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Vessels

Towers, Reactors, Drums, Tanks & Spheres

There is one aspect of design that is common to all of the types of vessel described below. It is that all of the piping nozzles or manways are positioned and orientated by a piping designer. The nozzle locations are based on Company standards, good engineering practice and the process information shown on the P&ID. In addition the platforms and ladders required to access some of these nozzles are also laid out by the piping designer based on industry standards and the clients maintenance and access requirements.

Distillation Towers

Tower is the generic name given to the iconic tall slender vessels always associated with refineries and other process facilities.

They are more accurately described by their process function as Distillation or Fractionation Columns, Absorbers or Contactor Columns as used in glycol dehydration or amine sweetening, but while they can have different process parameters their function and operation are similar

The layout of a tower and its associated piping and platforms is arguably the most complex design challenge a piping designer can face. It should only be undertaken by the most senior of piping designers.

Towers are rarely more than 2.5 M in diameter and can be up to 120M high, they operate at relatively low pressures and temperatures.

It is impossible to write a definitive guide to tower layout as each stage of the layout process is interdependent on the others and there are many different tower variables. This interdependence and complexity means that the moving of a single nozzle late in the design can cause a complete redesign of the whole tower. What follows are some operational info and design guidelines common to all towers.

Operation

Distillation occurs when heated liquid passing down the tower by gravity comes into contact with vapours flowing up the tower by convection, this contact occurs on the many bubble trays which are usually placed at approximately 600-800mm equal spacings up the tower. Some towers use packed beds rather than trays and in this case the nozzle orientation is simplified by the absence of tray downcomers, the following guide is based on trayed towers as these are the most complex.

The tray consists of multiple bubble caps across the flat surface of the tray, at the edge or edges of the tray a small lip or weir retains about 50-75mm of liquid on the tray before it spills over into the downcomer and onto the next tray down. The vapour travels up through the bubble caps and interacts with the liquid on the tray due to the liquid seal created by the weir.

At various levels in the tower different petroleum products with different boiling points are drawn off. The lighter petroleum products such as aviation fuel near the top, the heavier such as bitumen near the bottom.

The heated crude feed inlet is usually between the middle and the top of the tower, any un-distilled liquid that makes its way down the trays to the bottom of the tower (Bottoms) is drawn off and re-heated to a vapour through a kettle type re-boiler located on a structure close to the bottom of the tower.

The vapour produced is recycled to the side of the tower below the trays to flow up and react with the down-flowing liquid on the trays. The vapour (Overheads) exits at the top of the tower and after being condensed to liquid through an aerial condenser it flows down to a Relfux drum, some of this condensed liquid is pumped back up to the top of the tower to again flow down and react with the up flowing vapour in a continuous reflux process. Some of the condensed fluid is pumped away as petroleum product.

Orientation

At the start of the design process the only information a Senior Piping Designer will have or require is a P&ID, Plot Plan and preliminary tray vendor drawings. He/She will not have, or need, a vendor vessel drawing as most of the information is flowing from the designer to the vendor not vice versa. The P&ID will show the tower diameter, tan to tan length, skirt height, location of diameter transitions, number and type of trays and nozzle size and spec and their elevation locations relative to each tray. The Plot Plan will show the tower location relative to the pipe rack and maintenance access area.

All nozzle and platform orientations should always be quoted in positive clockwise degrees from 0 to 360. 0 is always pointing towards Plant North.

Location of the process nozzles is closely tied to orientation of the trays, they are interdependent on each other and must be orientated together.

There are basically two types of tray design, single or double downcomer. In the single design the downcomers ( about one third of the towers diameter forming a chord across the diameter) are placed on alternate sides of the tower on alternate trays.

In the double design there is a downcomer each side on the first tray (each about one quarter of the towers diameter) on the next tray down there is a single downcomer in the middle of the tray. Then at the next tray the downcomers are each side again and so on alternately down the tower.

Once the orientation of the downcomers is established they cannot be individually changed or rotated within that bank of trays in that section of the tower. If there is a diameter transition in the tower or a break in the trays a different rotated tray pattern can be established in the next bank of trays but it must remain consistent in that bank. Sometimes a diameter transition will necessitate a change from single to double downcomers. The types of tray and their locations will always be shown on the P&ID.

The fundamental rule in tower design is that no nozzle or manway shall ever be placed in a downcomer. Even vapour TI’s should be placed above the tray liquid level, not in the downcomer area.

As all of the feed and draw off nozzles are best located in an arc facing the pipe rack this tends to orientate the downcomers perpendicular to the rack. However it is always possible that rotating the trays by a few degrees may assist in the nozzle and piping layout.

The first nozzles to be located and orientated are the liquid draw off nozzles. This is due to the fact that their elevation is critical to the tray level where the draw off is to occur, the ID of the nozzle bottom must be as close as possible to the top of the tray.

Next the liquid feed and reflux nozzles should be located and orientated, while their elevation still needs to be at the location shown on the P&ID the exact elevation and orientation is not as critical as they will often have an internal distributor above the tray to feed the liquid on to the tray parallel to the downcomers. This internal distributor pipe can have a 45 deg. , or less, elbow to achieve this from a nozzle that is not parallel to the downcomer.

The manways are orientated on the back arc of the tower opposite the piperack, facing the maintenance area. Again it is important not to overlap the downcomer area with these large (20”- 24”) nozzles. There is usually only one manway for 5 or 6 tray levels. The trays have a removable panel for access between the trays.

Finally the re-boiler vapour return inlet and the level bridle nozzles can be located. Their orientation is not dependant on internals as they are both located below the last tray at the bottom of the tower.

The lower bridle nozzle needs care in its elevation as it needs to be as low on the shell as possible while avoiding the lower head seam line. The seam line is usually 50mm above the lower head tan line but on heavy wall vessels this distance can be larger. The upper bridle nozzle is always located directly above the lower nozzle and above the high high liquid level (HHLL). The vessel bridle will support all of the level instrumentation but pressure and temperature instruments (PI’s & TI’s) are located at other locations shown on the P&ID. PI’s are always in vapour spaces away from downcomers. TI’s are usually positioned in the liquid level of the tray, their height relative to the tray is critical. However they are sometimes required to measure vapour temperature, and will need to be well above the tray, if in doubt check with the process engineer.

Ideally no nozzle should intersect a seam and usually all vertical and horizontal vessel seam lines will be designed to avoid nozzles. However, where it is unavoidable the vessel vendor will place a reinforcing pad around the nozzle. Seams and re-pads will be designed by the vessel vendor once they receive the nozzle layout

The Overheads vapour nozzle and the Bottoms liquid nozzle are both located respectively in the centre of the top and bottom semi elliptical heads. The top head will also contain the PSV nozzle offset from center. The bottoms nozzle drops down vertically, then is elbowed and orientated horizontally to its flange outside the vessel skirt as no flanges should ever be located inside the skirt.

After positioning all the nozzles and manways the only other wall penetration items requiring orientation are the skirt access hole and the 4 equi spaced skirt vents. The access hole should be no more than 600mm above grade towards the back of the tower and the skirt vents, which are short 2” pipe sections, as high as possible in the top of the skirt.

Piping Layout

With only the arc of the tower facing the rack between downcomers available for all nozzle orientations it is impossible to place each nozzle in an orientation where there will be a clear run for piping to run straight down the tower to or from every nozzle.

It is important at this stage to make allowances for pipe supports and guides. If no thought is given to their impact on line spacing down the tower it can result in much rework rearranging the piping layout and even reorientation of nozzles. Pipe and vessel insulation thickness also need to be taken into account when positioning lines on the tower

While some lines can drop straight down from their nozzles others will need offsets at the nozzle to avoid nozzles and piping below them. These offsets are usually a 90 deg elbow rolled at 45 deg after the nozzle mating flange and then a 45deg elbow to go vertical. They can be fitting to fitting but some will require a pup piece between the elbows. Offsets are always made at the nozzle, never on the run down the tower.

Once the piping is laid out the pipe supports can be added. Any line dropping from a nozzle must be supported as close to the nozzle as possible. It is acceptable to support immediately below the offset described above. Larger lines (4” and above) are usually supported by trunnions found in your company’s pipe support standards or under the Standards section on this web site.

Trunnions need a fairly substantial support structure so care must be taken during nozzle orientation and initial piping to allow for them not to interfere with other supports or lines.

After the supports are positioned the guides can be placed. Some guides can be relatively small and simple and can be selected and placed by following your company’s vessel guide standards. Others can be even larger than trunnion supports, these are usually two or four way guides required at the request of the stress engineer.

All steel required for pipe supporting is usually supplied by the Pipe Support Vendor. The vessel vendor only supplies the welded support clips at the vessel shell locations specified by the piping designer.

Ladders & Platforms

Unlike most other platforming on the plant, which is designed by the EPC Company’s structural group, vessel platforms are usually laid out by the piping designer but engineered and supplied by the vessel vendor.

Before starting to lay out any ladders or platforms the designer should familiarise him/herself with the regulatory health and safety standards at the plant’s location, the engineering company’s standards and the clients requirements.

The regulatory health and safety standards will dictate, handrail height, ladder egress, cage height and the maximum vertical ladder run allowed, longer than maximum allowed vertical ladder runs require an intermediate platform. In most jurisdictions this maximum run is 30ft or 9M but it can be less in some jurisdictions. Adhering to the correct standard is critical as it would drastically change the platform and ladder arrangement if the wrong standard were initially used.

The company/clients standards should specify which nozzles need permanent access. It is a given that all manways should have permanent platform access if they are higher than a given distance from grade. Also the level bridle and its instruments always need good access although operator access can often be achieved directly from a ladder with no actual platform required.

Process nozzle access can vary greatly from client to client. Some require all nozzles accessed, some require access only to those fitted with spectacle blinds or valves. It is imperative that the designer checks the nozzle access requirements before starting the layout.

Except for the top rectangular platform all other platforms are semi circular with varying circumferences and usually positioned on the back arc of the tower. They are usually 1.5M wide and accessed by side step ladders, not step through. Always remember several platforms can be accessed from the same single ladder providing its total vertical run does not exceed the maximum and that the ladder rungs can line up with the top of each platform.

The platform levels are mostly determined by the manway levels as there is a minimum standard distance between the platform and the underside of the manway. Any other nozzles in the same general location that require access can be reached from the manway platform if they are within the height restrictions for good access. If not they will require a dedicated platform

Platform layouts are infinitely variable and is difficult to define what constitutes good layout other than to say that any platform should be efficiently sized to service as many items as possible from a single level while not being larger in circumference than necessary. Ladders should be positioned such that the access or egress can never be obstructed by an open manway cover or any other obstruction. Be aware of overhead clearance of anything projecting above the platform. Be aware that the vessel vendor will sometimes require support braces approximately every 15 deg of shell circumference underneath each platform, which could also pose a headroom issue on the platform below or an interference with pipe supports.

Always check for this when you receive the vendor’s platform details for squad check. Also check that they have correctly incorporated holes for any piping platform penetrations, the holes should have a circular kick plate and be 2” larger than the insulation O.D.

The last item on the tower check list is the main tower davit for lifting or lowering items to and from the tower. It is positioned to be accessible and operated from the top platform but must be able to rotate to pick up any object from any platform. A reserved space envelope of at least the same diameter as the tower must be modeled from grade to the full height of the tower to ensure this space is kept free from obstructions.

It is the experienced Senior Piping Designers skill that makes this extremely complex piping and platform arrangement look well designed and deceptively simple. Perhaps one day A.I. might be able to attempt something of this complexity, I’d love to be the checker on its first attempt.

Catalytic Reactors

Reactors, like towers, are usually vertical and cylindrical. But unlike towers their diameter can be as large as 10M with a height of up to 50M. They also operate at high temperatures and pressures which is why their top and bottom heads are usually hemispherical not semi-elliptical and their wall thickness can be 50mm or more.

The process operation of a reactor is fairly simple. The process fluid is passed through a catalyst bed where a chemical reaction takes place to change the fluids properties. It is usually a once through process without the complex piping and internals associated with a refluxing distillation tower.

While the general principles of layout and orientation are the same as distillation towers, the numbers of nozzles, platforms and pipe supports are relatively small, although due to the higher temperatures involved pipe stress mitigation maybe more complex.

The major layout consideration for a reactor is the catalyst removal and loading, which has to be done at regular intervals. As no two catalytic reactors are exactly the same it is up to the piping designer to liaise with the mechanical engineer and the reactor vendor to ensure that adequate access and catalyst handling facilities are provided adjacent to the reactor.

Drums

Drums are always cylindrical and usually horizontal, they are rarely more than 5M diameter but their length can vary considerably. Drums up to 10M long will have 2 support saddles, longer drums can have multiple saddles depending on the vessel wall thickness. For layout purposes in the 2 saddle arrangement they can be positioned 1/5 of the drum length in from each end, but their final position must be determined by the vessel vendor.

Most drums are completely horizontal but sometimes the P&ID will call for the drum to be sloped. This is achieved by having one saddle higher than the other for 2 saddles or continuous increasing saddle heights on multiple saddles.

Like all horizontal equipment one support must be fixed and anchored while all the others are allowed to slide. It is the piping designers job to determine which is the fixed end. Generally speaking if a drum is located perpendicular to a pipe rack, like exchangers, it is the end closest to the piperack that is fixed. However this can vary depending on the stress analysis of the connecting piping. A stress sketch should always show the location and the distance from the connected nozzle to the fixed end.

Operation

Most drums are used for transient (not permanent) liquid storage and are being continuously partially filled and emptied as part of the process flow. Many drums are used for gas/liquid/solid separation and have internal baffles and weirs to achieve this function.

Liquid Inlet, gas outlet or PSV’s are usually on top of the shell or head. Liquid outlet, usually to pumps, is on the bottom of the shell. Just like any vessel feeding a pump suction the drum must be elevated to provide Net Positive Suction Head (NPSH) to protect the pumps from cavitation. This is shown on the P&ID as a dimension from grade (or platform) to the underside of the drum shell.

Some drums are equipped with a liquid boot, this is a cylindrical shell extension vertically down from the liquid section of the shell. They are usually no more than 1M in diameter and 1.5M long. Their purpose is to provide additional liquid capacity to the shell without increasing the shell diameter, they also provide additional NPSH to the pump suction which is often a nozzle on the bottom of the boot head. The lower level bridle nozzle is positioned as low as possible on the side of the boot.

There is also a sub group of drums commonly called Bullets which are used for high pressure gas (Butane or Propane) storage. Due to their high pressure they have hemi-spherical heads, are usually no more that 2.5M diameter and can be more than 20M long hence the name bullets, they are usually placed in groups of 2 or more. While their piping involves only small bore manifolded lines it is their location in the plant that it is important.

High pressure flammable gas is by far the most dangerous fluid stored on any plant. The explosion of a bullet can be catastrophic with the vessel heads travelling hundreds of meters and causing severe damage to anything in their path. The piping designer must therefore always locate Bullets at the edge of the plot with their heads facing a direction least likely to cause damage in the event of an explosion. They are usually surrounded by an earthworks bund in an attempt to contain the heads. It is not only their shape that lends them the name bullets.

Nozzle Orientation

Generally speaking the liquid inlet or gas outlet nozzles or are positioned along the top center line of the drum shell or high in one of the semi-elliptical heads. Liquid outlet nozzles are positioned along the bottom center line or low in one of the heads.

Manways can be along the top center line or low on the center line of the heads or even tangentially low on the shell. Some drums will require 2 or more manways depending on the internals.

The actual positions of the nozzles are also dependant on the internals and the piping designer must be in possession of a P&ID and a Vessel Data Sheet before orientation commences.

The level bridle nozzles can either be high and low tangentially on the side of the shell or in similar positions on the centerline of one of the heads or the boot.

It is worth mentioning here that the vessel vendor may not know the purpose of all of the nozzles so it is important that the vessel drawing should show that the level bridle nozzles should be “Jig Set”. This means that the vendor must use a temporary template or jig to ensure that the two nozzles, center to center distance, projection and their flange bolt holes line up exactly.

This applies to any bridle nozzles on any type of vessel the piping designer lays out. Jig Set also applies to each individual pair of instrument nozzles on the bridle piping isometric.

Platforms

Like tower platforms, drum platforms are usually supplied by the vessel vendor and laid out by the piping designer. They are usually rectangular and run the length of the drum with a single side step ladder at one end. Again it is dependent on company standards or client preference whether access to the top nozzles is required. But as there is often a gas blanket control system or a PSV to be inspected and maintained it usually is.

If a platform is required the only other decision to be made is whether the nozzles should project through the platform or whether the platform is to the side of the nozzles. The through nozzle arrangement is more practical from a maintenance point of view but results in a larger platform and longer nozzle projections and is therefore more expensive.

Tanks

Tanks are mainly used for relatively long term storage of produced liquid petroleum products or chemicals required by the process system, they are not pressure vessels and are not part of the process itself. Their diameters are often far greater than their height. Diameters can be greater than 50M with heights up to 15M.

As they are not pressure vessels they have flat bottoms resting on a compacted earth tank pad, the roofs are flat, domed or conical and can be fixed or floating. Floating roofs can be Internal or external and are more expensive than fixed roofs but are preferred because they eliminate the potentially explosive vapour space above the liquid in the tank. They are also less environmentally harmful as they eliminate the need to vent off vapour to atmosphere as the liquid rises during filling.

Whether the roof is fixed or floating makes no difference to the nozzle or piping layout except where a vapour recovery or fire suppression system is required, however these systems are not common.

Nozzle Orientation

Unlike other vessels which are generally covered under ASME Boiler & Pressure Vessel Code, tanks and their nozzles are covered under API 650, the piping designer should read the relevant parts of this standard before orientation.

Many of the nozzles on tanks are positioned to face the pipetrack serving the tank, this means most of the nozzles are grouped together in a relatively small area of the tank circumference and are located tangentially in parallel rather than radially. All of the inlet/outlet nozzles are also located as low as possible on the tank shell to maximize the operational capacity of the tank.

Exceptions to the above are shell nozzles for manways, mechanical mixers, electric heaters, instruments or steam coils which can be located anywhere that’s convenient providing there is room to remove large items such as mixers. The only other nozzles are located on the roof and are for level instruments, sampling and PVRV’s, they are accessed from a small, rectangular roof platform which in turn is served by a spiral staircase, with rest platforms, around the wall of the tank.

Piping

Piping runs to and from each tank on a branch from the main tank farm pipetrack which runs outside the bund wall. The branch track passes through the bund wall and each line is sealed on both sides of the bund to maintain the integrity of the bund in the event of a tank rupture.

Tanks are unique in the plant in that they are the only equipment where settlement is expected to occur. The significant weight and size of storage tanks makes it uneconomic to pile the bases of the tanks so they are usually erected on a pad which is comprised only of compacted earth.

Once the tank is filled settlement will begin and continue for the first few years of the tanks life until it reaches stability. The amount of settlement can be roughly calculated by the civil engineer and can be as much as 100mm.

This means that all of the piping connected to the tank must be flexible enough to be able to absorb the downward movement of the nozzle it’s connected to. The amount of movement and the space available usually precludes the use of natural flexibility so each nozzle must be fitted with a form of flexible connection.

These connections can vary from simple braided hoses for small bore nozzles to full articulated joints on the larger lines. The position of the pipetrack is offset from the tank nozzles to accommodate the flexible connections.

Tank Farm Layout

Storage tanks are always grouped together in an area adjacent to the main plant known as The Tank Farm. Tank farm layout is governed by company/client/ industry standards based on insurance requirements as there is potential for large tank fires and major asset loss when many tanks full of flammable liquid are grouped together.

The primary safety feature of the tank farm is the berm, bund wall or dyke, this is usually an earthworks embankment completely surrounding the tank with enough capacity to contain the entire contents of the tank in the event of rupture, with some room to spare (freeboard)

When dealing with a single tank this is a fairly simple calculation, the total volume of the tank divided by the proposed height of the bund will give the minimum area required within the toe of the bund. The additional volume created in the triangular space from the toe to the top will give freeboard. The nominal height of the band should not be more than 2M as even this height will require a toe to toe bund base width of approximately 7M. As the earthworks take up a considerable amount of the available area, any bund higher than 2M becomes impractical. Even single small tanks located within the plant for process chemical storage require containment, but due to space limitations it is usually a concrete wall not an earth berm.

Very often multiple tanks are placed within a single bund. This is a more complex calculation and must take into account the types of liquid stored, the distance between tanks and the required volumetric capacity of the bund, which is not the total capacity of all tanks. One basic rule that can be used in initial layout is that the minimum bund capacity should be the greater of 110% of the largest tank volume or 25% of the total volume of all the tanks

Many of these standards are quoted in para. 10.2 of the Piping Design and Layout Manual on this site, but the standards that apply to the specific plant location must also be followed.

Further safety requirements of tank farm layout is that no equipment, particularly pumps, shall be located within the bunded areas and that adequate fire hydrant coverage is located throughout the tank farm. Each hydrant should be served by alternative access and egress routes.

Spheres

As the name implies these are spherical high pressure vessels used for the cryogenic storage of LNG, methane, ethylene, hydrogen, and oxygen gases in a liquefied state and many others in a gaseous state. They are usually no more than 15M spherical diameter and supported on multiple legs on a concrete base.

They are usually located together in a separate area of the tank farm but are not surrounded by a bund wall.

A spherical shape is the strongest natural shape and can withstand the highest internal pressures, its other advantage is that it has a smaller surface area per unit volume than any other shape. This means, that the quantity of heat transferred from warmer surroundings to the liquid in the sphere, will be less than that for cylindrical or rectangular storage vessels. As cryogenic fluids must be kept cold at high pressures these are the primary reasons for their choice in cryogenic fluid storage.

Nozzle Orientation

The primary inlet/outlet nozzles are all located on the bottom and middle of the sphere pointing vertically down, there are a few ancillary nozzles such as level and PSV’s mounted on the middle top served by a spiral stair case and top platform similar to a tank.

Piping

It is likely that sphere piping will be subject to cryogenic conditions so the practices and support standards shown in the Special Pipe Support Details section of this site will apply.

Thermal Equipment

Exchangers, Coolers, Furnaces & Boilers

Heat is the primary driving force of any processing plant, it is used to initiate and maintain the chemical reactions that enable raw products to be processed into refined products.

Heat is either produced directly by Furnaces or Boilers or as a chemical reaction of another process. Whichever way it is produced it is a valuable resource and must be managed, conserved and recovered in the most efficient and economic way possible. This is usually achieved by heat transfer or exchange between fluids at different temperatures.

Heat Exchangers

While the term heat exchanger could be applied to any of the equipment named above, it is usually taken to mean heat exchange between liquids. The most common form of liquid heat exchanger is the Shell & Tube Exchanger.

The exchanger consists of a cylinder (Shell) usually no more than 1.5 meters diameter and no more than 10 meters long. At one or both ends of the Shell there is a Channel bolted to the shell flange. The Channel contains the tube sheet through which the tubes are connected, the tubes run the length of the shell and either connect with rear Channel (single pass) or U turn back to the single front Channel (multi pass) which is the most common form. The many combinations of Shell and Channel can be found in the Tubular Exchanger Manufacturers Association (TEMA) documentation

For multi pass the Channel contains horizontal compartments to separate the inlet from the outlet liquid. For a 2 pass there will be two compartments for more pass’ there will be more compartments to force the liquid back down the U tubes until it reaches the outlet nozzle compartment. The Shell also has vertical baffles along its length, they have alternate gaps top and bottom to force the Shell liquid up and down for maximum contact with the tube liquid as it travels the length of the Shell. The Shell fluid usually only has one pass but can have two. Using the TEMA chart above the most common 2 pass configuration described here would be AEU

Whenever possible the two liquids should always flow in opposite directions* for maximum heat exchange efficiency. While the P&ID will show which liquid is ‘Tube Side’ and which is ‘Shell Side’, it is often the Piping designer who will chose the actual location of the nozzles. The higher temperature fluid, often steam, will usually be tube side and the lower temperature shell side but this is the choice of the process/mechanical engineer and can vary.

Inlet and Outlet of both Tube and Shell nozzles are always top and bottom (not side). So in a multi pass exchanger as shown above, if you were to chose the Tube inlet nozzle to be on the bottom of the Channel then the Shell inlet will be on the top towards the Channel end of the Shell, while the shell outlet will be on the bottom of the shell at the opposite end. The Tube outlet is obviously on the top of the Channel.

If any of these locations change then the others must also change to maintain opposing flow between the shell and tube liquids.*

For instance if the tube side fluid is steam the flow will always be from the top channel nozzle down to condensate out at the bottom channel nozzle

The layout of Shell & Tube Exchangers is critical as their maintenance and cleaning is time and labour intensive. When placed at grade exchangers are often laid out in groups along the side of a pipe rack with their Channels facing out.

All multi pass exchangers are designed so that their Channel can be unbolted and the whole ‘tube bundle’ removed from the Shell for cleaning. (Single pass double channel exchanges usually have a fixed tube sheet that cannot be removed and are cleaned in situ) This means that the Piping designer must model a cylindrical reserved space envelope in front of each exchanger to ensure that no other designer places any object that would impede tube removal or steam cleaning lances.

As the Channel needs to be unbolted it is important to not only provide removable tube side piping spools but to also ensure that the non removable tube side piping is well away from the Channel flange. This is often achieved by angling the tube inlet or outlet piping back at forty five degrees before dropping or rising past the side of the exchanger.

Like all horizontal cylindrical equipment, exchangers are always supported by two saddles. It is the Piping designers responsibility to decide which end is the fixed or anchored saddle and which is sliding. When exchangers are adjacent to a Pipe rack the anchored , fixed saddle is always closest to the rack and opposite end to the Channel end.

This is to allow the Shell to expand in the same direction as the Piping running parallel to the exchanger from the rack rather than the Shell opposing the expansion of the piping **

Sometimes process conditions will dictate that the exchanger or group of exchangers must be elevated above grade. The Piping designer will have to lay out an exchanger structure to accommodate the elevated and possibly stacked exchanger group. At this point it is important to know or to ask what the client’s maintenance philosophy will be. Does the client intend to use a crane mounted tube pulling device or should you the designer allow tube pulling space in your exchanger structure layout?

There is one variation on the normal Shell & Tube exchanger called a Kettle Re-boiler, AKU. The only physical difference is that rather than the Shell being a straight cylinder after the Channel the Re-Boiler Shell expands eccentrically upwards to create a vapour collection space above the straight tube bundle below. Kettle Re-Boilers are usual used at the bottom of fractionation towers to ‘re boil’ the tower bottoms liquid back to a vapour to be re-circulated to the bottom of the tower. They are different in that the exchanger shell side usually remains liquid whereas re-boilers create a shell side vapour with steam being the tube side heating fluid.

Plate Exchangers

While Plate Exchangers are thermally efficient, smaller and easier to maintain they cannot equal the output of a large Shell & Tube exchanger, are more expensive than and therefore not as common as Shell & Tube.

They consist of a series of plates which are contoured on both sides so that when they are bolted together they form 2 unconnected but adjacent liquid pathways which are the equivalents of shell side and tube side.

They are rectangular in shape usually are supplied in a support frame which incorporates a mono rail for sliding and separating the plates for cleaning.

They do not therefore require the large reserved space maintenance envelope of the Shell and Tube, but removable spools need to be supplied on the movable plate nozzles to allow separation and movement of the plates.

Hairpin or U Tube Exchangers

Hairpin Exchangers are a very basic and simple form of Shell and Tube exchanger usually consisting of a single tube inside a shell in a vertical U configuration. The outer shell is rarely larger than 300mm diameter with the tube150mm diameter max.

They do not have a Channel as such, but flanges for disassembly, the tube nozzles are horizontal one above each other at the front with the shell nozzles vertically top and bottom just behind. Flow direction of tube side and shell side liquids are still in opposite directions

They have very low duty and are fairly uncommon.

*Where multiple exchangers are stacked vertically and connected in series it is not possible to consistently maintain these shell side nozzle locations. The shell outlet of the lower exchanger must match the shell inlet of the upper while keeping all the Channel nozzles inline vertically.

** An exception to this anchoring philosophy is where cooling water is the tube side liquid and the large diameter (36”+) cooling water mains are run underground because they are too large and heavy for the rack. In this case the cooling water flow and return branches leaving the ground adjacent to the Channel nozzles create very rigid connections and therefore the anchored, fixed end should be closest to the Channel.

Coolers

The term cooler is usually used to describe equipment that uses ambient air to cool a process liquid. Because the heat is lost to the atmosphere they are not an efficient form of heat exchange but are used when the high cooling load required cannot practically use any other form of heat exchange.

The most common type are Aerial Coolers, they consist of multiple bays often mounted above the pipe rack to save plant space at grade. If this is the case it is important that the steel columns of the pipe rack are fireproofed. The pipe rack is supporting a large equipment load in addition to the piping and the collapse of a rack supporting coolers can cause considerable damage in the event of a major refinery fire

The length of each bay is approximately the same as width as the pipe rack and consists of a single or double fan to move air across horizontal finned tubes containing the process fluid to be cooled, the tubes are fed from header boxes which run the full width of the each bay on both sides. Each bay is usually between 3 to 4 meters wide and it is not uncommon to see anything from 10 to 20 bays mounted adjacent to each other and fed in parallel.

The fans can be mounted below the tubes (Forced Draught) or above the tubes (Induced Draught ), this has no influence on inlet or outlet piping configurations

Each header box usually has 1 or more inlet and outlet nozzles, both on the same side for 2 pass tubes, on each side for single pass tubes. The inlet nozzles face up the outlet nozzles face down.

The most important consideration for the piping designer is to ensure equal liquid distribution across the whole bank of 10 to 20 cooler bays. This distribution will usually be shown on the P&ID and is dictated by the process engineer or sometimes the process licensor.

The simplest and most common distribution is to use a single continuous size header for the inlet and another for the outlet with straight branches to each nozzle. To achieve equal distribution the inlet header is run from one end of the cooler bank and the outlet header is run from the other end. This ensures that the cooler bay that receives its inlet liquid first is the last to outlet to the outlet header. This helps to balance the bank.

This method is the most economic and easiest to support although it can lead to some stress engineering problems due to so many nozzles being directly and rigidly connected to the headers.

The most sophisticated method is the Cascade. In this method the full size inlet and outlet headers run above and below to and from the center of the bank nozzles, they then tee vertically, reduce and elbow each way to each half of the bank, they then tee and reduce again to each quarter of the bank. This continues until each pair of bays is feed by a separate tee followed 2 reducers and elbows with connection to the 2 nozzles.

The Cascade method gives better distribution but is obviously very expensive and should only be used if the P&ID specifically requires it. It is difficult to support but does have the advantage of being easier to stress.

There are many configurations between simple and cascade the objective is always to achieve balanced flow to all coolers in the bank.

It is worth discussing a compromise of the two methods with process before deciding on either.

Cooling Towers

There are many types of Cooling Tower, they can be wet or dry, mechanical or natural draft. The most common type in petrochemical plants are Induced draft, wet, multi cell type with adjustable air inlet louvers, each cell has its own induced fan on top of the cell. Their main support structure is often wood which is both economic and corrosion resistant. Less common are the concrete, natural draft, evaporative, hyperboloid shaped, wet cooling towers often seen on power stations. Both of these types of cooling tower use evaporation to cool the returned condensate or hot water they are very wasteful in terms of heat recovery but are much more economic than aerial or shell and tube heat exchangers.

They both consist of an open top tower with hundreds of internal nozzles which spray hot condensate into a rising ambient air stream. In the hyperboloid type the air naturally rises from inlets around the base and is accelerated by the hyperboloid shape of the tower.

In the multi cell induced draft the air is drawn in from the side louvers by the induced draft fan. In both types the evaporation of the hot condensate results in massive clouds of pure water vapour often mistaken by the media as evidence of air pollution. The resulting cooled liquid droplets fall into the basin below the tower(s) called the Forebay. From there is pumped back to into the boiler feed water system by large pumps taking suction from the Forebay.

From a Piping Design point of view there is very little internal or external piping to be laid out as the Tower is usually a vendor supplied package so there are no particular design parameters to be taken into account other than good pump suction/discharge layout.

From a Plant Layout point of view The Cooling Towers should always be located downwind of the main plant to prevent the clouds of water vapour condensing and possibly freezing on plant structures and equipment.

Furnaces/Fired Heaters

As opposed to boilers which produce hot water and steam, the term furnace is usually used to describe large gas fired heaters which heat process fluids as part of the with thermal ‘cracking’ cycle in the production of petroleum products.

Furnaces can be single free standing units often circular, but any plant requiring major process heating, such as ethylene production, will usually have a large furnace area consisting of 8 or more furnaces adjacent to its own pipe rack.

These furnaces are usually rectangular and arranged in pairs. As each furnace has its own radiant section each pair is connected above the radiant sections by breaching and share a common convection section and stack.

The radiant section is used to heat the process fluid. As the name implies the process piping coil inside the radiant box receives radiant heat from the multiple burners that are mounted in the floor and walls of the radiant box.

From a piping design point of view connecting the vertical inlet and outlet flanges of the radiant coil is fairly simple and straightforward. From a stress point of view it can be complex. The radiant coil sees very high temperatures and therefore experiences high thermal growth.

The radiant coil(s) consists of vertical risers and drops connected top and bottom by U bends and is arranged to hang vertically from the top and guided at the bottom of the radiant box. The hanger arrangement involves springs or sometimes a complex pulley and weight system outside the box to absorb the vertical coil growth.

The Convection section above the radiant has no burners but uses the waste heat from the radiant section to pre heat the process fluids and also produce steam. This section is sometimes referred to as the Economiser. The process coils are usually at the bottom of the section where the flue gas is hotter, the steam coils at the top where the gas has become relatively cooler

The coils in the convection section are horizontal with many passes connected by external U bends front and back with the external inlet and outlet piping connections at the front. Some of these connections are crossovers from one coil to the next and the confined space between the coils can make this piping complex.

Another problem is that due to the internal temperatures the internal coil materials are more exotic than the external piping specs so a material change is often required at the coil connections. As space is limited there is sometimes no room for flanges so the connection has to made by dissimilar material welds which are undesirable and expensive.

This problem continues up the coil bank. Although the material integrity of each internal coil can be reduced as the flue gas gets cooler the external piping will always require a lesser quality material than the internal.

Finally one of the most challenging areas of piping design on a large furnace is the fuel gas piping to the burners, particularly the floor burners.

For ease of operation the underside of the furnace is usually between 2 and 3 meters from grade with multiple burners projecting down from the underside. The network of fuel gas piping must be accessible for each burner valve adjustment while at the same time cause no obstruction to safe operator access or egress and allow unobstructed view of the many peep holes used by operations to observe and adjust each burner flame.

Any open flame equipment is a potential danger in a petrochemical plant. For this reason a manual quick acting gas shut off valve must be placed on the main fuel gas header a safe distance (at least 50ft.) away from the nearest burner.

The design of the fire suppression hydrant system around furnaces must take this potential asset loss into account.

Boilers

The primary purpose of a boiler in a petrochemical plant is to produce high pressure superheated steam from treated water to power turbines and to be used as part of the refining process. While steam can also be produced as a by -product of other process’ such as a furnace boilers are usually required to supplement this ‘waste steam’ production. As the steam loses its superheat qualities it is used for other duties such as heating and steam tracing. Once the steam turns to condensate it is recovered, cooled and returned to the boiler feed system.

The water is treated and deaerated to mitigate the effects of corrosion and scaling inside the boiler. It is an expensive process requiring a dedicated water treatment unit and is the justification for recovering and recycling the resulting condensate whenever possible.

The boilers are usually the water tube type consisting of a series of many tubes vertically connecting a ‘mud’ or water drum at the bottom and a steam drum on the top. The boiler shell is often a horizontal cylinder with a horizontal oil or gas burner mounted at the front with the flue stack at the back.

Discharge from the boiler feed pumps enters the boiler via the economiser which, like the convection coils of a furnace, is mounted in the ‘cooler’ flue gas stream before the stack. This takes advantage of ‘waste heat’ and gives some preheating to the boiler feed water.

From the economiser it enters the mud drum and natural thermal circulation circulates the warming water between the mud and steam drums until the steam drum contains saturated steam ( The term saturated steam means pure steam in direct contact with, and at the same temperature as, the liquid water from which it was generated) This steam can still be partially ‘wet’ and contain water droplets which can severally damage turbine blades.

To remove any water droplets from the steam to produce dry superheated steam the saturated steam must pass from the steam drum through the superheater tubes. These tubes are separate from the drum circulation and pass through the relatively hot flue gas stream to raise the steam temperature and pressure to superheat condition.

Piping connections to boilers are relatively simple. Primary connections are boiler fed water inlet and superheat steam outlet, no special requirements other than normal good practice, support and stress considerations.

Secondary connections are PSV connections, fuel gas or oil and condensate blowdown.

Unlike process PSV’s, which must discharge to a flare header system, boiler PSV’s are only discharging water vapour so they can discharge directly to atmosphere. They should do this as directly as possible while taking sound attenuation and operator location into consideration. The PSV ‘s must be accessible for annual inspection and maintenance but their piping discharges must be remote and away from any area where there is a potential for operator hearing damage. Silencers are often installed in the PSV discharge.

The Boiler vendor will usually provide a fuel gas or oil piping skid containing meters, filters etc. The piping designer only has to locate the skid and pipe up to the inlet.

Even though the boiler feed water is treated the mud drum and internal steam tubes can still build up solids and sludge, this needs to be drained or blown-down intermittently or sometimes constantly. This involves connecting the many small bore (1”-2”) blowdown connections on the underside of the boiler and piping them into a header system that runs to the blowdown sump. As these connections all need access to their angled blowdown valves. Blowdown piping can be the most complex part of boiler piping design.

Once Through Steam Generators

OTSG’s are a simple form of boiler usually used on Steam Assisted Gravity Feed (SAGD) heavy oil recovery projects. They produce low quality wet saturated steam for injection into heavy oil bearing sands for the purpose of heating and emulsifying the oil, enabling it to be pumped to the surface. A SAGD facility will often have 10 or more OTSG’s in parallel.

There are no steam or mud drums in an OTSG. Their cylindrical shells contain only a continuous U bended coil running along the whole of the inside surface of the cylinder with the burner front and center. As their name implies the boiler feed water enters at one end of the coil and leaves as wet steam at the other end after a single pass.

The boiler feed is still treated but as the raw water used is already non potable and poor quality it is not treated to the same degree as in a conventional super heat steam boiler.

The piping connections are no different to a conventional boiler with the exception that if there is a blowdown at all it is likely to be a single connection.

Rotating Equipment

Pumps, Turbines & Compressors

Centrifugal Pumps

Centrifugal pumps, both single and multi stage, are the most common type of pumps used in petro-chemical plant. The fluid usually enters along the axis or center, is accelerated by the rotating impeller and exits at right angles to the shaft. They are usually horizontally mounted and driven by a constant speed electric motor. But they can be vertical, submerged or driven by a variable speed motor or turbine. They are often used in groups of 2 or more identical pumps in a single process service, often with a permanent spare pump to be brought online when one of the group is isolated and down for service.

They are usually connected in parallel, i.e. all the suctions are connected together by a one manifold and all the discharges by another, each pump has the same pumping volume (GPM) and operating pressure (psi) or head (ft.). When connected in parallel the total liquid volume required is the sum of the volumes of all pumps but each pump must be designed to supply the total head required.*

The suction and discharge manifolds are sized to carry the full pumping volume of all the related pumps. The smaller piping to and from each pump and the manifold must be designed to be symmetrical and without high points or low point pockets.

The nozzles on pumps are referred to as the suction and discharge. While discharge is an accurate description of the nozzles function, suction is not. Centrifugal pumps cannot create suction, they must have a minimum pressure or head of liquid at the inlet (suction) nozzle. As the impeller of the pump rotates it creates a low pressure area behind its trailing edge, depending on the vapor pressure of the liquid being pumped if the suction head pressure is too low the liquid will flash or boil behind the impeller. This causes vibration and wear of the impeller and is known as cavitation.

The process engineer must calculate the minimum height or head of liquid that must be maintained at the pump inlet to prevent cavitation. This calculation must take into account the specific liquid vapor pressure, the height of low liquid level of the vessel being pumped and the pressure loses due to friction in the pump inlet piping. The calculation will result in the net positive suction head required ( NPSH) for each pump or group of pumps.

The process engineer must indicate, on the P&ID, the minimum height above nominal grade, or the pump location, that the vessel bottom or tangent line must be to ensure that the NPSH is achieved. The piping designer must elevate the vessel to at least this height by means of saddles, support structure or vessel skirt.

Suction and discharge nozzles are typically smaller than their connecting piping due to manufacturers supplying pump casings for a range of duties with varying motor sizes. Reducers will therefore be required as close to the nozzle flanges as possible.

Pump casings and their nozzles are usually cast steel, but occasionally you will come across a casing , nozzle and flanges cast from iron, the flanges will be designated 125# or 250# and be flat faced. Cast Iron is a very brittle material and if a normal ANSI raised face flange is bolted to a CI flat face flange it is likely that the CI flange will crack because there is a gap between the faces. To avoid this all 125# or 250# CI flat face flanges must be mated with 150# or 300# with their raised faces removed. If this is not available in your piping spec than these flat face flanges mist be added as specialty items (SP)

The suction nozzle reducer should always be eccentric and be oriented top flat, if concentric or bottom flat reducers are used then air pockets can form on top of the suction piping and be drawn into the pump causing cavitation.

There are many opinions about if or when bottom flat suction reducers should be used. I have never heard a convincing argument for a concentric or bottom flat eccentric suction reducer regardless of the type of fluid or service of the pump, the only consideration is eradication of air in the top part of the horizontal suction piping. However the discharge nozzle can be concentric and vertical and bottom flat eccentrics can be used on horizontal discharges if required for drainage.

The suction and discharge reducers create natural flanged spools between the pumps and their isolating valves. The suction spool will contain the temporary strainer which must be removed after start up. The discharge spool must be removed before the pump can be lifted and removed for maintenance.

In the rare instance of suction or discharge piping being the same size as the nozzles always include straight spools on the suction and discharge nozzles between nozzle and first valve, do NOT be tempted to bolt the valves directly to the nozzles and eliminate these removable spools as it will compromise pump maintenance and removal.

Most, but not all, single stage pumps are arranged with their suction nozzle facing front and discharge nozzle facing up.

Single stage centrifugal pumps with suction and discharge nozzles facing each side are known as horizontal split casing pumps. The Casing is split to allow easier removal of the impeller.

All multi stage pumps have a side suction nozzle with an up or side facing discharge nozzle.

Regardless of the pump type, if it has a side facing suction nozzle the manufacturer will require at least 5 diameters of straight unrestricted pipe before the nozzle flange. This is to allow the liquid flow to become less turbulent after it leaves the last valve or elbow before the nozzle, excess turbulence at the impeller can again cause cavitation. (this assumes the most common multi pump layout where each suction line is running 90 deg from the manifold and parallel to each pump)

Nozzles on all types of rotating equipment are particularly sensitive to overloading and stress. It is not that they are weak, but rather that stress can be transferred through the casing to other components such as bearings and mechanical seals and cause premature failure. For this reason piping flexibility and pipe supporting is critical in this area.

The stress engineer will have the allowable loads that each nozzle can accept and after checking the layout for adequate flexibility, instruct the designer to place base supports on the suction and maybe the discharge piping close to the pump to minimize the nozzle loadings. What the stress engineer might not do is to request that these base supports be adjustable.

Adjustable base supports are required because after the initial installation and commissioning of the pumps and their piping small amounts of civil and mechanical ‘settlement’ take place. If the piping or pumps are removed during a shut down it may be found that there is some misalignment between the pump and it’s piping during re-assembly. Uncorrected misalignments of only fractions of an inch can cause the nozzle to become over stressed. If the supports are rigid no adjustment can be made to correct this misalignment. They must be adjustable, that decision is often made by the designer.

Pumps are fairly high maintenance equipment so their layout and accessibility is critical. Pumps are also one of the most common sources of fire due to ruptured pump seals. In the past common practice was that all pumps were placed under pipe racks which gave great accessibility for maintenance. This practice was discontinued in the 1970’s after many refinery fires where the whole pipe rack and aerial coolers above it collapsed after seal rupture fires originated in the pump row beneath. Modern plant layouts place the pump row outside but adjacent to the pipe rack, motors in, pumps out.

Always allow at least 1 meter between pump bases. This will need to be increased with the straight diameter requirements of side suction pumps. After the vertical reducer spool on top discharge pumps consider placing an elbow and running the check valve horizontal before turning back vertical to the isolating valve. This allows a base support under the second elbow to reduce nozzle load and lowers the isolating valve for operation, but this will also require wider pump spacing. Never run piping or allow cable tray to be run directly over the pump, this will eliminate any access to lift the pump or its motor.

Positive Displacement Pumps

These pumps are far less common than centrifugal pumps and fall into two sub categories

Reciprocating (Plunger, Diaphragm,Piston)

Reciprocating pumps move the fluid using one or more oscillating pistons, plungers, or diaphragms, while valves restrict fluid motion to the desired direction. In order for suction to take place, the pump must first pull the plunger in an outward motion to decrease pressure in the chamber. Once the plunger pushes back it will increase the pressure chamber and the inward pressure of the plunger will then open the discharge valve and release the fluid into the delivery pipe at a high velocity.

These pumps are usually used on very viscous and erosive fluids or slurries which would cause unacceptable wear on centrifugal pump impellers. They do not have the NPSH requirements of centrifugal pumps.

As they release the fluid in high velocity “slugs” they are usually are equipped with pneumatic suction and discharge dampeners to attempt to even out the flow. These dampeners are usually provided by the manufacturer and are mounted on the piping near the pump inlet and outlet. They consist of a vertical cylinder with an air filled bladder inside.

The release of the fluid is cyclic and just like reciprocating compressors the discharge piping is subject to vibration and must be firmly “held down” local to the pump.

Rotary (Gear, Screw, Rotary Vane)

Rotary positive displacement pumps are even less common than reciprocating but are used in similar services. They have the advantage of continuous non vibrating flow but the nature of these pumps requires very close clearances between the rotating impeller or gear and the inner wall of the casing, making it rotate at a slow, steady speed. If rotary pumps are operated at high speeds, the fluids cause erosion, which eventually causes enlarged clearances that liquid can pass through, which reduces efficiency..

Note

*In pipeline pumping stations multiple pumps are usually connected in series i.e, the discharge of one pump is connected to the suction of the next and each pump must be designed to supply the total fluid volume required. The total head required is the sum of the head of all the pumps. This due to the fact that the pipeline distances are much longer than plant piping and therefore the head is far greater. As the volumes are also greater pipeline pumps are also much larger.

Centrifugal Compressors & Gas Turbines

Centrifugal Compressors & Gas* Turbines are mechanically similar; they both contain a series or stages of rotary vanes connected to a shaft. The turbine is a driver, the compressor is driven.

In a gas turbine the gas or superheated steam (considered to be a dry gas) enters the inlet nozzle at high pressure, it expands as it passes through and rotates the vanes which rotate the drive shaft. It then exits the outlet nozzle as a low pressure gas or LP steam.

In a compressor it is the reverse. The gas enters the inlet nozzle at low pressure, it is compressed as it passes through the vanes which are rotated by the driven shaft (sometimes turbine driven **) and exits the outlet as high pressure gas.

Due to the high degree of engineering integrity and close mechanical tolerances of gas turbine and compressor internals the protection of those internals is even more critical than that of pumps. The nozzle loadings are usually governed by the National Electrical Manufactures Association (NEMA) this is due to the fact that most large turbines are the drivers of large electrical generators.

These fairly conservative allowable nozzle loadings make the coordination between the piping designer and the stress engineer critical, particularly when it comes to the inlet nozzle of HP steam turbines. The combination of high temperatures, expansion movement and low allowable inlet nozzle loads is particularly challenging for both designer and engineer. A general rule is to try and change the HP steam line routing direction in 3 planes immediately before the inlet nozzle trap.

The rotating vanes of a gas turbine or compressor are also very vulnerable to damage from small solid or liquid particles in the inlet gas stream and requires filtration of the inlet gas usually in the form of an inlet gas scrubber. With the steam turbine the biggest threat is from high velocity condensate droplet carry over during warm up prior to start up. It is critical that the steam trap system before the inlet Trip & Throttle Valve (T&T) is properly designed.

Notes

*The Gas turbine referred to here is a turbine driven by high pressure gas or superheat steam where the fluid expands through the turbine stages to rotate the vanes and shaft.

It is not to be confused with the jet engine type where fuel is injected and ignited. The expanding hot gas rotates the vanes and shaft and drives the built in in-line centrifugal combustion air compressor. However this type of jet turbine is sometimes used as the driver for large centrifugal gas transmission pipeline compressors.

Neither of these turbines is mechanically similar to the large water driven turbines used in the Hydroelectric generation industry.

** This turbine driven compressor arrangement is sometimes known a Turbo Expander in gas and refrigeration plants. The primary purpose of the Expander is to provide high gas pressure reduction but also provides drive to the compressor as a secondary function.

Reciprocating Compressors

A large Turbine driven Reciprocating Compressor with the suction and discharge bottles removed

Reciprocating Process Gas Compressors (recip.) * are usually large horizontally opposed twin or multi cylinder, multi stage machines which, like positive displacement pumps but unlike centrifugal compressors, produce a pulsating flow. This flow pattern coupled with the fact that they often are used to compress heavier than air gases makes them one of the most common causes of plant explosion. To avoid this hazard the layout and piping design around reciprocating compressors is critical.

From a layout point of view two points are critical. Firstly enclosing a recip inside a building significantly increases the explosion risk, it is much safer to place them in a shelter which has some open sides to ensure good ventilation. Secondly the temptation to run low level piping in open or closed trenches should be avoided, again because of the explosion risk due to heavier than air gases collecting at low points with poor or no ventilation.

The reason for running all suction and discharge piping at low level is to “Hold Down” the piping subject to pulsating flow, these hold downs must be on a solid concrete surface not elevated steel structures. The hold down points are determined by the Analogue Study that must be commissioned on all large recip piping systems. This study is usually carried out by a specialist contractor and examines the interactions of the pulsation cycles and natural vibration frequencies and determines were the hold downs must be placed to minimise those interactions. Placing of the hold downs where required by the study is critical. Hold downs are usually included in the company pipe support standards and consist of special clamps designed to limit vertical piping movement while allowing lateral movement.

The Analogue Study will cover the whole piping system from the suction scrubber outlet to the discharge scrubber inlet as a minimum, but often it will go far beyond the discharge scrubber. A scrubber is more accurately described as a vapor-liquid separator and is usually a vertical vessel. They are required to prevent liquid entering and damaging the recip and from forming liquid slugs in the discharge piping. It is important not to pocket the piping between the scrubbers and the compressor more than absolutely necessary as a liquid slug forming in any part of the suction or discharge piping can cause catastrophic damage.

Notes

*Instrument and Utility Air compressors are also usually reciprocating but are much smaller that the compressors above and are usually supplied in an enclosed vendor package.

Lube Oil Systems and Cranes

All compressors and turbines require a Lubrication (Lube) Oil system. This is usually provided by the equipment vendor and consists of tanks, pumps filters and coolers. In the case of a large recip the Lube Oil system will be extensive and usually be mounted on its own skid or module.

As this module will have been designed by the equipment vendor care should be taken in checking the vendor’s layout drawings to ensure it meets the clients access and maintenance standards.

Most large centrifugal compressors and turbines require a dedicated overhead crane for maintenance. In the case of reciprocating compressors this is mandatory. The cylinders, pistons and suction / discharge bottles are very heavy and require the designer to allow adequate space for removal and lifting over the main crankshaft casing.

As with pumps, running any piping or cable tray directly above a compressor or turbine will seriously compromise maintenance of the equipment.

Racks and Tracks

Pipe racks and tracks are the primary means of routing multiple lines through a plant facility.

Pipe Track

The pipe track or sleeperway is the less common of the two types. The track is a series of laterally unconnected low beams supported on piles usually no more than one meter above finished grade. They are usually a single level of piping although they can sometimes incorporate an elevated partial level to support cable trays.

The beam spacing can be based on the maximum acceptable span of the smallest line, with intermediate tray supports, if required. However this will limit the track for future additions of smaller lines. If future additions are likely then the standard spacing of 6 Meters should be used.

Care should be exercised in the routing of pipe tracks as they present a continuous obstruction to access, while stiles can be erected for personnel access, providing vehicle access will usually involve elevating the pipe track to a bridge over the road.

Unlike elevated pipe racks tracks do not change elevation when they change direction. Care is therefore required to arrange the lines in the correct order as there are few opportunities to change order. The flat turn nature of the track also makes adding future lines more difficult than a rack.

The most common use of tracks or sleeperways is in offsite tank farms where they are necessary to keep the suction lines low until they reach the tank export pumps located outside the tank berm. The lines pass through the bottom of the berm with sealed sleeves.

As there is a significant reduction in the capital cost of tracks over racks the discharge from these pumps together with the tank feed lines and utilities are usually routed on tracks until they reach the main plant process unit pipe racks..

Pipe Rack

Pipe racks are the freeways of piping through any unit or plant. They form the spine of the unit along which all plant equipment is located. They are always elevated as this provides good secondary vehicle access beneath them. The overhead clearance to the lowest side steel should be 6.0 Meters within unit battery limits but this should be increased when crossing major plant roads or railroads. See para 8.1 of Piping and Plant Layout Standard For Oil & Gas Facilities in the Procedures and Standards blog on this site.

(Historic Note :- Until the 1970’s process pump rows were commonly located each side of and underneath the pipe rack. Motors were on the inside with the nozzles facing out, and fork lift access was provided down the middle. This was a very efficient use of plant real estate and gave good maintenance access to the pumps.

Unfortunately ruptured pump seals are a major cause of refinery fires. With the lowest level of process rack lines running directly above the pumps fire could quickly spread into the rack which would often collapse completely bringing down the aerial coolers mounted above it.

After several major refinery fires involving significant equipment loss this practice was discontinued and the pumps were moved to the out sides of the rack in future designs.)

Rack Levels

Main unit pipe racks usually consist of a minimum of 3 levels. The top level is cable tray, the next level down is for utility lines and the bottom level is for process lines. This arrangement prevents electrical cables being subjected to leaks from any lines and prevents utility lines being subjected to possibly corrosive leaks from process lines.

The levels are usually 2 meters apart with lateral side steel positioned 1 meter below the top, middle and bottom levels. These distances can be reduced but it must be remembered that the 1 meter side steel will allow all line sizes up to 12” to drop or rise out of the rack using 2-90 deg. elbows.

If this distance is reduced the larger lines will require 1-45 deg and 1 rolling 90deg. Elbow.

If the rack is to be transported as a module this may have an impact on the level spacing and the overall height. See Modularization below.

Width and Span

There is no theoretical maximum width of a Pipe Rack but they are usually limited to a maximum of around 10 meters to economize on plant space and keep beam sizes to a reasonable depth and avoid the need for center beam columns. If the rack is to be modularized then local road transportation permit limits will apply and place limits on the rack width.

For these reasons major racks connecting several units may require two process and or utility levels.

New pipe racks should be sized for present needs plus 25%. This practice assumes a contingency of 10% at the outset of the job, but anticipates this will have been used upon completion of engineering, leaving 15% for future needs.

The span between ‘bents’ (the goal post arrangement of columns and beams at each support) in process units has always been 20 ft. or 6 meters. This is based upon the span and acceptable deflection of a 2” Sch.40 liquid filled line.

For this reason it is common practice for rack lines to be a minimum of 2”. Any line below this size is increased to 2” as it enters and reduced to normal when it exits the rack.

Change of Elevation

The major philosophy of Pipe Rack design is that a change elevation must occur at each change of direction. As the rack turns through 90 deg, each level will rise or drop by the distance between the main levels and the side steel.

This allows piping to change order at the turn and the easy transition of one rack making a tee junction with another.

Change of elevation with direction applies equally to an individual line as the whole rack. Expansion loops and the rise or drop of lines leaving the rack are good examples of this.

A flat turn across a currently unoccupied rack will effectively kill that rack space for future lines.

Line Entry or Exit

Whether a line should rise or drop out of a rack is dependent on the fluid phase. Vapour lines should always branch from the top of the header and rise out of or into the rack, this prevents liquid carry over from the condensates that form in the bottom of most vapour lines.

Liquid lines can branch from either the top or the bottom of the header and rise or drop out of the rack, although top connections are still preferred if there is a choice..

Generally speaking pocketing of any line should be avoided, all rack expansion loops should therefore rise up and over the side steel above the specific rack level. Drains or drip legs should be provided on all lines between loops.

Line Position and Expansion

The largest and heaviest (liquid filled) lines should always be located on the outside of the rack close to the columns.

The reasons being :-

To reduce mid span beam deflection and size.
To maximise the rack width available for the largest expansion loops.

Anchors for all lines should be placed at the same ‘bent’ or support beam. This allows the structural group to design the additional bracing required for the anchor loading in one bay rather than several. The ‘nested’ expansion loops for all lines will occur midway between the anchor points.

Most steel fabricated pipe racks are fireproofed with a fire retardant coating during construction, especially those which have aerial coolers mounted above cable tray level.

This coating can be up to 50mm thick so allowance must be made when positioning the outer lines nearest the rack columns.

For general line rack spacing see the Rack Spacing Chart in the Standards/Selection and Application Guides section of the Procedures and Standards Blog of this site.

These charts are based on maintaining approximately 25mm between any pipe, insulation or flanges.

When checking the rack layout against the stress sketch it is important to check that the expansion movement at the change of direction of each line does not interfere with the adjacent line.

If so then the line spacing must be increased or the expansion movement decreased.

Rack Access

Pipe racks are generally considered to be an accessible area for access to valves or orifice meter runs. Generally the only area where permanent platforms and ladders are always required is at the battery limit of the unit rack were it joins the main plant rack.

This is where double block and bled valves are located to isolate all lines in the unit from the headers in the main plant rack to allow a unit shut down. The process and utility lines use an elevation change ‘waterfall’ to arrange the valves vertically at the front and rear sides of the platform.

Safe isolation is achieved by inserting blinds at the valves, this is a heavy duty manual task which requires good permanent access.

Sloping Lines and Flare

With the exception of flare lines it is unusual for any line to be required to slope in the rack

If a P&ID shows that a non flare line is required to slope it is worth asking the process engineer whether sloping the line is absolutely necessary. There are occasions when there is confusion over the subtle difference between ‘slope’ and ‘do not pocket.’

If a non flare line must slope then it will have to be placed on the elevated tee posts or cantilevers described below. As a slope also implies free draining with no pockets any expansion loops on this line must ‘flat turn’ across the rack in the same way that the flare line loops do.

Flare lines are always required to slope or drop continuously from the far end of a unit to the Flare Knock Out Drum to ensure that no condensate liquids can be trapped in the line and prevent a PSV from discharging freely and without resistance.

The flare line is usually run on a tee post extension of the main rack columns above the cable tray level on one side of the rack. Where there is an aerial cooler structure on top of the rack the line is run on cantilevered beams outside the columns.

To achieve the slope (usually 1:500 min.) a combination of variable height shoes and changing top of steel elevations is used.

The top of steel elevation stays consistent for around 4 tee posts/cantilevers while the shoes are varied from max to min height at each subsequent support, then the tee post/cantilever is lowered and the process repeats.

Modularization

Modularization has become the preferred method of most major plant construction over the past 30 years. While it can be argued that there is a limit to how many pieces of equipment can be economically modularized and whether the amount of additional transport steel can be justified, there is no argument when it comes to pipe racks. Their size , shape and natural framework make them ideal candidates for modularization.

One disadvantage is that the structural engineer will often design bracing on both sides and vertically across all rack levels and all bays to stiffen the structure for transport and lifting. This becomes a restriction to line exit and entry and must be carefully clash checked.

Some engineering companies feel that all module connections should be flanged for ease of construction. I personally disagree. A pair of flanges on connecting modules are far more susceptible to misalignment than butt welds and for the sake of saving some construction time hundreds of potential flange leak points have been created.

Transport restrictions control all of the design dimensions of a module but particularly the height. The clearance for the module to pass under power lines and bridges is critical. The layout of the rack and it’s absolute highest point must be carefully checked during design and compared with the lowest permitted height clearance along the whole intended transport route. This information should be provided to the design team by the transport company early in the design phase. To reduce the height measured from the truck bed the lower support columns, lower side steel and bracing are not included as part of the module but are ‘stick built’ (constructed on site).

The active module transport height is measured from the underside of process level beam, which is supported on the truck bed, to the top cable tray level or the highest vent valve, the columns, which overhang and drop below the truck bed, are provided with splice plates to connect with the stick built columns.

As the truck bed is directly below the process level support beam any lines which drop down out of the bottom process level and leave the rack via the lower side steel are not included in the module and are also stick built.

The module can usually be up to 30 meters (4 bays+ 2 half bays) long (check your local transport restrictions), the split between modules should be located mid bay at each end.

The only additional steel required to transport a rack are temporary line hold downs and temporary braced beams at each level to support the 3 meter line overhangs at each end during transportation.

Lists & Logs

This section contains a collection of downloadable Excel spreadsheets of typical process/piping templates such as line and equipment lists together with others which can be useful in logging or tracking the many types of information a piping lead or designer has to manage during the course of a project.
They include in the following order :-

Line Designation Table (LDT or Line List) template
LDT Notes
Equipment List template
Instrument Index template
Tie-In List template
Vendor Equipment Drawing tracking log
Vendor In-Line Instrument Drawing tracking log
Stress Critical Line List template
Stress Sketch Log template
Piping Man-Hour Estimate template
Piping Needs List template
Piping Material Take Off – Small Bore template
Piping Material Take Off – Large Bore template
Piping & Steel Component Dimension Charts
Imperial Dimension Abacus
Metric/Imperial Dimension Converter
Iso & GA Tracking Log template

Procedures & Standards

Procedures

The following text and graphics link to full size Word, Excel and PDF documents that are freely downloadable to non commercial individuals seeking to enhance their piping knowledge.

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Piping and Plant Layout of Oil and Gas Facilities

Appendix 1 Vents & Drains

Appendix 2 Straight Run Requirements

Specification for Pipe Fabrication & Installation

Model, Isometric & GA Checking Procedures

Appendix 1 Clash Check Procedure

GA Check List

Piping Isometric Check List

Plot & Key Plan Check List

Equipment Model Checking Flowchart

Model Review Procedure

Study Model Readiness Checklist

Model Readiness Checklist (30%)

Model Readiness Checklist (60%)

Model Readiness Checklist (90%)

Model Review Matrix Table

Model Review Log Form

Model Review Covenants

Standards

Selection and Application Guides

Standard Piping Details

Piping Standards Detail Drawing Index

Piping Details

Glycol Tracing Details

Pipe Support Details

Pipe Support Specification

Base Anchor, Support & Guide Details

Clamp Details

Full & Directional Anchor Details

Dummy Support Details

Field Support Details

Pipe Carrier Details

Guide Details

Pipe Hanger & Spring Details

Welded Pipe Shoe Details

Clamped Shoe Details

Riser Clamp Details

Reinforcing Pad Details

Teflon Slide Plate Details

Special Pipe Support Details

Vessel Pipe Guide Details

Vessel Pipe Support Details

The Basics of Piping

1.1 A Brief History
1.2 Codes and Standards
1.3 Organizations
1.3.1 ASTM
1.3.2 ANSI
1.3.3 ASME
1.3.4 API
1.3.5 MSS
1.3.6 CSA
1.3.7 Other Organizations

1.4 Pipe and Tube Definitions and Dimensions
1.4.1 Pipe
1.4.2 Tube

1.5 Pipe and Tube Manufacturing Terminology
1.5.1 Continuous Weld (CW) or Butt Weld (BW)
1.5.2 Electric Resistance Weld (ERW)
1.5.3 Double Submerged Arc Weld (DSAW)
1.5.4 Spiral Weld (SPRLW)
1.5.5 Seamless (SMLS)

1.6 Materials

1.7 Fittings and Joining Methods
1.7.1 Threaded
1.7.2 Socket-weld
1.7.3 Butt-weld
1.7.4 Other Joining Methods

1.8 Types of Fittings
1.8.1 Branch Fittings
1.8.2 Reducing Fittings
1.8.3 Changes of Direction Fittings
1.8.4 Joining Fittings
1.8.5 Closure Fittings

1.9 Flanges, Gaskets, Bolting
1.9.1 Flanges
1.9.2 Gaskets
1.9.3 Bolts and Nuts

2.0 Valves
2.1.1 Gate
2.1.2 Globe
2.1.3 Butterfly
2.1.4 Diaphragm
2.1.5 Ball
2.1.6 Plug
2.2 Valve Operators
2.2.1 Hand-wheels & Levers
2.2.2 Gear Operators
2.2.3 Control
2.2.4 Pressure Safety/Relief

3.0 Bibliography

1 PIPE AND FITTINGS

1.1 A Brief History

Piping has been discovered in civilizations dating back many thousands of years. Initially pipe materials were limited to locally available natural substances, such as wood, stone and clay. Wooden pipes made from logs have been uncovered in many parts of the world and clay pipes dating back 6000 years have been discovered in ancient ruins such as Babylon. Sewage pipeline systems made from bored logs were laid in Boston, Philadelphia and New York as late as the 18th century. With the ability to smelt metals, society also turned to iron, brass, copper, and lead. The Greeks and Romans both experimented with lead and a lead piping system has been uncovered in the ruins of Pompeii, complete with bronze plug valves, just as it was when covered by ash in 87 BC.
The invention of the cast iron cannon brought about the adaptation to cast iron pipe. It isn’t surprising therefore that the first pipe manufacturers were the same that had the processes to manufacture cannons and muskets. Cast iron pipe was used in Germany as early as the 15th century, and by the French in the 17th century to supply water to the fountains at Versailles.
The first strong but economical pipe was made in 1825 when a method of manufacturing pipe from long strips of hot metal was devised. As the Industrial Revolution gained momentum and the efficiency of the steam engine was improved, the need for stronger piping materials that could contain higher pressures and temperatures became necessary. The discovery of the Bessemer process in 1855 and the open-hearth process in 1861 were important steps that made steel pipe widely available.
In the early part of the 19th century industry recognized the need for standardization, and the Iron Pipe Size (IPS) system was established. This system standardized an outside diameter and a wall thickness for each pipe size, and designated that pipe be referred to as 2″, 3”, 4″, 6″, and so on, according to the approximate inside diameter in inches, a practice that continues to this day. The one wall thickness per pipe size became known as standard weight (STD WT) with the introduction of two further heavier wall thicknesses required to satisfy the growing industrial demands for the handling of higher pressure fluids. These heavier walls, known as extra strong weight (XS WT) and double extra strong weight (XXS WT), were accomplished by reducing the pipe inside diameter while the standardized outside diameter remained unchanged.
In the post-World War 1 U.S. the power and process industries began to expand greatly, with the eventual need for even higher-pressure and higher-temperature materials and joining methods. Advances in welding technology were made, stronger more corrosion resistant materials were developed and manufacturing and testing methods of pipe and fittings were improved. For example, seamless pipe formed from solid billets of steel became common. The three IPS wall thicknesses no longer sufficed for all applications, and as a result a new method of specifying pipe size and wall thickness became necessary. In 1927 the American Standards Association (ASA), later to become the American National Standards Institute (ANSI), started the development of the Nominal Pipe Size (NPS) system to replace IPS. This system incorporated a wider range of wall thicknesses than the previous IPS system. In this system pipe is specified by two dimensionless designators: a nominal pipe size (NPS) for the diameter and a schedule number (Sch.) for the wall thickness.
Piping systems include pipe, flanges, fittings, bolting, gaskets, valves, and other pressure-containing components such as expansion joints and instruments. In today’s society piping systems transport products and waste of all types of fluids, and in all types of industries: residential, commercial, and industrial. They are designed to specific codes and standards for numerous applications. The design, construction, operation, and maintenance of piping systems involves an intimate understanding of piping principals, materials, generic and specific design considerations, fabrication and installation, examination, testing and inspection requirements, and application of local, provincial and federal regulations.

1.2 Codes and Standards

The assurance that the design and construction of a piping system will meet prescribed pressure-integrity requirements is achieved through the use of published codes and standards. Codes usually set forth requirements for design, materials, fabrication, erection, testing, and inspection of piping systems, whereas standards contain design and construction rules and requirements for materials and individual piping components such as elbows, tees, flanges and valves. Compliance to standards is normally required by the rules of the applicable code or the purchaser’s specifications. Compliance to codes is at the least generally imposed by insurance companies and owners’ requirements, but most often is mandated by government legislation enforced by regulatory agencies to ensure the safety of workers and the general public.
Two such legislations in Alberta are the Safety Codes Act and the Pressure Equipment Safety Regulation, enforced by ABSA the pressure equipment safety authority for Alberta. Two codes mandated in the legislation are: CSA B51, Boiler, pressure vessel, and pressure piping code, and CSA Z662, Oil and gas pipeline systems.

1.3 Organizations

Codes and standards relating to piping systems and piping components are published by various organizations. These organizations have committees made up of representatives from industry associations, manufacturers, professional groups, government agencies, insurance companies, and other interested parties. The committees are responsible for maintaining, updating and revising the codes and standards in view of technological developments, research, experience feedback, problems, and changes in referenced codes, standards, specifications, and regulations. The following describes several of the organizations most often encountered:

1.3.1 ASTM

The American Society for Testing Materials, now called ASTM International, is an organization that develops and publishes standards on the characteristics and performance of materials, products, systems, and services. The standards include test procedures for determining or verifying characteristics, such as chemical composition, and measuring performance, such as tensile strength and bending properties. The standards cover refined materials, such as steel and plastic, and basic products manufacturing methods and tolerances, such as for pipes and tubes.

1.3.2 ANSI

The American National Standards Institute was earlier known as the American Standards Association (ASA) and for a short period of time, from 1967 to 1969, as the United States of America Standards Institute (USASI). ANSI provides a forum for development or obtaining a consensus for approval of standards having national impact and serves as a focal point for distribution of national and other standards, including those developed and issued by the International Organization for Standardization (ISO) and foreign governments. Development and approval functions are performed by the various committees. Many of the committees are chaired or sponsored by engineering societies such as ASME. Safety is the basic objective of the engineering design and construction requirements contained in ANSI standards. The standards include prohibition for practices considered unsafe and cautions where advisory warnings, instead of prohibitions, are deemed necessary. Many ANSI codes and standards have become ASME codes and standards. For example: the original ANSI B31, Pressure Piping Code has become ASME B31, Pressure Piping Code, and ANSI B16.5, Pipe Flanges and Flanged Fittings has become ASME B16.5 Pipe Flanges and Flanged Fittings. However, they are subjected to the approval of ANSI.

1.3.3 ASME

The American Society of Mechanical Engineers is one of the leading organizations in the world that develops and publishes codes and standards. Notably, the ASME established a committee in 1911 to formulate rules for the construction of steam boilers and other pressure vessels. This committee is responsible for the ASME Boiler and Pressure Vessel Code, an 11-section code covering the materials, construction and testing of piping, boilers, and pressure vessels in many different industries, including the nuclear industry. Other committees are responsible for the sections of the ASME B31, Pressure Piping Code.

1.3.4 API

The American Petroleum Institute publishes specifications, bulletins, recommended practices, standards and other publications as an aid to procurement of standardized equipment and materials. These publications are primarily intended for use in petroleum production and transmission facilities, specifically oil and gas pipelines. Examples of API standards are API 650, Welded Tanks for Oil Storage, and API 5L, Specification for Line Pipe.

1.3.5 MSS

The Manufacturers Standardization Society of the Valve and Fittings Industry publishes Standard Practices, which provide a basis for common practice by manufacturers, the user, and the general public. The MSS is represented on the committees of other standardization groups, such as ANSI and ASME. The existence of a MSS Standard Practice does not preclude the manufacture, sale, or use of products not conforming to the Standard Practice. Mandatory conformance is established only by reference in a code, specification, sales contract or public law, as applicable.
A MSS Standard Practice will often fill gaps not covered by other organizations and may lead to the development of other standards. For instance, MSS SP-44, Steel Pipeline Flanges, was originally written to provide a standard for flange sizes larger than NPS 24 not covered by ASME in the B16.5 standard, and later formed the basis for the ASME standard B16.47, Large Diameter Steel Flanges NPS 26 through NPS 60. Many of the ASME B16 series standards were originally developed as MSS Standard Practices.

1.3.6 CSA

The Canadian Standards Association publishes codes and standards to enhance the safety and health of the Canadian public. For instance, the CSA Z662, Oil and Gas Pipeline Systems, specifically deals with the design, construction, operation, and maintenance of oil and gas industry pipeline systems in Canada.

1.3.7 Other Organizations

While the above may be some of the more commonly encountered organizations, there are many other organizations to be aware of that make their own significant contributions to industry, such as:
• The National Association of Corrosion Engineers, now called NACE International.
• The Tubular Exchanger Manufacturers Association, Inc. (TEMA).
• The National Fire Protection Association (NFPA).
• The American Water Works Association (AWWA).
• The American Welding Society (AWS).

1.4 Pipe and Tube Definitions and Dimensions

Pipes and round tubes are separate, although quite similar, products. The term tubular product, which infers a long hollow cylinder, is applied to both, and both are fabricated of materials and to dimensions governed by ASTM and ASME standards. The main differences between the two are the end uses and that pipe is specified by nominal diameter and schedule for wall thickness, while round tube is specified by outside diameter and gauge for wall thickness.

1.4.1 Pipe

A tube with a round cross section conforming to the dimensional requirements for nominal pipe size as tabulated in ASME B36.10M, Welded and Seamless Wrought Steel Pipe, and ASME B36.19M, Stainless Steel Pipe, and materials per the appropriate ASTM or API specifications. Products called pipe include conduit pipe, piling pipe, transmission (line) pipe, and pressure pipe.
An initial standardization between manufactures was the Iron Pipe Size (IPS) system which established an outside and an inside diameter for each of the various pipe sizes. Pipe was referred to by its approximate inside diameter in inches, e.g. 2″, 3″, 4″, and so on. Later, two heavier wall thicknesses were added, making three wall thicknesses per pipe size available: the existing standard weight (STD), plus the designations of extra strong (XS) and double extra strong (XXS). Extra strong and double extra strong are sometimes referred to as extra heavy (XH) and double extra heavy (XXH). Eventually the demand grew for an even broader range of wall thicknesses and the Nominal Pipe Size (NPS) system was introduced. The outside diameters (OD) established in the IPS system were retained, but in this system the correct nomenclature for pipe size became NPS followed by a dimensionless designator, e.g. NPS 2, NPS 3, NPS 4, and so on. Wall thicknesses (WT) are expressed as a schedule number (Sch. 5, 10, 20, 30, 40, 60, 80, 100, 120, 140, or 160). While it was intended that the three IPS wall thickness designations would be phased out, these were retained and correspond to certain schedule numbers: STD corresponds to Sch. 40 in pipe sizes NPS 10 and smaller; XS corresponds to Sch. 80 in pipe sizes NPS 8 and smaller.
In both the IPS and NPS systems the outside diameter of a given pipe size remains constant and the inside diameter (ID) decreases as the wall thickness increases. Refer to Figure 1-1 Pipe Dimensions. For pipe sizes NPS 12 and smaller the actual OD is larger than the nominal OD. For NPS 14 and above the actual OD and the nominal OD are the same, e.g. a NPS 12 pipe has an actual OD of 12.75″, and a NPS 14 pipe has an actual OD of 14″. Be aware that, although available, certain NPS sizes are not commonly used: 1¼, 2½, 3½, and 5.
The original intent of the NPS system was to establish a dimensionless system of schedule numbers for wall thickness and pipe size combinations having an approximately
uniform relationship equal to the expression 1000 x P/S, where P is the internal working pressure (psig) and S is the allowable stress (psi) for the pipe material at temperature, derived from the pipe wall thickness formula used at the time. However, while many texts still state this relationship, the official ASME position is that the numbers deviated appreciably from the common wall thicknesses in use and this original intent could not be accomplished, rendering the schedule numbers as a strictly convenient nominal number for use in ordering. (Note that the B31 code requires the use of a more complex hoop stress calculation to determine the actual pipe wall thickness to be used. This calculation takes into account mill tolerance, corrosion allowance, thread allowance, and seam weld strength.)
Stainless steel pipes, which were coming into more common use in the mid 20th century, permitted the use of thinner pipe walls with much less risk of failure due to corrosion. By 1949 thinner schedules 5S and 10S, which were based on the pressure requirements modified to the nearest Birmingham Wire Gauge (BWG) number, had been created, and other S schedule sizes followed (20S, 30S, 40S, and 80S). Schedule numbers followed by the letter S
are primarily intended for use with stainless steel pipe, and may or may not be the same wall thickness as that specified for a schedule number without the letter S. Note that due to their thin walls, the smaller S sizes cannot be threaded together according to ASME code, but must be fusion welded.

1.4.2 Tube

Tube is defined as: a hollow product of round or any other cross-section having a continuous periphery. Round tube size is specified with respect to outside diameter and wall thickness. Dimensions and materials are specified in the appropriate ASME or ASTM specifications. Pressure tubes are used in externally fired applications while carrying pressurized fluids. Structural tubing is used for general structural purposes related to the construction industry. Mechanical tubing is produced to meet particular dimensional, chemical, and mechanical property and finish specifications, which are a function of the end use, such as machinery and automotive parts. The biggest use of tubing in the process piping industry is instrument tubing, heat tracing, and heat exchanger and boiler tubes.
Any tubular products not built to ASME B36.10 or B36.19 dimensions are called tubing. Round tubing is referred to by its actual OD and WT. 1″ tubing is actually 1″ OD, 3″ tubing is actually 3″ OD, etc. For each tube size a variety of wall thicknesses are available, so the WT must also be specified. WT is often specified using Birmingham Wire Gauge.

1.5 Pipe and Tube Manufacturing Terminology

There are many methods of manufacturing pipe and tube, but basically there are two types of pipe and tube forming processes, namely welded and seamless. Seamless pipe or tube does not have a welded seam along the length of the pipe. The seam on welded pipe is a source of potential weakness and the allowable stresses for the pipe wall are reduced by a weld joint quality factor (E) ranging from 0.6 for furnace butt welded to 1.0 for seamless pipe (60% to 100% of the allowable stress value (S) for the material) in the B31 code wall thickness formula. The weld joint quality factor is set based on manufacturing process and Non-Destructive Examination (NDE) used. A weld joint strength reduction factor (W) ranging from 0.5 to 1.0 was added to the wall thickness formula in 2004. This factor is to account for the loss of pressure retaining strength of weld metal operating at creep range temperatures above 427°C (800°F). In the revised wall thickness formula, SE is multiplied by W.
Although longer lengths may be special ordered for pipeline use, steel pipe is commonly manufactured in random lengths, approximately 20′ (6m) long, and double random lengths, approximately 40′ (12m) long. The lengths vary due to the removal of damaged ends. The wall thickness of pipe is also subject to an allowable mill tolerance of -12.5% that must be taken into account when doing wall thickness calculations.
There are three end finishes available: beveled end (BE), plain end (PE), and threaded and coupled (T&C) to match the three most commonly used joining methods.
Some common manufacturing methods follow:-

1.5.1 Continuous Weld (CW) or Butt Weld (BW)

To produce this product a continuous flat strip of steel called a skelp is fed into a furnace and heated to approximately 2500°F. The hot strip is then shaped by a series of rollers into a round. The edges are superheated by a blast of air and the rolls provide sufficient pressure to form a fusion weld. This pipe is manufactured in size ranges of NPS 1/8 to NPS 3.

1.5.2 Electric Resistance Weld (ERW)

There are several electric welding methods employed in this type of manufacture: flash welding, low-frequency resistance-welding, high-frequency induction-welding or high-frequency resistance-welding. All processes begin with the forming of the cylinder with the longitudinal seam butt edges ready for welding. A skelp is gradually formed into a cylindrical shape by a series of rollers. As the two edges come together they are fed into a electric arc welder. The welding operation consists of copper electrodes making contact on each side of the open seam. A combination of the high temperature caused by the weld current passing from one copper electrode to the other, and the pressure exerted by the rolls, results in a fusion of the strip edges. No weld material is added. This type of pipe is manufactured in the size ranges up to NPS 42.

1.5.3 Double Submerged Arc Weld (DSAW)

A set of rollers pre-forms the edges of a steel plate with a curve. Pre-forming of edges ensures the proper curvature results in the O-Press forming operation. The plate moves into position in the U-Press where a U-Die pushes the plate down between the breaker rolls. At the same time the breaker rolls move together. The U-Die is retracted leaving a “U” shaped product. The “U” shaped plate moves into the O-Press, which consists of two semi-circular dies. The top semi-circular die moves down to form the “U” into an “O”.
A series of belts surround the pipe at intervals to hold the free edges tightly together. The edges are tack welded to secure the “O” form. A boom containing a welding head is inserted through the length of the pipe to create a continuous internal weld. An external weld is performed at a different welding station. This type of pipe is manufactured in the size ranges of NPS 20 to NPS 42.

1.5.4 Spiral Weld Pipe (SPRLW)

In this process, narrow sheets of steel sheet are helically wound into cylinders. The edges of the strip can either be butting or overlapping and are welded by any of several electric arc-welding processes. Spiral weld pipe is suited to larger diameter and is manufactured in size ranges NPS 36 to NPS 60.

1.5.5 Seamless (SMLS)

This is a hot formed product. Seamless tube and pipe are manufactured by first producing a hollow tube which is larger in diameter and thickness than the final product. Various piercing methods are employed dependent on pipe size range and material, but all follow a similar manufacturing process. Billets of steel are heated in a furnace, and then each billet is conditioned by a machine similar to a lathe. In the piercing mill, the billet is gripped by rolls that rotate and advance it over the piercing point, forming a hole through the length. Large sizes must go through more than once. From the piercing mill, the pierced billet is put through a plug-rolling mill where the billet is rolled over a mandrel to reduce the diameter and wall thickness and to increase the length of the pipe. A rotary mill is used for NPS 16 and over, the diameter is enlarged, and the wall thickness is reduced to approximate finished dimensions. From there the pipe passes through the sizing mill on a series of rolls that create a true round shape of the required diameter and wall thickness. As no weld exists the weld joint quality factor is rated as 1.0.

1.6 Materials

Pipe and piping components are made from many different materials. One of the most common materials is carbon steel, although steels made with other alloying elements such as manganese and chromium are also widely used. The choice of material is based on the following requirements:
• Service conditions – pressure, temperature and type of fluid.
• Strength.
• Corrosion and erosion resistance.
• Ease of welding or bending.
• Availability.
• Cost.

Each material is manufactured to an ASTM standard. The most common piping materials are specified by ASTM with the following prefixes:
• A – Ferrous metals.
• B – Non-ferrous metals.
• C – Ceramics and concrete.
• D – Plastics.

Some common ASTM standards for steel pipe are A106 Gr. B (carbon steel for high temperature service), A333 Gr.6 (carbon steel for low temperature service) and A312 TP316/316L (stainless steel for corrosion resistant service). Figure 1-3 Typical ASTM Specifications for Materials lists other common standards.
The standards are further subdivided into various grades, e.g. Grade A, B, C and Grade 1, 2. The grades indicate different chemistry of the same basic steel, such as a higher carbon content, which increases the tensile strength but tends to make the steel more brittle (less ductile). Note: ASME add an S prefix to the ASTM code for piping materials approved for use in boilers and pressure vessels, e.g. SA-106.

1.7 Fittings and Joining Methods

Fittings come in a range of materials, wall thicknesses and end connections to join with pipe. There are three basic types of end connections for the three basic pipe-to-pipe and pipe-to-fitting joining methods: threaded (Thrd), socket-weld (SW), and beveled end (BE). Fittings with threaded or socket-weld ends, although available in all pipe sizes up to and including NPS 4, are, generally speaking, only used in piping systems NPS 1½ and smaller, often referred to as small-bore piping. Fittings with beveled ends, although available in all pipe
sizes down to and including NPS 1/8, are, again generally speaking, only used in piping systems NPS 2 and larger, often referred to as large-bore piping.

1.7.1 Threaded (Thrd/Scrd)

Threaded fittings, also known as screwed (Scrd) fittings, are manufactured according to ASME B16.11, Forged Fittings, Socket-Welding and Threaded. These threaded fittings come in Service Classes 2000, 3000 and 6000, with threads that conform to the American National Standard Taper Pipe Threads (NPT). The service classes correlate to pipe schedule/wall thickness: 2000 equals Sch. 80/XS, 3000 equals Sch. 160, and 6000 equals XXS. The fittings have female threaded end connections, while the pipe has a male threaded end which must be threaded into the fitting a minimum distance; this is referred to as a thread engagement length. Refer to Figure 1-4 Socket-weld and Threaded Insertions. Piping systems made of this type of joint are economical and can be rapidly assembled, however the threads are prone to damage, and leakage.

1.7.2 Socket-weld (SW)

Socket-weld fittings are also manufactured according to ASME B16.11 and come in Service Classes 3000, 6000 and 9000. As with threaded fittings, the service classes correlate to pipe schedule/wall thickness: 3000 equals Sch. 80/XS, 6000 equals Sch. 160, and 9000 equals XXS. These socket-weld fittings have female connections whose ID is very slightly larger than the pipe OD in order to accept the insertion of plain end (PE) pipe. The distance that the pipe is inserted into the fitting is referred to as the insertion depth. Refer to Figure 1-4 Socket-weld and Threaded Insertions. An approximately 1/16” gap is left between the shoulder of the socket and the end of the pipe to allow for expansion during welding and operation. A full 360O fillet weld holds the pipe into the fitting. Piping systems made of this type of joint are economical in the smaller size ranges, can be rapidly assembled, can accept a certain amount of misalignment, and are strong and leak free; however, the gaps can be a source of sludge build-up and corrosion.

1.7.3 Butt-weld (BW)

Fittings with beveled ends are referred to as welded fittings and are manufactured according to ASME B16.9, Factory-Made Wrought Steel Buttwelding Fittings. This standard requires that the butt-weld fittings must be at least equal to seamless pipe in strength.
The end preparation of butt-welded pipe and fittings is known as a beveled end (BE) because the pipe or fitting end has an angled bevel. The companion bevels (pipe-to-pipe, pipe-to-fitting, or fitting-to-fitting) are welded together by a full 360° circumferential butt weld, also called a full penetration weld because its depth is fully to the inside of the pipe. Piping systems made of this type of joint are strong and leak proof, and, because the weld can be x-rayed to prove integrity, are well suited to severe service, such as vibration. However, they require accurate alignment, and weld icicles inside the pipe can cause sludge build-up.

1.7.4 Other Joining Methods

As stated, the three joining methods discussed above are the most common used for pipe and fittings, but it is worth mentioning that there are other joining methods. One of these, often found in lower temperature and pressure water service applications, is the grooved joint method. Made famous by the Victaulic Company, a 360° groove is placed a short distance from the end of the pipe or fitting. The two ends of pipe and or fittings are held together by means of a two bolt clamp that includes a gasket that fits into the grooves.
Another joining method is a flanged joint. Flanges are most often attached to pipe and fittings by one of the three common joining methods, but, as will be discussed in more detail later, the flanged joint is also a common joining method unto itself for connecting to valves, instruments and equipment. Also, fittings with flanged ends are available for use in piping systems where welding is impractical, such as is the case with lined piping systems.

1.8 Types of Fittings

A fitting is a piping system component used for: branching; reducing pipe size; changing direction; joining of pipe and piping components; and pipe end closure.

1.8.1 Branch Fittings

Branch fittings allow branches to be made on pipes for splitting or combining fluid flow, or for instrument connections. Common branch fittings are tees, branch-reinforced fittings, and laterals.
• Tees are available in straight or reducing configurations. Straight tees get their name from the fact that the run and the branch are the same NPS size. Reducing tees have a smaller NPS branch size than the run. Straight tees are referred to by the run and the branch size as one, e.g. an 8 inch tee has an NPS 8 run and NPS 8 branch. Reducing tees are referred to by the run size times the branch size, e.g. an 8 x 6 tee is one with an NPS 8 run and a NPS 6 branch.
• Pioneered by the Bonney Forge Corporation in the nineteen-thirties and manufactured to MSS SP-97, Integrally Reinforced Forged Branch Outlet Fittings – Socket Welding, Threaded, and Buttwelding Ends, branch reinforced fittings are commonly referred to as Olets and primarily consist of thredolets (TOL), sockolets (SOL) and weldolets (WOL). These are welded directly to the pipe, and are referred to by the pipe size they are welded to times the branch size, e.g. a 10 x 2 WOL is one where the pipe run is NPS 10 and the branch pipe size to be matched is NPS 2.
• Laterals are similar to tees with the exception that the branch is at a 45° angle to the run.

1.8.2 Reducing Fittings

Reducing fittings allow for a change of pipe size in-line. They are available in concentric and eccentric configurations.
• Reducers are used in large-bore piping and are referred to by the large end times the small end, e.g. a 10 x 8 reducer is one that reduces the pipe size from NPS 10 to NPS 8. They come with beveled ends for butt-welding.
• Swages are used in small-bore piping and differ from reducers in that they have a tangent portion for insertion into the female threaded or socket-weld fitting. They are available in all combinations of end connection types, which must be noted when ordering, e.g. Plain Large End (PLE) x Threaded Small End (TSE), or Threaded Both Ends (TBE).

1.8.3 Change of Direction Fittings

Change of direction fittings are elbows (ELLs) fabricated to accommodate a required angle change in the piping configuration.
• Large-bore elbows come with beveled ends and are available in 45°, 90° and 180° configurations. The 90° and 180° elbows are available in Long Radius (LR) and Short Radius (SR) configurations, whereas the 45° elbows are only available in a long radius configuration. Long radius elbows have a radius equal to 1½ times the NPS, e.g. a NPS 6 LR ELL has a radius of 9”. This is also referred to as 1½ D. Short radius elbows have a radius equal to 1 times the NPS, e.g. a NPS 6 SR ELL has a radius of 6”. Longer radius elbows can be created by bending pipe. In pipelines it is quite common to specify 3D or 5D elbows.
• Small-bore elbows come with threaded or socket-weld ends and are only available in 45° or 90° configurations, with one radius for any given NPS pipe size.

1.8.4 Joining Fittings

Joining fittings are used in piping systems to connect lengths of pipe, and to connect pipe to instruments, valves, and equipment.
• Couplings are used to join lengths of pipe in small-bore pipe configurations. They are available in threaded or socket-weld end types.
• Unions are also used in small-bore piping configurations, but are used in strategic locations around instruments, equipment and valves to allow for ease of assembly and disassembly. They too are available in threaded or socket-weld end types.
• Flanges are a stud-bolted, gasketed joint used to connect to instruments, equipment and valves. They come in a variety of facings, ratings and end types to address pressure, temperature and commodity requirements. They are found commonly in large-bore piping configurations, but are sometimes also used in small-bore piping configurations in place of unions.

1.8.5 Closure Fittings

Sometimes it is required to Blind-off or Cap-off an open-ended line. An example would be where piping has been designed with future expansion in mind, or equipment has been removed for repair.
• Plugs are used in small-bore lines, in socket-weld and threaded configurations. They are of a male configuration, and are inserted into the female fitting.
• Caps come in socket-weld, threaded and butt-weld configurations. The socket-weld and threaded caps are female types that the pipe inserts into. The butt-weld caps are welded to the pipe, as per other butt-weld fittings.
• Blind flanges bolt directly to a flange, and are of equal facing and class rating.

1.9 Flanges, Gaskets, Bolting

1.9.1 Flanges

Description:
Flanges – a stud-bolted, gasketed joint – are one of the most common methods used to join piping systems. Flanges provide a ready method of assembly and disassembly of the piping components: in-line instruments, equipment, and valves, for maintenance and repair. They come in a variety of ratings, facings, end types and materials to address pressure, temperature and commodity requirements.

Steel flanges NPS 1/8 to NPS 24 conform to ASME B16.5, Pipe Flanges and Flanged Fittings. Steel flanges NPS 26 to NPS 60 conform to ASME B16.47, Large Diameter Steel Flanges. Caution: care must be taken, by the designer, when using flanges covered in B16.47, to ensure that the bolt hole drilling pattern will match the equipment to which it will be attached. Use Series A for previous installations with MSS SP-44, Steel Pipeline Flanges, and Series B for flanges mating to API 605 (now withdrawn), Large-Diameter Carbon Steel Flanges. Orifice flanges NPS 1 to NPS 24 conform to ASME B16.36, Orifice Flanges. Cast-iron flanges NPS 1 to NPS 96 conform to ASME B16.1, Cast Iron Pipe Flanges and Flanged Fittings.

Classes (Pressure – Temperature Ratings):
Steel flanges come in seven classes of pressure – temperature ratings: 150, 300, 400, 600, 900, 1500, and 2500. Common vernacular is to make reference to flange ratings in “pounds”: 150 lb, 300 lb, etc. This is because previously, in the older ASA B16.5, reference was in those “nominal” terms. To avoid confusion, as pounds generally infers either pressure containment (psi) or weight (lbs), further revisions to the standard dropped this practice in favour of Classes. The correct terminology is now Class 150, Class 300, etc. Note: Class 400 is not commonly specified for use in the process piping industry, but may show up on some equipment.

As the class rating goes up, so does the ability to contain higher pressure – temperature combinations. Referring to the attached extract from B16.5, Tables 1A and 2-1.1, it can be seen that a Class 150 flange of Material Group 1.1 can contain 285 psig between design temperatures of -20 to 100°F. Whereas a similar flange of Class 2500 can contain 6170 psig. The higher the rating the more material (thicker the flange), and the greater the number of bolts. Bolting is equally spaced around the flange on the bolt circle diameter (BCD). 360° divided by the number of bolts gives the bolt spacing, e.g. 4 bolts will be spaced 90° apart. The number of bolts increases by groups of 4: 4, 8, 12, 16, 20, etc.

Cast-iron flanges come in four classes of pressure – temperature ratings: 25, 125, 250, and 800. Classes 125, 250, and 800, have the same number of bolt holes and BCD as per Classes 150, 300, and 600 respectively, and can be bolted directly to those flanges of the same NPS size. Because of the brittle nature of cast-iron, and therefore the risk of cracking the flanges, the mating steel flange must be flat faced with a full face gasket.

Flange Types
Flanges are available in different types to match the piping systems:
• Welding Neck (WN)
• Lap Joint (no abbreviation)
• Slip-On (SO)
• Socket-weld (SW)
• Threaded (Thr’d)
• Blind
• Orifice

Welding neck, lap joint, and slip-on are primarily used in large-bore(NPS 2 and larger), butt-weld piping systems. Socket-weld and threaded are primarily used in small-bore (NPS 11/2 and smaller) piping systems. The most common type, in the petro-chemical industry , is the welding neck flange with a raised face (RFWN).

Facings and Finishes:
It is important to have a leak-free joint between the mating faces of a pair of flanges. To ensure this a variety of flange facings and gasket materials are available. The choice of facing and gasket (see next section “Gaskets”) are closely linked, and are decided based on the pressure, temperature and commodity of the piping system. There are five basic types of flange facings commonly found:
• Raised Face (RF)
• Male and Female
• Tongue and Groove
• Ring Joint (RJ)
• Flat Face (FF)

Note: ASME B.16.5 uses the nomenclature of Ring Joint and RJ. While it is quite common to hear reference to Ring Type Joint and RTJ, this should not be used.

The raised face is the most common facing employed. This face type allows the use of a wide combination of gasket designs. The purpose of the raised face is to concentrate more pressure on a smaller gasket area and thereby increase the pressure containment capability of the joint. With RJ flanges, the force on the gasket is even greater, making them suitable for use at very high pressures.

In order for the gasket to seal it is required that the flange face “bite” into the gasket material. Therefore, flange facings are machined with grooves, the heights of which are measured in microinches (in) or micrometres (m), and are stated as Arithmetic Average Roughness Height (AARH) or Root Mean Square (RMS). AARH states the average height of the grooves. RMS averages the squared heights of the grooves, and takes the square root of that number to get an average height. RMS gives a more accurate result, as squaring the height accentuates the higher spots. The facing of raised face and flat face flanges are machined with a phonographic (most common) or concentric grooved finish, the industry standard being 125 to 500 in or 3.2 to 12.5 m. Most gasket manufacturers recommend 125 to 250 in (3.2 to 6.3 m) for spiral wound, and 250 to 500 in (6.3 to 12.5 m) for sheet gaskets. See diagram – flange facing finish.

1.9.2 Gaskets

Gaskets are covered under ASME B.16.20 or B16.21, depending on the style. They are placed between mating flanges to prevent leakage. The gasket material is softer than the flange material and will fill-in the grooves of the mating faces creating a seal. Gaskets are chosen based on several factors:
• Mechanical integrity – the ability to provide sufficient strength against crushing and in-service blowouts.
• Leak tightness – the ability to be “springy” and maintain a seal at times when the flange bolts may relax.
• Fluid service compatibility – the ability to tolerate the chemical concentration in the expected temperature range, providing resistance to degradation.
• Fire safety – the ability to maintain leak tightness, for piping in flammable services, when exposed to fire.

Gasket materials include graphite, rubber, fabric, steel, aluminum, copper, brass, and monel, and are constructed in the following ways: flat, composition, corrugated, grooved, jacketed, spiral wound, and oval ring. Prior to falling out of favour, asbestos-based gaskets represented about 95 % of all the gaskets used in process piping, due to the unique properties of chemical inertness, thermal behaviour, and excellent sealability. In recent years, flexible graphite has become the leading gasket material to replace asbestos in the petro-chemical industry .

The most common gasket styles used in the petro-chemical industry are the spiral wound, in lower to medium pressures, and the oval ring (made of soft iron or stainless steel) in higher pressures.

1.9.3 Bolts and Nuts

Mating flanges are held together with bolts. Two types of bolts are common – square head machine bolts (conform to B18.2.1, Square and Hex Bolts and Screws), and stud bolts (conform to B1.1, Unified Inch Screw Threads). Machine bolts are common with cast-iron flanges, while stud bolts are commonly used to join steel flanges. Stud bolts have several advantages:
• More easily removed if corroded.
• Not easily confused with other types of bolts.
• Easier to use in confined areas.
• Can be manufactured in the field by threading compatible bar stock.

In the petro-chemical industry alloy-steel is the common bolting material, because of its improved strength and toughness over carbon-steel. Various grades of steel are available to suit the design requirements. The vast majority of studs, used in regular service, are ASTM A193 Gr.B7 with ASTM A194 Gr.2H nuts; ASTM A193 Gr.B7M studs are used in sour service; ASTM A320 Gr.L7 studs are used in cold service.

2.0 Valves

Description:
Valves are mechanical devices whose purpose is to control the flow of fluids in piping systems. A valve performs this control function by placing an obstruction in the path of the fluid. The obstruction is referred to as the flow control element. The design of the flow control element determines the type of valve and the form of control for which the valve is suited.

There are many different valves, conforming to many standards written by various organizations. API and ASME are two of the principal organizations that publish standards for the petro-chemical industry. Two of the most frequently used standards in process piping are, ASME B16.34, Valves – Flanged, Threaded, and Welding End, and ASME B16.10, Face-to-Face and End-to-End Dimensions of Valves.

Dimensions for valves are listed in B16.10 . Note that many manufacturers do not follow these standard dimensions for ball, plug, and check valves. For dimensions of these valves always refer to the manufacturers’ catalog.

Pressure-Temperature Ratings:
Valves are manufactured in pressure classes, e.g. Classes 150, 300, etc., to match the piping system in which they are connected. Pressure classes are often referred to as pounds, e.g. a Class 600 valve is often called a 600 pound valve. This can be misleading, as it has nothing to do with weight (lbs), and a Class 600 valve can contain internal pressures of more than or less than 600 psi, dependent on temperature. See attached extract from B16.34, Table 2-1.1. Note that the working pressures match those listed in the extract from B16.5, Table 2-1.1, for flanges. The allowable stresses on a metal decreases as the temperature increases, therefore, working pressure goes down as temperature goes up (a valve shell is assumed to have the same temperature as the fluid passing through it).

The body of the valve is marked to indicate the pressure class. The way in which this is marked varies, depending on shell material and intended service. Steel valves are marked with the class number. On bronze and iron valves there are two markings: S, SP, or SWP (for Steam, Steam Pressure, or Steam Working Pressure respectively), and WOG (Water, Oil, Gas) or CWP (Cold Working Pressure). Valves marked with WOG or CWP rating are primarily intended for use in services in which the fluid is maintained at ambient temperatures, such as, but not limited to, water, oil, and gas. WOG and CWP are sometimes referred to as cold rating.

The S, SP, or SWP rating represents the maximum allowable working pressure of the valve when used with steam (provided the steam temperature does not exceed the maximum temperature for the shell material). Manufacturers list temperature restrictions in their catalogs.

The WOG or CWP rating represents the maximum allowable working pressure at ambient temperatures,
-20oF to 100oF (refer to B16.34, Table 2 series).

As an example, a valve marked 125 S – 200 WOG is rated to 125 psig in steam service (higher temperatures), and 200 psig when used in services at ambient temperatures.

Note that the pressure rating of soft-seated valves, e.g. ball and butterfly valves, falls much faster as the temperature rises than that of metal seated valves, e.g. gates and globes. This is because the soft seats are made of materials such as teflon or nylon which softens quickly as temperature increases.

End (Connection) Types:
Valve bodies are available in all end connection types to match the piping system:
e.g.
• Threaded (Thr’d)
• Socket-weld (SW)
• Flanged (Flg’d)
• Butt-weld (BW)
The end connections match the class ratings of fittings and flanges. Commonly threaded and socket-weld valves are used in small-bore (NPS 11/2 and smaller). Flanged and butt-weld are used in large-bore (NPS 2 and larger). Certain valves types, primarily butterfly, some checks, and some gates, have a wafer body style and are sandwiched between flanges.

Parts of a Valve:
There are four basic parts to a valve:

The “Body” – the part of a valve that houses the flow control element, contains seating surfaces, retains fluid pressure, and has ends for connecting into the piping system. The internal opening through the valve body is called the “Port”.

The “Bonnet” – the part of a gate, globe, or diaphragm valve, that is fastened to the body to complete the pressure containing shell. It has an opening for the stem to pass through. Depending on the valve stem
design, it may also have a yoke attachment. On other types of valve design, such as check valves, this may just be a “Cover” plate.

The “Trim” – the parts of a valve inside the shell that are “wetted” by the fluid. Components of the trim include:
• Disc – movable part which affects flow, the flow control element.
• Seat – causes seal when valve is closed.
• Stem – controls the position of the disc.
• Packing – seal between bonnet and stem.
• Gland – holds packing in place.

The “Operator” – the mechanism that moves the stem and opens or closes the valve. Operator types include:
• Handwheel – used on gate, globe, and diaphragm valves.
• Lever or wrench – quick open and closure (90° or quarter turn) on plug, ball, and butterfly valves.
• Chain operator – attached to the handwheel or lever for manual operation from grade, of a valve located too high to reach.
• Stem extension – used for valves below grade or floor level, to raise the handwheel to a convenient operating height for the plant personnel.
• Gear operators – used when it is necessary to reduce the force to manually operate the valve; such as is the case with large valves and valves operating against high fluid pressure.
• Electric, hydraulic or pneumatic actuators – used for automatic or remote operation of valves. Control valves are commonly operated by a pneumatic (diaphragm) actuator.

Also see section “Miscellaneous Information”.

Materials:
Valves are available in many materials, including: carbon steel, stainless steel, iron, brass, and bronze. Carbon steel valves are the primary choice of the process piping industry. When a valve is called bronze or steel reference is being made to the shell material. The shell material is selected based on pressure containment, and, unless the valve is lined, the ability to withstand the corrosive and erosive affects of the fluid. The body of the valve is marked to indicate the material, but this marking may be an abbreviation. For instance, A216 Gr. WCB may be abbreviated as WCB, A352 Gr. LCB may be abbreviated LCB.

Trim materials can be categorized as metallic or non-metallic. Metallic groups include copper alloys, stainless steels, and exotic alloys. Non-metallic groups include plastics and elastomers. Trim materials are selected based primarily on resistance to erosion and corrosion, and mechanical wear resistance. Mechanical wear resistance is particularly important for the disc and seats, as it is the tight mating of these surfaces that creates a leak-free seal when the valve is closed.

Often the materials used to make the shell do not have the desired properties to be used for the trim.

Additionally to the ASME standards, NACE International publishes standards for materials, mechanical properties, and heat treatments for metals used in sour service (exposure to Hydrogen Sulfide).

Valve Function:
The major valve functions, or service, are as follows:
• On-off – starting or stopping flow, fully open or fully closed.
• Throttling or regulating – varying the rate of flow.
• Checking – permitting flow in one direction only.
• Switching – diverting the flow direction.
• Discharging – discharging fluid from a system, or limiting fluid pressure.

Valve Selection:
There are hundreds of combinations of valve types, designs, materials, etc. Selecting the right valve for an application is based on several criteria:
• Fluid type – gas, liquid, two-phase, slurry.
• Fluid characteristics – corrosive, erosive, toxic.
• Operating conditions – pressure and temperature.
• Service requirements – on-off, throttling, checking, switching, discharging; degree of shutoff; slow or quick opening.
• Availability – cost vs. delivery.

Flow characteristics:
When a valve is first opened (the obstruction to flow is removed) fluid begins flowing through it. Further movement of the flow control element allows more fluid to flow, until the valve is fully open and maximum flow rate has been achieved. The flow characteristic of a valve is the relationship between the position of flow control element and the rate of fluid flow through the valve. As the flow control element moves through its travel, the shape and size of the opening are changed. Different flow characteristics are achieved with differing size and shapes of flow control elements. Tests determine the inherent flow characteristics of a valve design, and these results are plotted on a graph. The curve shows the position of the flow control element and the flow rate as percentages of their maximums. There are three common valve flow characteristics: quick-opening, linear, and equal percentage.

Refer to the attached graph “Valve flow characteristic curves”:
• Quick-opening. It can be seen that the quick-opening characteristic produces large changes in flow rate at the start of flow control element travel, and then progressively smaller changes until the valve is completely open. The intake and exhaust valve of the internal combustion engine are examples of quick opening valves, and are characterized by their ability to provide full flow with relatively small stem movement.
• Linear. The linear characteristic produces changes in flow rate that are directly proportional to the position of the flow control element over the full range of flow control element travel. Stated another way, when the flow control element is 25% from the seat the flow rate through the valve will be 25% of maximum, when it is 50% flow rate will be 50% of maximum, and when the flow control element has reached the limit of its travel the flow rate will be 100%.
• Equal percentage. With the equal percentage characteristics, equal increments of flow control element travel produce equal percentage changes in flow rate. To illustrate this, follow the equal percentage flow characteristics curve. The curve shows that changing the flow rate control element position from 40% open to 60% open (a 20% increment) produces a change in flow rate from 12% of maximum to 24% of maximum – a 100% increase. Changing the flow control element from 60% open to 80% open (also a 20% increment) produces a change in flow rate from 24% of maximum to 48%
of maximum – again a 100% increase.

Leakage:
Valves are designed not to leak internally or externally. Internally, when fully closed, there should be no flow. Externally, fluid cannot be allowed to leak into the environment. Manufacturers conduct leak tests, as per set standards such as API 598, to determine leak tightness. A valve is termed “bubble tight” when the upstream side of the valve is pressurized with air and the downstream side is filled with water and no air bubbles are detected on the downstream side of the valve with the valve in the fully closed position.

The most common types of valves used in process piping are listed below. Descriptions for each are of a generic nature. The basic designs come in variations designed to suit specific applications.

2.1.1 Gate

Gate valves are used in on-off service. Advantages are:
• Good shutoff characteristics.
• Bi-directional.
• Minimal pressure drop.

Disadvantages are:
• Not quick opening or closing. Full stem travel requires many turns of the handwheel or an actuator.
• Require lots of room for installation, operation, and maintenance.
• The slow movement of the disc near to full-closed position results in high-fluid velocities, causing erosion of the seats. This is referred to as “wire draw”.
• Susceptible to thermal and/or pressure binding.
• Difficult to repair in-situ.
• Not suitable for slurry applications.

2.1.2 Globe

Globe valves are used in throttling service. Advantages are:
• Good shut-off capability.
• Good throttling capability.
• Shorter stroke (compared to gate valve).
• Available in various configurations, each offering unique capabilities.
• Easy to machine or resurface the seats.
• Bi-directional.

Disadvantages are:
• High pressure drop (compared to gate valve) due to changes in fluid flow direction.
• Requires high force to seat the valve when the pressure is under the seat.
• Practical size limitation is NPS 12 due to stem thrust.

2.1.3 Butterfly

Advantages are:
• Suitable for on-off and throttling services.
• Compact design requires considerably less space than gate and globe valves.
• Light weight.
• Quick to open and close. Quarter turn.
• Available in all size ranges.
• Low pressure drop.
• Provides bubble tight service.
• Can be used in slurry applications.

Disadvantages are:
• Only good for throttling service involving low differential pressures, as in cooling water or air supply systems.
• Throttling is limited to a 30° to 80° disc opening.
• Cavitation and choked flow are two potential concerns.
• The disc movement is unguided and affected by flow turbulence.

2.1.4 Diaphragm

Advantages are:
• Suitable for on-off and throttling services.
• Offer good chemical resistance due to a variety of available linings.
• Stem leakage is eliminated.
• Provides bubble tight service.
• Does not have pockets to trap commodities, such as slurries. Used extensively in industries where contamination can be a problem, such as pharmaceuticals, and food processing.

Disadvantages are:
• The weir can prevent drainage of piping.
• Working pressures and temperatures are limited by the diaphragm material.
• The diaphragm may experience erosion when used extensively in severe throttling service containing impurities.
• Only available in limited sizes. Usually NPS 1/2 to NPS 12.

Check:
Check valves are used to prevent backflow. Advantages are:
• Fast acting and self-actuated, requiring no external means to open or close.

Disadvantages are:
• All moving parts are enclosed so it is difficult to assess the condition of the internals, and whether the valve is open or closed (disc can stick open).
• Limitations on the installation configuration.

2.1.5 Ball

Ball valves are used in on-off service. Advantages are:
• Provides bubble-tight service.
• Quick to open and close. Quarter turn.
• Smaller and lighter than a gate valve.
• Available in multi-port configurations.
• Force required to operate the valve is smaller than that required for a gate or a globe.
• Minimal pressure drop.

Disadvantages are:
• Not suitable for throttling applications.
• Not suitable for slurry applications.

2.1.6 Plug

Plug valves are used in on-off service. Advantages are:
• Simple design with few parts.
• Quick to open and close. Quarter turn.
• Can be serviced in place.
• Minimal pressure drop.
• Provides reliable leek tight service.
• Available in multi-port configurations.
• Can be used in slurry applications.

Disadvantages are:
• Requires greater force to open/close due to high friction. NPS 4 and larger require actuators.
• Reduced port due to tapered plug.
• Typically cost more than ball valves.
Needle:
Needle valves are used in throttling service. They are primarily used in instrumentation. Advantages are:
• Very accurate throttling.
• Can be used in high pressure/temperature applications.

Disadvantages are:
• Available only in small sizes to NPS 1.

2.2 Valve Operators

2.2.1 Hand-wheels & Levers

Manually operated valves require a hand-wheel or lever to be opened or closed. Ball, plug, and butterfly valves (quarter turn valves) have a lever, while gate, globe, and diaphragm valves have hand-wheels. There are various stem combinations available (see attached “Variations in Stem Operation”). Inside Screw, Outside Screw, Raising Stem, and Non-Rising Stem.

External and internal corrosion considerations determine which design will be used. For example, it is desirable to have the threads outside of a corrosive fluid that could damage them. Likewise, in a corrosive atmosphere, such as offshore, it may be less damaging to have internal threads.

Generally speaking, small-bore valves have an internal screw and a rising stem. Large-bore globe and diaphragm valves come with an outside screw and a rising stem. Large-bore gate valves come in two variations: Outside Screw and Yoke (OS&Y), where the handwheel is attached to the yoke and draws the stem through itself. And an internal screw with non-rising stem arrangement, where the disc has internal threads and is drawn up the stem.

2.2.2 Gear Operators

Gear operators assist in the opening of large valves and/or valves with a high-pressure differential across the flow control element by providing reduction gearing to minimize the manual effort of opening or closing the valve

2.2.3 Control

The term “control valve” could likely be applied to all valves, as all valves perform a fluid control function. However, this term has a specific meaning. The Instrument Society of America (ISA) defines a control valve as “a final controlling element, through which a fluid passes, which adjusts the size of flow passage as directed by a signal from a controller to modify the rate of flow of the fluid.” From this definition it is apparent that the regulation of the flow is automatic, and that a control valve is part of an automated system. Systems of this nature are referred to as ”closed loop”, and by regulating the flow, control valves can be used to regulate all four process variables: level, pressure, temperature, and flow.

For the valve to operate automatically, it must be equipped to do so. The equipment which achieves this is called the actuator. Actuators are attached to the valve bonnet and stem, and operate by either pneumatic, hydraulic, or electric signals.

2.2.4 Pressure Safety/Relief

Piping systems must be protected from overpressure. This is accomplished by discharging some of the fluid. There are three types of valves for discharging:

Pressure Safety Valve (PSV): an automatic pressure relieving device actuated by the static pressure upstream of the valve, and characterized by rapid, full opening as a pop action. A PSV reseats when the fluid pressure has been reduced to a level below the pressure at which the valve began to open. Used for steam, gas or vapour services (compressible fluids).

Pressure Relief Valve (PRV): an automatic pressure relieving device actuated by the static pressure upstream of the valve, which opens in proportion to the increase in pressure over the opening pressure. A PRV will close when pressures have been restored to normal. It is used primarily for liquid service (non-compressible fluids).

Pressure Safety-Relief Valve: an automatic pressure relieving device suitable for use as either PSV or PRV, depending on its application.

3.0 Bibliography

The contents of this section were kindly provided by Richard Beale, co-author of The Planning Guide to Piping Design

Other References are

• Piping Handbook – Seventh Edition, by Mohinder L. Nayyar. McGraw-Hill, ISBN 0-07-047106-1
• Piping Systems – Drafting and Design, by Louis Gary Lamit. Prentice Hall, ISBN 0-13-676445-2
• The Valve Primer, by Brent T. Stojkov. Industrial Press Inc., ISBN 0-8311-3077-6
• Process Piping Drafting, by Rip Weaver. Gulf Publishing Company, ISBN 0-87201-761-3
• ENGD 320 – Process Piping Drafting 1, Construction Department, Southern Alberta Institute of Technology
• Welding Fittings and Forged Flanges, Crane catalog 61
• Piping Equipment (handbook), Trouvay & Cauvin

Various websites and applicable ASTM and ASME standards where also referenced for the compilation of this material.