Posts Tagged ‘plant layout’

Technical Information about the Spacing of Equipment in Petrochemical Plants

March 15, 2012 1 comment

Equipment spacing in the plant design and piping discipline is one area that continues to resist automation. Sure there are in-house and third party programs out there that assist designers in developing plot plans. Most of these programs are just overlays on CADD products. These 2D/3D CADD overlays may give feedback on costs of the arrangement – or – these 2D/3D CADD overlays may speed up the development of the plot by automating the generation of equipment graphics and structural graphics. However there are no tools out there that will arrange a plot plan automatically.
The main reason for this lack of equipment arrangement automation is the inability to develop rules that completely define how a list of equipment shall be arranged on a plot. The difficulty in defining equipment arrangement rules is due to the complexity involved.
Here is a partial list of the equipment arrangement design considerations that must be addressed on each project.

  • High hazard operations
  • Grouped operations
  • Critical operations
  • Number of personnel at risk
  • Concentration of property and business interruption values
  • Equipment replacement and installation time
  • Interdependency of facilities
  • Critical customer or supplier relationships
  • Market share concerns
  • Fire and explosion exposures
  • Corrosive or incompatible materials exposures
  • Vapor cloud explosions
  • Sources of ignition
  • Maintenance and emergency accessibility
  • Drainage and grade sloping
  • Prevailing wind conditions
  • Natural hazards and climate
  • Future expansions
  • External exposures

The design consideration for ‘Vapor Cloud Explosions’ alone is a subject that fills books. The analytical automation tools for studying Boiling Liquid Evaporating Vapor Explosions (BLEVE) are few and are proprietary. There is documentation on how to evaluate BLEVE impacts using hand calculations, such as the TNT equivalency method. However it is generally accepted that these hand calculation methods do a poor job of predicting BLEVE.
And BLEVEs are just one form of Vapor Cloud explosions! Other types of vapor cloud explosions require different analytical techniques.
So what does the designer do? Designers the world over generally rely on their company’s (or their client’s) table standard that lists how far one piece of equipment needs to be from another piece of equipment. These tables are typically generated based on experience – particularly the experience of the insurance industry. A sample chart from the Bausbacher/Hunt book is shown above.
The following pages are going to compare and discuss the various spacing criteria available in the public domain. We will also try to point out where these criteria conflict, and where they may be weak.
By the way, the picture to the right is of a recent explosion in a plant where the spacing criteria satisfied an insurance group’s requirements for equipment spacing. The initial explosion caused a domino effect that leveled three units.


Plant Layout – Storage Tanks

March 15, 2012 1 comment

Table of Contents
1. Tankage Grouping
2. Classification of Crude Oil and Its Derivatives
3. Tankage Layout
4. Pump Areas
5. Fire Protection
6. Road and Rail Loading Facilities

1. Tankage Grouping

Tankage area will be subdivided into various groups determined by the contents of the tanks and the relative shape and area of the plot available, access and fire fighting must also be considered. See below table API tank size for layout purposes.

2. Classification of Crude Oil and Its Derivatives

Crude oil and its derivatives are potentially hazardous materials. The degree of the hazard is determined essentially by volatility and flash point.
The Institute of Petroleum has specified the following classes:

Class 0 Liquified petroleum gases (LPG)
Class I Liquids which have flash points below 21 oC
Class II (1) Liquids which have flash points from 21 oC upto and including 55 oC handled, below flash point
Class II (2) Liquids which have flash points from 21 oC upto and including 55 oC handled, at or above flash point
Class III (1) Liquids which have flash points above 55 oC upto and including 100 oC handled, below flash point
Class III (2) Liquids which have flash points above 55 oC upto and including 100 oC handled, above flash point
Unclassified. Liquids with flash points above 100 oC

For further information see IP refinery safety code part 3.

3. Tankage Layout

3.1 General

The layout of tanks, as distinct from their spacing, should always take into consideration the accessibility needed for fire-fighting and the potential value of a storage tank farm in providing a buffer area between process plant and public roads, houses, etc. , for environmental reasons.
The location of tankage relative to process units must be such as to ensure maximum safety from possible incidents.
Primarily requirements for the layout of refinery tanks farms are summarised as follows.

  1. Inter tank spacings and separation distances between tank and boundary line and tank and other facilities are of fundamental importance. (See 3.2) .
  2. Suitable roadways should be provided for approach to tank sites by mobile fire fighting equipment and personnel.
  3. The fire water system should be laid out to provide adequate fire protection to all parts of the storage area and the transfer facilities.
  4. Bunding and draining of the area surrounding the tanks should be such that a spillage from any tank can be controlled to minimise subsequent damage to the tank and its contents. They should also minimise the possibility of other tanks being involved.
  5. Tank farms should preferably not be located at higher levels than process units in the same catchment area.
  6. Storage tanks holding flammable liquids should be installed in such a way that any spill will not flow towards a process area or any other source of ignition.

3.2. Spacing of Tanks for LPG Stocks of Class 0

Factor Recommendations for LPG Stored in Pressure Tanks
1. Between LPG pressure storage tanks One quarter of the sum of the diameters of the two adjacent tanks.
2. To Class I, II, or III product tanks. 15 M from the top of the surrounding Class I, II or III product tanks.
3. To low pressure refrigerated LPG tanks. One diameter of the largest low pressure refrigerated storage tanks but not less than 30 M.
4. To building containing flammable material e.g. filling shed, storage building. 15 M
5. To boundary or any fixed source of ignition. Related to water capacity of tank as follows :
Capacity Up to 135 cu.M Over 135 to 565 cu.M Over 565 cu.M Distance 15 M 24 M 30 M

The distance given in the above table are minimum recommendations for aboveground tanks and refer to the horizontal distance in plan between the nearest point on the storage tank and a specified feature, e.g. an adjacent storage tank, building, boundary. The distances are for both spherical and cylindrical tanks.

3.3 Bunding and Grouping of LPG Tanks

The provision of bunds around LPG pressure storage tanks is not normally justified.
Separation kerbs, low to avoid gas traps, maximum 600 mm high, may be located to prevent spillage reaching important areas, e.g. pump manifold area, pipe track.
Ground under tanks should be graded to levels which ensure that any spillage has a preferential flow away from the tank.
Pits and depressions, other than those which have been provided as catchment areas, should be avoided to prevent the forming of gas pockets.
Pressure storage tanks for LPG should not be located within the bunded enclosures of Class I, II or III product tankage or of low pressure refrigerated LPG tankage.
The layout and grouping of tanks, as distinct from spacing, should receive careful consideration with the view of accessibility for fire fighting and the avoidance of spillage from one tank flowing towards the other tank or towards a nearby important area.

3.4 Spacing of Tanks for Low Pressure Refrigerated LPG Storage Class 0

Factor Recommendations for Low Pressure Refrigerated LPG Storage
1. Between refrigerated LPG storage tanks One half of the sum of the diameters of the two adjacent tanks.
2. To Class I, II, or III product tanks. One diameter of the largest refrigerated storage tank but not less than 30 M.
3. To pressure storage tanks. One diameter of the largest refrigerated storage tank but not less than 30 M.
4. To process units, office building, work-shop, laboratory, warehouse, boundary, or any fixed source of ignition. 45 M

The distance given in the above table are minimum recommendations and refer to the horizontal distance in plan between the nearest point on the storage tank and a specified feature, e.g. an adjacent storage tank, building, boundary.

3.5. Bund or Impounded Basin for Refrigerated LPG Storage

A bund should be provided around all low pressure tanks containing refrigerated LPG. The tank should be completely surrounded by the bund, unless the topography of the area is such, either naturally or by construction, that spills can be directed quickly and safely, by gravity drainage and diversion walls if required, to a depression or impounding basin located within the boundary of the plant.
Bunds should be designed to be of sufficient strength to withstand the pressure to which they would be subjected if the volume within the bunded enclosure were filled with water. The area within the bund, depression, or impounding basis should be isolated from any outside drainage system by a valve, normally closed unless the area is being drained of water under controlled conditions.
Where only one tank is within the bund, the capacity of the bunded enclosure, including the capacity of any depression or impounding basis, should be 75 per cent of the tank capacity. Where more than one tank is within the main enclosure, intermediate bunds should be provided, so as to give an enclosure around each tank of 50 per cent of the capacity of that tank, and the minimum effective capacity of the main enclosure, including any depression or impounding basin, should be 100 per cent of the capacity of the largest tank, after allowing for the volume of the enclosure occupied by the remaining tanks. It is desirable for the required capacity to be provided with bunds not exceeding an average height of 6 foot as measured from the outside ground level.
The area within the bund should be graded to levels which ensure that any spillage has a preferential flow away from the tank.
No tankage other than low pressure tankage for refrigerated LPG should be within the bund. The layout and grouping of tanks, as distinct from spacing, should receive careful consideration with the view of accessibility for fire fighting.

3.6 Piping Installation and Flexibility

Liquid and vapour pipelines should have adequate flexibility to accommodate any settlement of tanks or other equipment, thermal expansion or other stresses that may occur in the pipe work system.
Precaution must be taken to prevent drain or sample valves freezing in the open position. The flow diagram will indicate the type of double valving to be installed, with a minimum distance between the valves of 1 meter. Do not allow liquid traps in vent lines.

3.7 Spacing of Tank for Petroleum Stocks of Classes I, II and III (2) .

Factor Type of Tank Roof Recommended Minimum Distance
1. Within a group of small tanks Fixed or Floating Determined solely by construction / maintenance operational convenience
2. Between a group of small tanks or other larger tanks. Fixed or Floating 10 M minimum, otherwise determined by the size of the larger tanks (see 3 below)
3. Between adjacent individual tanks (other than small tanks). (a)Fixed Half the diameter of the larger tank, but not than 10 M and need not be more than 15 M.
(b)Fixed 0.3 times the diameter of the larger tank, but not less than 10 M and need not be more than 15 M. (In the case of crude oil tankage this 15 M option does not apply)
4. Between a tank and the top of the inside of the wall of its compound Fixed or Floating Distance equal to not less than half the height of the tank. (Access around the tank at compound grade level must be maintained)
5. Between any tank in a group of tanks and the inside top of the adjacent compound wall. Fixed or Floating
6. Between a tank and a public boundary fence. Fixed or Floating Not less than 30 M
7. Between the top of the inside of the wall of a tank compound and a public boundary fence or to any fixed ignition source.

Not less than 15 M
8. Between a tank and the battery limit of a process plant. Fixed or Floating Not less than 30 M
9. Between the top of the inside wall of a tank compound and the battery limit of a process plant

Not less than 15 M

The table above gives a guidance on the minimum tank spacing for Class I, II and III (2) storage facilities, the following points should be noted.

  1. Tanks of diameter up to 10 M are classed as small tanks
  2. Small tanks may be sited together in groups, no group having an aggregate capacity of more than 8000 m3. Such a group may be regarded as one tank.
  3. Where future changes of service of a storage tank are anticipated the layout and spacing should be designed for the most stringent case.
  4. For reasons of fire fighting access there should be no more than two rows of tanks between adjacent access roads.
  5. Fixed roof with internal floating covers should be treated for spacing purposes as fixed roof tanks.
  6. Where fixed roof and floating roof tanks are adjacent, spacing should be on the basis of the tank(s) with the most stringent conditions.
  7. Where tanks are erected on compressible soils, the distance between adjacent tanks should be sufficient to avoid excessive distortion. This can be caused by additional settlements of the ground where the stressed soil zone of one tank overlaps that of the adjacent tank.
  8. For Class III (1) and unclassified petroleum stocks, spacing of tanks is governed only by constructional and operational convenience. However, the spacing of Class III (1) tankage from Class I, II or III (2) tankage is governed by the requirements for the latter.
  9. For typical tank installation, illustrating how the spacing guides are interpreted see below figures.

    For details of a typical vertical tank foundation see below figures.

3.8 Tank Farm Piping and Layout

Pipelines connected to tanks should be designed so that stresses imposed are within the tank design limits. The settlement of the tank and the outward movement of the shell under the full hydrostatic pressure should be taken into account. The first pipe support from the tank should be located at a sufficient distance to prevent damage both to the line and to tank connections. Consideration may be given to installing spring supports near to tank connection for large bore pipework.
As large diameter tanks have a tendency to settle on their foundations, provision must be made in the suction and filling piping to take care of tank settlement. This may require the use of expansion joints, victaulic couplings, or a lap joint flange installed as shown in see below figure.
The following note must be added to all piping drawings containing storage tanks:
“All piping must be disconnected from tank during hydrostatic test of storage tank”
The number of pipelines in tank compounds should be kept to a minimum. They should be routed in the shortest practicable way to the main pipe tracks located outside the tank compounds, with adequate allowance for expansion.
Flexibility in piping systems may be provided through the use of bends, loops or offsets. Where space is a problem suitable expansion joints of the bellows type may be considered for installation in accordance with manufacturer’s design specifications and guides. These expansion joints should be used only in services where the fluid properties are such that plugging of the bellows cannot occur. They should be anchored and guided, should not be subjected to torsional loads, and should be capable of ready inspection.
Tank farm piping should preferably be run above ground on concrete or steel supports. Ground beneath piping should be so graded as to prevent the accumulation of surface water or product leakage. Manifolds should be located outside the tank bunds.
Piping should pass over earth bund walls, however, if this is impossible, a suitable pipe sleeve will be provided to allow for expansion and possible movement of the lines. The annular space should be properly sealed. Likewise lines passing through concrete bund walls will be provided with pipe sleeves.
Pedestrian walkways should be provided to give operational access over ground level pipelines.
Pipelines should be protected against uneven ground settlement where they pass under roadways, railways or other points subject to moving loads.
Buried pipelines should be protected externally by corrosion preventing materials, or by cathodic means.
Routes of buried pipelines should be adequately marked above ground and recorded.
Pipe racks carried across paths or roads should have adequate clearance from grade. Adequate access stairways or ladders and operating platforms should be provided to facilitate operation and maintenance at tanks. Tanks may be interconnected at roof level by bridge platforming.
All nozzles, including drains on a tank shell, should have block valves adjacent to the tank shell or as close as practicable.

3.9 Tank Bund Compound Capacities

Above ground tanks for Class I, II (1), II (2) and III (2) petroleum liquids should be completely surrounded by a wall or walls. Alternatively, it is acceptable to arrange that spillage or a major leak from any tank are directed quickly and safely by gravity to a depression or impounding basis at a convenient location.
The distance between the edge of the impounding basin and the nearest tank or the inside top of the nearest bund wall should be a minimum of 30 M. The distance between the edge of the basin and road fence battery limit of a process plant should not be less than 15 M.
The height of the bund wall as measured from outside ground level should be sufficient to afford protection for personnel when engaged in fire fighting and the wall should be located so that a reasonably close approach can be made to a tank fire to allow use of mobile fire fighting equipment. Access roads over bund walls into very large compounds are helpful in certain fire situations.
Separate walls around each tank are not necessary, but the total capacity of the tanks in one bunded area should be restricted to the following maximum figures:

Single tanks No restriction
Groups of floating roof tanks 120,000 m3
Groups of fixed roof tanks 60,000 m3
Crude tanks Not more than two tanks of greater individual capacity than 60,000 m3

The figures for b. and c. may be exceeded for groups of not more than three tanks, where there can be no risk of pollution or hazard to the public.
Intermediate walls of lesser height than the main bund walls may be provided to divide tankage into groups of a convenient size so as to contain small spillages and act as fire breaks.
Buried, semiburied or mounded tanks need not be enclosed by a bund wall except when they are located in ground higher than the surrounding terrain. However, consideration should be given to the provision of small bund walls around associated tank valves.
The net capacity of the tank compound should generally be equivalent to the capacity of the largest tank in the compound. However, a reduction of this capacity of 75% will provide reasonable protection against spillage and may be adopted where conditions are suitable (e.g. where there can be no risk of pollution or hazard to the public). The net capacity of a tank compound should be calculated by deducting from the total capacity a. the volume of all tanks, other than the largest, below the level of the top the compound wall and b. the volume of all intermediate walls.
A low wall which need not be more than 0.5 m high, should be constructed for Class III (1) and unclassified petroleum product tankage where conditions are such than any spillage or leakage could escape from the installation and cause damage to third party property drainage systems, rivers or waterways.
Where there is a possibility that tanks storing these products may be in the future required for Class I, II (1) or III (2), then the compound walls should be suitable for this potential situation.

4. Pump Areas

Pumps will be located outside bund areas. The vessels practice is to group the pumps into bays. Keep the suction lines as short as practical. The discharge piping will run on low level tracks to the process or loading areas. These tracks will usually pass under roads in culverts, but may pass over on a pipe bridge. Long pipe runs may require expansion loops to provide flexibility. Consult with stress section.

5. Fire Protection

For storage areas the major fire fighting effort will be provided by mobile equipment laying down large blankets of foam and/or applying large volumes of water for cooling purposes.
It is essential to provide a good system of all weather roads to facilitate the transfer of fire protection materials and equipment to the scene of the fire. These roads must be of adequate width and, wherever possible, with no deadends.
It is important in the siting of tanks, bund walls and access roads that the tanks can be protected by cooling water or foam appliances situated outside the compound walls. Account must be taken of the height of the tank and the possible need to cool the roof or project foam on to a tank.
Dry risers for foam may be provided to the top of storage tanks with their connections adjacent to access roads, fixed monitors may also be employed. The flow diagram will define the system to be employed.

6. Road and Rail Loading Facilities

Road and rail loading facilities are usually associated with storage area. The safe location of these in relation to storage tanks is laid down in section 3.7.
The road or railcar will be filled from a loading island, the supply lines will be either routed underground, or on an overhead pipe bridge. Check for clearances.
Below figures show such installations.
It has become common practice to provide a vapour collection system for the safe removal of vapours during the loading process. This system would employ unloading arms which are connected to a collection system and piped to a vent stack at a safe location.
When laying out a loading area consideration must be given to the number of vehicles or rail cars per hour to be loaded. A suitable movement pattern must be established for incoming and outgoing vehicles or railcars. Weigh bridges will be required, the system of moving rail cars must be defined, building housing, operation offices and facilities for drives etc. , must be provided.
Based on API650

Capacity Approximately Diameter Height
US Barrels CU Meters Meters Meters













































































































Inter-tank spacings between small and larger tanks.

Figure 3.

Figure 4.

Inter-tank spacings for fixed and floating roof tanks (greater than 10 m diameter)
Lap joint Flange Detail for Tank Settlement
Figure 5.

Foundation for vertical tank
Based on BS2654
Figure 6.

Plant Layout – Column

March 15, 2012 Leave a comment

Table of Contents

  1. General
  2. Layout
  3. Internals
  4. Overheads
  5. Reflux
  6. Feeds
  7. Instruments
  8. Reboiler Connections
  9. Platforms
  10. Piping
  11. Top Head Relief Valves
  12. Clips

1. General

The fractionation column comprises a vertical cylinder interspaced at equal intervals with trays. Often these are in the form of simple perforated disks, but more complex arrangements occur depending upon column function. Contents are heated near the bottom producing vapours which rise up through the trays, meeting a flow of liquid passing down as a result of condensation occuring at various levels.
It is essential to ensure maximum surface contact between vapour and liquid. The lightest fractions are drawn from the highest elevations, the heaviest residue being deposited at the bottom.

2. Layout

It is necessary to establish whether column is working as a single unit or in conjunction with others similar. Dependent upon process arrangements flow may be sequential from one to the next. Thus for maximum economy order of columns must be arranged to give shortest piping runs and lowest pumping losses. Consideration should be given, where necessary, to material used, since although correct sequence may have been effected unnecessary expense may be involved with alloy lines. Such cases must be treated on their merits.
Column is interconnected with other process equipment so it must be located adjacent to pipe rack to allow piping connections to run to and from the rack in orderly fashion. Automatically this means that manways (provided for erection of trays and maintenance) should be located on the opposite side of the column away from the rack to provide suitable access for equipment required to be removed (see below figures). This is not mandatory since occasions arise when other arrangements are necessary.

3. Internals

Having located manways, orientate internal trays to ensure unimpeded access. Depending upon the type of tray used one or more downcomer partitions may be required. If these are orientated incorrectly entry will be impossible via manhole unless the column is exceptionally large. Preferably downcomers are arranged normal to manway access center line. Process connections can be located in logical sequence, starting from the top when tray orientation is established.

4. Overheads

Highest connection is the overhead vapour line which is usually connected to a condensing unit. An air fin type unit may be located on top of the pipe rack. Alternatively a shell and tube exchanger type condenser is usually located on a structure adjacent to the column (as may air fin unit).
Overhead vapour connection may project vertically from top of the column followed by a 90° bend or it may emerge from the side at 45°, using an integral projection extending up almost to the center top inside the head (see below figure 9).
The latter is more economic in piping since it eliminates use of some expensive fittings especially when large diameter overhead lines are involved. It also makes piping supporting simpler as use of a 45° elbow enables pipe to run down close to the column. Disadvantage is greater rigidity making stress analysis more difficult.
Often permitted pressure drop between outlet nozzle and exchanger is low (i.e. approximately 0.5 PSI) thus it is essential to obtain straightest and shortest run possible. If connection is from the top special arrangements must be made for supporting the line which is often large diameter.
The condenser is usually self draining. Often some of the condensed liquid is required to be pumped back into the column (reflux). Thus the condensed liquid flows by gravity to a reflux drum situated immediately below the exchanger. This drum can also be mounted in the same structure supporting the exchanger. This is important since if it were located elsewhere an additional pump would be required if the liquid had to be elevated again after flowing from the condenser.
Furthermore, since the liquid in the reflux drum has to be returned to the column by a pump it is convenient to locate this underneath the reflux drum at the base of the structure.
It follows, therefore, that the orientation of the outlet of the vapour connection will automatically fix the location of the exchanger and the reflux drum or vice-versa. The reflux pump discharges back into the tower usually at a high elevation, and since the piping should be straight and as short as possible, it will probably come up at the side as the vapour connection.

5. Reflux

Trays are numbered starting from the top. The first downcomer is therefore an odd one. Often the reflux connection is located above the top tray (see below figure 3). This means that orientation of the odd and even trays can be fixed since to utilize the tray contact surface, the reflux connection must occur on the opposite side of the downcomer.

6. Feeds

The most important connections are the feeds (see figures 4 and 6). These may occur over the odd or even trays or a combination of both. Their elevational location is entirely a function of process design. Depending upon this, orientation of the nozzle will follow, but ensure that the nozzle is not located behind the downcomer from the tray above. This would result in a liquid build up in the downcomer restricting flow through the tray below and preventing correct operation.
Feed connections are usually located in the tray area between the downcomers in a manner to ensure maximum use of the tray area as possible. Often an internal feed pipe or sparger is used to facilitate this.

7. Instruments

Instr ument connections must be arranged so that pressure connections are in the vapour space and temperature connections are immersed in the liquid.
Sometimes it is better to put the temperature connections in the downcomer part of the tray since the depth of liquid will be greater and it will be easier to obtain effective coverage.
Probe length and mechanical interference may prevent this, if so locate thermowell over the tray itself. This should be done only on installations where the liquid depth on the tray is sufficient (see below figure 8).
The base of the tower contains a level of liquid which is controlled by high and low level controllers, liquid level alarms and level gauges (see below figure 7). Care should be taken when orientating these instruments, that they do not obstruct access on the platform. Physical space that these instruments occupy can be excessive. Do not position immediately adjacent to ladders or manholes.

8. Reboiler Connections

Reboiler liquid and vapour connections are located either relevant to liquid head (elevation) or stress requirements, or both. Two configurations are possible :

  1. Vertical
  2. Horizontal

For horizontal reboilers, consideration must be given to shortest most direct connection route to reduce pressure drop which will probably govern design layout. In both cases there may be support problems. Usually, a vertical reboiler (thermosyphon operated) offers the easiest solution.
Flexibility is obtained on the lower connection where entry into the bottom of the tower can be varied as required and support problems are simplified.

9. Platforms

All of the above requires access of some kind. To minimise cost minimum platforming should be provided consistent with safety.
Orientation arrangements should be designed to avoid need for 360° platforms.
A platform should not extend almost entirely round the column simply to provide access to a temperature connection which could have been located on the oposite side. Where several columns may be working together, link platforms may be required to move from one to the next. In these cases strict consideration must be given to maximise economy.
Overall height is governed by a. number of trays, b. pump NPSH requirements and, c. static liquid head. This latter head necessary for thermosyphon reboiler establishes the skirt height.

10. Piping

Some circumstances require routing lines partially around the column. Should these lines cross a platform sufficient headroom clearance must be provided.

11. Top Head Relief Valves

Relief valves vary in number and size. Location can depend on whether discharge is to atmosphere or a closed system. If discharging to a closed system, locate at a convenient platform down the column above the relief header see below figure 5). If discharging to atmosphere locate on top of the column, with the open end of the discharge a minimum of 3000 mm above the top platform. For maintenance removal, valve should be located to allow top head davit to pick it up. Dependent upon size multiple relief valves may require a gantry structure on the top head.

12. Clips

Early orientation of nozzles and routing of lines allow platforms and pipe support clip locations to be passed to column vendor quickly.
It is becoming more a requirement that clips be welded on in the vessel fabrication shop particularly for alloy steels.
When locating platforms and ladders, the maximum ladder length should not exceed 9M without a rest platform.
Platforms should, where possible, be elevated 900 mm below manways.
Manways Davits or hinges should be positioned to avoid swing of cover fouling instruments or other connections.
When positioning vertical piping, to simplify supporting, attain a common back of pipe dimension from column shell of 300 mm.

Figures 1 – 8 Incl.

Plant Layout – Compressors

March 15, 2012 1 comment

Table of Contents

  1. Introduction
  2. Reciprocating Compressors
  3. Centrifugal Compressors
  4. Drives

1. Introduction

Compressors are the mechanical means to increase vapor pressure, as pumps are used to increase liquid pressure .
There are two basic types of compressors, reciprocating and centrifugal. Each has one specific duty to intake vapor at low pressure, compress it and discharge it at a higher pressure. The quantity of vapor to be moved and discharge pressure it usually the deciding factor in the type selected .

1.1 Reciprocating compressors

Reciprocating compression is the force converted to pressure by the movement of the piston in a cylinder. These machine are generally specified for lower volumes than centrifugal compressors. If several stages of compression are employed, extremely high pressures may be developed. Because of their reciprocating action these machines cause piping, if not properly designed and supported, to pulsate, vibrate and generate fatigue .

1.2 Centrifugal Compressors

Centrifugal compression is the force converted to pressure when a gas is ejected by an impeller at increasing velocity. Centrifugal compressors are specified for large quantities of vapor. Pressure differential may be small or large. These machines are not subject to pulsation and therefore do not produce vibrational effects .

1.3 Compressor Drives

Drivers fall into three categories, i.e. electric, steam and gas.
Electrical drivers range from small flameproof motors to large motors, 2000 HP or more, requiring their own cooling systems . Steam drivers are comprised of single or multistage turbines, either fully condensing of backpressure . Gas drivers cover gas turbines or gas engines.

2. Reciprocating Compressors

2.1 Types of Machines

Reciprocating compressors can be obtained in a variety of patterns from a simple single cylinder to multicylinder multistage machines. See figure 1,2,3 for the most widely used patterns.
Figure 1 below is a single cylinder machine. It will operate at low speed, may be single or double acting.
Figure 2 is a balanced horizontally opposed multicylinder machine. It will operate at low speed, may be single or double acting, it can also be multistage .
Figure 3 is a gas fuelled angle – type engine. The compression cylinders are all on one side of the frame, cylinder diameters and lengths vary according to the composition, pressure and volume of gas to be compressed. Dimensions from frame center line to cylinder nozzles will vary with compression forces.

2.2 Types of Cylinders

Figure 3. Gas engine driven machine (note: gas engine may take ‘V’ form)
Figures 4,5 for details of cylinder arrangements.
Figure 4: single acting cylinder, having one suction, compression and discharge area per cylinder.
Figure 5 : double acting cylinder, having two suction, compression and discharge areas per cylinder.
Multicompression stages : number of times the vapor is compressed by going through a series of compression cylinders to increase pressure.
Gas compression raises temperature. In a reciprocating machine, compression is violent and heat rise is great. Inlet temperatures of 40 oC may be raised to over 100 oC by the act of compression. The cylinder gets hot and depending on the vapor being compressed, will need some form of cooling. This will usually be in the form of cooling water, but for low heat increases a glycol – filled jacket may suffice .

2.3 Compressor Foundation, Cylinder and Snubber Supports

The foundation for LP reciprocating compressors must be independent from all other foundations. It must support the compressor and all its auxiliary equipment.
Cylinder supports are supplied by the vendor if they are required.
They must be attached to the foundation concrete. Likewise the snubber supports must be attached to the foundation concrete, springs will be used locally to support the snubbers .

2.4 Compressor Layout

Effective compressor layout results in cost savings on process and utility piping, good maintenance accessibility and possibly reduced pulsation in suction and discharge piping. Poor layout does the opossite.
For angle type compressors, locate the crankshaft parallel to the suction and discharge headers. For balanced horizontally opposed compressors, the crankshaft should run at right angles to the suction and discharge headers. Compressor houses containing more than one machine, particularly if they are long, will probably be equipped with a travelling gantry crane which will be manually or electrically operated. This feature can influence the overall dimensions of the house, as in addition to the necessary building and maintenance clearances, the vertical reactions of the loaded crane will increase foundation size. Since these must not be connected to the machine foundations, the building size will be affected. It is usual for compressor vendors to indicate the overall foundation dimensions on their layout drawings. (These should be requested as early as possible).
The compressor building must be sized very early in the layout stage when only preliminary dimensions are available. It may be known that the overall length of the machine is 6 meters and the width is 4 meters. To these dimensions must be added adequate clearance for maintenance plus possible control valve stations, lube oil equipment, local control panel, etc. Allow 2 meters all around the original dimensions. In practice this 2 meter allowance will provide a walkway of only 1200 – 1500 mm due to other items occupying floor space. With two or more machines, allow 2 meters between compression cylinders to allow for adequate piston removal. All dimensions must be confirmed from certified vendor drawings.
Allow a maintenance area at one end of the building. A 6 meter bay should be sufficient . Pits, trenches and similar gas traps should be avoided in gas compressor houses . Large reciprocating gas compressors will usually be elevated abovegrade with mezzanine floor level with the top of the foundation for operation and maintenance. The height of the mezzanine floor abovegrade will be kept to a minimum consistent with the adequacy of space for piping and access, especially to valves and drains .

2.5 Piping Layout

The piping layout will follow the plow diagrams as issued for the job. If they conflict with any of the following notes, the flow diagrams will always take precedence. It is usual for the suction piping to be routed to the top of the cylinder and discharge piping from the bottom. Liquids must be prevented from entering the compressors. As liquids do not compress, extensive precautions must be taken to ensure that absolutely no liquid enters the compressor cylinder ; a small quantity would do extensive damage.
If there is any doubt that the vapor is near its dew point, the suction line must be steam traced between the suction drum and the compressor inlet or local to the compressor inlet. Process Department will advise the extent and it will be shown on the flow diagram.
Suction and discharge headers will be located at grade level on sleepers up to the first piece of connecting equipment, e.g. suction KO drum or aftercooler. Branch connections to the compressor from the suction header will be taken from the top of the header . Suction and discharge piping will be kept as straight as possible between the compressors and headers. The use of short radius bends or tees and similar installations giving opposed flow shall not be permitted .
Piping shall not be less than compressor nozzle size. Piping local to cylinders shall clear the cylinder by sufficient distance to permit proper maintenance on the cylinder valves. When compressors are elevated with a mezzanine floor, piping and valves will normally run under the floor.
When more than one compressor is employed on the same service, all piping to and from the compressors will be valved so that any compressor may be shutdown and taken out of service. Spectacle blindes will be installed at the compressor side of the isolating valves.
Startup bypasses are to be installed between suction and discharge pipes of compressors and will be located between the compressor and the line block valve. When not furnished by the manufacturer, a relief valve will take be installed between the compressor discharge and block valve. This relief valve will discharge into the suction line downstream of the block valve. The relief valve will be provided with a bypass for hand venting.
Distance piece and packing vent piping will be manifolded into systems as indicated on the flow diagrams. These systems are either vented to atmosphere outside the compressor house or connected to a collection system.
Utility piping will comprise cooling water supply and return to lube oil cooler also to cylinder jackets. The minimum line size used will be 3/4” . Sufficient vents and drains will be provided so that water lines and jackets may be completely drained at shutdown. A steam or electrical supply may be required if lube oil heaters are provided for either the compressor or gear box oil. This system is used prior to startup.
Check for lines that have to be chemically and ensure drawings indicate this requirement .

3. Centrifugal Compressors

3.1 Types of Machine

Centrifugal compressors can be obtained in a variety of patterns. See figure 8. Centrifugal Radial Compressor
Centrifugal radial compressors ( figure 8) : the compression process is effected by rotating impellers of radial flow design ( figure 9 Radial Impellor) in fixed guide elements.
Centrifugal axial compressors ( figure 10) : the force is converted into pressure by rotating vanes between fixed guide vanes; the flow is axial .

3.2 Size and Position of Nozzles

Centrifugal compressor manufacturers have basic case designs; they change the rotor blade design to meet volume and pressure requirements. For this reason suction nozzles are sometimes much larger or smaller than the line size for hydrocarbon process applications. For example, a 30” suction nozzle may have a 20” or 24” suction line. It will be necessary to increase the suction line diameter locally at the compressor nozzle. Do not use a reducing flange as this will introduce full velocity to the rotor blades at a turbulent condition. Use 30” flange and a concentric reducer as a minimum. It is better if a pipe length of 3 dias of 30” pipe can also be accommodated .
Suction and discharge nozzles are either on the underside or the top of the compressor. On multistage compressors two or more inlet nozzles may be provided ; the suction lines are connected to suction drums controlled to maintain the various inlet pressures .

3.3 Compressor Foundations

(See fig.10 Centrigfugal axial compressors)
The foundation of each machine will be combined with its direct coupled drives but must be independent from all other foundations, including the lube console .

3.4 Compressor Layout

(See fig. 11,12,13 below)
Centrifugal compressors are usually large capacity machines. They are driven by electric motors, steam or gas turbine, the drive may be via a gearbox. It is usual to mount such machines on a tabletop about 4 meters high with elevated access all around. The lube and seal oil consoles for both the compressor and turbine, if used, will be located at grade. The suction and discharge connections of the compressor will most likely be on the underside; these lines can be anchored at grade. Should these connections be on the top of a horizontally split case compressor, see fig 13 for details of removable spools.
A typical compressor house layout is shown in figures 11 and 12. Here an electrical motor and a condensing type turbine has been used. Note the withdrawal and maintenance areas, also the acoustic hoods. Determine the type of travelling gantry crane, and ensure that piping, etc. is clear of it. Note the lube oil header tanks, these must be elevated above the machines, if the vendor has not stated a minimum elevation use 10 meters above the center line of the machines.
Their purpose is for emergency lubrication, and are tripped – in should the normal lubrication supply system fail. They supply oil to the bearings until the machine comes to a standstill .
The lube and seal oil consoles are comprised of the following items : oil storage tank, filters, pumps, oil cooler, sometimes an oil heater for startup, control instruments.
Interconnecting piping must be in accordance with the flow diagram, all return lines must be free – draining from the machines to the console.
Suction and discharge piping must be supported so that the nozzles are not overloaded, use reducers not reducing flange local to suction and discharge nozzles. Make provision for removal of strainers in the inlet line. Silencers may be required in both the suction and discharge piping.
Acoustic hoods may be required for both the compressor and turbine ; ensure that the tabletop is large enough to accommodate them. They may be of sectional construction. The travelling gantry crane will be used to dismantle them; this must be taken into consideration when determining the elevation of the crane hook.
Maintenance area must be large enough to accommodate the acoustic hood, turbine and compressor half casing rotors, etc.

4. Drives

4.1 Electrical Motors

Flameproof motors will be employed for small to medium HP machines.
Ensure that the cables can be routed to the terminations, also that there is space behind the motor to remove the rotor .
Large HP machines their own cooling systems ; these fall into two categories : CACW (close – air – circuit water cooled machine ) or CACA ( closed – air – circuit air cooled machine ) . These types of machines may require an area of 7 m x 7 m and, therefore, determine the size of the compressor house.
CACW machines (see fig. 14) : may be mounted on a tabletop with the cooler located under, in a sealed room. The cooling air circulating around the motor is itself cooled by water cooled heat exchanger. Provision must be made for removal and service of the exchanger.
It is possible to obtain motors with the cooler mounted above or to one side of the motor.
CACA machine consideration must be given regarding the safe location of the air intake, which will be outside the compressor house. If a filter is required in the intake system, provide access for replacement or cleaning .

4.2 Steam Turbines

Two types of steam turbines must be considered, condensing and noncondensing. The noncondensing type uses high pressure steam and exhausts lower pressure steam to a stream header. The condensing turbine exhausts to a surface condenser (which is usually a large exchanger with hot well attached, but may take the form of an air fan ) to recover condensate. Surface condensers are often grade-mounted directly below the compressors turbine. This arrangement employs a turbine with outlet nozzle directly connected via an expansion joint to the surface condenser. (See fig.16 ) . The surface condenser may be mounted at grade alongside a grade-mounted turbine. With arrangement very little NPSH is available.
If an air fan is used as a surface condenser it will usually be located above the turbine, either on the compressor house roof or over a pipe rack. If the condenser is the shell and tube type, it will most likely be of the fixed tube plate design and will require access for rodding the tubes. The cooling water lines associated with the condenser are large bore and some consideration must be given to the piping arrangement and placing of valves to give good operation and utilization of plot space.
The steam supply to the turbine will be taken from the top of the steam header, a bellow may be required local to the turbine and a temporary strainer will be used for startup.
The turbine will required a similar lube oil console to that provided for the compressor. Do not pocket the return drains. An elevated lube oil header tank also be required.
Noncondensing turbine assemblies comprise a turbine, lube oil console and header tank. The low pressure steam discharge line will be a large bore, a bellow will most likely be required in the line, which must join the top of the header. If the line has a low point, a steam trap and drip pocket must be provided.
Maintenance access : provision must be made to dismantle the acoustic hood, and remove half of the turbine casing and the rotor .

4.3 Gas Turbines

When using a gas turbine to drive a compressor, a similar arrangement to a steam turbine can be used; the lube oil console and header tanks will be required. In addition, the exhaust system must be considered; this will be comprised of ducting to some heat recovery system, either a steam raising plant or process heaters.
Combustion air to the turbine burner must be taken from a safe location outside the compressor house. Inlet silencer and filter will most likely be required. Provision for operation and maintenance to all machinery must be provided .

4.4 Gas Engines

Gas engines are used to drive reciprocating compressors, either directly or through a gearbox. The machine may have both compression and drive cylinder attached to a common crankshaft. These types of engines may develop 2,000 HP or more. Ensure that adequate space is allowed for removal of cylinder heads and pistons. The lube oil system may be integral with the engine that or in the form of a console. Should the latter be used, ensure that the engine is at suitable elevation to allow for free-draining oil return lines. (see fig.17)
The engine and compressor will be mounted on a common foundation that is independent of all other foundations. Due to the vibration produced by these machines, a large mass concrete foundation will be employed.
The general layout of the compressor house will enable the use of a travelling gantry crane for all maintenance, therefore when routing piping this must be considered. It is not likely that a mezzanine floor will be employed local to the machines, enabling most of the piping to be kept low.
Combustion air must be taken from a safe location outside the compressor house. If an air filter will be required, arrange for maintenance access. Likewise, the exhaust must be discharged outside the building.
This system will be fitted with a silencer and flame trap. Utility systems will comprise a start-up air system, also fuel gas. The engine will most likely have a closed circuit jacket water cooling system.
This will comprise a shell and tube exchanger or an air fan. If the former, cooling water supply will be required and the usual clearance for tube pulling, etc. will be provided. (see fig.18).

Figures incl.




Plant Layout – Exchangers

March 15, 2012 Leave a comment

Table of Contents

  1. Use of Exchangers
  2. Types of Exchangers
  3. Types of Shell and Tube Exchangers
  4. Layout of Shell and Tube Exchangers in Banks
  5. Alterations That Can Be Made to Shell and Tube Exchangers
  6. Establishing Elevations of Exchangers
  7. Piping
  8. Layout of Exchangers Other Than in Banks
  9. Types of Air Fins
  10. Layout of Air Fins
  11. Piping
  12. Fin Tube Exchangers
  13. Chillers

1. Use of Exchangers

Heat exchangers transfer heat from one media to another. In the petrochemical industry, they can be generally classified under the following headings :
Exchanger: Heats one stream and cools the other. There is no heat loss and physical change in either flowing media.
Cooler: Cools liquid or gases without condensation; applies also to intercooler and aftercooler.
Condenser: Condenses vapour or vapour mixture. Can be water – cooled or by sufficiently cold process stream which requires heating.
Chiller: Uses refrigerant for cooling process stream below freezing point or bellow prevailing cooling water temperature.
Heater (non fired) Heats process stream generally up to its boiling point without appreciable vaporization. Heating medium is usually steam; applies also to preheaters.
Reboiler: Reboils the bottom stream of tower for the fractionation process. Heating medium can be steam or hot process stream. When large quantities of vapor have to be produced the kettle type reboiler is used.
Waste heat boiler: Uses waste heat, such as internal combustion exhaust from gas turbines or similar drivers for steam generation.
Steam generator: Uses heat of process liquid or gas for producing steam.
Vapourizer: Vapourizes part of a process liquid stream as does an evaporator.

2. Types of Exchangers

Briefly, exchangers, etc. , can be divided into the following three groups :
Shell and tube: Which can be vertical or horizontal with the horizontal ones single or stacked in multi-units. As the name suggests, they consist of a cylindrical shell with a nest of tubes inside.
Fin tube:This consist of a finned tube through which passes one media jacketed by another tube through which passes the other media. They can be used as single or multi – units.
Air fins: Come in two shapes ; flat box units and “a” frame units. Both consist of banks of finned tubes through which passes the media to be cooled. Large fans blow air from atmosphere through the banks, thus cooling the flowing media. There are other types, such as plate exchangers, carbon block exchanger, etc., but these are used infrequently.

3. Types of Shell and Tube Exchangers

Floating head exchangers are used when the media being handled causes fairly rapid fouling, and the temperature creates expansion problems. Tubes can expand freely ; channel head and shell cover arrangement is convenient for inspection, and the tube bundle can easily be removed for cleaning.
U-tube exchangers are used when fouling of the tubes on the inside is unlikely. The tubes are free to expand and the bundle can be removed from the shell for cleaning on the shell side of tubes.
Fixed head exchangers have no provision for the tube expansion and unless a shell expansion joint is provided can only be used for relatively low temperature service.
The end covers are removable so that the inside of the tubes can be cleaned by rodding or other similar tools. This type of cleaning is usually carried out in situ so some space should be allowed in the piping layout to allow for this.

4. Layout of Shell and Tube Exchangers in Banks

For good maintenance and safe working conditions, it is necessary to space exchangers such that surrounding area is adequate and clear. They may be spaced apart and grouped in pairs. When apart, a clear access way of 750 mm is considered adequate, this being the clear space between the shells and/or the associated pipework and insulation. For paired exchangers a similar condition is required between pairs and adjacent singles, but between each shell of the pair this may be reduced to 450 mm between head flanges. Exchangers should always be arranged such that the ideally there is a minimum of 150 mm clear at the rear for removal of the bonnet and space provided for dropping it clear of the working area. At the front or channel end, a minimum distance of the tube length plus 2500 mm is considered good. This latter does not of course apply to exchangers located in structures were a total of 1500 mm would be sufficient.
Piping connected to heat exchangers is generally simple. Piping economy and good engineering design depend largely on knowing what alterations can be made to exchangers. In other words, the piping designer can influence the exchanger design. For example, the direction of flow, nozzle locations, etc. Alterations to exchangers of course, should not affect their duty and cost.
Money saved on simpler piping should not be spent on costly alterations to exchangers. The accompanying chart shows the possible alterations that may be instigated by the piping designers to typical shell and tube exchangers without affecting the thermal design. When contemplating such a change it should be remembered that generally the heated media should flow upward, and the cooled media flow downward. This is particularly important if there is a physical change taking place within the exchanger, such as vaporization or condensation. Typical example of this are:
Reboilers where the process stream enters the shell at the bottoms as a liquid and leaves at the top as a vapour after flowing through the tubes, and stream enters the shell near the top of the tubes and leaves at the bottom on the shell as condensate.
Condensers where the process stream enters the shell at the top as a vapour and leaves the bottom as a liquid, whilst cooling water enters the tubes side at the bottom and leaves at the top.

5. Alterations That Can Be Made to Shell and Tube Exchangers

Interchange, flowing media between the tube and shell side. This change is often possible, more so when the flowing media are similar, for example, liquid hydrocarbons. Preferably the hotter media should flow in the tube side to avoid heat losses through the shell, or the necessity for thicker insulation.
Change direction on flow on either tube or shell side. On most exchangers in petrochemical plants, these changes are frequently possible without affecting the required duty of the exchanger if the tubes are in double or multi – pass arrangement and the shell has cross flow arrangement.
In exchangers where counterflow conditions can be arranged, changing of flow direction should be made simultaneously in tube and shell. Some points to consider when contemplating a flow change are :
Shell leakage : When water cooling gases, liquid hydrocarbons or other streams of dangerous nature it is better to have the water in the shell and the process in the tubes, since any leakage of gas, etc. , will contaminate the water rather than leaking to atmosphere.
High pressure conditions : It is usually more economical to have high pressure in the tubes than in the shell as this allows for minimum wall thickness shell.
Corrosion : Corrosive fluids should pass through the tubes, thus allowing the use of carbon steel for the shell.
Fouling : It is preferable to pass the clean stream through the shell and the dirty through the tubes. This allows for easier cleaning. Mechanical changes, such as tangential or elbowed nozzles can sometimes assists in simplifying the piping or lowering stacked exchangers.

6. Establishing Elevations of Exchangers

Where process requirements dictate the elevation, it will usually be noted on the P and I diagram.
From the economic point of view, grade is the best location, where it is also more convenient for the tube bundle handling and general maintenance. Exchangers are located in structures when gravity flow is required to the collecting drum, or where the outlet is connected to a pump suction which has specific NPSH requirements. To elevate exchangers without specific requirements, the following procedure is recommended :
Select the exchanger with the largest bottom connection; add to the nozzle standout dimension ( center line of exchanger to face of flange ) the dimension thru hub of flange, elbow (1 1/2 dia ), one – half the O/S pipe diameter and 300 mm for clearance above grade.
Now subtract the center line to under-side of support dimension from above, and the dimension remaining is the finished height of the foundation including grout.
It is preferable if this foundation height can be made common for all the exchangers in the bank. If this is impracticable due to extremes of shell and/or connection pipe sizes, then perhaps two heights can be decided upon.
When stacking exchangers, two or three high, it is desirable that overall height does not exceed 12’ 0” (3650 mm ) due to the problem of maintenance, bundle pulling, etc.

7. Piping

Plan-wise the exchanger bank should be laid out spaced as noted previously, and all the channel nozzles on a common center line.
This is particularly important if the cooling water headers are underground, as the CW inlets can rise into the lower channel nozzles.
The end of the exchanger adjacent to the rack will normally be the fixed end, if the CW headers are underground the fixed end will become the channel end.
All changes proposed must be discussed fully with Process Engineer and Client Engineer or Vessel Department.
Lines turning right in the yard should be right from the exchanger center line and those turning left should approach the yard on the left-hand side of exchanger center line. Lines from bottom connections should also turn up on the right or the left side of exchangers depending upon which way the line turns in the yard. Lines with valves should turn towards the access aisle with valves and control valves arranged close to exchanger. Utility lines connecting to a header in the yard can be arranged on any side of exchanger center line without increasing pipe length.
Access to valve handwheels and instruments will influence piping arrangement around heat exchangers. Valve handwheels should be accessible from grade and from a convenient access way. These access ways should be utilized for arranging manifolds, control valves and instruments.
In the piping arrangement, provision for tube removal access should be provided. This means a spool piece of flanged elbow in the pipe line connecting to the channel nozzle.
The requirements of good piping layout generally apply to the design of heat exchanger piping. The shortest lines and least number of fittings – temperature permitting – will obviously provide the most economical piping arrangement. The designer should avoid loops, pockets and crossovers, and he should investigate, nozzle to nozzle, the whole length of piping routed from the exchanger to some other equipment, aiming to provide not more than one high point and one low point, no matter how long the line.
Very often a flat turn in the yard, an alternative position for control valves or manifold, changed nozzle location on the exchanger, etc. , can accomplish this requirement.
Avoid excessive piping strains on exchanger nozzles from actual weight of pipe and fittings and from forces of thermal expansion.
For valves and blindes the best location is directly at the exchanger nozzle. In the case of an elbow nozzle on an exchanger it should be checked that sufficient clearances are provided between valve handwheel and outside of exchanger. Elevated valves may require a chain operation. The chain should hang freely at accessible spot near the exchanger.
Below figure shows sketches highlighting exchanger piping details. Orifice flanges in exchanger piping are usually in horizontal pipe runs. These lines should be just above headroom, and the orifice itself accessible with mobile ladder. Orifices in a liquid line and mercury type measuring element require more height. At gas lines the U-tube can be above the line with orifice, consequently the height is not critical. Lines with orifice flanges should have the necessary straight runs before and after the orifice flanges required in specification or standards.
Locally mounted pressure – and temperature indicators on exchanger nozzles, on the shell or process lines, should be visible from the access aisles. Similarly gauge glasses and level controllers on exchangers should be visible and associated valves accessible from this aisles. When arranging instrument connections on exchangers sufficient clearances should be left between flanges and exchanger support between instruments and adjacent piping. Insulation of piping and exchangers should also be taken into account.

8. Layout of Exchangers Other Than in Banks

Process equipment in most plants is arranged in the sequence of process flow. However, whatever layout system is used, the general evaluation regarding exchanger positions is very similar.
In layout the fractionation towers should be located in proper sequence first, although often the arrangement of other equipment – for example, condensers depend directly upon the tower orientation, and sometimes the decision whether to use a structure or not depends upon this. This relative position of exchangers can be readily evaluated from flow diagrams. For exchanger positions in a petrochemical plant the following general classification can be made.
Exchangers which must be next to other equipment. Such exchangers are the reboilers which should be located to their respective towers, or condensers which should be next to their reflux drums close to the tower.
Exchangers which should be close to other process equipment. For example, exchangers in closed pump circuits such as some reflux circuits. Overhead condensers should also be close to their tower to ensure that the line pressure drop in minimal. In case of tower-bottom-draw-off-exchanger-pump flow, exchangers should be close to the tower or drum, to give short suction lines.
Exchangers located between distant items of process equipment. These are for example, exchangers with process lines connected to both shell and tube side. Where parallel run is the ideal location for this type of exchanger. On that side of the yard, where the majority of related equipment is placed. Other locations will cost more in pipe runs.
Exchangers located between process equipment and the unit limit. Such exchangers are for example product coolers. These are frequently located near the unit limit.
Stacked exchangers. A further step in the layout is to establish which exchangers can be stacked for simplifying piping and saving plot space. Most units in the same service are grouped automatically. Two exchangers in series or parallel are usually stacked. Sometimes, small diameter exchangers in series can be stacked three high. Two exchangers in dissimilar services can also be stacked. Sufficient clearance must be provided for shell and channel side piping between the two exchangers. Reboilers and single condensers usually stand by themselves beside their respective towers. Vertical thermosyphon reboilers are usually hung from the side of their associated tower.

9. Types of Air Fins

There are two types of air fin construction : the box type and the “A” frame type.
The box type can be divided into two forms : forced draught and induced draught.
Forced draft air fins are the most commonly used type, possibly because maintenance of the fan is easy from an underslung platform.
“A” frame type air fins less common than the box type.
They offer the advantage of requiring less plot area than box type air fins of the same capacity. They do, however, present a few problems. Due to physical shape of them, i.e. triangular section with the apex uppermost, the inlet header is located at the apex, with the collecting headers at both bottom corners. This means that cooled product lines are coming off both sides of the rack which can present piping problems. Also, with 60o sides containing the product, it is possible to get uneven cooling due to the sun being on one side, or the prevailing wind tending to blow into the tube bank against the fan.

10. Layout of Air Fins

Air fins are large compared with shell and tube exchangers, and it is not uncommon for them to occupy several thousand square feet of plot area on a unit.
If this plot area is required at grade, there could well be siting problems, but fortunately most process using air fins require a gravity feed through them, which means they must be elevated.
The most common satisfactory location is on top of the main pipe rack. Pipe rack width is invariably determined by tube length of air fin units. In the absence of sufficient room on the rack, they may be located on top of any suitable structure, or an elevated structure may be built for the purpose.
When locating air fins on the plot a number of points have to be borne in mind.
Air fin of a given capacity could be made up of several units each weighing several tons.
It is important that each unit be reached by the site crane for erection and maintenance purposes. Therefore, the overall plot layout must provide for this crane access.
As most air fins will be condensing overheads from towers, it is important to consider the explanation problems of the overhead line when siting the relevant air fin, as air fins are unsuitable for accepting high loads on the nozzles.
Access platforms are always provided either side of the air fin for access to the header boxes, and underneath the units for access to fans and motors. Provision must be made for grade to all these platforms at least at either end.
It is a good idea to investigate connecting these access ways to adjacent structures to provide intermediate escape and for operational convenience.

11. Piping

There are four major problems when piping-up airfins :

  1. Correct configurations of piping to give equal or as near equal distribution as possible of the product through each unit of multi-unit air fins.
  2. Make piping from tower overhead as short as possible to minimize pressure drop.
  3. Obtaining a piping system that is sufficiently flexible to avoid overloading the unit nozzles.
  4. Providing sufficiently suitable pipe supports and anchors.

Below figure shows diagrammatically three methods of piping for distribution :

  1. Showing good distribution
  2. Showing good distribution
  3. Showing bad distribution

When designing the piping for air fin exchangers, the basic rules of piping still apply, that the piping runs should be as short and direct as possible, but at the same time be sufficiently flexible to avoid overloading the air fin nozzles. The below figure shows two methods of running product headers to air fins :
By running the inlet header down the center of the units, the off-takes to the unit drop out of the bottom of the header, run across the units and drop into the nozzles.
Thus, we have a series of off-takes sufficiently long to absorb expansion, at the same time having the minimum of elbows resulting in minimum pressure drop.
Supports can usually be attached to the steel members that run between units and are thus short and minimal. The header must be flanged at intervals along its length to facilitate the removal of units by crane for maintenance.
The preferred position for the header is directly above the inlet nozzles, keeping the branches as short as possible. Make sure that the air fin is capable of excepting the movement imposed on the header. Support from the rack steel is between the header boxes.
Outlet headers are less of a problem because the temperature is lower and the pipe size usually much smaller.
They can usually be supported off the air fin legs beneath the header box platform.
Any valves required to isolate units are the best located on the unit nozzles. Sometimes air fins handling light hydrocarbons may require snuffing steam supply.
These should be treated in the same way as snuffing steam to heaters, insomuch as the valves should be located at least 15 meters radius planwise from the perimeter of the air fin.
Piping runs that place loads of any sort on the air fin structures should be avoided if possible, or communicated to the vendor as soon as possible.

12. Fin Tube Exchangers

Fin tube exchangers consist of a hairpin shaped inner tube with heat transfer fins on the outside, except for the return bend.
The two legs are jacketed with larger bore pipe.
The heat exchange is achieved by the stream passing through the hairpin, and the other passing through the jackets. They may be used singly or in multiples.
The primary uses are for heathers or coolers; that is, the process stream passes through the inner tube and either steam or cooling water passes through the jackets. They are used mainly as a source of local heat exchange, such as outlet heaters from the tanks and drums to pumps, etc.
Our important point to remember when locating fin tubes is that the hairpin tube draws out from the back end, that is, the opposite end from the nozzles, and sufficient room must be allowed for this purpose.
Piping design considerations are similar to those on shell and tube exchangers.

13. Chillers

Chillers are used where the process stream requires cooling to lower temperature than possible with cooling water, and for this purpose it is necessary to use a refrigerant.
Depending upon the size of the chillers installation, the refrigerant can either be supplied by a proprietary package unit, or a custom-built job using LPG. The construction is similar to fin tube, insomuch as the tube within a tube feature is common.
Chillers usually consist of a multi-unit bank with the process stream passing through the inner tube and the refrigerant passing through the jackets. Once again space must be allowed at the rear for tube withdrawal. An important thing to remember when laying out these exchangers, is the considerable thickness of insulation required on all the pipe-work, necessitating larger than normal pipe spacing.




Plant Layout – Fired Heaters

March 15, 2012 1 comment

Table of Contents

  1. General
  2. Location
  3. Safety
  4. Inlet and Outlet Piping
  5. Burner Piping
  6. Decoking and Sootblowing
  7. Instruments

1. General

1.1. Function

The primary function of a fired heater is to supply all heat required by the process in one form or another. A fired heater utilizes gaseous or liquid fuels often produced as a by-product. The normal process function is raising the process stream to its required temperature for distillation, catalytic reaction, etc. Sizes of heater vary considerably, dependent upon the type of duty and throughput.

1.2 Types

There are two general basic designs or types of fired heaters:
  Box type
  Vertical type.

Either of which may be forced or natural draft.
BoxType Heaters (See below figures 2 and 3.)
A box type heater is considered to be any heater in which the tubes are horizontal. In this type of heater it is possible to have locations or zones of different heat densities. The zone of highest heat density is the “radiant section”. The tubes in this section are called “radiant tubes”.
The heat pickup in the radiant tubes is mainly by direct radiation from the heating flame. In some heater designs shield tubes are used between radiant and convection section. The zone of lower heat density is the “convection section”. The tubes in this section are called “convection tubes”. This heat pickup in the convection section is obtained from the combustion gases primarily by convection.
Box type heaters may be up-fired or down-fired with gas or oil fired burners located in the end or sidewalls, floor, roof or any combination thereof.
Up-fired Heaters
In the horizontal up-fired heater, products of combination in the radiation chamber pass upward through banks of roof tubes and a fire brick diffuser into a plenum or collecting chamber. From the plenum chamber flue gases are passed through an overhead convection section and then to an overhead stack. Such heaters may be fired vertically upward by panels, mounted in the heater floor or hearth, the heater floor being elevated to provide headroom beneath. Alternatively, these heaters may also be fired horizontally by burners mounted in the heater-end walls, in which case the heater floor is only elevated above grade to provide air cooling convection to the heater foundations. This type of heater may contain single or multiple radiation chambers discharging flue gases to a common convection section and stack.
Down-fired Heaters
In the down-fired heater, combustion gases generated in the radiant chamber pass downwards through a refractory checker hearth into a collecting chamber beneath. From there the flue gases flow upward through the convection section and then out to the stack. The down-fired heaters are basically intended to fire on heavy residual fuels, where the flue gases are corrosive and may clog flue gas passages of conventional heaters.
Convection sections are thus protected by removal of combustion solids and are usually provided with inspection ports, soot blowing devices and tube facilities to keep the coils clean. Burners in down-fired heaters are always mounted in the heater-end walls.
Vertical Heaters (See below figures 4,5 and 6) Vertical heaters are either cylindrical or rectangular. They may have radiant section only or convection and radiant sections. The radiant section tubes will usually be vertical, but some cylindrical heaters have helical coils. The convection section can be either vertical of horizontal.
Types of Heater Firing
Heaters can be fired from any position, i.e. bottom, top, side or end.
By far the most common is bottom fired, mainly because it is more economical. The burner of a bottom fired heater will be located 2.1-2.7 M above grade at a height which is suitable for an operator to work underneath. Operating from under the heater is more dangerous than other types of firing, which is the principle reason certain operating companies will not install a bottom fired heater.
Heaters are commonly light with an electric ignitor. some refineries use a propane torch while some still light the burners with a rag soaked in spirits or kerosene.
Forced or Natural Draft
Consideration must be given at the layout stage to accommodate the additional equipment associated with a forced draft heater. This will usually comprise an air inlet duct with silencer, forced draft fan and an air preheater. The inlet duct may require a support structure.

2. Location

Heaters are always located at a safe distance 15 meters away from other hydrocarbon bearing equipment and preferably upwind; however, on some process it is permitted for reactors to be within this distance to prevent light volatile vapors from begin blown towards an open flame.
Space must be allowed for tube replacement for both horizontal and vertical heaters and this, together with ample access for mobile equipment, should be considered on piping layouts and drawings. Ample access is always needed for firefighting equipment with areas under or around heaters usually paved and curbed.
No low points in the paving or grading are permitted as these provide excellent sports for trapping hydrocarbon liquids which could be ignited by the open flames of the burners.

3. Safety

3.1 Snuffing Steam Station

See below figure 7.
Snuffing steam connections are supplied by the heater manufacturers, generally in the combustion chamber and header boxes.
The control point or snuffing steam manifold is generally located at least 15 meters away from the heater, is supplied by a live steam header and is ready for instantaneous use. Smothering lines should be free from low pockets and should be so arranged as to have all drains grouped near the manifold.
Collected condensate (apart from freezing and blocking lines) can, when blown into a hot furnace, result in serious damage. (Low points should be drilled 10 mm diameter or provided with spring opening auto-drain valves).

3.2 Monitor Nozzles

Some customers request that turret or monitor nozzles be located around the heater so that water for fighting a fire is instantly available. Controls for such nozzles should be located at least 15 meters away from the heater.

3.3 Utility Stations

Steam, air and service water connections should be provided near tube-ends of heaters. 3.4. Process Control StationsProcess feed and discharging block valves and flow control valves shall be located at a distance from the heater, if indicated as necessary by the engineering flow diagram or instructed by the Piping Specialist Engineer or Project Department.

3.5 Explosion Doors

Piping shall not obstruct explosion doors or tube-access doors.

4. Inlet and Outlet Piping

See below figures 8 and 9.
Flow distribution through a multipass heater is affected by the inlet and outlet manifolding. The piping arrangement at the inlet of the furnace is the more critical and requires careful attention.

4.1 Inlet Piping

Inlet piping should preferably be symmetrical and of the same length from the point where flow splits to the heater inlets. This refers to the number of bends, elbows and valves, as well as the number of straight runs of pipe and their location. piping should avoid dead-end tee branches and sharp turns. Unequal flow through any part of the heater would result in deposits of coke and overheating of tube walls.

4.2 Outlet Piping

On outlet piping, symmetry is not as critical as on the inlet; however, nonsymmetrical piping may contribute to possible coking and overheating of tubes. A nonreturn and a shutoff valve is usual at the outlet of the furnace to eliminate any reverse in the case of tube failure.

4.3 Flexibility

Because of the high temperature involved and length of pipe runs required to isolate the heaters, piping flexibility must be examined carefully. Some heater manufacturers will permit a limited amount of tube movement to take all or part of the piping expansion. This possibility should be investigated in conjunction with the Stress Department, by the Piping Design Office during the study stage. It is generally necessary to anchor the piping adjacent to the heater to remove stresses from the nozzles.

5. Burner Piping

See below figures 8 and 9.
Supply of fuel to individual burners is adjusted by individual valves. These should be so located that the burners can be operated while observing the flame through peepholes or burner openings.
All burner leads for gas and steam (atomizing) must be taken from the top of the headers, and fuel gas piping should be so arranged that there are no pockets in which condensate could collect. The fuel oil header must have full circulation; under no condition shall it be a dead-end line. Noncirculating branches to burners should be as short as possible or insulated together with atomizing steam.
A ring header around the furnace mounted a short distance above the peepholes, having vertical leads adjacent to the vertical doors to the burners, provides the greatest degree of visibility from the operator’s point of view.
Atomizing steam to be used in conjunction with fuel oil shall be taken the main steam supply header at or near the heater. Steam traps shall be provided to drain all low points in the atomizing steam system. Separate leads to each burner shall be taken from the top of the atomizing steam subheader. Shutoff valves shall be so located that they can be operated while observing the flames from the observations ports.

6. Decoking and Sootblowing

6.1 Decoking

(See below figure 12)
The internal cleaning of tubes and fittings may be accomplished by several methods. One is to circulate gas oil through the coil after the heater has been shutdown but before the coils are steamed and waterwashed and prior to the opening and start of inspection work.
This method is effective if deposits in the coil are such that they will be softened or dissolved by gas oil. When tubes are coked or contain hard deposit, other methods may be used, such as steam air decoking and mechanical cleaning for coke deposits and chemical cleaning for salt deposits. Chemical cleaning and steam air decoking are preferable as they tend to clean the tube to bare metal. The chemical cleaning process requires circulation of an inhibited acid through the coil until all deposits have been softened and removed. This is usually followed by water washing to flush all deposits from the coil. Steam air decoking process consists of the use steam, the coil. Steam air decoking process consists of the use of steam, air and heat to remove the coke. The mechanics of decoking are:
a. Shrinking and cracking the coke loose by heating tubes from outside while steam blows coke from the coil.
b. Chemical reaction of hot coke with steam.
c. Chemical reaction of coke and oxygen in air.
Steam and air services are permanently connected to the heater. The heater outlet line incorporates a swing elbow which, during the decoking operation, is disconnected from the outlet line and connected to the decoking header. Care must be taken to allow sufficient access and platforming when the swing elbows are changed over. Coke is carried by this header to the drum or sump.
In some instances it may requested by the Process Department or Client that the decoking manifold is connected to allow for reverse flow during the decoking.

6.2 Soot Blowing

In some heaters the convection section contains tubes with extended surface in the form of either fins or studs. Extended surface tubes are used to increase the convection heat transfer area at low capital cost. Because of the tendency of extended surface tubes to foul when burning heavy oils, sootblowers are usually installed.
Sootblowers employ high pressure steam to clean the tube outer surfaces of soot and other foreign material. Sootblowers may be either automatic electric motor operated by a pushbutton at grade, or manual requiring operation from a platform located at the convection bank level. Care must be taken that sufficient clearance is allowed for the withdrawal of sootblowers.
Generally heaters are supplied with sootblowing facilities in the convection section although tubes may not be of the extended surface type.

7. Instruments

7.1 Stack

a. Damper: Mechanical or pneumatically operated to control the draft through the stack.
b. Draft gauge (P and I)
c. Flue temperature (TI)
d. Orsat (O2 CO CO2 analyzer).
Instruments b., c. and d. are used to access the correct combustion conditions. Steam is supplied for the Orsat connection in the stack. Water is supplied to the O2 analyzer. Platforming for the access to the stack instruments is supplied with the heater.

7.2 Heater Body

a. Skin thermocouples or tube wall TI’s: to indicate overheating of tubes.
b. PI’s: to measure the draft pressure through the combustion section of the heater.

Figures 1-11 incl. Figure1. BOX TYPE HEATER PLAN



Plant Layout – Pumps

March 15, 2012 Leave a comment

Table of Contents

  1. General
  2. Centrifugal Pumps
  3. Reciprocating Pumps
  4. Rotary Pumps
  5. Pump Drivers
  6. Pump Harness Piping

1. General

1.1 Definition

In this context a pump is defined as a machine used to generate a pressure differential in order to propel liquid through a piping system from one location to another.

1.2 Types of Pump

The three basic types of pump are centrifugal, reciprocating, and rotary. See below figures.
Centrifugal pumps are the most common. They are more economic in service and require less maintenance than other types. Rotation of the impeller blades produces a reduction in pressure at the center of the impeller. This causes liquid to flow onto the impeller from the suction nozzle thrown outwards along the blades by centrifugal force leaving the blade tips via the pump volute finally leaving the discharge nozzle, in a smooth, nonpulsating flow.
Reciprocating pumps are used where a precise amount of liquid is required to be delivered, also where the delivery pressure required is higher than can be achieved with other types. The liquid is moved by means of a piston in a cylinder after being drawn into the cylinder, through an inlet valve, as the piston moves down the cylinder. As the piston moves back up the cylinder the liquid is discharged at a pre-set pressure controlled by delivery valve.
The liquid is ejected from the cylinder into the piping system in pulses which are transmitted to the suction and discharge piping, thus hold downs could be required on the piping system. Rotary pumps are used to move heavy or very viscous fluids. These employ mechanical means such as gear, cam and screw, to move the fluid.

2. Centrifugal Pumps

2.1 Nett Positive Suction Head

Centrifugal pumps must have their suction lines flooded at all times.
The suction piping has to be designed to avoid cavitation or prevent vopour entering the pump. Therefore, suction lines should fall continuously for a sufficient height from overhead source to pump.
The minimum vertical height required from source to pump suction is called the Nett Positive Suction Head, (NPSH). This is critical for efficient pump operation and must not be reduced. Vessel elevations are often dependent on the NPSH of its associated pump. See below figures.

2.2 Pump Types

There are three basic types of centrifugal pumps. Horizontal drive shaft with pump drive mounted remote from the line, vertical drive shaft with pump and drive mounted on the line, vertical barrel type with direct immersion suction facility. In each case the type refers to drive shaft direction.
The most common is the horizontal with its shaft in the horizontal, vertical in line pumps have their shafts vertical and the pump is installed in the pipe line, as a valve must be. Vertical can pumps are usually single stage, but horizontal and vertical can types can be multi-staged to obtain higher delivery pressures.

2.3 Suction Piping for Horizontal Pumps

Line Size
Suction piping is usually one or two line sizes larger than the pump suction nozzle size. Suction piping more than two sizes larger should be queried with Process Department.
Suction Nozzle Orientation
Centrifugal pumps are supplied with suction nozzles on the end of pump casing, axially in line with impeller shaft, also on top or side of pump casing. Usually pumps are specified with end or top suction for general services. Side suction pumps, with side discharge are frequently selected for large water duty. Also side suction – side discharge pumps can be obtained in multi-stage form for higher pressure differentials. These pumps tend to become very long, so if plot space is tight, consideration should be given to purchasing the pump in vertical form with a sump at grade. See below figures.
Flexibility of Suction Lines
Consistent with good piping practice, pump suction lines should be as short as possible, but with enough flexibility to absorb any pipe movement caused by temperature differentials and to maintain pump nozzle loads to within those permitted by pump vendor. For further details refer to section on piping flexibility.
Suction Line Fittings
Due to suction line being larger than the suction nozzles, reducers are required in the line. Reducers should be as close as possible to nozzle. Eccentric reducers will be used with the flat on top for horizontal pumps. See below figures. For pumps with suction and discharge nozzles on top of casing, care must be taken to ensure that the flats on eccentric reducers are orientated so that suction and discharge lines do not foul each other. See below figures.
Temporary Startup Strainers
All pumps must have a temporary startup strainer in the suction line to prevent any pipe debris damaging the pump. Strainers will be located between pump suction block valve and pump. Strainers are available in the following styles : flat, basket, conical and bath or “tee” type.
For basket and conical types a removable spool piece must be provided downstream of suction block valve, which must not interfere with line supports. Both types have the advantage that the piping is left undisturbed and strainer element can be removed simply by removing the blind flange on the tee, thus leaving the piping and supports undisturbed. See below figures.

2.4 Discharge Piping for Horizontal Pumps

Line Size
Generally, discharge piping is one or two sizes larger than the pump discharge nozzle size.
Discharge Line Fittings
Due to discharge line being larger than the discharge nozzle eccentric reducers are required in the line. Reducers should be as close as possible to the nozzle, with top suction – top discharge pumps, care must be taken to ensure that the flats on eccentric reducers are orientated so that the lines do not foul each other.
A pressure gauge is located in the discharge line, and should be upstream of the check and gate valves which are usually flanged together with a dripring between them. When a level switch for pump protection is installed in the discharge line, upstream of block valves, ensure good access for maintenance of switch.
To enable good access to valve handwheels and ease of supporting, the discharge line should be turned flat after reducer, and the line angled away from the nozzle to enable the line to be supported from grade. See below figures.
Avoid supporting large lines from piperack structures if possible, this enables minimum size beam sections to be used and better access for pump removal and maintenance.

2.5 Side Suction and Discharge Horizontal Pump

This type of pump is usually installed in a large duty service with large bore lines. Never connect an elbow flange fitting makeup to the nozzle of suction line coming down to the pump. Supply a straight piece of pipe two pipe diameters long between the nozzle and elbow.
The two diameter pipe length can be eliminated if the elbow is in the horizontal, only eliminate pipe length if available space is tight. See below figures

2.6 Vertical Pumps

Vertical pumps, also called can type or barrel type are used when available NPSH is very low or nonexistent.
Vertical In-Line Pumps
This type of pump is mounted directly into the pipe line, as a valve would be. For smaller sizes, the piping system supports the pump and motor, thus it is essential that the line is supported local to the pump to prevent the line moving when the pump is removed. Also ensure that there is good access to pump for maintenance and withdrawal with no overhead obstructions for lifting out pump. Larger size in-line pumps have feet or lugs on the casing for supporting from grade or steelwork.
Vertical Can or Barrel Type
Usually this type of pump is installed in cooling tower water circulating service, retention ponds, and applications where NPSH is low and suction is taken from a sump below grade. In most cases, there is no suction piping to be considered, but the discharge line must be routed to ensure good access for pump maintenance, with no overhead obstructions for pump removal by a crane. See below figures.

3. Reciprocating Pumps

3.1 Types of Pumps

There are three classes of reciprocating pumps, piston, plunger and diaphragm.
Piston pumps are generally used where medium to high delivery pressures are required, such a high pressure flushing of vessel interiors, etc. These can be obtained in multi-cylinder form and can be single or double acting. Plunger pumps are usually used for metering or proportioning.
Frequently a variable speed drive or stroke adjusting mechanism is provided to vary the flow as desired.
Diaphragm pumps are invariably air driven and very compact, also there are no seals or packing exposed to the liquid being pumped which makes them ideal for handling hazardous or toxic liquids. These are often used for sump pump out. See below figures.

4. Rotary Pumps

4.1 Types of Pumps

There are two main classes of rotary pumps, gear or screw.
Gear pumps are usually employed to pump oils and nonabrasive fluids.
Screw pumps are usually used to pump heavy viscous fluids and nonabrasive sludges. Apart from maintaining good access to pumps for operation and maintenance each case should be treated on an individual basis.

5. Pump Drivers

5.1 Types of Pump Drivers

The three most common types of driver are the electric motor, diesel engine, and steam turbine.
5.2 Electric motors are the most common pump driver and are of the totally enclosed, flame proof type suitable for zone 1 use. Their sizes range from small to very large which require their own cooling systems.
5.3 Diesel engines are usually to be found as drivers for fire-water pumps which are housed in a separate building away from the main complex.
5.4 Steam turbines used for pump drivers are ussualy single stage and the pump that they drive are invariably for standby service (spare).

5.4.1 Steam Nozzle Orientation

The steam inlet nozzle is usually on the right hand side when viewed from the pump coupling end of the turbine with the exhaust on the left hand side as standard. Turbines can be purchased with inlet and exhaust on the same side. This means that the piping designer can place the exhaust connection either on the same or opposite side from the inlet. Generally opposite side location of nozzles results in less piping congestion.

5.4.2 Inlet Piping

Steam inlets are furnished with strainers as part of the turbine for protection against pipe debris, therefore inlet piping must be designed with a removable section for strainer removal.
Steam supply to turbines must be moisture free at all times, otherwise damage to the turbine will occur if condensate enters the turbine while it is running. To separate condensate from steam a boot-leg must be installed up stream of the inlet block valve.
The two basic turbine installations are manual startup or automatic startup. The manual startup will have a gate valve in the steam supply near the turbine inlet. Upstream of the block valve a boot-leg must be installed with connections for blow-down and steam trap to remove any condensate in the steam supply. For automatic startup the gate valve is replaced with remote operated control valve, the boot-leg and traps are still required upstream as for manual startup.
Steam traps should be provided to keep the turbine casing free from condensate. These can be installed at the casing low point if a connection is provided or, on the outlet piping if the casing drains into the outlet system.
Note there must be a trap before any vertical rise which could form a pocket where condensate could collect.

5.4.3 Warm-up Bypass

On automatic startup a warm-up bypass must be provided around the control valve. This bypass is usually a “1” globe valve, and is partially opened to allow steam to keep the turbine constantly warm and slowly turning to prevent the shock of hot steam entering a cold turbine, and eliminate damage to turbine blades.
For manual startup it is recommended that a warm-up bypass be installed, but the job flowsheets will govern.
When a warm-up bypass is installed a steam trap on the casing keeps the system free of condensate. See below figures.

5.4.4 Exhaust Piping

Turbine exhausts are routed either to a closed exhaust steam system or to atmosphere. When exhaust is to a closed system there must be a block valve between turbine and main header, this block is always open during normal conditions and only closed for turbine maintenance or removal. Thought should be given to locating exhaust block valve on the piperack immediately before lines enter main header, this will prevent accidental closure of this valve. If the exhaust line is routed to atmosphere, the steam trap on turbine casing will not be installed, but replaced by gate valve partially open to allow condensate to drain off from casing. See below figures.

5.4.5 Rotor Withdrawal

Most small turbine casings are split along their horizontal axis and enough space above the turbine should be kept clear to allow for the top section of casing to be lifted clear of rotor by crane. See below figures.

6. Pump Harness Piping

Most pumps require external services to be piped to them for bearing cooling, bearing lubrication, seal flushing, venting and draining.
These requirements will be shown on utility flowsheets, and it is the piping designers responsibility to ensure that the actual geographic location of pumps with harnesses are correctly shown on the flowsheets. Though should be given to running subheaders to groups of pumps that have harness requirements. These subheaders must be sized and marked on flowsheet masters. Because branch lines to individual pumps are small diameter, i.e. 6 mm, it is advisable to take branch connections from the top of subheaders. This will eliminate pipe debris getting into the branch line and into the pump bearings, etc.
Care should be taken to ensure harness piping does not interfere with good operation and maintenance space.

The above diagrams indicate correct and incorrect methods of attaching suction piping.

Fig. 1 Shows air pocket formed along upper side of pipe by sing concentric reducer.
Fig. 2 (A) Horizontal ell directly into pump suction results in an unbalanced thrust on pump bearings. (B) Use spool piece 3 pipe diameters long or long radius ell with center vertical vane. (C) May be installed with or without spool piece but 2 pipe diameters spool is preferred.
Fig. 3 Shows proper method of connecting pump suction to a suction header in order to avoid air pockets.
Fig. 4 Represents a common error made suction piping to a centrifugal pump by placing piping over an embankment of a reservoir, or other obstruction.

SUCTION PIPING: The suction piping should be as direct and short as possible. In general it should be one or two sizes larger than pump nozzle. If changes from one pipe size to another are necessary, standard reducers should be used. Correct and incorrect ways are shown in the picture referred to above.