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

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Figure 13.28. A typical fuel oil system.

574 CHAPTER 13

The pumps discharge the fuel oil via the pressure controller to a pre-heater. This

pre-heater may be a simple double pipe heat exchanger for relatively small units or

regular shell and tube for the larger systems. Double pipe type exchangers are favored

in this service when economical because they are easier to clean and maintain. The

fuel oil leaves the pre-heater to enter the fuel oil distribution system at a temperature

high enough to maintain a viscosity low enough for the oil to ﬂow easily and to be

easily atomized by steam at the fuel oil “gun”(or burner). All the piping associated

with residual fuel systems are heavily insulated and steam traced. The distribution

systems of residual fuel oils is usually the re-circulating type. That is the fuel leaves

the pre-heater to circulate to all the user plants in a loop where the quantity used is

taken off the stream and the remainder allowed to return to the system. The return

header is routed back to the storage tanks. The circulation system handles between 1

to 3 times that amount of oil that is actually burnt.

Fuel oils are introduced into the ﬁre box and ignited through a fuel oil burner some-

times called a fuel oil gun. In order to ensure combustion in a manner suitable for

a ﬁre box operation the fuel oil needs to be dispersed into small droplets or spray at

the burner tip. In heavy residual oils this is almost always accomplished by steam.

Compressed air is however sometimes used for this purpose. This atomizing stream

is introduced into the gun chamber and comes into contact with the oil stream just

before the burner tip. The kinetic energy in the atomizing medium forces the oil into

suitable droplets as it leaves the burner. Steam is normally used as the atomizing

material because it is usually cheaper, more readily available, and has a more reliable

source than air from a compressor.

The steam pressure for atomizing should be 15–25 psig higher than the fuel oil

pressure. The quantity of steam will range from 1.5 to 5 lbs per gallon of oil. Dry

steam with a superheat of about 50

◦

F is preferred for atomizing. In order to con-

trol the process heater operation oil burners require a turndown ability. That is they

require to operate satisfactory over a prescribed range of ﬂow. In keeping with an

operating range for oil ﬂow the atomizing medium must also have a similar oper-

ating range. Burner pressure is a critical requirement for turndown. The steam (or

air) pressure should be 15 psi or 10% (whichever is the greater) higher than oil pres-

sure. The fuel oil supply system should be 100 psi higher than the burner require-

ment.

The oil burner operation as with the fuel gas burner is controlled by the heater’s process

stream outlet temperature. The temperature control valve activated by the coil outlet

temperature increases or decreases the oil ﬂow from the circulating oil stream to the

burner. A proportional control valve on the atomizing steam line regulates the ﬂow of

steam to the burner in keeping with the oil ﬂow. Figure 13.29 shows a typical burner

control system.

SUPPORT SYSTEMS COMMON TO MOST REFINERIES 575

There are various methods for safety shutdown. The one shown here shuts down the

oil ﬂow on steam failure and on loss of the pilot burner. In some systems there is also

an automatic change over to gas ﬁring on low oil pressure.

Water systems

The major water systems generated in most chemical plants are:

Cooling water

Treated water for BFW

Potable water as raw water is usually drawn from municipal supply. Where water is

required for cleaning or drinking this potable water is used without further processing.

Cooling water

Figure 13.30 is a mechanical ﬂow sheet showing the arrangement around the base of

a cooling tower for the collection and supply of cooling water.

The cooling water system is a circulating one. That is there is a cold supply line with

an associated warmer return line from all its users. Figure 13.31 shows a section of

this distribution system.

The water returned to the cooling tower by the return header enters the top of the

tower and ﬂows down across the tower internals counter current to an air ﬂow either

induced or forced by fans passing up through the tower. The water cooled by the air

ﬂow is collected in the cooling tower basin. Make up water (usually potable water)

is added to the basin under level control. Vertical cooling water circulating water

pumps take suction from the cooling tower basin sump to deliver the water into the

plant’s distribution header. These pumps are usually high capacity with a moderate

differential head. Because of the critical nature of the water supply the pumps are

each rated at around 60% of design capacity with two in operation and two on stand

by. A mixture of motor and steam turbine drivers are quite common.

The supply header pressure is kept at around 30 psig and, very often in large plants

covering long distances, booster stations are installed at predetermined locations to

maintain the supply header pressure. These booster stations consist of pump pits

with again high capacity vertical pumps rated smaller of course than the main supply

pumps. The location of these booster stations is determined by a rigorous hydraulic

analysis of the distribution system which also determines the header pipeline sizes.

The return ﬂow is collected from each user into the return header and ﬂows back to

the cooling tower under the users’outlet pressure.

Figure 13.29. A burner control system.

Figure 13.30. Mechanical ﬂow diagram of a water cooling system.

578 CHAPTER 13

Figure 13.31. A diagram of a cooling water distribution system.

SUPPORT SYSTEMS COMMON TO MOST REFINERIES 579

The water in the cooling tower basin and in the cooling tower itself requires some

treatment to prevent the build up of algae and other undesirable contaminants. A

separate small treatment plant is used for mixing the inhibiting chemicals and injecting

them into the critical sections of the system.

Boiler feed water treating

All water contains impurities no matter from what source the water comes from. Ap-

pendix 13.2 gives a listing of the common impurities found in water for industrial

use. Normally, in a chemical plant, water with most of these impurities can be used

without treating of any kind. However when it comes to generating steam and par-

ticularly high-pressure steam these impurities become problematic. To operate steam

generators effectively and to avoid serious damage to the unit, these impurities either

have to be removed or be converted into compounds that can be tolerated in the sys-

tem. Appendix 13.2 also provides a description of the effect of these impurities on

steam generators and gives the normal means of treating.

In general there are three types of soluble impurities naturally present in water and

which must be removed or converted in order to make the water suitable for boiler

feed purpose. These are:

Scale forming impurities. These are salts of calcium, magnesium, silica, manganese,

and iron

Compounds that cause foaming. These are usually soluble sodium salts

Dissolved gases. These are usually oxygen and carbon dioxide. The soluble gases

must be removed to prevent corrosion

Solid build up in the boiler itself is removed or kept at a low level by blow down. This

is the mechanism of draining a prescribed amount of the boiling water from the boiler

steam drum at regular intervals. This amount is calculated from the analysis of the

solid content of the feed water and must equal the amount brought into the system by

the feed water. Figure 13.32 gives an example of boiler blow down.

The American Boiler Manufacturers Association (ABMA) have developed limits for

the control of various solids in BFW. These are given in Table 13.1.

Other considerations regarding the limits of solids in BFW are:

Sludge. This is a direct measurement of feed water hardness (calcium and magne-

sium salts) since virtually all hardness comes out of solution in a boiler.

Total dissolved solids. These consist of sodium salts, soluble silica, and any chemi-

cals added. Total solids do not contribute to scale formation, but excessive amounts

can cause foaming.

580 CHAPTER 13

Figure 13.32. How blow down reduces the amount of solids build up.

Silica. This may be the blow down controlling factor in pre-softened water con-

taining high silica. At elevated pressures high silica content can cause foaming and

carry over.

Iron. High concentration of iron in BFW can cause serious deposit problems. Where

concentration is particularly high blow down may be based on reducing this con-

centration.

There are two types of BFW treatment in use. There are the external type of treating

and the internal processes. As the names suggest the external processes are those that

treat the water before it enters the boiler. The internal treatments are those in the form

Table 13.1. ABMA limits of various solids in BFW

Boiler pressure Total solids Alkalinity Suspended

(psig) (ppm) (ppm) solids Silica

0–300 3500 700 300 125

301–450 3000 600 250 90

451–600 2500 500 150 50

601–750 2000 400 100 35

751–900 1500 300 60 20

901–1000 1250 250 40 8

1001–1500 1000 200 20 2.5

1501–2000 750 150 10 1.0

Over 2000 500 100 5 0.5

SUPPORT SYSTEMS COMMON TO MOST REFINERIES 581

of added chemicals that treat the water inside the boiler. Only the external processes

are described here.

The “hot lime” process

This is a water softening process which uses a hot lime contact to induce a precipitate

of the compounds contributing to the hardness. The sludge formed is allowed to

settle out. Very often coagulation chemicals such as alum or iron salts are used to

enhance the settling and the removal of the sludge formed. In most plants that use

the “lime”process the reaction by the addition of lime and soda ash is carried out at

elevated temperatures. However the reaction can be allowed to take place at ambient

temperatures. The hardness of the water from the “cold”process will be about 17–35

ppm while that from the “hot”process will be 8–17 ppm. Clean up ﬁlters containing

anthracite are often used to ﬁnish the treating process.

The ion exchange processes

As the name implies this process exchanges undesirable ions contained in the raw

water with more desirable ones that produces acceptable BFW. For example, in the

softening process, calcium and magnesium ions are exchanged for sodium ions. In

dealkalization, the ions contributing to alkalinity (carbonates, bicarbonates, etc) are

removed and replaced with chloride ions. Demineralization in this process replaces

all cations with hydrogen ions (H

), and all anions with hydroxyl ions (OH

−

) making

pure water (H

+ OH

−

The ion exchange material needs to be regenerated after a period of operation. The

operating period will differ from process to process and will depend to some extent

on the amount of impurities in the water and the required purity of the treated water.

Regeneration is accomplished in three steps:

Back washing

Regenerating the resin bed with regenerating chemicals

Rinsing

Figure 13.33 shows the internals of a typical ion exchange unit.

Under operating conditions the raw water is introduced through the top connection

and distributor. The water ﬂows through the resin bed where ion exchange takes

place. The treated water is removed via the bottom connection. Under regeneration

operation, raw water as backwash is introduced through the bottom connection and

removed from the top connection. During its passage upward through the resin and

support beds it “ﬂuffs”the beds and removes any waste material that has adhered

to them. The backwash water is then sent to the plants waste water disposal system.

582 CHAPTER 13

Figure 13.33. A typical ion exchange unit.

Regenerating exchange chemical is introduced directly above the resin bed through a

chemical distributor and allowed to ﬂow downward to be removed at the bottom water

outlet. The regenerating cycle is completed with the rinsing of the bed to remove any

surplus regenerating chemicals. This is done by introducing a stream of raw water at

the top connection and removing it from the bottom connection. This water is also

disposed to waste.

Normally ion exchange units are installed in pairs. When one is operating the other is

being regenerated. An automatic switch over of electronically controlled valves takes

the pair of units through the correct cycles at the prescribed time intervals, without

disrupting the treating process. Figure 13.34 shows a typical “hook up”of an ion

exchange unit.

Deaeration

The deaeration process is used in almost all BFW treatment to remove dissolved

gases from the water. Normally treated water and returned condensate are routed to

a deaerator immediately prior to entering the boiler steam drum. Figure 13.35 is a

drawing of a typical deaerator drum layout.

The drum consists of a retention vessel surmounted by a degassing tower section.

The degassing section contains a packed volume over which the treated water (and

condensate) stream is passed. Low-pressure steam, usually let down saturated 50 psig

steam or, if available 5 psig steam from condensate ﬂash is introduced to the bottom

of the degassing section. The steam ﬂows upward through the packed section and