used. Plate-type
test run’s results, it could be
concluded that the revamp targets
for the CDU-1 main fractionator
(C-150) were achieved. No hydrau-lic
Properties of coker and hydroconverter liquid productsa
constraint was experienced in
Coker Hydroconverter
heat exchanger usage is
achieving the design intake of
13 000 t/d and the required prod-uct
Property Naphtha LGO HGO Naphtha LGO HGO Vacuum residue
Yield, wt% 26.8 34.1 39.1 14.0 37.9 27.8 20.4
SG 60/60°F 0.7363 0.8715 0.9736 0.7365 0.8710 0.9715 1.1240
API gravity 60.7 30.9 13.8 60.6 31.0 14.2 -5.6
Sulphur, wt% 1.79 3.67 4.43 0.25 0.71 1.37 6.90
Nitrogen, wppm 316 1694 3973 393 1582 3063 8905
Aromatics, wt% 27.1 58.0 66.0 20.5 42.5 53.0 99.8
Nickel, wppm - - 8.2 - - 3.0 262.9
Vanadium, wppm - - 27.4 - - 6.2 458.3
CCR, wt% - - 1.5 - - 0.2 14.3
limited in pressure (to 40 bar)
• Using a flash drum before a frac-tionator
creates a driving force
effect that may enable some addi-tional
energy recovery or heat duty
Table 3
shift from steam production to cold
feed streams (furnace duty).
However, the main point in making
a preflash drum a feasible option is
whether there is wasted, air-cooled
pumparound duty near the tray
flash vapour. Giving preflash
vapour to higher trays may not be
desired because of liquid entrain-ment
quality was achieved.
Conclusions
The performance of Shell ConSep
trays in the HGO pumparound
section of the CDU-1 main fractiona-tor
met the target of capacity
enhancement without any drawback
compared to the pre-revamp condi-tions.
During the test run, the trays
were operating at 10-15% lower than
the design capacity even at the
design intake of 13 000 t/d due to
heavier crude feed and lower feed
temperature. However, the built-in
capacity margin enabled stable oper-ation
such cases. In this revamp project,
use of only three of these trays in
the most capacity-constrained
section of the column made it possi-ble
to retrofit the existing column
and made the capex option more
attractive over the other debottle-necking
options.
Properties of hydrotreated products and SCO
concerns; therefore, special
consideration should be given to
the preflash drum design, such as
high retention time, high L/D ratio
and usage of demister pads. Even a
preflash tower may be considered
to eliminate risks, although this
would, of course, increase the
investment cost
• Overall refinery steam balance is
tion, in combination with the key
points taken from the other options.
Conclusion
Heat integration options and stud-ies
Substations, whether owned by
the utility company or the refinery,
tend to break down if not properly
maintained. In October 2009,
Valero’s McKee, Texas, plant had a
substation should malfunction, be considered which
as
forced units offline. Substation
malfunctions have occurred more
frequently than many people think.
In March 2010, Chevron’s El
Segundo, California, refinery shut
down due to fire at a substation.
And, in August 2011, Tesoro’s
Kapolei, Hawaii, complex had a
power outage due to a failure at
one of the local electric utility’s
substations.
In May 2010, BP’s Texas City,
Texas, refinery had a power blip
caused by switchgear failure.
Switchgear failures also occur quite
frequently. The relay that failed at
the Super Bowl was a part of the
switchgear setup that supplied
power to the stadium. Switchgears
operate as a protective device
against overcurrent and arc flashes.
They also need to be properly
maintained to avoid failures. A few
case-specific evaluations. There is
no rule of thumb whether an option
is the best for a specific unit or a
specific refinery. Unit layout, inte-gration
with other downstream
units, overall refinery utility
balance and unit-specific problems
(such a) Yield as values the are based hydrocracker on total liquid product.
effluent
air cooler example) all affect the
selection process:
• Drawing the overall boundary is
very important, especially in CDU/
VDU studies. Integration will most
of the time bring additional benefits
in energy savings and area effi-ciency.
* Shell ConSep, Shell CS and Shell HiFi are Shell
trademarks. ** Mellapak Plus 252Y is a Sulzer
Chemtech trademark.
Coker-based scheme Hydroconverter-based scheme
Drawing the boundary
Table 3
Property Naphtha LGO HGO SCO Naphtha LGO HGO SCO
SG 60/for 60°F the trays 0.7375 at much 0.8597 above
0.9131 0.8680 0.7375 0.8573 0.9115 0.8665
API gravity 60.4 33.1 23.5 31.5 60.4 33.6 23.7 31.8
Sulphur, wt% 0.018 0.112 0.16 0.13 0.014 0.044 0.15 0.10
Nitrogen, wppm 12 204 740 482 21 264 455 336
Aromatics, wt% 19.9 41.8 54.2 45.9 15.8 36.5 50.9 41.7
incorrectly may even make a feasi-ble
the capacity limit of the first genera-tion
option infeasible, or vice versa
of high-capacity trays.
The options to debottleneck
columns already equipped with the
first generation of high-capacity
trays are limited. ConSep trays
provide an attractive solution for
(for instance, the CDU/VDU
preflash drum example)
• Using all welded-type plate
exchangers Table 4
creates the opportunity
to recover heat efficiently and cost
References
1 Refinery expansion means NZ more self
reliant, media release by NZRC, 16 July 2010.
2 Wilkinson P M, De Villiers W E, Mosca
G, Tonon L, Achieve challenging targets in
propylene yield using ultra system fractionation
trays, ERTC 2006.
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