Optimising steam systems: part II

A second article on steam system optimisation addresses steam at point of use

and good engineering practice to remove and return condensate
Ian Fleming
Spirax Sarco



4EMPERATURE#

se of steam in the oil and

petrochemical sector can be
classified under:
Primary process requirements;
for instance, a reboiler on a distillation column
Secondary process requirements
such as steam tracing
Emergency requirements, including snuffing in the case of fire or
turbine rupture
Utility
requirements such as
turbogenerators.



Steam saturation curve













0RESSUREBARG











Steam in process heating

Steam is used to vapourise, preheat

and heat a process. Regardless of
the heat exchanger used, whether it
is a kettle-type reboiler (shell and
tube), plate-type heat exchanger or
heating coils in a tank, the principles of operation and the end result
on the steam side are very similar.
When using steam, the rate of
heat transfer in a heat exchanger
can be defined (in its simplest form)
by a basic equation:
Q = U*A*(Ts - Tp)
Where:
Q = Heat transfer rate, W
U = Heat transfer coefficient, W/m2 C
A = Heat transfer surface area, m2
Ts = Steam saturation temperature, C
Tp = Mean process temperature, C

The heat transfer coefficient, U,

decreases during operation due to
fouling, so heat exchange manufacturers add in a fouling factor to
ensure that the reboiler, for example, meets the process load for the
required service period. The fouling
factor is the additional heat transfer
surface area (A) of the heat

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Figure 1 Steam saturation curve

exchanger, which can be anything

from 1050% greater than the area
required for a clean surface
(depending on the process). The
importance of the fouling factor on
steam loads and condensate
removal will become apparent later
in this article.
The steam saturation temperature
(Ts) is determined by the steam
pressure within the heat exchanger
and is defined by the steam saturation curve (see Figure 1). The
control valve therefore achieves the
correct process temperature by
limiting the steam flow (and consequently the steams pressure/
temperature) entering the heat
exchanger, replacing the steam that
has condensed as it gives up its
enthalpy of evaporation to the process fluid. As demand increases, the
control valve opens, increasing the
steam pressure and temperature,
leading to a greater heat transfer
rate.
If demand reduces, the control
valve throttles and the opposite
occurs, lowering the steam pressure

and temperature on the primary

side. In addition, if the heat
exchanger is new or has just been
cleaned, the additional fouling
factor may lead to a significantly
greater heat transfer surface area
(A) than is required for the actual
duty, resulting in a lower steam
temperature requirement. It is not
unusual to find heat exchangers
operating with steam pressures just
above atmospheric conditions or
even at sub-atmospheric pressures,
regardless of the steam pressure
upstream of the control valve.
Understanding this helps to explain
the root cause of many of the problems arising with heat exchangers
and how they can be overcome.

Heat exchanger stall

Stall occurs when the steam pressure in the heat exchanger drops
below the back pressure (condensate line pressure) acting on the
steam trap. This prevents the flow
of condensate through the steam
trap, which in turn causes the
condensate to back up. Although

PTQ Q3 2010 53

Steam control valve

Steam
to reboiler

Reboiler
Air vent

Motive steam

Condensate
from reboiler

Condensate
return
Reservoir

Steam trap

Pressure
powered
pump

Not all ancillary equipment

is shown for clarity

Figure 2 Condensate pump arrangement to overcome stall

this sounds unusual, it is a fairly

common situation, particularly on
temperature-controlled equipment.
Typical symptoms indicating that
a heat exchanger is suffering from
stall include:
Cold or cool steam traps draining
the heat exchanger, due to a back up
of condensate in the heat exchanger
Corrosion
within
the
heat
exchanger, due to waterlogged
condensate standing in the steam
space. Many operators believe this
is normal and accept it as a fact of
life. (It is worth mentioning that
corrosion is also a sign of poor
water treatment, which should also
be investigated)
Unstable control or cyclic temperatures of the process fluid: as the
heat exchanger stalls, it begins to
flood, reducing the heat transfer
surface area and heat transfer rate.
The control valve opens to meet the
demand and, in so doing, the steam
pressure rises, which in turn overcomes the stall conditions and the
condensate is rapidly removed from
the heat exchanger. With this

54 PTQ Q3 2010

sudden increase in available

effective heat transfer surface area,
the process starts to go overtemperature. The control valve
closes and the cycle repeats itself
Mechanical stress and cracking in
the heat exchanger can be caused
by the difference in temperature
between steam at the top of the
heat exchanger and cool condensate
at the bottom
Water
hammer can lead to
premature failure of the heat
exchanger or surrounding pipework. The heat exchanger makes
cracking, banging or thumping
noises as hot steam bubbles,
surrounded by cooler condensate,
implode as they condense. Since
steam has a considerably higher
specific volume compared to water,
when the steam collapses condensate is accelerated into the resulting
vacuum. As the void is filled, water
impacts the centre, sending shockwaves out in all directions
Water and energy losses are
caused by the steam trap bypass
valves being left open and conden-

sate being dumped in an attempt to

achieve the required process
conditions.
Stall can occur when:
The process temperature is less
than 100C (implying steam temperature on the primary side could be
lower than 100C and therefore
below atmospheric pressure)
The heat exchanger is oversized
(which may be necessary to allow
for fouling)
Heat
exchanger loads vary,
resulting in the control valve having
to throttle on low load conditions
Back pressure is present on the
condensate line due to lift, failed
open steam traps pressurising the
line or if the line is undersized for
the condensate loads and flash
steam generated.
Stall is easily overcome by using
a condensate pump, which allows
condensate from the heat exchanger
in question to drain freely. A
typical arrangement is shown in
Figure 2.
When steam pressure on the
primary side exceeds the condensate back pressure, condensate
passes through the pump body,
check valves and steam trap,
discharging into the condensate
line. Under stall conditions, the
condensate backs up in the pump
body, lifting a ball float, which
closes the exhaust valve and opens
the motive steam valve. This pressurises the pump body, forcing
condensate into the condensate line.
The check valves ensure condensate
can only flow in one direction.
Figure 3 shows a typical mechanical
pump operation.

Stall

To illustrate the effect stall can have

on a process, a refinery wished to
increase the capacity of one of its
columns. Instead of replacing the
existing reboiler, it made more
commercial sense for the refinery to
install an additional shell and tube
heat exchanger to preheat the feed
column. Once installed, however,
the preheater, which had to deal
with varying loads, did not meet
the required capacity. The inverted
bucket trap seemed undersized, but
bypassing the steam trap only
helped occasionally. Stable control

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Figure 3 Operation of a mechanical pump

Safety valve
Strainer
Steam
Stop
valve

Pneumatic
control valve

Separator

Reboiler

Trap set
To trap set or
pump/trap set

Figure 4 Controlling steam supply to a reboiler

Manual drip points

Figure 5 Incorrect control valve installation

56 PTQ Q3 2010

could not be achieved and condensate was being dumped at an

average rate of 4000 kg/h.
It was discovered that the
preheater was operating under
clean conditions (maximum fouling
factor) and on low loads the control
valve was only 25% open. The
condensate temperature upstream
of the trap was measured at 105C,
which equates to a saturated steam
pressure of 0.2 barg. The total back
pressure acting on the downstream
side of the trap was 1 barg, preventing the condensate from draining
from the preheater under these
conditions. In other words, the
preheater had stalled. By installing
a pump and trap with sufficient
capacity to drain the preheater,
under all operating conditions, the
operators achieved the increased
capacity.
In this case, the payback period
was less than four months, based
purely on returning the condensate,
which was being dumped, back to
the boiler house. The pump was
sized to overcome the back pressure caused by the lift and frictional
losses generated in the pumped
condensate line on its return to the
boiler house.
For a process to operate at maximum efficiency, the steam needs to
arrive at the correct quality (100%
dryness fraction), quantity and
pressure. Just before entering the
heat exchanger (say, a reboiler), the
steam should pass through a separator to remove any entrained water
in the steam to maximise quality, a
strainer to remove debris and then
normally through a control valve
(see Figure 4).
Figure 5 shows a poor, but typical, control valve installation below
a process heat exchanger. The
control valve is at a low point
where condensate will collect when
the valve is closed. This particular
installation caused serious problems
for the instrument engineers, leading to:
Standing corrosion to the isolation valve and associated piping
Heat
exchanger temperature
fluctuations
Water hammer in the coils
Product
losses through poor
repeatability.

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The control valve had recently

been replaced, as it was believed
to be the cause of unstable
control. In fact, the control system
was no more stable after the
change-out. In addition to the
problems identified earlier, it is
common to find control valves
suffering from erosion or wire
drawing as a result of the twophase flow (steam and condensate)
it is exposed to. The problem can
be easily rectified by installing dirt
pockets and steam traps to the
bottom of each riser, allowing
condensate to be removed as it
forms. The return on investment is
usually
very
short
and
in
one case was within a matter of
weeks.
Figure 6 shows how a steam line
should be drained at a low point,
whether this is either side of a
control valve or on a steam main
between gantries.

Condensate and flash steam

recovery

Once the steam has given out its

heat (enthalpy of evaporation), the
condensate formed should, wherever possible, be returned back to
the boiler house/power plant.
Recovering condensate and utilising flash steam results in energy
savings, water savings, reduced
effluent (as returning condensate
means less water dumped) and
fewer water treatment chemicals
(condensate is pure distilled water,
which has already been treated).

Energy savings

Returning condensate alone in a

typical refinery, even without utilising the flash steam, will save

Figure 6 Draining a steam line at a low point

KGHRFROM
REFORMERFLUE

KGHRFROM
PROCESSCOOLING

(0STEAMBAR#

K7

KGHR
-0STEAMBAR#

K7
KGHRFROM
PROCESSCOOLING

KGHR
TOREFORMER

#7

,0STEAMBAR#SATURATED

KGHRFROM
PROCESS

KGHR

KGHR
TODE AERATOR

KGHR
TO#/REMOVALPLANT

#ONDENSATEBAR#

Figure 7 Three-header steam system

approximately 10% of fuel costs.

The steam tables (see Table 1)
show that, as pressure rises, the
amount of energy remaining in the
condensate (sensible heat) increases.
In fact, at 30 barg, the energy in the

condensate accounts for 36% of the

total steam energy (total heat). Once
the condensate has passed through
a steam trap to a lower pressure
(and hence has a lower saturation
temperature),
some
of
the

Steam tables (extract)

Gauge pressure,
Absolute pressure,
Temp., C
Water (hf)
Specific enthalpy
barg
bara
(sensible heat), Evapouration (hfg)

kj/kg
(latent heat),

kj/kg
0
1
100
419
2257
1
2
120
506
2201
4
5
159
671
2086
10
11
184
782
2000
30
31
236
1017
1787
80
81
269
1322
1435
100
101
312
1412
1311

Steam (hg)
(total heat),
kj/kg

Specific volume,
m3/kg

2676
2707
2757
2782
2804
2757
2723

1.673
0.881
0.315
0.177
0.065
0.023
0.018

Table 1

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PTQ Q3 2010 57

condensate will flash off. This flash

steam can be utilised for lower
pressure systems.
The schematic in Figure 7 shows
a typical three-header steam system.
The high-pressure (HP) steam
distribution main from the powerhouse is also receiving additional
HP steam from the process heat
recovery steam generators (HRSG)
in the reformer. The HP steam is
then let down from HP to medium
pressure (MP) using a steam turbine
generator. The turbine exhaust
steam is fed into the powerhouse
MP distribution line for use elsewhere. The low-pressure (LP) steam
main from the powerhouse is
receiving additional steam from a
process cooling HRSG, plus steam
from a MP steam turbine generator.
The LP steam from the final stage
of this turbine goes through a
condenser and the condensate is
returned to the powerhouse treatment plant.
The greatest amount of condensate
is returned through the LP condensate return, which includes the
condensate from processes to minimise the risk of stall. However, a
typical oil and petrochemical plant
will also have separate common
condensate lines for draining the HP
and MP steam lines.

(0STEAMMAINSBARG

,ETDOWN
STATION

3TEAMTRAP
SET

-0STEAMMAINS
BARG

(0COMMONCONDENSATERETURN

-0STEAMHEADER
BARG

3TEAMTRAP
SET
-0COMMONCONDENSATERETURN
BARG

Figure 8 Condensate return for HP steam

Vent

MP steam main (30 bar g)

Surplussing
valve

LP steam main (3 bar g)

Steam trap
station
MP common condensate return
(at LP steam pressure)

LP receiver (3 bar g)

HP condensate return

Due to the pressures and energy

involved, any condensate formed in
the HP distribution system is
normally passed into a MP steam
header (see Figure 8).
The letdown station acts as a
throttle, maintaining pressure in the
HP condensate line, reducing the
amount of flash steam generated
and, hence, keeping the condensate
line at minimum size. In addition,
it protects the MP header from
HP steam, should any of the
steam traps fail open. The letdown
station then reduces the pressure to
MP steam levels. The flash steam
generated is used as MP steam,
while the remaining condensate is
cascaded into the MP condensate
line.

MP condensate return

MP condensate is normally returned

to a LP receiver (see Figure 9).

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Pump
LP condensate return

Figure 9 Condensate return for MP steam

Basic types of condensate line
Type of condensate line
1 Drain line from process outlet to steam trap
2 Discharge line from steam trap
3 Common return line

4 Pumped return line

Condensate line is sized to carry the following

Condensate (still at steam pressure)
Flash steam
Flash steam (sum of flash steam from all
traps discharging into the line)
Condensate (flash steam will be vented at the
pump receiver)

Table 2

Flash steam generated from the

condensate can be used as LP steam.
A surplussing valve vents excess
steam, which will be discussed later.

LP condensate return

Finally, the LP common condensate

line can be returned to a vented
condensate receiver, before being

PTQ Q3 2010 59

worth mentioning that there are

four basic types of condensate line
(see Table 2).

Vent

Types of condensate lines

Condensate from other lines
Pumped
condensate

Common
return line

1:7 slope = 150 mm/10 m run

Vented
receiver

Pump

Flash steam evaporated = ((782 - 506) /

2201))*100

= 12.5% of

condensate flashed

off

Figure 10 LP condensate return

&LASHSTEAMPRESSUREBARG



This is also shown graphically in

Figure 11. Although 12.5% of
condensate flashing off does not
sound significant, the relative
volume it occupies compared to the
condensate is huge. Taking the
example above, 1kg of condensate
at 10 barg discharging into a
condensate line at atmospheric
pressure generates 0.125kg of flash
steam. However, in terms of the
volume occupied:



0 ba
rg

arg
0.5
b

rg
barg
1 .0

1.5
ba

2 .5



2 .0

bar g
bar g





0RESSUREONTRAPSBAR





0.875kg (10.125) of condensate occupies:

0.000875 m3 (based on density of water at
approximately 1000 kg/m3)




0.125kg of flash steam occupies:

0.110 m3 (0.125 kg * 0.881 m3/kg using
specific volume of steam at 1 barg from steam
tables above)





Atmospheric
pressure

Total volume occupied: 0.000875 + 0.110

= 0.111 m3

12.5%








&LASHSTEAMKGCONDENSATEKG





Figure 11 Flash steam generation

pumped back to the boiler/

powerhouse (see Figure 10).
Even
though
most
of
the
energy has been utilised, the
condensate still has sensible heat

60

In the case of the discharge line

from the trap and the common
return line, any flash steam generated must be taken into account.
Taking the example of a heat
exchanger operating at 10 barg
steam pressure where condensate is
discharged into a common condensate line at 1 barg, and applying the
steam tables (see Table 1), the
percentage of flash steam generated
is:

PTQ Q3 2010

and is treated boiler feed water.

Undersized condensate lines

Sizing condensate lines is a subject

in its own right. However, it is

% volume occupied by condensate:

1% (0.000875/0.111)
% volume occupied by flash steam:
99% (0.11/0.111)

By not taking into account the

flash steam generated downstream
of the steam trap, the condensate
line will be undersized, increasing
the pressure in the line and resulting in higher flash steam velocities.
This, in turn, leads to water hammer

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and possibly de-rates any steam

trap also discharging into the same
condensate line.

Flash steam

Common condensate return lines

Flash steam bubble

implodes as steam
condenses

Figure 12 Water hammer caused by flash steam in a condensate line

2,365 #/hr
flash steam

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Heat exchangers
operating at 400 psi

150 # HDR
22,774 #/hr

Common condensate
lines operating
at 25 psi

D-104
E-2650

E-2648

25 # HDR

10,295 #/hr
flash steam

E-2646

400 #
4,900 #/hr

400 #
2,244 #/hr

400 #
15,630 #/hr

Heat exchangers
operating at 150 psi
81,182 #/hr
condensate
to return system

D-105

91,477 #/hr
E-2649

At 0 psig 76,776 #/hr condensate

4,520 #/hr flash steam

E-2647

E-2645
Heat exchanger

150 #
36,400 #/hr

150 #
6,756 #/hr

150 #
27,912 #/hr

Condensate pot:
Condensate pots are used instead of steam
traps where very large condensate loads exist

Balance line

Level
control

Condensate & flash steam

discharge to return system
Control
valve

Pumped return lines

Although it is tempting to add trap

discharge lines directly into the

Cool condensate

20,409 #/hr

Condensate from trap discharge

lines is normally connected to a
common return line, which should
gravitate to a receiver or header,
where it should eventually be
pumped back to the boiler house. In
reality, there may be occasions
where the condensate line will be at
a low point before, say, a riser. In
this case, the condensate line will be
flooded and will rely on pressure to
lift the condensate. There is a real
risk of water hammer caused by the
flash steam generated travelling
along the condensate line at high
velocity, picking up slugs of water
in its path. In addition, steam traps
discharging into the common return
line at this point generate the risk of
causing water hammer, as the flash
steam surrounded by cool condensate can condense rapidly, causing
thermal shocks (see Figure 12).
Where possible, low points in the
common condensate line should be
avoided. However, where this situation arises, it is advisable to use
either a float trap, with its continuous discharge, which allows the
energy from the relatively small
continuous flow to be absorbed and
dissipated in the condensate line.
Alternatively, a thermostatic trap
can be used, depending on the
application, which allows the
condensate to sub-cool before
discharging it into the common
line. A thermodynamic trap, with
its blast discharge option, should
be avoided where possible in this
case.
It is important that the separate
condensate lines for HP, MP and
LP steam are reserved for the specified purpose. For example, a steam
trap draining an MP steam main
should never be linked to an LP
condensate line because of the
amount of flash steam generated
and the impact such a trap would
have on pressurising the system if
it failed open.

Figure 13 Flash steam recovery

PTQ Q3 2010

61

Availability of flash steam from a single asset

Flash steam pressure
150 psi (10.3 barg)
25 psi (1.7 barg)
Sub-total
Atmospheric pressure
Total

Quantity
2365 lb/hr (1070 kg/hr)
10 295 lb/hr (4680 kg/hr)
12 660 lb/hr (5755 kg/hr)
4520 lb/hr (2055 kg/hr)
17 180 lb/hr (7810 kg/hr)

Application
150 psi steam header
25 psi steam header

Table 3

175 psig
motive steam

45 psig
consumed
steam

20 psig
exhaust steam

Figure 14 Use of a thermocompressor to upgrade exhaust steam pressure

pumped return line because it

happens to be the nearest, it should
be remembered that the line will
be:
Sized for condensate only
Flooded, resulting in the risk of
water hammer caused by thermal
shock and high velocities caused by
flash steam expanding in the
condensate main
Pressurised, which will be acting
as a back pressure on the traps
discharging into this line, so
possibly
de-rating
the
traps
performance.

Flash steam recovery

Depending on pressure, the energy

used to flash off condensate can
account for a large percentage of
the total energy in the condensate
at pressure. This flash steam can be
used on lower pressure applications, saving significant amounts of
energy and water. Figure 13 illustrates an example taken from an
audit carried out for a refinery in
the US.
This example demonstrates the
scale of flash steam available, which
can be utilised from just one asset
(see Table 3).
Unfortunately, in this case, the
4520 lb/h of flash steam generated

62

PTQ Q3 2010

at atmospheric pressure was causing significant problems for the

refiner, as the condensate line was
seriously undersized. This led to
extremely high velocities in the
atmospheric condensate return and
severe water hammer, which in
turn resulted in leaks developing in
the line. This could be overcome by
adding a vented receiver and pump
downstream of the 25 psi flash
vessel, allowing the condensate to
be pumped back to the condensate
tank. Where possible, this flash
steam should also be utilised, possibly preheating the boiler feed water,
or condensed, where at least the
water could be returned to the
boiler.
One option, depending on energy
balances, could be to use a thermocompressor or mechanical vapour
recompression to re-energise the
flash steam to a useable pressure.
The following example shows how
a thermocompressor could be used
to induce 20 psig steam to an intermediate pressure (45 psig) by using
a 175 psig motive supply (see
Figure 14).
In this example, an alkylation unit
consumes over 24 000 lb/h of 45
psig steam that is currently
imported from another asset.

Therefore, there is the potential to

utilise steam from a thermocompressor for this service, assuming:
The 45 psig steam from the other
asset could be used elsewhere in
the refinery, even if it needs to be
generated at a higher pressure
The cost of 175 psig and 45 psig
steam are the same
A two-to-one ratio of 175 psig
and 45 psig steam from the
thermocompressor
Production of 24 000 lb/h of 45
psig steam for use in the alkylation
unit.
Under these conditions, the
alkylation unit would now consume
16 000 lb/h of 175 psig steam and
8000 lb/h of the currently exhausted
20 psig steam in lieu of the 24 000
lb/h of 45 psig steam from the
other asset. This results in annual
savings of 8000 lb/hr of exhausted
steam. The return on investment in
this case would be a matter of
months.

Conclusion

Steam generation accounts for

approximately 50% of total energy
consumption in a typical refinery.
This article has focused on:
The impact stall can have on a
heat exchanger and how it can be
easily overcome, normally resulting
in rapid returns on investment
The
importance of returning
condensate to the powerhouse and
the good engineering practices
involved
The benefits of utilising flash
steam, giving examples of the
savings that can be made.
Through good engineering practice and management of the steam
and condensate system, significant
savings can be realised through
lower energy costs, emissions and
effluent costs. This, in turn, has a
positive impact on process efficiency by increasing output and
improving control.

Ian Fleming is Marketing Manager for Oil and

Petrochemicals at Spirax Sarco, Cheltenham,
UK. He has 20 years experience in steam
systems.
Email: ian.fleming@uk.spiraxsarco.com

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